TotalEnergies SE (TTE) 2021 Q1 法說會逐字稿

Ladies and gentlemen, thank you for standing by, and welcome to the Total First Quarter 2021 Results Conference Call.

(Operator Instructions) I must advise you that this conference is being recorded today.

I would now like to hand the conference over to Mr. Jean-Pierre Sbraire, 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 '20, 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 this $3 billion of adjusted net income is actually above the level of the precrisis 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 1/3 compared to a year ago.

And gearing, 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 Brent 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 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 savings 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 billion 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 allow 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 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 project start-ups and ramp-ups, including North Russkoye 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, which sets 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 6 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 sites.

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 [scale], 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 expansion 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.

While increasing our level of disclosure, so you can see that our proportional share of EBITDA for these activities 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 developing this activity.

In addition to the acquisition of 20% of Adani Green Energy, the largest solar developer in the world, and of 4 gigawatts of portfolios in the U.S. during the first quarter, we will lease these rights of 1.5 gigawatts U.K. offshore wind projects.

And we farmed down our equity interest in more than 300 megawatts of renewable asset in France on the basis of $600 million enterprise value at 100%, in line with our capital-light model and also contributing to derisking 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, 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.

With the signature of definitive agreements enabling to launch Tilenga 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 resilience, low-breakeven 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 million barrels per day in the first quarter of 2021 versus 15 million barrels per day 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 at La Mède and our facility at Oudalle in France, early stage but demonstrating the group ability to transform and adjust to the changing environments 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 precrisis 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 hydrocarbon environment like the first quarter with Brent around $50 per barrel, European gas around $6 per million BTU and assuming European margins, 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 ranged 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 insurance of the 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 and transforming the company, to support the dividend through the economic cycle and to maintain a strong balance sheet and a minimum long-term A debt rating, with gearing sustainably anchored below 20%.

I remind you that at end of 2018, the gearing was about around 15%.

And of course, 15% is better than 20% to face volatilities.

We have a strong start to the year and confident in the fundamentals of the group.

The Board of Directors decided to distribute the first interim dividend of EUR 0.66 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 represent 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 TotalEnergies.

At our Shareholder Meeting in May, we'll 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.

And we'll submit to the -- and 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 refer on the clear ambition to get to net zero emissions by 2050 across our worldwide production and energy products used by our customers, Scope 1 plus 2 plus 3, together with society.

Specific commitments are taken by 2030, the next decade (inaudible): minus 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 of targets.

Minus 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 plus 2 plus 3 versus 2015.

Our climate ambitions are well as our sustainable development 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.

(Operator Instructions) Your first question today is from the line of Jon Rigby from UBS.

Two questions, if I can.

The first is on your segmental earnings numbers.

With 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 another chemicals operation just simply because I'm conscious of those 2 numbers 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.

I take the point about renewables improvement sequentially, but it doesn't explain even closely the delta on the earnings.

And 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?

So perhaps will start with the second question regarding iGRP.

You will not be surprised, I will not give you the detailed figures regarding the performance of trading.

So I [can] confirm that given the volatility, we are able to -- I think given our global footprint, the -- our portfolio we have now in our hands, we're 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 driver of the [rent] performance this quarter.

But you do not have to minimize the contribution of Renewables and Electricity contribution as well.

We give you the EBITDA of these segments, 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 3 -- between $300 million and $400 million.

And so it starts being sizable, I would say.

So the second question regarding [LC], you have the right analysis.

The performance of refineries, and particularly in Europe, were poor in -- during the first quarter.

And the U.S. were impacted by (inaudible) as well.

And total margin were close to 0 in Europe.

Honestly, summer should see some improvement.

And so this improvement would 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 market.

Even we -- you notice that we continue to be very cautious regarding the margins.

So we gave a guidance for the debt adjusted cash flow using, I would say, comparative assumption, 10% to 15% for [refining 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 Q-to-Q.

The volumes, the margins, they proved resilience through the pandemic, the COVID-19 crisis.

The volumes remain robust for both [PA and NPP].

And it is clear that some segments like food packaging, medical, protective equipments more than compensate the slowdown in our sectors, such as automotive and in construction.

So we continue to be optimistic regarding petrochem.

We benefit from integrated platforms as far as Total is concerned.

And so we are well positioned to capture a possible continued -- market that for sure will continue to be very -- If I were to put it, to be strong.

And performance of the trading, yes, I have already commented that.

So just -- 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 breakeven?

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 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 voluntary [cuts -- the rents] in some of our refineries.

So it was the case in [Orange] in particular, it's our refinery in France.

So it could -- we could continue with the same policy.

And on the other side, you know perfectly that we have sold our U.K. refinery in the U.K. So that we have still the operation in (inaudible) 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 or our assets to the situation and to the current markets.

But once again, we can -- 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 the [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.

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

Yes.

I know.

That's clear that the situation for the airlines company and the aviation and the fact that we have to pull the (inaudible) into distillate at present time, it's one of the reasons why the margins are so low.

That's true.

So I don't know when this sector will come back to precrisis 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 active and so to focus on what we control.

And so honestly, difficult to control demand and to anticipate what could happen in the coming months.

The next question is from the line of Oswald Clint from Sanford C. Bernstein.

Just on CapEx, I mean I had a $12 billion number in my head for this year.

I think you talked about $12 billion to $13 billion potentially.

and obviously, the $12 billion 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 time line on this initiative?

Is it short term, longer term?

Is it focused on greenfields?

Or can you really retrofit your brownfield LNG plants?

And any emissions intensity numbers that you're kind of playing with at this point?

Okay.

So regarding the CapEx, so that's true that we -- when we have made our budget, we are not at $60 per barrel.

And so the budget was done -- for the 2021, it was done at $40 per barrel.

So at that time, we mentioned a guidance for CapEx, so the global CapEx, organic CapEx plus the net between acquisition [in session] and the divestments at $12 billion.

In February during the Investor 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 billion to $13 billion.

Having said that, and it's clear it's now in the [G&A] 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 LNG project and force majeure on globally the CapEx for the full year.

But [it does not] 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 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 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.

So it's possible for us to come back and to sanction this new (inaudible) cycle project.

And we can allocate part of this additional CapEx of $12 billion to $13 billion to some Renewables and Electricity project, if it makes sense.

And that means that if we are profitable.

So that's the main guidance for us when we select -- when we have to select the different projects.

On Siemens agreement, I have to admit that I'm not very familiar with this agreement.

So I suggest that you come back to the IR teams, and they will give you some more details regarding this agreement.

But I think 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, in the transformation of Total into TotalEnergies.

So it's one step in this transformation.

The next question is from the line of Paul Cheng from Scotiabank.

Two questions.

One, when I'm looking at your LNG and renewable, the cash flow from operations, 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 that why there's a big difference on here?

Secondly there, on the asset sales with the (inaudible) is there any gain that you have reported in the segment?

So your question regarding the iGRP, so in short...

That's correct.

Sorry?

That's correct.

Yes.

In short, what I can tell you is that in the fourth quarter, the results, the net operating income in the fourth quarter 2020, last year, was negatively affected by noncash elements, such as mark-to-market elements or deferred tax elements.

That's the main driver behind this, that explained 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 of the [seasonality] of the dividend.

So that's the 2 main elements that explain this difference.

But overall, what is more relevant is to compare the [NOE] increase year-over-year with the cash flow generated year-over-year.

And so you see that is very current and very much in line.

Asset sales, yes, I think -- I'm not sure to have really understood your question.

But of course, the farm-down of our -- on our renewable assets.

They are reported, of course, in iGRP segment.

It's key in our capital-light model.

It's what we explained.

It is the best way for us to monetize as soon as the production -- as soon as the (inaudible) project starts.

[To project], to monetize a significant part of the future results through the PPA [signs].

And it's another way for us to, by the way, to derisk the project as well.

So it's part of the model.

And of course, it's reported into the iGRP segment 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 these segments, it's net CapEx with net investments.

So it takes into account the divestments, and this divestment are part of these figures as well.

No, I understand that.

No, I understand that.

I'm just asking that what the farm-down had we sell in, any gain that recorded 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 we see.

Did you book any gain?

Yes.

Did you book any gain in the first quarter?

Yes, yes.

And if you do, can you share that?

How big are those gains?

Is it a meaningful number?

I gave you the fact that we farm down on 2 projects in France.

So -- and I give you the enterprise value.

So it's around $600 million of enterprise value, 100%.

And so the way with we consider this farm-down is to farm down 50% of the projects.

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 [modelization] is a gearing between 70%, 80%.

So that means that at (inaudible) so we farm down 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.

By the way, I gave you a lot of figures regarding this farm-down.

This $600 million on 100 basis EV, it's for something like 340 megawatt, I think, if I'm correct.

So that means that if you consider that it's $1 million of CapEx for 1 megawatt 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.

And it's in line with the metrics we gave, I think, in February.

Because at that time, we gave some additional examples, 5 or 6 different farm-down that occurred over the last couple of years.

The next question is from the line of Christyan Malek from JPMorgan.

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 (inaudible) CapEx whether in [oil] or transition.

So you've gone from $12 billion, $12 billion to $13 billion, 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% is a comfortable gearing target.

What sort of cash return framework would you consider?

And within that previously suspended buybacks, would you revisit if oil -- it looks like returning to [17%].

Is there a distribution of cash flow that's viewed as most appropriate in the medium term?

And I guess one of the things I want to sort of you answer around that question is, cash flow or distribution relative to previous years when you look at it on a yield basis is only sitting around 20%.

And so I wonder whether that's a sort of the new norm for you on cash, particularly within the yield, or whether you would consider upside once you get to 15%.

Okay.

So regarding the cash flow allocation.

So you know we are consistent in Total.

So perhaps I will repeat -- sorry for that, what we said in February.

What are our priority in terms of cash allocation at Total?

So first, the CapEx, and so it's linked to your first question.

So you had -- I gave the guidance for 2021.

We gave a guidance between $13 billion 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 project is a 15% (inaudible) [at $60] per barrel.

You know that for renewable and power, 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 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 can confirm 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 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 stronger balance sheet for us is key and is a key element in our cash flow allocation frame.

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 the other comment I made now at EUR 1.2 per dollar compared to the EUR 1.1 we had 1 year ago, it means that it's a reasonable increase in dollar, by the way.

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.

The next question is from the line of Biraj Borkhataria from RBC.

The first one was on Mozambique.

Originally, the intention was, I guess, to have the 2 projects in there on the (inaudible) area, one area 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're building infrastructure that maybe is jointly used for the 2 projects.

So is there an agreement already in place where the -- sort of 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 doing -- as you've been growing your low carbon business, most recently you issued a hybrid, which looks like at very competitive rates.

So 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?

So on Mozambique, honestly, at present time, we -- it's not the priority to enter into discussions or to enter into agreements about the different agreements you have in mind.

The priority is to maintain the sites, 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 1-year delay.

So we see it -- honestly, it's not a top priority on the agenda to discuss with this subject with our peers or with the other operators.

Hybrid bonds, but we were very opportunistic in January last year when -- this year, sorry, when we issued 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 very -- with low cost with the capital -- with low-cost capital.

That's the strategy we have implemented.

By the way, most of the -- in renewable projects, the debt that you -- the project finance that you raise on your renewables, it's on a nonrecourse basis.

So that means that you transfer the risk to the lenders by doing that.

The next question is from the line of Lydia Rainforth from Barclays.

Three questions, if I could.

And the first one is just can you just walk through the idea of the working capital release in the quarter?

Obviously, we've seen [build] around (inaudible) just sort of what you expect around that working cap side going forward?

And then the second one was just to comment to the renewables business again.

And if I think about the Adani asset JV [and 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 cash costs.

Normally -- and usually when you've sold things down, then you get a premium for -- whilst it's in development.

I'm just wondering kind of what it is in terms of that project that has been attractive for you?

Okay.

So the first question regarding working capital, so it was -- we -- 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, in Belgium for downstream and in Norway for upstream.

And on the opposite, we have, of course, the impact of the oil price, or globally, the hydrocarbon 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 end of last year, we continue or we decided at Ex Comm 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 color regarding working cap in the coming quarters because the main uncertainty, of course, is the level of prices that impacted -- 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 subjects.

So the -- India, obviously, we took into account this currency risk in our economics when we decided to go into the 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 hedging as well and 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 a project only if they are able to deliver double-digit profitability for our equity.

For the offshore agreement in Taiwan that we announced this morning, honestly, it's the same.

So 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 renewables, 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, a good PPA for this asset.

So it is offshore.

So the CapEx are not the same, of course, when you compare to onshore -- offshore wind.

But all in all, the same answer for Adani.

If we decided to go into that project, it's because it's coherent, it's in line with double-digit equity profitability I mentioned to you as thresholds.

And it was, of course, the way for us to be present in this Taiwan market, very active as far as the offshore wind is concerned.

The next question is from the line of Thomas Adolff from Credit Suisse.

Two questions for me as well, please.

Just firstly going back to what you said earlier on, so for this year, obviously, paying the dividend.

And next year, if oil is higher than $60, there might be a buyback.

But once the world is back to normal -- whenever that is, December, next summer.

Pre-COVID, you did have a preference for a progressive dividend.

So how do you think about the progressive dividend versus, "No, I'm going to do buybacks to bring down the cash dividend.

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 recontract all the volumes, i.e., start from scratch?

Okay.

So buyback, the beauty, I would say, it's obvious that buyback -- the beauty of buyback is the flexibility that we offer.

At Total, when you announce an increase in dividends, of course, it's not to cut the dividend 2 or 4 quarters after the announcement.

We want to be coherent, and honestly, 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 1/3, 2/3 in the middle of the crisis.

So buyback, it's flexible, once again.

And we consider dividend as a long-term piece in our 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 deleverage 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 pre-maturate (sic) [premature] to confirm or to enter into this mindset.

On Mozambique LNG force majeure, so to be clear, what has been declared is the force majeure for Total E&P Mozambique as the operator of the project.

So it's a force majeure vis-à-vis (inaudible).

So 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 in 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 who are involved in this Mozambique LNG project; so on one side, the contractor; on the other side, the LNG buyers.

And of course, you can imagine that we have a lot of different contracts, SPA contracts, with different 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.

The next question is from the line of Jean-Luc Romain from CM-CIC Securities.

Middle East economic survey recently mentioned potential projects for Total in Iraq.

Could you -- involving both gas and renewables.

Could you elaborate a little on that?

Honestly, I will not comment on that.

So you're correct, but I will not comment on ongoing discussions.

Sorry for my answer.

But more generally speaking, we can -- 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, the upstream project and coupled, I would say, with the renewable project, of course, it makes sense, particularly in our ongoing transformation.

But discussions on it are currently ongoing, so I will not share with you more than that.

The next question is from the line of Martijn Rats from Morgan Stanley.

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 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 U.K. -- 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.

And secondly, sort of a little bit building on the previous question, I actually sort of quite -- sort of the same one about Iran because it does look like negotiations around sort of 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 2 very different questions.

Yes, I realize that.

[So on the taxonomy], 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 comment we made to the commission end of -- it was the end of last year.

So we see different subject 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 the -- our transitioning activities, so new energies, renewable, electricity, they will be reported using an equity method.

And you know that in taxonomy, you have to report the -- (foreign language)

Turnover?

The turnover, yes, sorry, the OpEx and the CapEx.

And so 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.

So 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 [OP], they are exactly in the same situation.

That means that these efforts, I would say, towards low-carbon businesses, renewables and so on will not be captured through the current taxonomy rules.

And the second or the third comment we made at that time, we commented, I think, in February or even in September 2020, the fact that we will use -- we will reduce the carbon footprint of our activity.

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 Apache.

And so given it's intra-group flows, in fact, it will not be captured in the taxonomy current method.

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, in fact, very, 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 meet our ambition to be net zero by 2050.

That's what I can tell you regarding taxonomy.

And for Iran, honestly what 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.

So -- and I'm not so sure it will be the case in the very next future.

I can imagine.

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 the position to make possible to start considering a possible comeback to Iran.

So it's not on the agenda at present time.

And it's far from being the case.

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

Just one quick follow-up on renewables, and I appreciate the U.K. is a somewhat peculiar place to bid for U.K. offshore licenses 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 renewables 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?

Honestly, on the last U.K. bid, I will not share with you all the assumptions we used.

No, I cannot give you the details.

The [CFD] is to come, but no, sorry, Chris.

But the strategy is to, as far as Renewables and Electricity is concerned, is to try to enter at early stage in projects.

If we can enter into bilateral discussion rather than going into auction, of course, it could be easier to attract profitable projects.

But if we decided to go into this U.K. offshore project, that means that given the assumption 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 onstream.

S&P perspective, I will share with you my personal feeling regarding this subject.

The value, the intrinsic value, of our renewables in our portfolio is not properly valued by investors, by the credit agencies as well.

And so the transformation of the group, the journey towards the carbon neutrality, this is not captured at all, I think, in S&P calculation.

And so the fact that we are well positioned, and that by end of -- or by 2030, we'll be probably in the top 5 in terms of electricity producer is not well taken into account into the credit agencies' 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 our peers.

We are in -- on a regular basis, in discussion, so 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'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 agencies in the coming months.

That is not the case, to be honest with you, at present time.

So [acquisition] strategy is not valued at all, for me, by S&P.

Yes.

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 be extremely attractive.

Well, yes.

No, it's not a problem at all, so no problem.

We issued 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 to 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 I will not say that it's open bar, but it's very, very low cost financing.

And so by the way, you see that in our first quarter results.

You see that the cost, the financial cost, has been reduced dramatically year-on-year.

And so it's the 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.

And the next question is from the line of Bertrand Hodee from Kepler Cheuvreux.

Yes.

Two questions, if I may.

First, congratulations for the very strong results.

It's not every quarter that Total 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.

Can you -- 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 2021 on (inaudible) is one, where you have -- where you had a 10% stake?

And then on the LNG market, you mentioned in your introductory remarks that you will now concentrate on marketing Papua LNG and Cameron LNG expansion.

But how do you see at the market in terms of long-term offtakers?

Because there's a lot of new volumes yet to be marketed, Qatar [north field] expansion, [Arctic 2] in a way also.

So any color on that, I would say, long-term offtakes a new LNG project would be helpful.

Okay.

Bertrand, a lot of questions.

But you're a bit severe.

I think we delivered very strong cash flow.

Honestly, delivering cash flow in Q1 '21 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 0 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 2 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, much better for refinery margin because at that time, I think, margins were above $30.

It's -- I think it's a good performance, I would say.

So you have to consider that on a quarterly basis, it's sometimes a bit difficult to reconciliate the cash flow with net operating income, even what I mentioned to you previously, the timing issue in relation with the dividends.

And the fact that's a renewable part of our business in an equity -- consolidated on an equity basis.

For Qatargas, it's a decision of QP.

So they asked, in fact, the IOC to concentrate on new developments and to the north field expansion project.

When I think -- where I think QP thinks the IOC can bring highest value.

So we have decided not to renew the Q1 licenses.

It's [light] for the business.

So does that mean that -- it's like that.

We have to accept that.

So it's what I can share with you regarding this [dossier on] Qatargas.

And for Papua New Guinea, that's clear that considering the Mozambique LNG project situation, we'll give priority to Cameron energy expansion and to Papua LNG project.

And so we will focus on marketing the LNG sales of these 2 projects.

And I mentioned -- you mentioned the Papua New Guinea project, so it's a project well positioned in the year to supply at competitive cost, I would say, Asian buyers.

So we 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 sales to -- because in most of the cases as well in LNG project, we use project finance to derisk the project as well.

Yes.

Yes, because 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.

But that's not your view.

No.

I -- no.

The next question is from the line of Jason Gabelman from Cowen.

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 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 presanctioned 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.

And the second one is just on petchems.

First, just given the strength that we've seen in margins, can you give any indication of how much longer 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?

Okay.

So the line was not very good, so I'm not so sure to have captured all what you said.

So perhaps I will start with petrochem.

But 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.

We'll be -- 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 -- 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 Q2 better than Q1, honestly I cannot make this bet today.

And you mentioned, I think, the recycling technologies.

So we have some project to recycle plastics.

What has been announced in (inaudible), the fact that we'll build a plant to recycle plastics is part of this -- 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 of recycling.

We have some agreement to -- we are, at present time, a producer of bioplastic in Thailand, I think, with Corbion.

And so we have the same -- we expand this type of agreement with Corbion France.

So we will 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 this force majeure in Mozambique, the fact that, as I mentioned to you, there is 1 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 a project if the conditions are not good.

But we are one of the major LNG player in the world, having the capacity of being in 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 see that when we acquired the Engie LNG portfolio, it was a very, very significative movement.

And it's at that time that we are able to leverage a very efficient way, our LNG position.

So it's not volumes over value, it's -- or with value of our volumes that will drive our strategy, it's the case for LNG, it's the case more globally for all our business at that time.

The last question today is from the line of Jason Kenney from Santander.

So I'm interested in the 8-gigawatt green hydrogen MOU that was signed last week in Australia, the Total Eren.

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 3 to 4 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, preabandonment, subeconomic 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 is not directly Total.

So the MOU was signed by Total Eren.

So Total Eren 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 prefeasibility study for this hydrogen project, so very early stage.

CO2 injection -- what I can share with you is that, of course, we are interested in hydrogen in Total.

So we have some projects for, on one side, green hydrogen; and on 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 this -- the strategy regarding hydrogen at Total.

Okay.

So I think 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.

I'd say 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 activity, I would say, not through screens or through phones.

And it's only a matter of months now.

So having said that, thank you very much, and (foreign language).

Bye-bye.

Thank you.

That does conclude the conference for today.

Thank you for participating, and you may now disconnect.