TotalEnergies SE Ordinary Shares

Ladies and gentlemen, thank you for standing by and welcome to the Total first quarter 2021 results conference call. At this time, all participants are in a listener only mode. After the speaker presentation, there will be a question and answer session. To ask a question during the session, you will need to press star one on your telephone. I must advise you that this conference is being recorded today. I would now like to hand the conference over to Mr. Jean-Pierre Spré, CFO of Total. Please go ahead, sir.

Thank you very much. And hello, everyone. So we began the year with a strong set of first quarter results that demonstrate total ability to fully leverage the upside of an improving environment. While Brent was up by 22% compared to Q1 2020, total first quarter 2021 adjusted net income jumped by about 70% to $3 billion, or $1.1 per share. We are back on track, and 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. And 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 a difficult and uncertain 2020 environment when brands dipped below $20 per barrel, and we have benefited from rebounding markets including Brent, which averaged more than $60 per barrel in the first quarter. However, to be clear, we credit mainly the Saudi-led OPEX Plus 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 focus 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 $5.1 per barrel in 2020 with a target of $5 per barrel. 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 and $13 billion for 2021. And I will give you more details on this later. We are continuing to high-grade the portfolio, and the organic breakeven was below $25 per barrel in the first quarter. And this allows us to capture the upside of the stronger environment. Operationally, the group's first quarter production was up slightly compared to previous quarter, by 0.8% to $2.86 million barrels per oil equivalent per day, and still reflect the impact of OPEX Plus 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 project startups and ramp-ups, including North Ruskoie in Russia, Kulean in the UK, Ualverdrup in Norway, and Yara in Brazil. all largely offsetting the natural decline. Looking now at the operating segments, we are pleased with the performance of the IGRP segments, which 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 renewable 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. And 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 personnels from the Afungi site. We have declared force majeure and 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 Energy 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 gigawatts from 3 gigawatts a year ago, and net power production grew to 4.7 terawatt hour from 3.2 terawatt hour 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 Adeni Green Energy, the largest solar developer in the world, And of 4 gigawatts of portfolios in the U.S. during the first quarter, we won Lizzie's rights of 1.5 gigawatts UK offshore wind project. And we farmed down our equity interest in more than 300 megawatts of renewable assets in France on the basis of a $600 billion enterprise value at 100%, in line with our capital-like 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 tripled the same quarter last year, and 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. We, the signature of definitive agreements Enabling to launch of Tilanga and Kingfisher upstream oil projects 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 continues 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 million barrels per day in the first quarter of 2021 versus 15 million barrels per day in the first quarter of 2021. In contrast, petrochemical margins were strong, showing improvements 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 Lamed and our facility at Undal 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. So, 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, we rent around $60 per barrel, European gas around $6 per million BTU, and assuming European refining margins around $10 to $15 per ton, then 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 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. by the insurance of the hybrids to finance the renewable acquisition in India in Adeni 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 and transforming the company, to support the dividend through the economic cycle, and to maintain a strong balance sheet and a minimum long-term single aid debt rating with gearing sustainably anchored below 20%. I remind you that at the end of 2018, the gearing was about around 15%. And, of course, 15% is better than 20% to face volatility. With a strong start to the year and confidence in the fundamentals of the group, the board of directors decided to distribute a first interim dividend fund of 0.66 euro per share. That means that the first interim dividend will be stable in euro. But considering the foreign exchange rates, compared to a year ago, this interim dividend represents an increase of about 9% in dollar. Overcoming the challenges of 2020 has made us a stronger company, and the market rebound is allowing us to accelerate our transformation to Total Energies. At our shareholder meeting in May, we will propose the adoption of Total Energies 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 And we will submit 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 products used by our customers, scope one, plus two, plus three, together with society. Specific commitments are taken by 2030. The next decade is key. Minus 40% 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 COP3 worldwide emissions by 2030 versus 2015, we are the only ones among our peers having set an absolute figure target. Minus 20% carbon intensity reduction for energy products sold to our customer, COP3, this is a more stringent target than the one announced previously. In Europe, 30% reduction of absolute emissions by 2030 extended to scope 1 plus 2 plus 3 versus 2015. Our climate ambitions are well, as 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. And now, let's go to the Q&A.

Thank you. If you would like to ask a question, please press star and 1 on your telephone keypad and wait for your name to be announced. And to cancel your request, you can press the hash key. Once again, that's star and 1 to ask a question. Your first question today is from the line of John Rigby from UBS. Please go ahead.

Thank you. Hi, Jean-Pierre. Hi, Jonathan. 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 chemicals 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 chemicals, some kind of split between the contribution from refining and the contribution from either both PetChem and um and and other chemicals operations just simply because i'm conscious that those two numbers um are very widely different and actually the market probably ascribes very significant different values to them and then if i can just talk on just igrp um i take the point about the renewables improvement sequentially but it doesn't explain even even closely the the delta on the earnings and i'm guessing there's a contribution from trading 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. So perhaps I will start with a second question regarding IGRP. You will not be surprised. I will not give you a detailed figure regarding the performance of trading. So I can confirm that given the volatility, we are able to, and given our global footprint, the 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. And so that's true that it's one of the drivers of the rain performance this quarter, but 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. And so you have all the details, I think, in the annex, in the appendix as well. And so you will see that this segment alone contributes, has an EBITDA more than three, between three and four hundred million dollars. And so it starts being sizable, I would say. So the second question regarding ARC, you have the right analysis. The performance of refineries, and particularly in Europe, were poor during the first quarter. In the U.S., we were impacted by the hurricane as well. And so the margins were close to zero in Europe. Honestly, summer should see some improvements. And so 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. you have noticed that we continue to be very cautious regarding the margin, so we gave a guidance for the debt-adjusted cash flow using, I would say, a conservative assumption, $10 to $15 per ton for refinery margins for the full year. On the opposite, PetroChem results were very good, and because Petro margins were strong in Q1, showing improvement, by the way, year-over-year or queue-to-queue. The volumes, the margins, they've improved resilience through the pandemic, the COVID-19 crisis. The volumes remain robust for both PA and NPP. And it's clear that some segments like food, packaging, medicals, protective equipments, more than compensate the slowdown in other sectors such as automotive and construction. So we continue to be optimistic regarding Petrochem. from integrated platforms, as far as Total is concerned, and so we are well positioned to capture a possible market that for sure will continue to be strong. And performance of the trading, I have already commented that.

So maybe we can just reverse it out a little bit. What level of refining margin would you expect to have to have for that refining business to be break-even? At least I can sort of gauge the relative sort of negative, positive contributions to the net results.

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 to $15 per ton of assumption for building our guidance. It doesn't mean that, of course, it will be true. I would say that what has been done, and so we will continue to do that if needed, so we have voluntarily cut the rent in some refineries, so it was the case in Dons in particular, it's a refinery in France, So we could continue with the same policy. And on the other side, you know perfectly that we have sold our UK refinery in the UK, so that we have stopped the operation in Grand Prix, so another refinery in France. And so the plan is, of course, to adapt our footprint to the markets. That's what I can answer to you, to this question and to adapt our model, our assets to the situation and to the current market. But 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. And by the way, the stocks globally, the stocks in OCD countries, they are back to around, I think, 70 days. So it gives us some hope regarding this sector in the coming months or quarters. Okay.

Well, I hope to contribute to aviation demand over the summer, Jean-Pierre.

Yes, that's clear. The situation for the airlines company and the aviation and the fact that we have to pull the Cairo into a distillate at present time, it's one of the reasons why the margins are so low. That's true. Thank you. So I don't know when this... this sector will come back to pre-crisis level. I'm not so sure that it will take many quarters, I don't know. So we have to be patient and once again to be reactive and to focus on what we control. So 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.

John-Pierre, thank you so much. Just on capex, I mean, I had a 12 billion number in my head for this year. I think you talked about 12 to 13 potentially. Obviously, the 12 was at a lower oil price, but We're now going to minimize the capex in Mozambique as well for the rest of the year. So is there a capex pickup taking place somewhere else in the business relative to the plan? And 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? You know, is it short-term, longer-term? Is it focused on green fields, or can you really retrofit your brownfield LNG plants? And any emissions intensity numbers that you're kind of playing with at this point? Thank you.

Okay, so regarding the CAPEX. So that's true that we, when we have made our budgets, we are not at $60 per barrel. And so the budget was done for the 2021, was done at $40 per barrel. So at that time, we mentioned the guidance for CAPEX, so the global CAPEX, organic CAPEX, plus the net between acquisition and session, and the divestments, at $12 billion. Except in February, during the New Year's Day, we mentioned that in better, if the prices remain above this level, we can increase CAPEX, and so we gave a range between $12 to $13 billion. Having said that, and it's clear, it's now in the DNA of Total, we want to maintain the discipline on CAPEX. So, honestly, I don't know, it's premature to evaluate the impact on Mozambique energy project and force majeure on globally the CAPEX for the full year. But it doesn't mean that even if we save some CAPEX that we'll use this CAPEX to increase significantly investments in ENP or in downstream. We want to keep the discipline. We want to be selective. And once again, our priority is 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, and particularly for the upstream segment, we have some flexibilities on short-cycle investments 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, so it's possible for us to come back and to sanction this new cycle project. And we can allocate part of this additional capex of $12 to $13 to some renewable and electricity project if it makes sense and that means that if they are profitable. So that's the main guidance for us. when we have to select the different projects. On CMS agreement, I have to admit that I'm not very familiar with this agreement, so I suggest that you come back to the IRF teams and they will give you some more details regarding this agreement. But it's clearly in our objective to lower or to reduce the CO2 emissions. And it's part of this global strategy. And once again, the transformation of total into total energy. So it's one step 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 questions. 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 earning is up a lot. So wondering if you can maybe help us to bridge the gap and why 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.

So your question regarding the IGRP. So in short... That's correct. Sorry?

That's correct.

Yeah. In short, what I can tell you is that in the fourth quarter, the results, the net operating income in the fourth quarter of 2020, last year, was negatively affected by non-cash elements, such as mark-to-market elements or deferred tax elements. That's the main driver behind this crisis. that explain the phenomenon you pointed out the second is the seasonality in dividends as well so 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 seasonability of the dividends so that's the two main elements that explain this Overall, what is more relevant is to compare the NOE increase year-over-year with the cash flow generated year-over-year. You see that it's very coherent and very much in line. Asset sales. Yes, I'm not sure to have really understood your question, but of course the farm down of our renewable assets, they are reported, of course, in IGRP segments. 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 production, as soon as the COD is COD when the project starts to pocket, to monetize significant part of the future results through the PPA signs. And it's another way for us to, by the way, to direct the project as well. So it's part of the model and, of course, it's reported into the IGRP segments for the results and for the investment as well because when I mentioned when we say that we'll allocate more than 20% of capex to this segment, it's net capex, it's net investment. So it takes into account the divestments, and these divestments are part of these figures as well.

No, I understand that. No, I understand that. I'm just asking that whether the farm down had resulted in any gain that we caught in the first quarter in this segment. I'm not sure to understand what you have in mind. Well, when you farm down, it depends on the value you receive. Did you book any gain? Yes. Did you book any gain in the first quarter? And if you do, can you share how big are those gains? Is it a meaningful number?

Ah, but I gave you the fact that we found out two projects in France, and I gave you the the enterprise value. So it's around $600 million of enterprise value, 100%. And so the way we consider this farm-down is to farm-down 50% of the project. At the same time, as you know, we leverage the project, and so the figures or the debt-to-equity ratio you can use for your modernization is between 70% and 80%. So that means that At COD, so we found out 50%, and so we've leveraged the project at 70, 80%. And so all this mechanism, I would say, is included into IGRP results and cash flows and investments. All right, thank you. By the way, I gave you a lot of figures regarding this firm down. This $600 million on a 100 basis EV It's for something like 340 megawatts, I think, if I'm correct. So that means that if you consider that it's $1 million of capex for one megawatt on this type of project, that means that we double more or less the value of the of the initial cash we used for developing this project through this farm down. And it's in line with the metrics we gave, I think, in February, because at that time we gave some additional examples, five or six different farm downs that occurred over the last couple of years. Thank you.

Thank you. The next question is from the line of Christian Malik from J.P. Morgan. Please go ahead.

Hi, good afternoon, Champion. 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 high capex, whether in oil or transition. So you've gone from 12 to 12 to 13, and that's admittedly at a $40 Brent. I mean, 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 framework would you consider? And within that, you know, previously suspended buybacks, would you revisit? If oil looks like it's heading to 70, is there a distribution of cash flow that's viewed as most appropriate over the medium term? And I guess one of the things that I want to sort of nuance around that question is, you know, cash flow distribution relative to previous years, when you look at a yield basis, is only sitting around 20%. And so I wonder whether that's a sort of new norm, the new norm for you on cash, particularly within the yield, or whether you would consider upside once you get to 15%. Thank you.

Okay. So regarding the cash flow allocation, so you know we're consistent in total. So perhaps I will repeat, sorry for that, what we said in February. What are our priorities in terms of cash allocation at total? So first, the capex, and so it's linked to your first question. So I gave the guidance for 2021. We gave a guidance between $13 to $16 billion for the year 2020 to 2025, assuming an environment between $50 to $60 per barrel. Why? Because, once again, we want to keep the discipline, invest only in profitable projects. So 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. So for oil and for upstream projects, it's a 15% error at 15%. You know that for renewable and power, and renewable in particular, it's a double digit, so more than 10% profitability for our equity. So 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, additional assets. development in renewable if it makes 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 barrel last year, to maintain the dividend is a clear and strong commitment vis-à-vis the shareholders. So the decision was not to cut the dividend. So I repeat, I get confirmed that the dividend is supported at $40 per barrel, 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. And so the best way to do that, of course, is to have low gearing. And so the objective for us is to anchor durably, I would say, the gearing below 20%. So we are already at this level. That's true. We are at 19.5% end of March. But it's not a joke. We were at 15% in end of 2018. And obviously, 15% is better than 20% is what I mentioned in my speech, in my introduction. Why? Because we are in the commodity market, and so we have to be ready for the next possible new downturn. So having this strong balance sheet for us is key and is a key element in our cash flow allocation strategy. So that means that, and it was clear as well in February, we mentioned that buybacks will come only if oil prices will come or will stay above $60 per barrel, and when gearing will be durably, and durably I think is very important, installed below 20%. So to be clear, for 2021, we will maintain the dividend. So in Euro, and so I mean now at 1.2 Euro per dollar, compared to the 1.5 we had one year ago, it means that it's a reasonable increase in dollar by dollar. So it's a 8, 9, 10% increase in dollar when you translate the Euro into dollar. And so maintaining this dividend in Euro, And that means that buybacks will come later.

Great. Thank you, Jean-Pierre.

Thank you. The next question is from the line of Biraj Borkataria from RBC. Please go ahead.

Hi. Thanks for taking my questions. The first one was on Mozambique. Originally, the intention was, I guess, to... to have the two projects on the onshore in area one and area four to run along in sync. But I guess the operator on the other side has deferred the project pre-FID and now you've had to declare force majeure. So 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 would be my first question. And 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 very competitive rates. So I'm just wondering how do you think about the overall capital structure of Total as you build this business and the mixture of instruments like that versus just vanilla debt and equity? Thank you.

So on Mozambique, honestly, at present time, it's not the priority to enter into discussions or to enter into agreements, 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. So we see, I mentioned to you that at present time we anticipate at least one year delay. So we see it's not a top priority on the agenda to to discuss with this subject with our peers or with the other operators. Hybrid bonds. You know, we were very opportunistic in January last year, this year, sorry, when we issued this €3 billion of hybrids to finance the 20% acquisition 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 Renier-Wobble with low-cost capital. That's the strategy we have implemented. By the way, most of the renewable projects, the debt that you, the project finance that you raise on renewables, it's on a non-recourse basis. So that means 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. 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 what you expect around that working cap side going forward. And then the second one was just to come on to the renewables business again. If I think about the... Adani, as I said, JV in this data, how do you think about managing the currency risk for that, so just given what we're seeing in terms of currency? And then just linked to that, the offshore project in Taiwan that you entered this morning, it does talk about basically paying a consideration based on the share of past costs. Normally, you see when you've sold things down that you get a premium whilst it's in development. I'm just wondering what it is in terms of that project that has been attractive for you.

Thanks. Okay, so the first question regarding working capital. So it was, yes, we reported the cash-in this quarter. The main driver behind this cash-in was the timing of some tax elements. So if I remember well, it was in Germany and Belgium for... for downstream and in Norway for upstream. And 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. But 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 and I remind you that given that it works well and of last year we continue or we decided at EXCOMM level to continue to incentivize our managers to proactively I would say manage working capital and so to be sure that they made all the actions to minimize the working capital. when it's needed. And so it's very difficult for me to give you colors regarding working cap in the coming quarters because the main certainty of course is the level of prices that that will obviously impact the work gap. What I can confirm to you is that we will continue to mobilize our staff, our people, to manage this working capital subject. So the India, obviously we took into account this currency risk in our economics when we decided to go into a different project with Adani in India. So it's taken into account. And I can share with you that Given the predictability of the cash flow coming from PPA in renewable businesses, we can consider forward aging as well, but it's under consideration at present time. So we'll see in the coming months. the outcome of these studies. But once again, it's taken into account when we decided to go into that project and it's embedded, I would say, in the fact that we sanction projects 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, I will 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, so now we know the people, we know the assets, so we are able to move very quickly and to capture and to seize these opportunities. We have, obviously, good PPA for these assets, so it's offshore, so the capex are not the same, of course, when you compare to to onshore winds. But all in all, the same answer as for Ordany. 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 a threshold. And it was, of course, the way for us to be present in this Taiwan market, very active as far as offshore wind is concerned.

Great, thank you.

Thank you. The next question is from the line of Thomas Adolf from Credit Suisse. Please go ahead.

Hi, good afternoon. Two questions for me as well, please. Firstly, going back to what you said earlier on, so for this year, um obviously paying the dividend the next year if oil is higher than 60 there might be a buyback but once the world is back to normal um whenever that is you know this summer next summer um you pre pre-covered you did have a preference for a progressive dividend so 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. So that's the 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. And 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 reconstruct all the volumes, i.e. you start from scratch? Thank you.

Okay, so buyback. The beauty, it's obvious that buyback, the beauty of buyback 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, and honestly, it's once again what we demonstrated last year. And I will not comment on my peers, but it's easy to increase or to communicate on buybacks when you have cut your dividend by one-third, two-thirds in the middle of the crisis. So buyback is flexible, once again, and we consider dividend as a long-term piece in financial policy so I think I was very clear for 2021 we do not anticipate to increase the dividend and so if we have excess cash this year it will be allocated to continue to deliver to the company and after that next year if the prices if the environment is good we could consider buyback but at present time honestly it's premature to confirm or to enter into this mindset. On Mozambique energy, force majeure. So to be clear, what has been declared is the force majeure for total ENP Mozambique as the operator of the project. So it's a force majeure vis-a-vis the GOE. So now, of course, we are considering the force majeure declaration vis-a-vis the contractors or vis-a-vis the different contractors gas buyers. We are entering into discussion, 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 over the last couple of months. That's the main driver we have in mind at present time. But let's wait and see the outcome of the discussion with the different stakeholders involved in this Mozambique LNG project. So, on one side, the contractor, and the other side, the LNG buyers.

Perfect. Thank you very much.

And, of course, you can imagine that we have a lot of different contracts, SPA contracts, wording and different, so we have to negotiate or to discuss contract by contract with the different buyers. And so the 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 from CMCIC Securities. Please go ahead.

Good afternoon. Middle East Economic Survey recently mentioned potential projects for total in Iraq. Could you, while involving both gas and renewables, could you elaborate a little on that?

Honestly, I will not comment on that. You are correct. But I will not comment on ongoing discussions. Sorry for my answer.

Thank you.

But 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. But 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 Martin Ratz 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, and specifically with regards to the decision that we're all anticipating later this year, whether natural gas could come on the UK EU taxonomy. Does that mean anything for Total? Maybe not in the short run, but if you could say a few things about that, that would be most helpful. And secondly, sort of a little bit building on the previous question, I actually thought I got quite the same one about Iran. Because 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 in the cards. And Total was, I think, the only European major, at least, who had a project the last time the sanctions were reactivated. And I was wondering if Total would be pursuing sort of reentering the country, if that was possible.

Okay, so two very different questions. You know that we consider that gas is the energy on 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 the end of last year. So we see different subjects or different problems in relation with this taxonomy. So the first one is natural gas. But in terms of methodology, we have a second issue. Most of our conditioning activities, so new energy, renewable, electricity, they will be reported using an equity method. And you know that in taxonomy, you have to report the turnover, yes, sorry, the OPEX and the CAPEX. And so if you are on an equity method, that means that you do not generate turnover, you do not generate OPEX, and even you do not generate CAPEX because most of the CAPEX is financed through external debt. So it's one of the limits of the taxonomy. That means that for players like Total, but it's not only for Total. Most of the OPEX, they are exactly in the same situation. That means that these efforts, I would say, towards low-carbon businesses, and so on, will not be captured through the current taxonomy rules. And 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 or we will to reduce the carbon footprint of our activity, or we'll green the electricity supply for our assets. And so 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 Port Arthur. And so, given that it's intra-group flows, in fact, it will not be captured in the taxonomy current methods. So, honestly, it's a real concern for us. So, the message that we try to convey to the Commission is that the taxonomy is, at the same time, very, very narrow, and too narrow, in fact, because it does not reflect It does not capture all the investments, all the efforts that a company like Total could do to meet our ambition to be a net zero by 2050. That's what I can tell you regarding taxonomy. And for Iran, honestly, what we need, we need long-term, I would say, visibility on the sanctions to start considering coming back to Iran. So honestly, it's not the case at present time. And I'm not so sure it will be the case in the very next future.

Oh, I can imagine. Well, anyway, that was very helpful.

Let's wait for further development with the new U.S. Biden administration. But 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 Iran. So it's not on the agenda at present time. It's far from being the case.

Okay, thank you.

Thank you. The next question is from the line of Christopher Coupland from Bank of America. Please go ahead.

Thank you and good afternoon, Jean-Pierre. Just one quick follow-up on renewables. And I appreciate the UK is a somewhat peculiar place to bid for UK offshore licences and seabeds. But 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. And 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 UK bid, I will not share with you all the all the assumptions we used. No, I cannot give you the details, the CFD to come, but no, sorry Chris. The strategy is to, as far as renewable and electricity is concerned, is to try to enter at early stage in projects. If we can enter into bilateral discussion rather than going to action, of course, it could be easier. to attract a profitable project, but if we decided to go into this UK offshore project, that means that given the association we used for CAPEX for all the, 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. I will share with you my personal feeling regarding this subject. The value, the intrinsic value of our renewable in our portfolio is not properly valued by investors, but by the credit agencies as well. And so the transformation of the group, the the journey towards the carbon neutrality this is not captured at all I think in S&P calculations and so the fact that we are well positioned and that by end of or by 2030 will be probably in the top 5 in terms of electricity producer is not well taken into account into the credit agency's calculation. Having said that, the fact that being, I have a strong feeling that being a European company is a disadvantage. And so you know that they do not share all the details of their calculation. So it's very difficult for me to compare the retreatment done by S&P compared to the retreatment done by S&P for RPOs. We are on a regular basis in discussions. We exchange with both S&P and Moody's. But honestly, if I am optimistic, I will tell you that our investment case, our transition strategy, that is already in motion, and so 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, in my mind, there are clear differentiating factors and that could lead to an improvement in our performance. perception I would say by the by the credit agency in the coming in the coming in the coming months but it's not the case to be honest with you at present time our 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

It 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. So, no problem. We issue this hybrid bond at a very attractive level. less than 2% so it's very cheap capital and in terms of more generally when we go into the market for issuing bonds we have no problem and so now we can access to very long term maturity beyond 20 years at less than 3% so it's I would not say that it's open bar but it's very very low low cost financing and so by the way you see that in our first quarter results You see that the financial cost has been reduced dramatically year on year, and so it's a translation of this situation. And there is a reasonably strong appetite from banks to finance our project, and particularly, as you can imagine, renewable projects. So no problem. Yeah. Thank you very much, Jean-Pierre.

Thank you. The next question is from the line of Bertrand Hody from Kepler Shuffra. Please go ahead.

Yes. Hello, Jean-Pierre. Two questions, if I may. First, congratulations for the very strong results. It's not every quarter that the total beats consensus on clean net income by 25%. However, when I look at the cash flow, X working capital, X inventory effect, it was a bit shy of my estimate. Were there any cash collection headwinds in Q1? That is my first question. And then the second question is on LNG. It's twofold. Were you surprised first that Qatar Petroleum decided not to renew terms beyond the end of 2021 on Qatar Gas One, where you had a 10% stake? And then on the LNG market, you mentioned in your introduction remark that you you will now concentrate on marketing Papua LNG and Cameroon LNG expansion. But how do you see the market in terms of long-term off-takers? Because there's a lot of new volumes yet to be marketed. Qatar, Northfield expansion, Arctic II expansion, in a way also, so any color on that, I would say, long-term of 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, above $5 billion. in the environment of the first quarter. So you have to take into account the fact that the margins were close to zero at that time. And so being able to deliver more or less the same level of cash flow compared to the cash flow we generated two years ago in an environment better by more or less $2 per barrel as far as Brent is concerned, also better for gas, but also much That's better for refinery margins, because at that time, I think margins were above $30. I think it's good performance. You have to consider that on a quarterly basis, it's sometimes a bit difficult to reconciliate the cash flow with the net operating income, even what I mentioned to you previously, the timing issue in relation with the dividends. And the fact that we have a reasonable part of our business in an equity, consolidated on an equity basis. For Keter Gas, it's a decision of CUPE. They asked the IOC to concentrate on new developments, and so the Northfield Expansion Project, where I think CUPE thinks that the IOCs can bring highest value. So they have decided not to renew the Q1 licenses, but it's life, it's life for the business. It doesn't mean that it's like that, we have to accept that. So it's what I can share with you regarding this dossier Qatar-Gaza. And for Papua New Guinea, that's clear that considering the Mozambique LNG project situation We'll give priority to Cameroon energy extension and to Papua energy projects. And so we'll focus on marketing the energy cells. These two projects, 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 who are quite optimistic that we'll be able to lock in very attractive SPA in the coming months. And what you have probably in mind is that in our strategy, In total strategy, we sanction projects when we are able to secure a reasonable part of the future gas cells, because in most of the cases as well, in energy projects, we use project finance to derail the project as well.

Yes, yes. Because in fact, that was a bit my concern. With all those volumes yet to be marketed, I was thinking that maybe it's the timing of trying to market Papua and Cameroon at the same time or in competition with Qatar could be problematic. But that's not your view. No. No. Okay. Thank you. Thank you, Jean-Pierre. Thank you, Bertrand.

Thank you. The next question is from the line of Jason Gableman from Cowan. Please go ahead.

Yeah, hey, thanks for taking my question. I guess I'll stick with the LNG discussion. So it sounds like because Mozambique is delayed and decided to move forward on these other projects. So I guess, you know, in that vein, how important is it to maintain scale And relative scale in the LNG industry as it expands, is that kind of something that you need to maintain to be competitive in the business? And 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-sanctioned projects? Are you pursuing projects that may be don't have as competitive returns in order to maintain that scale in the LNG business. That's the first question. And the second one is just on PECMS. First, 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? And then 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.

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 anticipate what the prices could be, what the Petrochem prices will be. Given that we are integrated, we can capture the rebound in the markets. We are well positioned. Having said that, anticipating Q2 better than Q1, honestly, I cannot make this bet today. You mentioned, I think, the recycling technologies. So we have some projects to recycle plastics. What has been announced in Grand Puy, the fact that we will build plan to recycle plastics is part of this 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, something else came into my mind regarding this question. We have some agreements. We are a producer of bioplastic in Thailand, I think, with Corbion. We have the same. We expand this type of agreement. with Corbillon in France, also in Grands Puys. So 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, but the fact that we have a resource measure in Mozambique, the fact that, as I mentioned to you, there is one year at least delay in this project, that means that the priority came back to Papua New Guinea, to Papua LNG project and Cameroon extension. We sanctioned the project if the conditions are not good, but we are one of the major LNG players in the world. having the capacity of being a position to produce LNG in the main LNG hubs worldwide, having a trading that are 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, so we we see that when we acquired the NG-LNG portfolio, it was a very, very significant movement, and it's at that time that we were able to leverage in a very efficient way our LNG position. So it's not volumes over value, it's always value over volumes that will drive our strategy, It's the case for energy. It's the case for all our business. Thanks.

Thank you. Thank you. The last question today is from the line of Jason Kenny from Santander. Please go ahead.

Thanks very much for the time. So I'm interested in the eight gigawatt green hydrogen MOU that was signed last week in Australia for Total Erin. It's a massive scale. I mean, a potential major play in the hydrogen theme for the Total group. So do you see capex in the next three to four years on that particular position? And if so, is that already in your strategy guidance? And then 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. And 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, so the first deal you mentioned, it's not directly Total, so the MOU was signed by Total ARN, so Total ARN is a 30% owned subsidiary of Total. Having said that, so 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, so very early stage. CO2 injection potential. What I can share with you is that, of course, we're interested in hydrogen at total, so we have some projects on one side green hydrogen and the other side blue hydrogen. So 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 the time. Okay, thanks. Thank you very much. Thank you for your attention. And so 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. And I hope that we'll be soon in a position to have real exchanges, I would say, not full screens or full phones. And it's only a matter of months now. So having said that, thank you very much and au revoir. Bye-bye.

Thank you. That does conclude the conference for today. Thank you for participating and you may now disconnect.