Thank you very much. Hello, everyone. We began the year with a strong set of first-quarter results that demonstrate TotalEnergies' ability to fully leverage the upside of an improving environment. While Brent was up by 22% compared to Q1 2020, TotalEnergies' first quarter of 2021 adjusted net income jumped by about 70% to $ 3 billion or $1.10 per share. We are back on track. The $3 billion of adjusted net income is actually above the level of the pre-crisis first quarter 2019, despite a less favorable environment this year, benefiting from the action plan delivered in 2020. Debt-adjusted cash flow was very strong at $5.8 billion, up by one-third compared to a year ago. Gearing, you know one of our key metrics, was brought back down to less than 20% by the end of the first quarter, which is a top priority for us in terms of restoring sustainable financial flexibility. We have indeed recovered significantly from the difficult and uncertain 2020 environment, when Brent dipped below $20 per bbl, and we have benefited from rebounding markets, including Brent, which averaged more than $60 per bbl in the first quarter. However, to be clear, we credit mainly the Saudi-led OPEC+ discipline for the current oil price. We note that many parts of the global economy are still struggling with persistently weak demand for aviation fuel, and lockdowns are still in effect in many areas. We remain prudently optimistic and focused on the fundamentals that got us through the crisis and contributed to the strong first-quarter results. As a reminder, the key actions and lessons learned from 2020 are the following. First, discipline on costs. With more than $ 1 billion of cost reduction in 2020, we target an additional $0.5 billion of cost saving this year. Best-in-class production costs of $5.10 per bbl in 2020 with a target of $5 per bbl. Within the context of developing a world-class renewable power business, we managed CapEx down to $13 billion in 2020 and set a target between $ 12 billion and $13 billion for 2021. I will give you more details. We are continuing to high-grade the portfolio, the organic breakeven was below $25 per bbl in the first quarter. This allow us to capture the upside of the stronger environment. Operationally, the group's first quarter production was up slightly compared to the previous quarter by 0.8% to 2.86 million barrels per MMbpd oil equivalent and still reflects the impact of OPEC+ quotas. This is in line with our guidance for stable production in 2021 compared to 2020. Production benefited mainly from the progressive return of Libya as well as our process and ramp-ups, including Novy Urengoy in Russia, Culzean in the U.K., Johan Sverdrup in Norway, and Iara in Brazil, all largely offsetting the natural decline. Looking now at the operating segments, we are pleased with the performance of the iGRP segment. We've set a new record high for adjusted net operating income in the first quarter of $1 billion and generated strong cash flow of more than $1 billion. Although LNG prices were down compared to a year ago, iGRP posted very strong results thanks to growing LNG sales and the positive contribution of renewables and electricity. The recent ramp-up in oil prices will continue to have a positive impact on our LNG prices over the coming six months due to the lag effect on pricing formulas. Regarding the situation at our Mozambique LNG project, let me emphasize that security is our top priority. We reported last month that the security situation near Palma was very serious. Considering the evolution of the security situation in the north of the Cabo Delgado province in Mozambique. Total decided to withdraw all Mozambique LNG project personnel from the Afungi site. We have declared force majeure. We are managing the situation with contractors to minimize spending as long as we do not have clarity on the situation. We hope that the actions carried out by the Government of Mozambique and its regional and international partners will enable the restoration of security and stabilize the Cabo Delgado province in a sustained manner. Obviously, these events will impact the project schedule, and at this stage, we estimate the impact of at least a year of delay. As we have a large portfolio of LNG projects, we will give priority to Cameron LNG Extension and Papua LNG projects. Turning now to the renewables and electricity activity. We are continuing to accelerate growth in 2021, notably with the recent acquired 20% stake in Adani Green Energy Limited company. We are increasing our level of disclosure so you can see that our proportional share of EBITDA for this activity increased by about 40% year-over-year, close to $350 million in the first quarter. Gross installed renewable power generation increased to 7.8 GW from 3 GW a year ago, and net power production grew 4.7 TW hour from 3.2 TWh over the same period. We are continuing to add to the portfolio, focusing on early-stage acquisition opportunities, and in 2021, we will allocate more than 20% of our CapEx to developing this activity. In addition to the acquisition of 20% of Adani Green Energy, the largest solar developer in the world, and of 4 GW of portfolios in the U.S. during the first quarter, we won leases rights of 1.5 GW U.K. offshore wind project, and we farmed down our equity interest in more than 300 MW of renewable assets in France on the basis of a $600 million enterprise value at 100%, in line with our capital-light model and also contributing to de-risking the portfolio. Moving to our oil business, the E&P segment successfully leveraged the rebound in oil and gas prices and increased first quarter adjusted net operating income to $2 billion, nearly triple the same quarter last year. Cash flow to $3.8 billion, up by about 50% compared to a year ago. E&P continues to be the cash flow engine that is powering the group through the transition and into the future, and Total clearly benefits from the leverage on the oil price. With the signature of definitive agreements enabling to launch our Tilenga and Kingfisher upstream oil project and construction of East African crude oil pipeline in Uganda and Tanzania, the group is implementing a strategy to invest in resilient, low break-even projects that reduce the carbon intensity of its portfolio. Unlike the upstream, the downstream continued to face a tough environment, generating net adjusted operating income of $527 million and a cash flow of close to $900 million. European refining margins remain in the single digits, reflecting mainly the still depressed demand for aviation fuel, impacting the whole distillate market, but also the global level of demand. 13 MMbpd in the first quarter of 2021 versus 15 MMbpd in the first quarter of 2020. In contrast, petrochemical margins were strong, showing improvement year-over-year and quarter-to-quarter. Marketing results were resilient despite ongoing lockdowns that decreased volume by about 5%, mainly in Europe. We started production of sustainable aviation fuel, SAF, at La Mède and our facility at Oudalle in France. Early stage, but demonstrating the group ability to transform and adjust to the changing environment across its different business units. Finally, at the group level, we generated $5.8 billion of cash flow, debt-adjusted cash flow in the first quarter. For now, we are back on track at pre-crisis levels. In the first quarter, we also benefited from a working capital release of about $0.3 billion. For the full year, if we maintain a hydrocarbon environment like the first quarter, with Brent around $60 per bbl, European gas around $6 per million BTU, and assuming European margins, refining margins, around $ 10-$ 15 per ton, we would expect to generate around $24 billion of debt-adjusted cash flow. First quarter net investments, which include acquisition and asset sales, was $4 billion. Our guidance for the year 2021 net investments is a range between $ 12 billion and $13 billion, which is split roughly as half for maintaining the existing business activities and half for sustainable growth. Our strategy is to invest responsibly in profitable projects that reduce the carbon intensity of the portfolio and achieve the transformation of the group to a broad energy company. To this end, half of the net investments will be allocated to maintain the group's activities and half for growth. Nearly 50% of these growth investments will be allocated to renewable and electricity. Our gearing was 19.5% at the end of the first quarter, helped by the issuance of hybrids to finance the renewable acquisition in India in Adani Green. The current environment is allowing us to restore balance sheet strength faster than expected. We confirm that our priorities for cash flow allocation are to invest in growing the company, to support the dividend through the economic cycle, and to maintain a strong balance sheet and a minimum long-term single A debt rating, with gearing sustainably anchored below 20%. I remind you that at the end of 2018, the gearing was around 15%, of course, 15% is better than 20% to face volatility. With a strong start to the year and confidence in the fundamental of the group, the board of directors decided to distribute a first interim dividend of EUR 0.66 per share. That means that the first interim dividend will be stable in euro, considering the foreign exchange rates, compared to a year ago, this interim dividend represents an increase of about 9% in USD. Overcoming the challenges of 2020 has made us a stronger company, the market rebound is allowing us to accelerate our transformation to TotalEnergies. At our shareholder meeting in May, we will propose the adoption of TotalEnergies as the new name of the company to mark our expansion into the renewable power generation business on a worldwide scale, transforming the group into a broadly diversified energy company. We will submit, sorry, to the advisory board of shareholders a resolution about our energy transition strategy towards carbon neutrality. This move demonstrates our commitment to the energy transition and to carbon neutrality that we have presented in a number of targets. First, we reaffirm the clear ambition to get to net zero emissions by 2050 across our worldwide production and energy product used by our customers, Scope 1 + 2 + 3, together with society. Specific commitments are taken by 2030. The next decade is key. -30% net emissions on operated oil and gas operations worldwide by 2030 compared to 2015, the date of the Paris Agreement. Reduction in absolute terms of Scope 3 worldwide emissions by 2030 versus 2015. We are the only ones among our peers having set an absolute figure target. -20% carbon intensity reduction for energy products sold to our customer, Scope 3. This is a more stringent target than the one announced previously. In Europe, 30% reduction of absolute emission by 2030 extended to Scope 1 + 2 + 3 versus 2015. Our climate ambitions are well and other sustainable developments are embedded in the strategies of the group and, like our name, mark the beginning of a new phase in the development of the company. Now let's go to the Q&A. Thank you. Your first question today is from the line of Jon Rigby. Please go ahead. Thank you. Hi, Jean-Pierre. Hi, Jon. Hi. Two questions, if I can. The first is on your segmental earnings numbers. Both your iGRP and your downstream numbers, or I should say your refining and c hemicals numbers, have a couple of quite big moving parts in them that we can't see. I just wondered whether you were able to sort of characterize, particularly, I think, for refining and c hemicals, some kind of split between the contribution from refining and the contribution from either both petchem and other chemicals operations. Just simply because I'm conscious that those two numbers are very widely different and actually the market probably ascribes very significant different values to them. If I can just talk on just iGRP. I take the point about the renewables improvement sequentially, it doesn't explain even closely the delta on the earnings. I'm guessing there's a contribution from trading in there. I'm not expecting you to give me an exact number, but as we sort of think about the moving parts going to 2Q with rising LNG prices on a contract basis, but presumably not the kind of windfall earnings you saw in 1Q. Are you able to sort of at least give us a little bit of color on that, please? Okay. Perhaps I will start with the second question regarding iGRP. Well, you will not be surprised that we cannot give you a detailed figure regarding the performance of trading. I can confirm that given the volatility, and given our global footprint, our portfolio we have now in our hands, we are able to capture the volatility in the market. I have in mind some record sales done by our trading in January in the U.S. in the situation of a very cold winter. That's true that it's one of the driver of the high-end performance this quarter. You do not have to minimize the contribution of renewable and electricity contribution as well. We give you the EBITDA of this segment, I would say, in the press release. You have all the details, I think, in the appendix as well. You will see that this segment alone contributes as EBITDA more than between $300 million and $400 million. It starts being sizable, I would say. The second question regarding R&C, you have the right analysis. The performance of refineries, and particularly in Europe, was poor during the first quarter. In the U.S., we're impacted by the Uri again as well. The margin, we are close to zero in Europe. Honestly, summer should see some improvement. This improvement could come from the U.S. and the recovery that seems to happen in this country in the coming months, and the exit from the pandemic will obviously help to restore the margin. Even you have noticed that we continue to be very cautious regarding the margin, so we gave a guidance for the net adjusted cash flow using, I would say, conservative assumption, $ 10-$ 15 per ton for refinery margins for the full year. On the opposite, petrochem results were very good. Because petrol margins were strong in Q1, showing improvement, by the way, year-over-year or Q-to-Q. The volumes, the margins, they proved resilient through the pandemic, the COVID-19 crisis. The volumes remain robust for both PE and NPP. It is clear that some segments like food packaging, medical, protective equipment, more than compensate the slowdown in other sectors such as automotive and construction. We continue to be optimistic regarding Petrochem. We benefit from integrated platforms as far as Total is concerned. We are well-positioned to capture a possible continued market that for sure will continue to be strong. Performance of the trading, yes, I have already commented that. Maybe if we can just reverse it out a little bit. What level of refining margin would you expect to have to have for the refining business to be break even? At least I can sort of gauge the relative sort of negative, positive contributions to the net result. It's different, of course, if you are dealing with integrated platforms or more isolated refineries. Once again, we are conservative, and so we use this $ 10-$ 15 per ton of assumption for building our guidance. It doesn't mean that, of course, will be true. Yeah. I would say that what has been done. We will continue to do that if needed. We have voluntary cuts, the runs in terms of our refinery. It was the case in those in particular to refinery in France. We could continue with the same policy. On the other side, you know perfectly that we have sold our U.K. refinery in the U.K., so that we have stopped the operation in Grandpuits, so another refinery in France. The plan is, of course, to adapt our footprint to the market. That's what I can answer to you to this question and to adapt our model or our assets to the situation and to the current market. Once again, we are a bit more optimistic than before, given the recovery we see in China, in Asia, more generally in the U.S. The fact that, hopefully, the vaccine will help to exit from the current situation. By the way, the stocks globally, the stocks in OECD countries, they are back to around, I think, 70 days. It give us some hope regarding this sector in the coming months or quarters. Okay. Well, I hope to contribute to aviation demand somehow, Jean-Pierre. Yes. Thanks for that. That's clear. That's the situation for the airlines company and the aviation, and the fact that we have to pull the kerosene into a distillate at present time. It's one of the reason why the margin are so low. That's true. Thank you. I don't know when this sector will come back to pre-crisis level. I'm not so sure that it will take many quarters. I don't know. We have to be patient and once again, to be active and so to focus on what we control. Honestly, it's difficult to control demand and to anticipate what could happen in the coming months. Okay, thank you. Thank you. The next question is from the line of Oswald Clint from Sanford C. Bernstein. Please go ahead. Jean-Pierre, thank you so much. Just on CapEx, I had a $12 billion number in my head for this year. I think you talked about $ 12 billion-$ 13 billion potentially. Yeah. Obviously, the $12 billion was at a lower oil price. We're now going to minimize the CapEx in Mozambique rest of the year. Is there a CapEx pickup taking place somewhere else in the business relative to the plan? The second question, I wanted to ask you about the Siemens Energy collaboration on reducing your CO2 around the LNG portfolio. What's the timeline on this initiative? Is it short-term, longer term? Is it focused on green fields, or can you really retrofit your brownfield LNG plants? Any emissions intensity numbers that you're kind of playing with at this point? Thank you. Okay. Regarding the CapEx. That's true that when we made our budget, we are not at $60 per bbl, and the budget was done for 2021, was done at $40 per bbl. At that time, we mentioned the guidance for CapEx or the global CapEx, organic CapEx, plus the net between acquisition and cessation, and the divestments at $12 billion. Except in February, during the Investors Day, we mentioned that if the prices remain above this level, we can increase CapEx, and we gave a range between $ 12 billion-$13 billion. Having said that, and it's now in the DNA of Total. We want to maintain the discipline on CapEx. Honestly, I don't know, it's premature to evaluate the impact on Mozambique LNG project and force majeure on globally the CapEx for the full year. It doesn't mean that even if we save some CapEx, that we'll use this CapEx to increase significantly investments in E&P or in downstream. We want to keep the discipline, we want to be selective, and once again, our priority to invest in profitable projects that will contribute to the transition of Total into a broad energy company. Having said that, we have some flexibility. Particularly for the upstream segment, we have some flexibilities on short cycle investment that we can restart. I would say, part of this short cycle investment has been stopped or postponed last year in the middle of the crisis. It's possible for us to come back and to sanction this new short cycle project. We can allocate part of this additional CapEx of $12 billion to $13 billion to some renewable and electricity project, if it makes sense, and that means that if we are profitable. That's the main guidance for us when we have to select the different projects. On Siemens agreement, I have to admit that I'm not very familiar with this agreement. I suggest that you come back to the IR teams, and they will give you some more details regarding this agreement. It's clearly in our objective to lower or to reduce the CO2 emissions. It's part of this global strategy, and once again, in the transformation of Total into TotalEnergies. It's in this transformation. Understood. Thank you, Jean-Pierre. Thank you. The next question is from the line of Paul Cheng from Scotiabank. Please go ahead. Thank you. Two question. One, when I'm looking at your LNG and renewable, the cash flow from operation excluding working capital changes versus the fourth quarter is relatively flat, while earnings is up a lot. Wondering if you can maybe help us to bridge the gap, and that why that there's a big difference on here. Secondly, on the asset sales, with the farm down, is there any gain that you have reported in the segment? Thank you. Your question regarding the iGRP. That's correct. Sorry? That's correct. Yeah. In short, what I can tell you is that in the first quarter, or the results, the net operating income in the first quarter 2020, last year, was negatively affected by non-cash elements, the mark-to-market elements or deferred tax elements. That's the main driver behind this, that explain the phenomenon you pointed out. The second is the seasonality in dividends as well. You do not have the same impact of our assets consolidated on an equity basis in the net operating income and in the cash flow, depending, of course, on the seasonality of the dividends. That's the two main elements that explain this difference. Overall, what is more relevant is to compare the NOI increase year-over-year with the cash flow year-over-year. You see that it's very current and very much in line. Asset sales. I'm not sure to have really understood your question. Of course, the farm down on our renewable assets, they are reported, of course, in iGRP segment. It's key in our capital-like model. It's what we explain. It's the best way for us to monetize as soon as the projection, as soon as the COD, when the project starts to pocket, to monetize a significant part of the future results through the PPA signs. It's another way for us, by the way, to direct the project as well. It's part of the model, and of course, it's reported into the iGRP segments for the result and for the investment as well. When we say that we'll allocate more than 20% of CapEx to this segment, it's net CapEx, it's net investments. It takes into account the divestments, and these divestments are part of these figures as well. No, I understand that. Yep. No, I understand that. I'm just asking that whether the farm-down had result in any gain that we recorded in the first quarter in this segment? I'm not sure to understand what you have in mind. Well, when you farm down. Yes. That depends on the value we see. Yes. Did you book any gain? Yes. Did you book any gain in- Yes. The answer is yes. gthe first quarter? Yes. If you do, can you share that? How big are those gains? Is it a meaningful number? I give you the fact that we farmed down two projects in France, I give you the enterprise value. It's around $600 million of enterprise value, 100%. The way we consider this farm down is to farm down 50% of the projects. At the same time, as you know, we leverage the project, the figures or the debt to equity ratio you can use for your modelization is gearing between 70%-80%. That mean that at COD, we farm down 50%, we lever project at 70%-80%. All this mechanism, I would say, is included into iGRP results and cash flows and investments. All right. Thank you. By the way, I give you a lot of figures regarding this farm down. This $600 million on 100 basis EV, it's for something like 340 MW, I think, if I'm correct. That mean that if you consider that it's $1 million of CapEx for 1 MW on this type of project, that means that we double more or less the value of the initial cash we use for developing this project through this farm down. Thanks. It's in line with the metrics we gave, I think, in February, because at that time we gave some additional example, five or six different farm down that occurred over the last couple of years. Thank you. Thank you. The next question is from the line of Christyan Malek from JP Morgan. Please go ahead. Hi, good afternoon, Jean-Pierre. Thank you for letting me ask a question. I've got two. First on CapEx, but not necessarily CapEx in the context of the range, but more in the context of a broader point on whether you'll be able to demonstrate discipline on CapEx over the medium term. I think one of the major concerns is that the free cash flow that you're generating isn't necessarily free because it's going to either pay down debt and then look to see higher CapEx, whether in oil or transition. You've gone from $ 12 billion-$13 billion, and that's admittedly at a $40 Brent. If I interpolate to $60, where are we going on CapEx is basically the first question. The second, please, is on buybacks and cash return. You mentioned 15% as a comfortable gearing target. What sort of cash return frame would you consider? Within that, previously suspended buybacks, would you revisit if oil, it looks like it's heading to $70? Is there a distribution of cash flow that's viewed as most appropriate over the medium term? I guess one of the things that I want to sort of nuance around that question is, cash flow or distribution relative to previous years, when you look at a yield basis, is only sitting around 20%. I wonder whether that's the new norm for you on cash, particularly within a yield, or whether you would consider upside once you get to 15%. Thank you. Okay. Regarding the cash flow allocation. You know we are consistent in Total. Perhaps I will repeat, sorry for that, what we said in February. What are our priority in terms of cash allocation at Total? First, the CapEx, and so it's linked to your first question. I gave a year guidance for 2021. We gave a guidance between $ 13 billion-$16 billion for the year 2020 - 2025, assuming an environment between $ 50-$ 60 per bbl. Why? Because once again, we want to keep the discipline, invest only in profitable projects. You know the metrics we use for sanctioning the project, and the best way for us to be sure that we will continue to be resilient and profitable is to continue to be disciplined and to stick to these targets. For oil and for upstream project is a 15% IRR at $60 per bbl. You know that for renewable and power, and renewable in particular, it's a double digit, so more than 10% profitability for our equity. That's the discipline we want to implement, and that's why, by the way, we are not able to spend money like that to capture additional assets or additional development in renewable if it make no sense and it does not meet our criteria. Having said that, the second priority for cash flow allocation is supporting dividends through the economic cycles. I think that the decision made by the board in the middle of the crisis, when prices were below $30 per bbl last year, to maintain the dividend, is a clear and strong commitment vis-a-vis the shareholders. The decision was not to cut the dividend. I repeat, I can confirm that the dividend is supported at $40 per bbl, and of course, we will maintain the dividend this year. The third priority, and it's key, and it was very clear, I think, in our statement in February. We want to have a strong balance sheet, and we want to keep a long-term Grade A credit rating. The way to do that, of course, is to have low gearing. The objective for us is to anchor durably, I would say, the gearing below 20%. We are already at this level, that's true. We are at 19.5% end of March. It's not a joke. We were at 15% in end of 2018. Obviously, 15% is better than 20%, is what I mentioned in my speech, in my introduction. Why? We are in the commodity market, we have to be ready for the next possible new downturn. Having this stronger balance sheet for us is key, and is a key element in our cash flow allocation frame. That mean that, it was clear as well in February, we mentioned that buybacks will come only if oil prices will stay above $60 per bbl, and when gearing will be durably, I think, is very important, installed below 20%. To be clear, for 2021, we will maintain the dividend. In euro, another comment I made now at EUR 1.2 per dollar, compared to the EUR 1.5 we had one year ago. It means that it's a reasonable increase in dollar, by dollar, it's 8%, 9%, 10% increase in dollar when you translate the euro into dollar. Maintaining this dividend in euro, and that mean that buybacks will come later. Great. Thank you, Jean-Pierre. Thank you. The next question is from the line of Biraj Borkhataria from RBC. Please go ahead. Hi, thanks for taking my questions. The first one was on Mozambique. Originally, the intention was, I guess, to have the two projects on the onshore in Area 1, Area 4 to run along in sync. I guess the operator on the other side has deferred the project pre-FID, and now you've had to declare force majeure. I was just wondering, if you are able to get back in, you're likely to be ahead of the other operator, and you'll be building infrastructure that maybe is jointly used for the two projects. Is there an agreement already in place where the other block partners compensate Total for any kind of early expenditures, or is that still to be agreed? That'd be my first question. Then the second question is on capital structure. As you've been growing your low-carbon business, most recently, you issued a hybrid, which looks like at very competitive rates. I was just wondering, how do you think about the overall capital structure of Total as you build business and the mixture of instruments like that versus just the newer debt and equity? Thank you. On Mozambique, honestly, at present time, it's not the priority to enter into discussions or to enter into agreements or the different agreements you have in mind. The priority is to maintain the site, to ensure the safety and the security of our employees, to minimize the costs with our contractors. We'll see. I mentioned to you that at present time, we anticipate at least one year delay. We see it's not top priority on the agenda to discuss this subject with the other operators. Hybrid bonds. We were very opportunistic in January of this year, when we issue this EUR 3 billion of hybrids to finance the 20% acquisition of Adani Green. I consider hybrid as a long-term component in my balance sheet. We will continue to be opportunistic. It's a very competitive way to finance renewable with low cost capital. That's the strategy we have implemented. Most of the in renewable project, the project finance that you raise on renewables, it's on a no cost basis. That mean that you transfer the risk to the lenders by doing that. Okay, understood. Thank you. Thank you. Thank you. The next question is from the line of Lydia Rainforth from Barclays. Please go ahead. Thanks, and good afternoon, Jean-Pierre. Good afternoon. Two questions, if I could. The first one is, can you just walk through the idea of the working capital release in the quarter? Obviously, we've seen bills from elsewhere, so just sort of what you expect around that working cap side going forward. The second one was just to come onto the renewables business again. If I think about the Adani JV and this data, how do you think about managing the currency risk for that? Just given what we're seeing in terms of currency. Just linked to that, the offshore project that you entered this morning. It does talk about you basically paying a consideration based on the share of past cost. Normally, you've seen when you've sold things down that you get a premium for whilst it's in development. I'm just wondering kind of what it is that in terms of that project that has been attractive? Thanks. Okay. The first question regarding working capital. We reported the cash in this quarter. The main driver behind this cash in was the timing of some tax elements. If I remember well, it was in Germany and Belgium for downstream, and in Norway for upstream. On the opposite, we have, of course, the impact of the oil price or globally the hydrocarbons price increase that impacted, obviously, the stock values and customer credits. All in all, it was a positive impact. On top of that, we continue, of course, to make some optimization, I would say, of our working capital. I remind you that given that it works well end of last year, we continue or we decided at Excom level to continue to incentivize our managers to proactively manage working capital. To be sure that they made all the actions to minimize the working capital when it's needed. It's very difficult for me to give you colors regarding working cap in the coming quarter because the main certainty, of course, is the level of prices that will obviously impact the work cap. What I can confirm to you is that we will continue to mobilize our staff, our people, to manage proactively this working capital subject. The India. Obviously, we took into account this currency risk in our economy. We decided to go into a different project with Adani in India. It's taken into account. I can share with you that given the predictability of the cash flow coming from PPA in renewable businesses, we can consider forward hedging as well, and it's under consideration at present time. We'll see in the coming months the outcome of these studies. Once again, it's taken into account when we decided to go into that project. It's embedded, I would say, in the fact that we sanction only if they are able to deliver a double-digit profitability for our equity. For the offshore agreement in Taiwan that we announced this morning. Honestly, it's the same. We not give you all the details regarding the CapEx or the cost of the project. It's an opportunistic deal that we were able to sign now that we have, I would say, a lot of connections in this world, in this renewable. Now we know the people, we know the assets. We are able to move very quickly and to capture and to seize these opportunities. We have, obviously, a good PPA for these assets. It's offshore, the CapEx are not the same when you compare to onshore wind. All in all, the same answer as for Adani. If we decided to go into that project, it's because it's coherent, it's in line with the double-digit equity profitability I mentioned to you as thresholds. It was, of course, the way for us to be present in this Taiwan market, very active as far as offshore wind is concerned. Right. Thank you. Thank you. The next question is from the line of Thomas Adolff from Credit Suisse. Please go ahead. Hi. Good afternoon. Two questions from me as well, please. Just firstly, going back to what you said earlier on. For this year, obviously paying the dividend and next year, if oil is higher than $60, there might be a buyback. Once the world is back to normal, whenever that is, this summer, next summer. Pre-COVID, you did have a preference for a progressive dividend. How you think about the progressive dividend versus, "No, I'm going to do buybacks to bring down the cash dividend burden. The world has changed permanently." That's first question. Second question, just going back to Mozambique on the force majeure, just to understand it precisely. The force majeure is a global one, so it includes all the EPC contracts, any contracts you have in upstream, but also the SPAs? If it includes the SPAs, I was just wondering about the process. Once you want to go back to construction activity, do you have to recontract all the volumes, i.e. start from scratch? Thank you. Okay. Buyback. The beauty of buybacks is the flexibility that they offer. At Total, when you announce an increase in dividends, of course, it's not to cut the dividends two or four quarters after the announcement. We want to be coherent. Honestly, once again, what we demonstrated last year. I will not comment on my peer, but it's easy to increase or to communicate on buybacks when you have cut your dividend by 1/3, 2/3 in the middle of the crisis. Buyback, it's flexible once again. We consider dividend as a long-term piece in our financial policy. I think I was very clear for 2021. We do not anticipate to increase the dividend. If we have excess cash this year, it will be allocated to continue to deleverage the company. After that, next year, if the prices or if the environment is good, we could consider a buyback. But at present time, honestly, it's premature to confirm or to enter into this mindset. On Mozambique LNG force majeure. To be clear, what has been declared is the force majeure for Total E&P Mozambique, as the operator of the project. Now, of course, we are considering the force majeure declaration vis-à-vis the contractors or vis-à-vis the different gas buyers. We are entering into discussions, so honestly, it's premature for me to share the outcome of the discussion with you. On one side, the objective is to minimize the spending around the last couple of months. That's the main driver we have in mind at present time. Let wait and see the outcome of the discussion with the different stakeholders who are involved in this Mozambique LNG project. On one side, the contractor, on the other side, the LNG buyers. Perfect. Thank you very much. Of course, you can imagine that we have a lot of different SPA contracts, so with different wording. We have to negotiate or to discuss contract by contract with the different buyers. Perfect. Thanks. This situation is very new, so please give us some time to answer to your question. Thank you. Thank you. The next question is from the line of Jean-Luc Romain from CM-CIC Securities. Please go ahead. Good afternoon. Middle East Economic Survey recently mentioned potential projects for Total in Iraq. Involving both gas and renewables. Could you elaborate a little on that? Honestly, I will not comment on that. You are correct. I will not comment on ongoing discussions. Sorry for my answer. Thank you. More generally speaking, when we discuss this kind of project, it's only if, once again, it's coherent with our strategy in terms of profitability, in terms of carbon footprint, and the fact that perhaps, in some cases, you can have on one side an upstream project and coupled, I would say, with a renewable project. Of course, it makes sense, particularly in our ongoing transformation. Discussions on Iraq are ongoing, so I will not share with you more than that. Thank you very much. Thank you. The next question is from the line of Martijn Rats from Morgan Stanley. Please go ahead. Hi. Hello. I also have two, if I may. I wanted to ask you about the EU taxonomy. I find it somewhat of a tricky topic, to be honest, so I recognize the question is a little broad, but, I was wondering if you could say a few words what you think the EU taxonomy could mean for a company like Total. Specifically with regards to the decision that we're all anticipating later, whether natural gas could come on the EU taxonomy. Does that mean anything for Total? Maybe not in the short run, but if you could say a few things about it, that would be most helpful. Secondly, a little bit building on the previous question. I actually sort of the same one about Iran. It does look like negotiations around the JCPOA are gaining tremendous momentum and there is a realistic probability that some sort of unwind of sanctions might be sort of parts. Total was, I think, the only European major, at least, who had a project the last time the sanctions were reactivated. I was wondering if Total would be pursuing reentering the country if that was possible. Okay. Two very different questions. Yeah. I realize that. Well, you know that we consider that gas is the energy of the transition, so of course, it's a concern for us not to have natural gas considered, I would say, into the taxonomy. You know that natural gas and nuclear, they are meant to be addressed separately by end of 2021. We are not involved in nuclear, but of course, we are much concerned regarding the natural gas dossier. Having said that, taxonomy, and by the way, the comments we made to the Commission, it was end of last year. We see different subject or different problems in relation with this taxonomy. The first one is natural gas, but in terms of methodology, we have a second issue. Most of our transition activity, new energies, renewable electricity, they will be reported using an equity method. You know that in taxonomy, you have to report the- Turnover. The turnover, yes. Sorry. The OpEx and the CapEx. If you are on an equity method, so that means that you do not generate a turnover or you do not generate OpEx, and even you do not generate CapEx because most of the CapEx is financed through external debt. It's one of the limits of the taxonomy. That means that for players like Total, but it's not only for Total, and most of the, [of where] they are exactly in the same situation. That means that these efforts, I would say, towards low carbon businesses, renewable, and so on, will not be captured through the current taxonomy rules. The second or the third comment we made at the time, we commented, I think, in February or even in September 2020, the fact that we will use to reduce the carbon footprint of our activity, or we'll green the electricity supply for our assets. We have a plan to supply electricity produced by our solar farms in Spain to our European refineries. We will do exactly the same in the U.S. using some solar farms that we will develop in the coming years, to supply green electricity to a Port Arthur. Given that it's intra-group flows, in fact, it will not be captured in the taxonomy current methods. Honestly, it's a real concern for us. The message that we try to convey to the commission is that the taxonomy is at the time very narrow and too narrow, in fact, because it does not reflect or it does not capture all the investments, all the efforts that a company like Total could do to our ambition to be net zero by 2050. That's what I can tell you regarding taxonomy. For Iran, honestly, what we need, we need long-term, I would say, visibility on the sanctions, to start considering coming back to Iran. Honestly, it's not the case at present time. I'm not so sure it will be the case in the very next future. No, I can imagine. That was very helpful. Let's wait for further development with the new U.S. Biden administration. Once again, what we need is clarity and stability to be in a position to make possible or to start considering a possible comeback to Iraq. It's not on the agenda at present time, and it's far from being the case. Okay. Thank you. Thank you. The next question is from the line of Christopher Kuplent from Bank of America. Please go ahead. Thank you, and good afternoon, Jean-Pierre. Good afternoon. Just one quick follow-up on renewables. I appreciate the U.K. is a somewhat peculiar place to bid for U.K. offshore licenses and seabed. Could you give us a little bit of an insight, not looking for numbers, in terms of your assumptions that you've taken for that winning bid earlier this year? Whether it's power prices, do they come close to what you've currently disclosed in your PPAs? Whether it's CapEx assumptions, turbine sizes, whatever you can give us hints on the underlying assumptions for your bid. My second question is a little bit wider, and it comes on the back of the recent industry risk reassessment by S&P. You've been active in the renewable space now for some time. What's your assessment so far? Is your balance sheet a competitive strength, or is it actually holding you back relative to the competitors you are facing in the renewable world, to sort of link that topic to the credit rating downgrade? Thank you. Honestly, on the last U.K. bid, I will not share with you the assumption we used. No. I cannot give you the details, the CFD to come. No. Sorry, Chris. The strategy as far as renewable and electricity is concerned, is to try to enter at early stage in project. If we can enter into bilateral discussion rather than going to auction, of course, it could be easier to attract profitable project. If we decided to go into this U.K. offshore project, that mean that given the assessment we used, for CapEx, for all that you mentioned, the turbine size and so on, is that we think that this project could deliver double-digit equity profitability when it will come on stream. Okay. Thank you. S&P perspective. I will share with you my personal feeling regarding this subject. The intrinsic value of our renewable in our portfolio is not properly valued, by investor, but by the credit agencies as well. The transformation of the group, the journey towards the carbon neutrality, this is not captured at all, I think, in S&P calculation. The fact that we are well-positioned and that by 2030, we'll be probably in the top five in terms of electricity producer is not well taken into account into the credit agencies calculation. Having said that, I have a strong feeling that being a European company is a disadvantage. You know that they do not share all the details of their calculation. It's very difficult for me to compare the risk treatment done by S&P compared to the risk treatment done by S&P for our peers. We are, on a regular basis, in discussions, or we exchange with both S&P and Moody's. Honestly, if I am optimistic, I will tell you that our investment case, our transition strategy that is already in motion, perhaps it's a factor of differentiation compared to some of our peers that are better valued by S&P or by Moody's. That's in my mind, there are clear differentiating factors and that could lead to an improvement in our perception, I would say, by the credit agency in the coming months. It's not the case, to be honest with you at present time. Transition strategy is not valued at all, for me, by S&P. Yeah. Thank you very much, Jean-Pierre. Just a quick follow-up. Would you say, though, that access to capital to invest in these renewable projects for you has not been a problem? Quite the contrary. I think some of the financing costs that you are exposed to look to me extremely attractive. Oh, yes. No, it's not a problem at all. No problem. We issue this hybrid bond at very attractive level, less than 2%. It's very cheap capital. In terms of more generally, when we go to market for issuing bonds, we have no problem. Now we can access to very long-term maturity, beyond 20 years at less than 3%. Yeah. I would not say that it's open bar, but it's very low cost financing. By the way, you see that in our first quarter result. You see that the financial cost has been reduced dramatically year- on- year. It's the translation of this situation. There is a reasonably strong appetite from banks to finance our project and particularly, as you can imagine, renewable projects. No problem. Yeah. Thank you very much, Jean-Pierre. Thank you. The next question is from the line of Bertrand Hodee from Kepler Cheuvreux. Please go ahead. Yes. Hello, Jean-Pierre. Hello, Bertrand. Two questions, if I may. First, congratulations for the very strong results. It's not every quarter that TotalEnergies beats consensus on clean net income by 25%. However, when I look at the cash flow, ex working capital, ex inventory effect, it was a bit shy of my estimate. Were there any cash collection headwinds in Q1? That is my first question. The second question is on LNG. It's twofold. Were you surprised first that Qatar Petroleum decided not to renew terms beyond end 2021 on Qatargas 1, where you had 10% as stake? On the LNG market, you mentioned in your introduction remark that you will now concentrate on marketing Papua LNG and Cameron LNG expansion. How do you see the market in terms of long-term off-takers? There's a lot of new volumes yet to be marketed. Qatar North Field expansion, Arctic 2, in a way also. Any color on that, I would say long-term off-takes of new LNG project would be helpful. Thank you. Okay, Bertrand, a lot of questions, but you're a bit severe. I think we deliver very strong cash flow. Honestly, delivering cash flow in the Q1 2021, $ 5 billion, in the environment of the first quarter. You have to take into account the fact that the margins were close to zero at that time. Being able to deliver more or less the level of cash flow compared to the cash flow we generated two years ago, in an environment better by more or less $2 per bbl as far as Brent is concerned, also better for gas, but also much better for refinery margin, because at that time, I think margins were above $30. I think it's a good performance, I would say. You have to consider that on a quarterly basis, it's sometimes a bit difficult to reconcile the cash with the net operating income, given what I mentioned to you previously, the timing issue in relation with the dividends and the fact that we have a renewable part of our business consolidated on an equity basis. For Qatargas, it's a decision of QP. They ask, in fact, the IOC to concentrate on new developments, and the North Field expansion project where I think QP thinks that the IOCs can bring highest value. They have decided not to renew the QG1 licenses. It's life. It's like business. It's like that. We have to accept that. It's what I can share with you regarding this dossier, Qatargas. For Papua New Guinea, that's clear that considering the Mozambique LNG project situation, we'll give priority to Cameron LNG extension and to Papua LNG project. We'll focus on marketing the LNG sales. These two projects are, and you mentioned the Papua New Guinea project, so it's a project well-positioned in Asia to supply at competitive cost, I would say, Asian buyers. We are quite optimistic that we'll be able to lock in very attractive SPA in the coming months. What you have probably in mind is that in our strategy, in Total strategy, we sanction project when we are able to secure a reasonable part of the future gas sales because in most of the cases as well, in LNG project, we use project finance to deliver the project as well. Yes. In fact, that was a bit my concern, because with all those volumes yet to be marketed, I was thinking that maybe it's the timing of trying to market Papua and Cameron at the same time or in competition with Qatar could be problematic. That's not your view. No. Okay. Thank you, Jean-Pierre. Thank you, Bertrand. Thank you. The next question is from the line of Jason Gabelman from Cowen. Please go ahead. Yeah. Hey, thanks for taking my question. I guess I'll stick with the LNG discussion. It sounds like because Mozambique is delayed, you've decided to move forward on these other projects. I guess, in that vein, how important is it to maintain scale and relative scale in the LNG as it expands? Is that something that you need to maintain to be competitive in the business? As such, are you pursuing now projects like Cameron expansion, which wasn't previously, I think, in the kind of competitive returns part of your pre-sanction projects? Are you pursuing projects that maybe don't have as competitive returns in order to maintain that scale in the LNG business? That's the first question. The second one is just chems. Just given the strength that we've seen in margins, can you give any indication of how much stronger you expect earnings within Chemicals to be this quarter versus first quarter? More broadly, it seems like there have been a decent amount of announcements on chemical recycling technologies moving forward, and I think you're pretty bullish on those technologies being used more widely in the future. Is that becoming a technology that could be profitable to deploy in the near term, or do you still need to see more technology advancements and maybe some government support? Thanks. Okay. The line was not very good, so I'm not so sure to have captured all what you said. Perhaps I will start with Petrochem. That's true that we do not give a lot of details regarding Petrochem in our reporting. I confirm to you that it's the main driver behind the resilience, I would say, of the downstream sector in Q1. Will Q2 be stronger than Q1? Honestly, it will remain at the same level, I will be more than happy. It's very difficult to what the prices could be, Petrochem prices will be. Given that we are integrated, we can capture the rebound in the market. We are well-positioned. Having said that, anticipating a Q2 better than Q1, honestly, I cannot make this bet today. You mentioned, I think, the recycling technologies. We have some project to recycle plastics. What has been announced in Grandpuits, the fact that we'll build a plant to recycle plastics is part of our objective to be part of this business in the coming years because, of course, it will play a growing role, I think, in the plastic industry in the coming years. I'm not a specialist in terms of technologies used for recycling plastics, I have to admit. For LNG, yes, perhaps for, sorry, something else came into my mind regarding this question, recycling. We have some agreement to, or we are at present time, a producer of bioplastic in Thailand, I think with Corbion, and so we expand this type of agreement with Corbion in France, also in Grandpuits. We'll be a producer of bioplastic on one side and we'll have some recycling capacity on the other side as well. LNG, no. The fact that we have a force majeure in Mozambique, the fact that, as I mentioned to you, there is a one year at least delay in this project. That means that the priority came back to Papua New Guinea, to Papua LNG project and Cameron extension. We do not sanction the project if the conditions are not good. We are one of the major LNG player in the world, having a capacity of being in a position to produce LNG in the main LNG hubs worldwide, having a trading that is able to play between the different areas and to capture the discrepancy, I would say, between the different markets. It's also a matter of size. We see that when we acquired the Engie LNG portfolio, it was a very significant movement, and it's at that time that we were able to leverage, very efficient way, our LNG position. It's not volumes over value. It's always value over volumes that will drive our strategy. It's the case for LNG, it's the case more globally for all our business at Total. Thanks. Thank you. Thank you, Jason. Thank you. The last question today is from the line of Jason Kenney from Santander. Please go ahead. Oh, thanks very much for the time. I'm interested in the 8 GW green hydrogen MOU that was signed last week in Australia for Total Eren. It's a massive scale. Potential major play in the hydrogen theme for the Total group. Do you see CapEx in the next three, four years on that particular position? If so, is that already in your strategy guidance? Separately on hydrogen as well. I'm looking at a technology for oxygen injection into oil reservoirs, in situ clean hydrogen production, where you leave carbon dioxide in the ground. I'm wondering if you have any particular oil assets, old, mature, end of life, pre-abandonment, sub-economic stuff that you could maybe try this out on and if you've actually looked at that technology specifically. Okay. The first deal you mentioned, it's not directly Total. The MOU was signed by Total Eren. Total Eren is a 30% owned subsidiary of Total. Having said that, I do not have all the details, to be honest, regarding this MOU. My understanding is that it's at a very early stage. It's a pre-feasibility study for this hydrogen project. Very early stage. CO2 injection potential. What I can share with you is that, of course, we're interested in hydrogen at Total. We have some projects for, on one side, green hydrogen, on the other side, blue hydrogen. I'm sure that in the coming months, perhaps in September or in February 2022, we'll be ready to share more with you regarding the strategy regarding hydrogen at Total. Okay, thanks. Okay, I think, thank you. Thank you very much. Thank you for your attention. I hope that, next time, of course, I'm not so sure that the pandemic will be over. It's just a matter of weeks, but let's be optimistic. I hope that we'll be soon in a position to have real exchanges, I would say, not through screens or through phones. It's only a matter of months now. Having said that, thank you very much, and au revoir. Bye-bye