TotalEnergies SE (TTE) 2020 Q2 法說會逐字稿

Ladies and gentlemen, thank you for standing by and welcome to the Total Second Quarter 2020 Results Conference Call hosted by Patrick Pouyanné and Jean-Pierre Sbraire (Operator Instructions) I must advise you this conference is being recorded today.

I would now like to hand the conference over to Mr. Patrick Pouyanné, Chairman and CEO of Total.

Please go ahead, sir.

Hello, everybody.

Good afternoon or good morning.

I hope that all of you are well and staying safe.

At Total, we are, almost all of us, back to Paris office, 75%, 80% of the staff, taking, of course, all the appropriate precautions, consistent with our safety culture.

But it's good to be again together.

We are more innovative when we are collectively at the office, not in front of screens.

And in the fields, all the business units are fully operational today.

And that's, of course, our big priority, our main priority, keeping people safe, but at the same time, maintaining all our business operational.

I'm happy to welcome you this afternoon together with Jean-Pierre for this earnings call.

I'm joining you today because we felt important that in -- with unprecedented times, the Chairman and CEO of the company can directly give you the big picture of where the company stands.

And Jean-Pierre will explain to you in detail all the 2Q -- Q2 results, how resilient we had been before we go to the Q&A.

So during this quarter, I will not be very original, we faced some very exceptional circumstances, the worst since 2014.

The COVID-related lockdown led to unprecedented global demand destruction, and this was made worse by the drop in oil and gas prices.

The Brent fell by 60%, dipping below $20 per barrel in April and averaging less than $30 per barrel for the quarter, with high differentials -- negative differentials between the Brent marker and the real crude prices, around $5 to $6 per barrel, because of low demand.

And the natural gas prices in Europe and Asia dropped by 60% to historic lows.

Of course, the production restraint mainly by OPEC+ countries helped lead the way to a market recovery, but has seen Brent come back to an average of more than $40 per barrel since the beginning of June.

And I will say we are optimistic about the willingness of all these producing countries to take actions and maintain the crude price above $40, which is, in fact, a low floor for most of them, if not all.

Of course, given our exposure to some of these countries, the impact of quotas on Total was close to 100,000 barrels per day in the quarter.

And so we have revised slightly our full year production outlook to be in the 2.9 million, 2.95 million barrel per day range because the discipline of OPEC+ countries is stronger than ever.

But again, that's good news for the market and for the crude price, and it is a matter of value over volume.

In the Downstream, refining margin collapsed to very low, even negative levels during several weeks.

And we had to limit the refining utilization rate under 60%.

And marketing volumes fell by 30% in the quarter as an average.

However, in Europe -- we can give you some good news from Europe.

Also since June, we have seen a rebound here in Europe, and activity in our marketing networks is back to, I would say, 90% of the pre-COVID levels.

And our gas, electricity business and marketing are close to the precrisis levels.

In the face of all this extraordinarily weak and volatile second quarter environment, I will say that the company has been quite resilient.

During this quarter, we generated $3.6 billion of cash flows and we reported positive adjusted net income.

And we preserved our balance sheet strength with a gearing of around -- of 23.6% for this first half of the year.

So what are the lessons that we can draw from this quarter from the group perspective?

The first lesson is, again, the value of the integrated business model.

These resilient results are due, in particular, to the overperformance of our trading activities, around $500 million above the usual levels.

So once again, we demonstrated the value of the integrated model.

Upstream was impacted by price and lower production, refining by low demand and low margins, marketing by the low demand.

But in the middle of the oil value chain, the trading business captured significant value from the high market volatility.

That's the first lesson, and we must keep that in mind for thinking of the future.

The second lesson is, of course, that we have the opportunity to demonstrate the reality of what -- of the low breakeven portfolio and quality of the portfolio of Total.

The cash generation of $3.6 billion is implying an organic breakeven close to $20 per barrel, so under the $25 per barrel.

These results highlight the underlying strength of the portfolio.

This is a benefit of following our strategy to focus on assets with low production costs.

And by the way, this quarter, we are at $5 per barrel.

We reached the $5 per barrel with all the savings.

And notably, the giant long plateau assets in the Middle East, which some could perceive as not giving some, I would say, increased returns when prices are high, but were very resilient, on the contrary, when prices are lower.

We also rely on an active portfolio management to continuously high grade the portfolio and the latest example being the announcement this morning of the divestment of our non-operated mature assets in Gabon and beginning of the week, the sale and the divestment of the Lindsey refinery in the U.K.

The third lesson is the effectiveness of our 2020 performance plan to control the spend.

The fast and effective implementation of the action plan at the start of the crisis is really the driving force behind the company-wide effort to maximize cash flow.

Net investments will be maintained under $14 billion, and OpEx savings of $1 billion are well underway.

And efforts also to control working capital have given this quarter positive results.

So the outcome is that the debt increase on this quarter has been limited to only $1.2 billion with the payment of a stable quarterly dividend of $1.9 billion.

The Board of Directors is comforted by this resilience and cash generation.

And as I announced to you on May 5, the Board maintains the second interim dividend of EUR 0.60 -- EUR 0.66 per share, the same level as the first interim dividend.

And we will review the situation at the end of the third quarter.

But equally important, the Board reaffirms the sustainability of this level of the dividend in a $40 per barrel Brent environment.

And as you know, we are above $40 per barrel since the beginning of June.

The fourth lesson that I draw is that in such volatile environment, developing a portfolio of renewable long-term PPAs will not only contribute to our strategy to become a broad energy company, but it also contributes to more stable results from our global business model.

We may be recovering from this crisis, it's too soon to know, but in our business, we must always prepare for volatility, even exceptional volatility.

And despite these short-term challenges, we are holding to our long-term strategy to invest in profitable growth.

And this is why the group is implementing with confidence, resolve our new climate ambition to build a more diversified energy company with stronger positions in the low-carbon electricity sector.

As you noticed during this quarter, we have been very active as well.

We entered into the giant Seagreen offshore wind project in the U.K. -- I will just say, in Scotland.

And we acquired an integrated gas and electricity portfolio with 2.5 million customers in Spain, which includes gas-fired power generation.

Globally, we will invest close to $2 billion this year or about 15%, 1-5, of our CapEx in low-carbon electricity to build the future.

And our low-carbon electricity growth capacity has increased this quarter from 3 gigawatts to about 5 gigawatts, thanks to our new Indian solar JV.

We produced 2,900 gigawatt hour during the quarter, and we sold more than 25 terawatts hour, the ambition being to be balanced between our own production and our sales.

And we will come back on this road map at our strategic presentation on September 30.

I will also underline that we are also preparing the future in our oil and gas -- for our oil and gas businesses with our successes in exploration.

And as you probably know, WoodMac has selected Total as the exploring company of the year.

So I pay tribute to our explorers today.

We have announced the nearby exploration success in Egypt, operated by Eni with a potentially fast track to market gas discovery.

And more importantly maybe, we have also explorations exploring large important resources in Surinam with 3 discoveries -- I would say, with 3 significant discoveries in a row and more to come.

And we are also preparing

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oil and gas by some countercyclical deals like, of course, the one in Uganda, where by acquiring the Tullow interest, putting us in charge of this process.

We have relaunched all the call for tender in Uganda for the next quarter to benefit from the depressing supply market, and we have the ambition to sanction the project as soon as possible.

We have also this quarter finalized the acquisition of the Block 20, 21 in Angola, which is a development which will benefit from synergies with our large base of operations in Angola.

As we announced yesterday, the dramatic change in the environment prompted the Board to make a comprehensive review of the assets using a different price scenario for the next few years.

We have been, I would say, quite stringent and have a pessimistic view or varied view for $35 per barrel in 2020, $40 per barrel in '21, then $50 in '22 and $60 in '23.

We adjusted the gas prices accordingly.

For the longer term, we maintain our analysis that the weakness of investments in the hydrocarbon sector since 2015, accentuated by the health and economic crisis of 2020, will result by 2025 in insufficient worldwide production capacity and potentially rebound in prices.

Beyond 2030, given technological developments and, in particular, the evolution of the transportation sector, we anticipate that oil demand might reach its peak, and Brent prices should trend towards a long-term price of $50 per barrel, in line with the International Energy Agency's below 2 degrees scenario.

As a result of this new price scenario, we recognized impairments of $2.6 billion, mainly linked to the Canadian oil sands for $1.5 billion and the Australian assets -- energy assets of $0.8 billion.

These were, in fact, giant projects with very high production costs.

You will notice that this $2.6 billion impairment due to the different new price scenario are quite limited, less than 2% of the balance sheet, which demonstrate that, again, we have, I would say, a safe balance sheet.

I would say that the Board of Directors has also decided, maybe more important, which demonstrates our consistency and our willingness, to implement the climate ambition that we announced on May 5 through our joint statement with the climate 100+ investors initiative.

In fact, we have decided to look to -- and the Board has made a review of the assets to check which could be the stranded assets within our portfolio, keeping in mind our climate ambitions, that outlook to 2050.

Stranded assets, we gave them a definition, were assets which -- where we have more than 20 years of reserve life with high production costs, I would say above $20 per barrel, $25.

The only assets which could -- which have been qualified as stranded after this review were Fort Hills and Surmont in Canada, the 2 oil sands projects which remain in our portfolio.

And this review resulted in a $5.5 billion additional impairment, bringing the total impairment for the group of $8.1 billion.

So being that I've given you, I think, the main element of my introduction, I will turn over to Jean-Pierre.

I will just like finally for this introductory comments to commend all of the teams of Total for performing at such a high level during such a challenging period.

And what I can tell you is while we are certainly more comfortable with the Brent above $40 per barrel than we were when it was below $30, we'll continue with the same discipline.

And I know that the teams will continue with the same discipline to execute and deliver on our 4 priorities: HSE, operational excellence, cost reduction and cash flow generation.

Now Jean-Pierre, the floor is yours.

Thank you, Patrick.

So for the first -- for the second quarter, Total resisted an exceptionally weak environment and reported positive adjusted net income.

And I think more importantly, the cash generation was good, even better than expectations.

Indeed, we generated $3.6 billion of net adjusted cash flow, a decrease of 50% compared to the same quarter last year despite, as mentioned by Patrick, a 60% drop in Brent as well as in European and Asian natural gas prices.

Net debt was limited -- net debt increase was limited to $1.2 billion.

This reflects the successful implementation of the action plan that Patrick mentioned that helped to drive the organic cash flow breakeven to less than $25 per barrel in the second quarter.

Let's look at the results by segment now.

Operationally, the group's Upstream production in the second quarter was 2.85 million barrel oil equivalent per day.

That means a decrease of 5% -- of 4%, sorry, compared to the second quarter last year.

New start-ups and ramp-ups, mainly Culzean in the U.K., Johan Sverdrup in Norway, Iara in Brazil and Tempa Rossa in Italy, were more than offset by reduction linked to OPEC+ production discipline, notably in the Emirates, in Nigeria, in Angola or in Kazakhstan as well as the curtailment in Canada, disruption in Libya and natural declines.

As highlighted by Patrick, we fully support the production discipline particularly by OPEC+, recognizing the positive effect it has on the oil price.

Given this OPEC+ quota as well as the situation in Libya, we now anticipate production in the summer season during the third quarter will be the low point.

So we now expect to average between 2.9 million to 2.95 million barrels oil equivalent per day for the full year 2020.

For the iGRP segment, Integrated Gas, Renewables & Power segment, we reported an average LNG price of $4.4 per million BTU in the second quarter, a decrease of 30% compared to the previous quarter and 23% compared to a year ago mainly due to 3 factors.

The long-term LNG contract price declined by 16% compared to the first quarter, reflecting the lower oil price, and given the time lag effect, we anticipate the low point will come in the third quarter.

Also, in recent months, some of our long-term contracts buyers exercised the contractual flexibility to reduce their offtakes.

So the share of spot volumes in the sales mix were 35% in the second quarter compared to 17%, 1-7, in the first quarter and 33%, 3-3, in the second quarter last year.

I'll remind you that last year, the early Yamal LNG cargoes were sold on spot.

And you know spot prices were particularly low during this quarter, reflecting the weak environment.

So impacted by the lower LNG prices, iGRP reported second quarter adjusted net operating income of $30 million -- something like $30 million, $26 million and cash flow from operation before working cap, the CFFO, close to $560 million.

This demonstrates that our global integrated portfolio including regas, including trading was able to mitigate the weak second quarter environment.

Going forward, the low oil prices observed during the first half will have an impact on LNG contract price in the second half of the year.

And at the same time, we also anticipate that third quarter contract LNG liftings will be harder hit by deferral than they were in the second quarter by an estimate between 20 to 25 cargoes in the third quarter compared to 9 in the second quarter.

So this will be likely a low point as well.

However, during the fourth quarter, a number of deferred cargo will be lifted, and combined with normal seasonality and a possible improvement in Brent, we can expect some recovery later in the year.

Despite the volatility, we confirm our strategy for profitable growth in this segment for both LNG and low-carbon electricity, which is consistent with the energy transition and our climate ambitions.

Mozambique LNG and Arctic LNG 2 are underway, and Nigeria LNG train 7 has been FID-ed.

So our position as the second largest player in the LNG business is solid for the long run.

Also, as part of our partnership in LNG with Sonatrach, we have agreed to renew and extend the agreement for LNG supply from Algeria.

As Patrick said, expanding our integrated low-carbon electricity activity is key to our long-term strategy to more broadly diversify the group's energy offering and to achieve net 0 emission by 2050 together with society.

In the U.K., in a move that changes the scale of our offshore wind activity we acquired a 51% stake in the giant Seagreen 1 project.

In Spain, we have become a key player in the integrated gas and low-carbon electricity market by acquiring 2 gigawatts of solar power generation capacity in the first quarter and in the second quarter, by acquiring a portfolio of 2.5 million B2C gas and power customers, along with 2 CCGT, representing nearly 850 megawatt capacity.

Gross installed renewable power generation capacity rose to 5.1 gigawatts, essentially doubling in the second quarter compared to the previous quarter, thanks mainly to the acquisition mentioned by Patrick in India of 50% of the portfolio of more than 2 gigawatts from the Adani group.

And we have increased the number of gas and electricity customers in Europe as well during the quarter to nearly 6 million, up 7% compared to a year ago.

These important steps allow us to confirm our goal of 25 gigawatts of growth capacity for low-carbon electricity by 2025.

As part of our net 0 ambition, we took the additional step of making the decision to join the Northern Lights CCS project in Norway.

Now moving to E&P.

So this segment reported an adjusted net operating loss in the second quarter of $209 million, reflecting the drop in commodity prices and the impact of the lower volumes that was mentioned before.

In line with the weaker environment, FFO, cash flow from operation from E&P fell to $1.8 billion, but of course, still the single largest cash flow contribution among all the segments and more than enough to cover, by the way, its net investment of $1.4 billion in the second quarter.

We are committed to profitably developing and high-grading the E&P portfolios.

We'll give you some illustration.

In the second quarter, we started up the second FPSO in Iara, the low-breakeven deep offshore field in pre-salt Brazil.

In terms of M&A, we have continued to move countercyclically and acquired 2 interests in the Lake Albert project in Uganda.

We have completed the Angola Block 20, 21 acquisition announced last year.

We closed the sale of Brunei Block CA1.

And we announced today that we were successful in divesting our non-operated mature assets in Gabon.

Although we have implemented strict discipline in capital spending this year, we continue to explore with some success.

Notably, in offshore Egypt or in Surinam, we made a third discovery, Kwaskwasi, after Maka well in January and the discovery Sapakara in April.

Turning now to Downstream.

Adjusted net operating income was $704 million, down 38% compared to a year ago.

And second quarter CFFO, cash flow from operation, was remarkably strong at $1.5 billion.

The decrease was primarily due to weaker refining driven by the 48% drop in the variable cost margin and below 60% utilization rates, which resulted mainly from prolonged outage at the Feyzin, the Normandy, the Grandpuits refineries in response to weak product demand.

Marketing was weaker as well with refined project -- product sale volumes down by 30% due to the demand destruction during the lockdown.

On the other side, our trading activities did very well in the volatile second quarter environment and overperformed by about $500 million.

And at the same time, petrochemicals were resilient due to a higher utilization rate as well as resilient margins this year.

Downstream CFFO in the first half was $2.6 billion.

High inventories levels continue to weigh on refining margins and utilization rates.

The recovery will largely depend on the speed and extent of the post-COVID global economic rebound.

So our guidance of a range between $5 billion to $6 billion for the year can be reached.

Finally, at the group level, our adjusted net income was $126 million in the second quarter.

And reported net income was negative, given the $8.1 billion impairments recorded this quarter.

The effective rate -- tax rate for the group was negative 7% in the second quarter compared to 30% in the previous quarter essentially due to the adjusted net operating loss in E&P with high tax rates, which was not offset by the positive results in the downstream, which has a lower tax rate.

Second quarter net investments were $2.9 billion, including organic CapEx of $2.2 billion.

For the first half, net investments were $6.5 billion, and our guidance for the full year is net investment of less than 30 -- $13 billion.

We confirm capital discipline is part of the action plan.

We implemented the action plan at the start of the crisis.

And since then, there is a strong company-wide effort to preserve cash flow this year, notably by saving $1 billion in operating expenses compared to last year.

And I can tell you that in the second quarter, we reduced OpEx per barrel to $5 per barrel from $5.20 per barrel in the first quarter as well as strictly controlling, at all levels, spending to keep the breakeven low and maximize the cash flow.

As part of the action plan, we also concentrate on turning working capital into a source of funds.

And in the second quarter, we had a release of $0.4 billion of additional cash flow through working capital.

For the final 2019 dividend payment, we offered, as you know, a scrip option that was subscribed at 62%.

And this will reduce our third quarter cash outlay by about $1.2 billion.

But as you know, the scrip dividend will not be possible for the next 3 interim '22 dividends.

We were very active on increasing liquidity during the quarter.

And as announced in May, we have improved our position by more than $30 billion, largely by securing $9 billion in long-maturity bonds and more than $6 billion through syndicated loan agreements.

We are net cash flow positive year-to-year so we have preserved our balance sheet strength, and gearing was below 24% at the end of the second quarter, taking into account the 1.3% impact associated with the impairments we have recorded.

To conclude, I would like to emphasize that our priority going forward is to deliver on our action plan, generating a level of cash flow that will allow us to continue investing in profitable projects while preserving, at the same time, an attractive return to shareholders and a strong balance sheet.

I think now we can move to the Q&A.

(Operator Instructions) Your first question today is from the line of Irene Himona from Societe Generale.

Congratulations on these numbers.

I had 2 questions, please.

First one for Patrick.

Perhaps in relation to the Board's review of stranded assets in the portfolio, I wonder if you can share with us your views on the risk of stranded refining assets and indeed, refining margins long term through the energy transition in relation to Total, but also in relation to the European industry in particular?

And my second question for Jean-Pierre.

In the second quarter, your Upstream tax was, in fact, a little bit above the first quarter.

I wonder if there is some guidance for full year expectations on that front?

And also, if you can please remind us of your full year expectation for working capital.

Okay.

Thank you, Irene, for your comments.

The refining assets, I would say, you have noticed that -- and you know, obviously, that we have committed, I would say, to Europe climate neutrality by 2050.

So we have to be consistent.

And we know that in Europe, refining is, I would say, oversupplied.

We have -- you'll notice that we have divested one refinery this year -- this week, Lindsey refinery.

It took us quite a long time to divest it.

I would say that we are left with not so many assets.

You know also that in our road map -- and we'll come back on this road map by September or the strategy meeting, but in the road map -- in the European road map, there is quite a strong willingness from the policymakers to develop biofuels, renewable fuels, I would say, biojet, biodiesel.

We have made a first positive experience, in fact, in La Mede.

The only positive refinery in France during the quarter is La Mede.

It's no more a refinery, it's a biorefinery.

And despite the specificity of the French market, which does not allow us to use palm oil, we are able to make positive results.

So this gives us obviously the willingness, and Bernard Pinatel will come back on it, to develop, I will say, more aggressive strategy to develop the bio business, in particular by converting some European refinery to these biofuels.

We have an advantage.

It's not -- from this perspective, not at all a stranded asset; on the contrary because when you convert brownfield assets, you have -- I would say, you spend $500 per ton to make, in CapEx, a biorefinery instead of a greenfield project to make -- above $1,000 per ton.

So part again of our climate ambition.

As we told, we want to decarbonize all assets by developing biofuels.

So that's my answer to you.

And so I'm not -- we have reviewed these assets definitely.

We are -- the Board is not -- has some answer about refining assets from a stranded point of view.

I leave the floor, to the complex second question, to Jean-Pierre.

Thank you very much.

The guidance for the tax rate for full year, of course, it depends on the crude price and the global environment.

But I would say that that's currently around $30, $40 per barrel.

We could expect group tax rate around 15%, and the contribution of E&P in that tax rate will be around 25%, 30%.

That's an average of $35 per barrel, I think, which is -- for the year.

We are a little above today.

So -- and it's quite sensitive to the oil price, so be careful.

And for the working cap, it's a matter of prices as well because the (inaudible) is impacted particularly by the stocks.

But we are very satisfied to see during the second quarter that we managed to cash in more or less $400 million this year.

So it's a cash in.

So I can tell you that we'll continue to monitor this working capital.

All the teams are mobilized to limit the working cap.

And we hope that if we maintain -- if we are around the current level of prices, we could have a positive impact on the (inaudible) for the full year, so cash in.

I remind you that we stated in the Q1, in May that we have an objective of a release of $1 billion.

At $30, $35 per barrel.

At $30, $35 per barrel.

So we are on this way.

Okay.

But it's clearly a priority.

And to be fully honest with you, we have put, as an incentive to all the executive of the company, cash -- working capital release before year-end.

So it seems to work.

So the focus on cash is strong in the company.

The next question is from the line of Michele Della Vigna from Goldman Sachs.

Patrick, Jean-Pierre, congratulations on strong results in a very difficult macro environment.

I had one strategic question on the low-carbon business.

Until now, it's made perfect sense to develop most of the businesses unconsolidated, associated with project financing, in this way limiting the CapEx and the corporate gearing.

But I was wondering, at a time when investors are very focused on seeing this business gaining scale and also with rising frameworks like the European green taxonomy that focus on revenue and CapEx exposure, perhaps wouldn't it be better to have a consolidated low-carbon business and show separately the debt, the CapEx and the unlevered and levered returns and in that way, offer greater visibility on the growing scale of that business and on the underlying economics?

So you have to be patient until September 30.

We are -- no, but to be clear, we are working on it, obviously.

And we will be -- I will tell you why we'll do it.

As you noticed during the -- since the beginning of the year, we have made a lot of progress in terms of acquiring -- of growing the portfolio.

We have grown project in India, the project in Scotland, projects in Qatar, projects in Spain.

So we have today a much stronger visibility on what will be the development of this business, low-carbon electricity business between today and 2025.

And by September, we'll be able to provide you not only projects but consolidated vision of -- and financial figures, but -- like we are doing today in E&P with what is the target of production, what is the target of financial returns.

So Michele, please wait a little for that.

But it's clear, and I'm fully -- I fully support your view.

And we all noticed that the market today is very keen and is giving a much better multiple to this type of businesses than, I would say, our heritage business.

And so the only way to track part of this multiple on the company will be to give more visibility.

But to do that, we need, of course, to grow it, to make it sensible.

So this will be, I would say, one of the main objectives of our strategy presentation in September, will be to give you, I would say, more than a flavor but to give you some insights on what is this new energy business for Total, this low-carbon electricity and -- so that you can be convinced that there is -- it's a growing business.

It's a profitable growth, I would say.

And of course, as you said, of course, this is sustained by the capacity to make some project financing to leverage the financing.

But we'll come back in detail on it.

So I fully support your analysis, and we have -- we are on the same, I would say, understanding.

And by September 30, you will have all that you want -- maybe not all, at least what we can deliver to you because we always keep a certain thing for us.

But honestly, the progress has been strong.

And in fact, we are clear -- Jean-Pierre told you that we are on the road map of delivering this 25 gigawatt gross capacity.

We can do more than that.

And I mentioned that the ambition is at least to produce as much as we sell.

So I can tell you, we'll give you high production figure.

It would become quite sensible in the company.

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

Two questions, if I may.

One regarding the oil price outlook.

I mean clearly, the revisions are sort of prudent.

And I wanted to understand better, Patrick, how you see the macro backdrop, particularly with the comments around underinvestments and the supply and also just how that compares to where demand -- and the trajectory for demand.

I know it's an impossible question, but it's clearly something that speaks to -- something you've been talking about in this analysis you've done.

So just a guidance around what your views are on the supply outlook.

And that sort of segues into the second question, specifically around how you plan for FIDs and the priorities around FIDs over the next 12 to 18 months.

If you are to sustain your production over the medium term, how should we think about the priority around projects, particularly with the discoveries in Surinam?

Okay.

Thank you, Christyan, for these 2 questions.

The first one is not fully impossible because I gave a sort of answer in our price scenario.

We didn't -- as you noticed, we have been very prudent, obviously, for the next 3 years, but we also kept in our scenario, the average on the next 30 years is around 30 -- $56.8.

But you noticed that we kept part of the scenario we published by beginning of the year, which is between $25 and $30, a rebound which could go up to $70 per barrel.

Why?

Because we had before this crisis -- and I think, again, this crisis reinforced this feeling today, is that the supply will be damaged.

In all business, when you don't invest, you have a natural decline.

Of course, in the last year, this was offset by the increase of the shale oil production.

But -- we can be wrong on it, but we have the feeling that this crisis is pushing investors to have an overview of the investments in the shale oil.

You have the drop today from 13 million barrel of oil per day to 11 million.

Next year should be around 11 million barrel per day in our views.

Of course, it could come back, but I think investors and shareholders will be more prudent.

So that means that this effect could be less efficient in the next years.

And at the same time, as you noticed, there is less and less FIDs, and so we come to the second question, for most of the players.

So it was not good before 2020, but it was -- the balance was coming from shale oil.

I would say that today, it's even worse.

Less FIDs and less shale oil could lead again to a lack of oil production.

Of course, there is a link to the demand.

And that's back to the other question, which I noticed that today, people are all obliged to stay beyond their screen so they write a lot, a lot of stories about the demand has vanished forever.

I don't think so it's right.

I think, yes, it's true, but I don't tell you -- I will not tell you if it's a V shape, a W shape.

My traders gave me a good story.

They told me it's a root square shape, a root square shape, which means that it could take -- go back to 90%, and then it could be 2 years to go down to the 20 -- to the back level -- but to the level pre-COVID.

But I'm convinced we'll come back to this level.

On the longer term, beyond 2030, we could have some effects of technology, but I don't think it would come very quickly.

And so from this perspective, we kept and the Board kept, because we had the discussion at the Board level, this vision of a price which could rebound by 2025.

Again, putting the price is difficult.

We have to make an assumption, but this is in our views, which lead us to -- back to FIDs.

And this is why -- by the way, the strategy of Total is clearly to be a multi-energy company, which means yes, low-carbon electricity, but also oil and gas, not to make any mistake.

We want to grow and we will grow.

So we will update you by September about the profile goal between 2020 and 2025.

Of course, we did not acquire Ghana and Algeria.

So we have an impact.

But we have some key projects.

And to come to your question, especially the FIDs, key FIDs for us on which we work are in Brazil, deepwater Mero 3, I think this year, up soon, and Mero 4. And in Uganda, of course, obviously, we have a big stake in Uganda, operating.

We have solved a lot of issue in Uganda.

We continue to work out despite the COVID by teleconference.

We progress a lot on the pipeline and -- with Uganda, with Tanzania.

So -- and I hope that we could benefit on Uganda and the very good project if we get good cost with the crisis being there.

And of course, don't forget that if the price comes back, there's short cycle CapEx, that we have canceled this year.

We have still the 1 billion barrels which are in the portfolio that can be reactivated.

So these ones could also fill the future growth of the production after a time.

Just sorry, can I just follow up very quickly on -- if I may, on the second point in that -- sort of in terms of the plan?

So hope for the best, plan for the worst.

I mean with your dividend set at $40, it's hard not to ask this, but if oil does stay below $40 on a sustainable view, what are the tools you have in order to mitigate?

Because it sounds more like a half glass full strategy in oil over the next 3 years.

No, but at $40, the dividend is sustainable.

And again, look, this quarter, I mean, there is an arbitration among our capital expenditures.

So we will arbitrate between the different projects.

It will be a matter of value over volume.

But the best projects, like the one I mentioned will be financed, for sure, and we don't intend to -- and if we have to arbitrate, we'll more arbitrate on the short cycle if we don't have the quick return.

So again, I cannot tell you more than that, that one I just told you about the sustainability of the dividend at $40 per barrel.

About Surinam, Christyan, you have to -- it's a matter of let's be a little patient.

We have announced 3 discoveries.

We are still making some logs.

And as you noticed, we are finding oil.

We are finding some oil with gas, with light oil, with condensate.

So we are quite convinced that a development -- at least one quick development should be put in place.

We are drilling a fourth exploration well on Kwaskwasi soon.

After that, Total is becoming operator.

So this could be for us a new very high -- large oil province, which will concentrate a lot of efforts of the company.

But I want to have all the data before to be -- to give you more, I would say, figures about the capacity of all that.

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

Two questions, please.

The first one, Patrick, the moves that we've seen this quarter and this year, whether it's selling Lindsey, Gabon, buying into Seagreen, they're all very consistent with the strategy that you set out, but it does seem to be moving very quickly.

And is that -- has that sort of change in strategy accelerated since the start of the year effectively?

Are you seeing more opportunities in low carbon relative to what you did at the start of the year?

And actually, sorry, linked to that one, the stranded assets review, did the results surprise you from that?

And then one last question, if I could.

On the Downstream, can you just give us an idea of where you expect the cash flow contribution to be?

Because, clearly, refining margins have been very weak over the last 3 months or so?

Okay.

The last one is quite clear.

I mean the cash came quite, of course, obviously, from the trading.

The trading business, when I tell you that trading has overperformed by around $500 million, the beauty of trading is that when I give you a result, you can translate it in cash.

So that is easy to do, and the tax rate is almost -- is quite small.

It's why, by the way, that we have a low tax rate globally.

So can it -- is it sustainable?

What Jean-Pierre told you is that at the first half despite the terrible second quarter, we have generated on the Downstream $2.6 billion.

So we gave you a guidance of $5 billion to $6 billion.

That means that if we double it, you are in the range.

Again, it's very difficult.

That's true that the margins -- refining margins are very low, but the marketing business has reached, I think, its very low point by the second quarter.

So it's giving better cash since June, more normal ones.

Of course, the trading cannot reiterate because it was linked with -- capture of strong performance was linked to the very high volatility.

And frankly, I hope we'll not have such a high volatility in the first -- second half.

But -- so all in all, I'm confident with the guidance, which was given to you by Jean-Pierre.

We'll see.

The other assets -- did the review surprise you in stranded asset?

No, I mean, I would tell you, the main point was for us to be very comfortable to say, okay, we have made this statement in May or June.

We want now to be clear and consistent with the climate strategy.

Let's do the review.

When I had the one-to-one road shows, people were asking me what about stranded assets.

Immediately, I was thinking to the oil sands, which was obvious to me because -- and by the way, this quarter, we demonstrated it because we have curtailed the production on the oil sands.

And the production has been reduced to 35,000 barrel per day on Suncor these last months.

Why?

Because, in fact, the cost of production was much higher than the oil price.

So we were -- so I think, again, if you think to the future -- and so we made an asset-by-asset review to be sure that we are missing nothing.

And long reserves and high production costs, we had only these ones in the portfolio.

And I think -- so the Board said, "Okay then, let's do it." We had to find, I would say, an accountable way to do it.

I mean, in terms of recognizing.

So we decided to use only the proven reserves to make the test, which is a way to be consistent with figures which can be audited, and the auditors were very comfortable with the way to make this review and this impairment.

And I think it's a vision that, in fact -- what does it mean for our proven reserve?

There are -- that means by 2040, 2050, we think that if oil demand is going down, then this type of assets which are high on the cost merit curve could be stranded.

And that means that what is happening today will become the new normal for the oil sand.

So we did not identify other ones.

The others which are not so -- we are not -- we don't have -- by the way, the over long-term oil assets we have are in Abu Dhabi.

In Abu Dhabi, the cost of production is less than $3.

So we don't have at all the situation.

The first questions are about the strategy in low-carbon electricity.

I think, yes, you have seen not only press release, you have seen assets moving.

It's not only press release.

This is a real deal.

Why did we accelerate?

I think first, I'd be clear, it is a result of 2 years and 3 years of putting in place the teams, identifying the opportunities, finding the right partners.

For example, India is a consequence of the partnership with Adani on the gas, and then we leveraged that to go to renewables.

And we've also made something strategically, which was, I would say, 1.5 years ago to decide, okay, don't -- let's not concentrate on solar only, but let's look to other technologies.

And clearly, I would tell you that maybe we made a mistake in the past, but it's better to recognize it but not to ignore it.

It's -- offshore wind is obviously fitting very well, I would say, in terms of capital intensity, production capacity as well.

So we are very happy to have managed to convince SSE to become a partner in these giant projects.

It's honestly for less than -- for around less than $100 million of entry costs.

It's safe to us.

Years of -- getting the permits in offshore wind can be very slow.

So I think it's a very efficient entry.

So yes, that's true.

It's also -- and as I said to Michele, I think, before, this recognizes the fact that we are more and more comfortable in, I would say, approving the projects.

We have a clear -- a better and better strategy, and we'll be able, again to show you more by September 30.

So it's -- and it's consistent.

I would -- as I would say, all that -- we were able also to make this statement on May 5, our climate ambition, it's because we are clearly more comfortable with developing this multi-energy company that we want Total to become.

So Total will not -- will become Total energy, as you know, with eveness and not only Total oil.

The next question is from the line of Jason Gammel from Jefferies.

I just wanted to ask a couple of questions on the LNG business.

You mentioned deferring quite a few cargoes in the third quarter.

And I'm curious right now where prices are at, if it's even profitable, to lift LNG from the U.S. Gulf Coast.

I know that your shipping fleet and regasification capacity could potentially have some benefit there.

And then the second question is really more on the medium term and the supply and demand balance.

You talked a little bit about oil fundamentals moving forward.

Could you maybe spend some time on the LNG market as well?

I mean, obviously, spot prices are pretty bad right now.

But you are investing in quite a bit of capacity for the middle of the decade.

Jean-Pierre, why don't you...

Yes.

So concerning the deferred cargo, I mentioned to you that during the Q2, we decided to defer 9 cargoes coming from the U.S. and mainly from Freeport.

Given the flexibility we have on the contracts for the third quarter, we can imagine and can anticipate that we will have more deferred cargo than in the second quarter depending, of course, on the time line in the formulas.

No, I think our trading team clearly are thinking to cancel and to cancel around 30 cargoes from the U.S. The U.S., obviously, today is less profitable.

It's very clear.

It depends.

We had some deals like the one -- it depends on the -- which provenance it is, I mean which -- the deal we've done with Toshiba last year gave us a much lower dollar per million BTU cost of production than some other ones.

So we arbitrate.

But clearly, today, this U.S. LNG is not very profitable.

So that's reality.

Again, that's today, short term.

It does not change what we think fundamentally.

Fundamentally, this LNG business is a business we will continue to grow.

There is -- you don't make the energy transition in this planet, shifting from coal to gas without involving LNG market.

And so that's a fundamental.

And so we'll keep it.

Having said that, coming back to your second question, I think first, this crisis has sometimes benefit.

And one of the best benefit from this crisis is that I think there were many LNG projects who are not far from being sanctioned.

All of them are stalled, which is good because we were a little afraid by having too much supply by '23, '24, '25, '26.

Today, what is happening is that we'll not have too much supply.

And all 3 projects we have, Arctic 2, Mozambique LNG and LNG train 7, which will come into that window will come at a time where we can expect, on the contrary, to have a much more balanced market.

And so we are -- I think, even if today we suffer, in 3, 4 years, we will benefit from the situation.

I think this is a wake-up call for everybody, what is just happening.

People were thinking that the business model of U.S. LNG, which is to make a sort of infrastructure business where you have -- you find people to offtake the gas with no integration, is a new way to make business.

Obviously, I think the offtakers today are -- will become more and more cautious, and it's back to what we think.

We think that the right business model is to be integrated, integrated on the upstream, integrated on the midstream and downstream.

Again, we are, as I said, when we acquired the Engie portfolio, we were thinking that maybe part of that was being too much regas capacities in Europe.

Today, we have been quite happy to have all these regas capacities, which give us a good result.

So we have -- and again, to be -- so the lesson is that when we are offtakers, we have to be integrated.

And for example, in Cameron, being an equity in Cameron give us an edge, in fact, because we -- from this perspective, because yes, the offtake part today is suffering.

But the plant -- the shareholder of the plant is quite happy today.

So again, I think the lesson is let's continue to -- it's part of -- it's -- I think LNG development and growth is really anchored in the strategy of the group.

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

A couple of questions, please.

I mean, firstly, considering your comments on gas, and obviously, you're also investing a lot in gas, called gas switch driving growth, is Europe making a mistake with the green deal?

I'd be interested to get your views on that.

And then secondly, you talked about low carbon being high multiple and your legacy business, fossil fuel, oil and gas currently being low multiple.

But is it now getting interesting for you considering your slightly more positive medium-term view on oil to actually be more active in M&A in fossil fuel?

Or are you just generally happy with what you already have in the portfolio?

And if I may, finally, just on gearing.

I know you do have a target or an ambition to be at around 20%, pre or post IFRS 16, but is there a soft or hard ceiling for that ratio?

Good question.

Now Europe, obviously, I mean, I'm more -- I think when you look and listen to the green deal and in particular to Frank Zimmermann, the Vice President in charge of the green deal, I think he has understood -- and the last speech he has delivered on the hydrogen ambition, it was very interesting because I think that Frank Zimmermann has clearly understood and the commission understands that you don't make a transition in Europe without natural gas.

And people want to jump immediately to green hydrogen, and he explained that we had to go through blue hydrogen if you want to be efficient.

So I think -- and for most of the countries and Germany in particular, natural gas is part of the -- is obviously the only way to move from coal to gas, if you don't take nuclear.

So I think -- I know that people in Europe try -- tend to put all the hydrocarbons in the same basket.

But I noticed since -- and maybe because they want to put more money in all this green deal, but the political leaders are becoming more and more realistic about the space for natural gas in this transition.

So -- and by the way, for -- I already said it, but along the good electricity business, today, we have this gas-fired power plant, which are running at a very high level, and we generate quite a good business.

So I think it would be a mistake obviously, to answer your question, if Europe was putting aside natural gas.

But I think it's not the case.

Of course, they will ask us to, I would say, make the gas greener by injecting some biogas, and we are looking to develop ourselves a business in biogas, to make it greener by injecting some hydrogen.

But I think and we should -- why not, you say.

Of course, it's a matter, of course, of will the European customer be happy to pay more.

But at the end, all that has to be paid by somebody, not by us.

So I'm optimistic about the situation in Europe because it will be a question of facing the reality.

Should we be more active on M&A in oil?

Again, we -- the multi-energy company -- strategy encompass oil, and don't make any mistake.

We want to grow.

So I'm not sure -- I have nothing -- no message today.

Obviously, the fundamental for me is to be on oil with low cost, low-cost oil.

I mean this is consistent.

So if we had opportunities because, of course, the cycle is very low and some people are desperate to have access to low-cost oil, we will study.

If it's high, of course, we will not do it.

And by the way, this is what we've done, I think, with Tullow, renegotiating the deal.

This is what we have done in Angola to access the 400 million barrels for, I would say, $400 million or less than $1 per barrel.

So again, the fundamental for me, it has to fit with the strategy of having access to assets with low cost of production.

And so you could see us on this field.

The gearing, to be clear, there is nothing I shared.

And we said less than 20%, I think, is without IFRS because this was -- target was set before the IFRS 16 on lease was put in place, so we didn't move it.

So that's the objective.

Today, we are at 24%.

I remind you, the allocation of capital we set before the crisis is still valid, a further CapEx of the company; the dividend, we keep the dividend; and then the gearing.

So clearly, one of the objectives if we have more cash flows coming because of pricy bond, we'll be able to allocate that to lower the debt.

And so I keep the 20% as a very strong move because, again, if today, we are comfortable at these prices to face the situation, to weather the storm, to maintain the dividend, it's, of course, because we have a stronger balance sheet.

So yes, we moved from 16% to 23%.

And so if I prefer to -- the lesson is clear to me.

Allocation of cash, extra cash, if we have it in the coming years, would be primarily to come back under 20%.

Do we have a very high ceiling?

No, but obviously, there is a certain point that we need to be careful.

Again, that will be a discussion for the Board.

But I'm -- again, at $40 per barrel, you noticed that this quarter, we have, I think, increased the debt by $1.2 billion.

So it is the equivalent of a Brent of around $44 per barrel.

By the way, Lydia has calculated it for me, and she's right.

So I mean -- so that means that we are -- at $40, we said we can maintain the dividend.

That means we are balanced more or less in terms of cash -- net cash, post dividend.

So that's important I would say.

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

I just wanted to touch base on chemicals following the impairments yesterday and your change of view on oil prices, but this is been a bit of a focus for Total.

And you do have a few growth projects there.

So I was wondering if you could talk about over the last 6 months, has your long-term or medium-term view on the chemicals market changed in terms of attractiveness and how you think about mid-cycle margins for that business?

And then the second question is on the comments you made on oil trading.

I think you've mentioned $400 million to $500 million this quarter.

Just for a reference point, can you say what your oil trading business typically generates in an average year?

Just to get a reference point for that.

The Total trading is a secret, and I just gave you, that we've done $500 million or more than usual, but you will not have the usual figure.

So sorry for the second question.

You tried, but it's a good try, but it's not.

I tried as well to answer you or not to answer you.

Chemicals, let me say, no, we have projects in chemical but petrochemicals.

I mean we have been always very clear and selective in the petrochemical role.

We say primarily and this doesn't change, we want to invest in feedstock-advantaged projects, which means mainly on natural gas projects because we want them to have an advantage on the feedstock compared to naphtha.

So of course, in an environment where everything is low, the advantage for nat gas cracker is less obvious than the naphtha cracker.

But the fundamental is that for me, is that even on the medium and long term, I see a disconnect between the oil and the gas price.

So that's where we are.

So we have not changed our views.

We have a certain level of projects.

We are working -- our cracker in the U.S. will start next year.

It's an integrated.

And the other fundamental petrochemicals for us is that we are integrated between monomers and polymers.

When we make a cracker, we want to have a polymer capacity coming together.

Otherwise, you could fail.

So to answer to your question on medium-term view and long-term view, no, it does not change because we look to be, I would say, integrated margin between monomer and polymer.

And so we have the U.S. coming or we have our projects in Korea, where we continue to grow and develop our Korean platforms together with our Korean partner.

And the other big project is the one in Saudi Arabia with Saudi Aramco, Amiral, on which we progress, we will launch the FID by, I think, September.

So we have progressed despite the COVID.

It's a very big plot projects.

So all these projects are moving forward.

There is also a project in Nigeria.

So we don't change our view on it.

I would say it's a selective growth based on projects which really fit with the fundamental characteristics, advantaged feedstock; and secondly, integration, monomer and polymer.

The next question is from the line of Jon Rigby from UBS.

Can I ask 2 questions?

First is on the impairment charges from yesterday and the discussion you had on the Canadian projects.

I'm sort of intrigued by your methodology because it seems somewhat artificial.

Are you saying that you don't think the 2P resource base will get produced out or you won't produce out the 2P resource base?

And either way, given your reluctance to sanction any more as a non op, wouldn't it sensible just to sell-out of these projects?

And if that's the case, would you expect to realize a price that's above the carrying value from -- on the balance sheet?

Because presumably, when you come to negotiate a disposal, you want the buyer to pay for the 2P resources, I would have thought, or that would be some odd.

Question two, just on your working capital.

Can you just confirm there's nothing funky going on?

You're not sort of selling receivables?

If you can bring the balances down, this is a structural benefit to the balance sheet going forward, not just a one-off in 2020?

No.

Jon, let's be clear.

By the way, all impairment calculations are artificial.

So it's not a -- the methodology, there is a -- the scenario, the price scenario has to be set by the Board.

And it's not -- each company has its own scenario.

So you have also the discounting rate, which can -- may be different.

So I can't give you -- I can't tell you this matter of impairment is not -- we don't find the answer and the methodology in a book, precise one.

First comment.

The second one, regarding the way when we came to Canadian projects.

I mean again, it was a matter for the Board to be consistent with the vision, which we put in our, I would say, the climate ambition.

But we have a vision, maybe we can be wrong, obviously, that the oil demand will plateau and will decline.

And then if it is the case because we have a lot of oil of this planet, that means the pressure on the oil price by 2040, '50 might be stronger like today.

And then what will happen is that the assets with the highest production cost will be in trouble.

So we made that review.

We had a 2P profile of our assets.

We are going until 2068, I think, some -- one of them.

And we said to ourselves, okay, if we don't believe by the pacing today and 2068, but the price of oil will remain at a level which might be enough to produce all the assets, we have to make something.

So then it was a conclusion of methodology.

Of course, the 2P reserves are proven and probable.

I'm are not certain, proven and probable mean it's proven for 1P and probable for 2P minus 1P.

And by the way, if you look to what are the SEC rules from some independents in the U.S., you take only the 1P and not the 2P.

So we said to ourself, okay, well, finding a way to translate this long-term price assumption and this long-term risk on these assets into a calculation.

So there was a form of logic to us to say, "No, the 2P does not disappear." But again, they are probable ones.

The 1P are certain.

The profile is going, I would say, until 2040.

So let's take the 1P, which were audited figures.

So okay, it's a matter then of finding the right accountable way to be -- everybody was comfortable to make the calculation.

Is it more artificial than something else?

It's a decision, at least it's more -- less artificial than just putting a figure.

The reconciliation that we've done as well obviously, and that's an accounting rule is what we are supposed to have in our books, a value of assets which makes sense compared to the market for either what could be the sale of the value of these assets, we want to sell them.

And that's the second part of your question, which is sensible.

And that was a check we've done.

So at the end, we are left with a certain carrying capital employed on these assets, which when we compare to various valuations, which were given to us by WoodMac, by banks, by -- we use many calculations.

The last transactions we have done on many metrics, et cetera.

We are at a level which is not 0, obviously, because it has a value.

It has a value, and which is in our book.

That's fine.

So -- and again, I think if we don't tell you, we never said that the 2P have disappeared.

The 2P are there.

We said that in our books, we'll not take into account the 2P to be consistent with the global impairment and ambition.

That's all what we said.

So yes, it's a sort of approach, which at least is transparent, clear.

And I think that the buyer, obviously, there is a buyer, will have a different view than us about the capacity of extracting value from these assets.

And maybe in 2068, we'll be happy to produce these assets.

For the time being, basically Total is just waiting to see the pipelines in Canada, the TMX pipeline being built, then the value of the asset will be higher.

And then if somebody has a good offer, we never say never.

But we are very patient on this one.

So working capital.

Working capital, yes, of course.

Managing the working capital is key for us to preserve our cash.

And as already mentioned during the call we had with you in May, we mentioned in the action plan that we target, it's to cash in $1 billion through working cap at $35 per barrel end of this year.

So for doing that, we use all the different tools we have and selling accounts receivable through programs with different banks, of course, is part of the way we manage the working cap.

There is nothing bizarre.

By the way, it's not this quarter.

It was done by the company for many years.

Yes.

So we do that on a regular basis.

The President of Refining & Chemicals few years ago decided that it was a good time to be a little more innovative in this way because the burden on the capital employed was so high that we have sometimes to take -- that's part of what this financial market with 0 interest rate credit is giving possibilities.

So that's nothing I call.

And nothing bizarre.

And nothing bizarre.

And obviously, the cost is almost nothing.

So everybody is happy there, so banks and us.

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

Yes, 2 -- 2 follow-ups, I guess.

I'm just thinking about the big upstream pipeline of projects you had, Patrick, the 800,000 barrels a day and the 15% internal rate of return that you had at $50 oil.

So you've obviously got a little bit of a square root going on with your oil price changes last night and going forward.

So I'm just curious if you could give us a sense of how that number may have changed post the price resetting, please?

And then, yes, you talked about chemicals there, which was interesting.

I was just curious, it's difficult for us to see chemicals, obviously, on a quarterly basis.

But given your more balanced monomer-polymer ratio, and given your very high ethane input.

I think it's well over 60%.

But is your chemical business outperforming peers in the first 6 months of 2020?

Is it possible just to talk about that, please?

On the second one, to be honest, I don't have all the peer figures.

What I can tell you is that clearly, the petrochemical business was very resilient.

And in fact, it was not far to be in line with the budget session.

We put -- budget figures we put last year.

So why?

In particular, because in the polymer business, we benefited from more demand on all the Elf segment.

Of course, we suffered from less demand from the car manufacturing businesses.

But on the contrary, we had more demand on the other part.

So of course, we have to be prudent because we also observed that there is a weaker business today in the U.S. than in Europe.

Europe has quite well resisted.

And I would say, our Middle East business is also well resilient.

So compared to our peers, I mean it's difficult because, honestly, none of us have really the same size of petrochemical business.

Two of our competitors have a very large ones.

We are, I would say, a middle-sized business, and some others do not have any business.

So on the upstream pipeline of projects, I would say that there is no -- I mean, the main influence between today and when we announced the 800,000 barrels per day of 18% is that I think -- it's 15%, we were taking into account, I think, the acquisition of Algeria and Ghana in this figure, which, of course, are not there in the profile today.

Having said that, as you noticed, Oswald, our scenario is coming back to $50 by 2023.

And we told you that we sanctioned projects at $50 per barrel.

So I'm sanctioning projects at $50 per barrel.

The scenario that we just put to make impairments is coming back to 50-plus from 2023.

So I think there is no change.

I mean -- and what I hope is that the cost of the project will be lower like Uganda because so we could have a better IRR even at $50 because we sanction at $50.

So it does not change that outlook fundamentally.

I would say the main impact today for us will be more on the LNG projects, not on oil projects.

On the LNG project, as I told you, we have already sanctioned 3 of them.

Of course, this today we are, I would say, more patient before to sanction a project like Papua LNG, but we have to work.

We are not planning to sanction it very quickly.

So we'll need to see.

And probably one of the consequence for me in LNG is that we will wait and we will ask and we'll wait to get some long-term contracts.

I think the new LNG projects will be more sanctioned with more long-term contracts with third-party customers like Mozambique LNG, by the way, and maybe less by a lot of spot contracts, people taking the risk.

That could influence the FIDs in terms of timing of sanctioning the new energy projects.

But in terms of price visibility, we are comfortable with $50 before.

We are still comfortable with $50 today.

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

Patrick, just 2 quick follow-ups.

Firstly, on dividend, of course, we're going to wait for Q3 and hear whether you can tell us more then.

But just wanted to ask a conceptual question.

You used to refer to a 40% payout ratio of CFFO.

Do you think that can be a model in the future rather than to highlight a progressive dividend policy?

So maybe I'm too soon asking that question, but I'm going to ask it anyway.

And secondly, you mentioned earlier, you obviously have made -- you've grown your appetite for more offshore wind.

So in terms of gross capacity, that's now a bit more than 1 gigawatt in your pipeline.

Can you perhaps give us an indication how much offshore wind do you think will play a role in your 25-gigawatt target for 2025?

So yes, not -- no, Chris.

You are not too soon.

You will never have the answer on your first question because there is one lesson for me is there is no way for Total to be trapped in any mathematical formula about the way to calculate the dividend.

That, I think, is a mistake.

I think we must keep a certain flexibility because it's not only a question of a short-term calculation.

It's a short term of confidence in the future and what is the vision of the company, and what is the vision and the trust we have in the capacity to deliver additional cash flows.

And this is a way that -- I explained you that in May that the Board of Directors has thought -- has had this long discussion about dividend.

It is a matter of not being too overreactive because we have suddenly a drop in the oil price and a drop in the cash flow.

And when I would apply a percentage of 40% or 40% or 60% and plus, I can make -- I think it's not the right way to manage it.

I think -- so -- and by the way, for the time being, I'm quite satisfied that we took time because price is coming up back to above $40.

And above $40, again, we can maintain our dividend.

And I think this capacity to build the trust with the shareholder is very important in our eyes.

So I would not be -- I will not come back to this type of mathematical formula.

That's not, I think, the best way to maintain to give the vision.

The most important for us is to explain you how we can continue to grow the cash flows in the future coming from oil and gas and electricity.

This we'll try to do it in September.

Offshore wind, okay.

Let me -- I mean, again, there are opportunities.

We are looking more and more again to that.

We are, in particular, looking more specifically to floating offshore wind because we have early come over.

We think there is a big potential.

There are countries where they can have some very good incentives.

We should be able to announce a new one by beginning of September and end of August.

So you see -- so you will see other figures, other gigawatts of offshore wind coming into the picture.

But I don't want to put, to declare a firm target for discipline.

We have a pipeline of solar in Spain, of solar and wind in India, of offshore wind in others.

I think if we begin to constrain all the system, what I can only tell you is that fundamentally, we think that offshore wind is getting very well with the business model of an oil and gas company because we can leverage some competencies from our offshore engineers, which are today working in the industry because there is in offshore wind a capital and clear barrier, entrance barrier compared to solar.

But it's also longer to develop a project.

It can take quite a lot of time to make the studies, to get -- when to get maritime licenses, when to get all the connection licenses.

So I think all that is -- so we see a good field for an oil and gas company to grow.

We have been late to that.

So no, we try to find some potential, I would say, business to develop.

But I think what they observed is that what part of the -- and I should have answered that, explained that also to you, one of your question we had before, I think from Lydia, is that the fact that Total is investing more and more.

We see more and more people looking to our doors to see if we could partner with them.

And in particular, offshore wind, we've seen for example, infrastructure funds, we do not have the technology.

We think that Total could bring this floating offshore wind technology and could be a good partner.

So that's more, I would say, a trend, but no precise figure.

The next question is from the line of Henry Tarr from Berenberg.

Just had one on the growth in low carbon.

I know you've talked a lot about that business today.

But how do you see the most attractive way of growing in that business?

So is organically the best way or you looking at M&A as well?

If you look at M&A, how do you assess the prices in that space?

And I think you referenced earlier that valuations there have definitely run quite hard.

And then have you got all the expertise you need in the company today across those different areas?

Or are there -- is there an area where you would like to add some expertise, whether it's offshore wind or somewhere else?

Okay.

To be clear, in M&A, you have 2 different types.

Something which I think is almost impossible for us is to buy an existing asset with a return of 5%.

I'm not -- so buying, making M&As on existing producing assets, I think, is almost no way.

I'm unsure here, and we are not an infrastructure firm or an insurance company.

So I mean, that's competition, we don't go.

But in M&A, what we have done, like, for example, in Spain, and we have other projects, which we work, is to acquire some pipeline.

We have development companies on the ground in many countries where people are developing, acquiring rights, connecting rights, land rights, and then they don't have the financial capacity to develop.

Then Total is coming.

And this M&A, I can tell you is a few million -- few tens of millions of dollars.

So it has nothing to see.

And this makes sense because, in fact, it's a way to have a sort of nonorganic business development teams.

So we are doing that in Spain.

We are looking to do that in another country, a big country where we are not very present, which is the U.S., because we want -- but then we will develop the projects together with the development team.

So it's, I would say pipeline, acquiring some pipelines might be the right way to grow quicker.

Internally, we have quite a lot of expertise today with all the teams which we put together.

So we are able in many areas to evaluate properly.

I mean the quality of the products are good.

And so with the -- because 1 plus 1 plus 1 plus 1 begin -- we begin to acquire some -- we continue to recruit in that segment because we grow.

So I think we are -- but again, it's more -- for me, the expertise will be mere geographic expertise because the -- like always in the electricity and in this part, the regulation in Spain is not the same in the U.S. So if you want to have teams and you going to develop a renewable business in the U.S., it's better to have some U.S. people in your teams rather than doing that from Madrid.

It will not work.

So -- but it's more -- so this could lead us to make some, I would say, small M&A.

But big ones, no, because it makes no sense from a pure allocation of capital.

And because as well, I think what we can use our balance sheet.

When Total is coming into a project, and part of what we brought to SEC in Scotland is that we were able to get very easy to a very low financing returns.

So we can -- when we put all that financial engineering in place, the Total is quite efficient.

We don't need to be listed as a green company to do it.

We have our balance sheet, which is even better than all these green companies.

Even if we can rebounds in the future to -- which is a way to leverage all that.

This is the objective of Jean-Pierre.

That's great.

Could I just ask a quick follow-up, just on net acquisitions.

So obviously, there's a lot of moving parts in and out.

Do you have a view on sort of where net acquisitions might come out for this year and next?

Are you looking to be flat?

Or...

This year you have under $14 billion guidance for net investments.

And so at the end of the year, you will do the math.

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

I wanted to ask you the following.

So when it comes to the number of customers that you now service in Europe, it starts to become sort of quite a lot.

And I'm not quite sure, I've sort of lost count here, but it's either 8.5 million or 8.5 million plus the other sort of 2.5 million that you just acquired.

And I was wondering what the -- sort of what the attraction of that business is sort of going forward?

Where -- how does it fit in the overall picture?

And the second thing I wanted to ask you is about the returns on Seagreen.

Look, us, sort of we've mostly been looking at oil over the last 10, 20 years, often find it quite a struggle to kind of really appreciate what kind of IRRs are available in the new energy space.

But clearly, you making this investment sort of expresses a view.

At the same time, also your oil price assumptions have come down.

So perhaps you could argue that perhaps the balance of returns in oil versus these renewable areas is moving.

And I was wondering how you currently compare these 2 areas from a -- purely from an IRR perspective.

Yes.

Okay.

The second question, we said already last year that fundamentally, when we have accepted to sanction renewable projects on a target on a double-digit IRR, which begins at 10.

So it's more than 10.

And -- but this is done, this calculation is done on an equity basis because, obviously, there is -- you have to use -- you don't make these PPAs.

Long-term PPAs are financeable.

You can make some project financing, so you have the leverage.

And so by the way, I do not understand the debate which seems to appear in some of the papers that you should be listed as a green company to have access to low cost of capital.

No, you don't need to do that.

I can tell you, it's easy to have access to low cost of capital by project financing when you have a long-term PPA.

And it's even a lower cost of capital.

So I mean, I'm a -- so that's the type of IRR.

Why did we accept it?

Because that's clear also, but this type of projects do not give the volatility.

When I'm investing in a project like this one, I have -- I mean, of course, I'm taking the risk of the counterpart, which is the U.K. government figures.

Should the U.K. government change its mind, it could be at risk.

But otherwise, I have a contract for difference for 15 years.

I know the figure.

So I put it in the figures.

So compared to the oil price, yes, I don't go to the high 15 or 20s.

I don't have the, I would say, the upside, but I don't have the downside as well.

So it's one I was selling.

This, somewhere, this type of business is giving more stability if the business model in the company like the Marketing & Services.

And it's back to your first question, why do we develop in electricity along the value chain because we believe in the integrated business model.

Of course, we will -- so we have some customers, yes, and they are giving -- yes, it's a small margin per customer, but if you have millions of customers, it will grow.

So it's like marketing business.

It's very, very similar, in fact.

But at the same time, of course, we want to grow.

And one of the objectives we have is to produce as much terawatt hour, but we have -- as we will sell.

I want to have an integrated business model.

So we will come back on that in September as well.

But so -- I mean, then do we have an objective in million of customers, we say more than 10.

We are not far from that.

It's not -- it's more a matter of again, finding along this electron value chain taking the money from producing, which will be volatile beyond when you go to a gas-fired power plant less on renewables from trading, obviously, because you have a trading machine in the middle, which will agglomerate your renewable business and then selling to customers.

And again, it's -- at the end of the day, my view is that it's probably the business selling to electricity, gas and electric power business customers, which is the most similar to what we had in the company.

It's not very different.

The next question is from the line of Peter Low from Redburn.

The first was just another one on the criteria you used to determine which oil assets would be classified as standard.

Was that solely based on the production costs and reserve life?

Or did the fact that oil sands or high carbon intensity for production also factor into your decision?

The second was just you mentioned that you're looking to sanction Uganda as soon as possible to take advantage of the current contracting environment.

How much deflation are you seeing in service costs?

And are there any other projects we're looking to accelerate to try and take advantage of that?

No.

I think we are clear about the stranded assets.

It was based not on a, I would say, CO2 content criteria.

It was fundamentally based on an economic approach, which was giving the vision that we put -- that we have on, I would say, a decreasing demand, a plateau and decreasing demand by 2050 and because climate change will be put into action.

And the policies will come, then what could be the high cost reserves, which could be at stake.

And we've done it like that.

So we -- and of course, it has to be long reserve.

So it was above 20 years of reserve, and I think about $25 per barrel.

And so I think with that, of course, when we made, I would say, when I made the calculations about the impairments, we put into action our assumption on CO2 price.

So it had an impact on the impairment levels because we said that we use $40 per ton and then we tested $100 per ton.

So it can influence the impairment -- the results of the impairment came as had embedded the CO2 pricing.

But honestly, there is, I think, no mystery at the end that the stranded assets are the oil sands.

I mean...

Not a surprise.

It's not a surprise to us.

I mean -- and again, that's true, but as well.

So -- okay.

Uganda, we made the tender.

So we'll see what will be the result.

Yes, we want the cost deflation across the whole -- I think what I can tell you is that before last year, we had only 2 consortium bidding.

This year, we have 3 or 4. So a lot of people are looking to order.

So more competition.

We have introduced new competitors, by the way, Chinese ones as well.

And so I hope that I think it's -- probably it will be one of the largest projects which will be sanctioned in the coming 6 or 10 or 12 months.

So I think it attracts a lot of interest of the industry.

And so I'm optimistic.

I think it's -- and that's why we are pushing hard on it.

And we are -- it's clearly a very high priority.

So it will be a test about the appetite from the supply chain and the service industry to get access to this project.

But then again, we have done it recently in Mozambique LNG.

The project team has already worked on, I remember, there were 2 tenders that came to us on service for drilling services, and we did not approve the award of the contract at the Executive Committee levels.

And we say to the team now, these tenders were done 6 months ago or 9 months ago.

The process has been long.

So we don't award anything and you will go back to the market in 3 months, and we'll see what you will get.

And we've done it as well for -- we've done it on all the tenders, by the way.

They are a little unhappy on friends of the project of Mozambique LNG.

But you know we've done it on the LNG tankers.

Same story, and we got a decrease of 10% or 15%.

So I think it's -- that's part of it.

We suffer today from our revenues part, but we have to try to get the maximum benefit from the cost part.

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

First question, just on the $40 Brent outlook and the ability to pay the dividend at $40 Brent.

That also includes an assumption for gas prices and refining margins, both that are probably currently below whatever you're assuming longer term.

So can you just discuss what you are assuming when you say you could sustain the dividend at a $40 Brent?

What those gas and refining -- the gas price and refining margins are that you're including?

It's -- for the U.S., I think, is around $3 or $2.8, if I remember, $2.8 to $3, $2.7, exactly.

For the Asian price, it's around $6.

No, yes, $6, we think.

And I don't want to make a mistake.

I know usually something longer.

And on the European price, I think it's around $5, something like that.

Maybe I'm wrong on the Asian price.

I have a doubt suddenly in my head.

No, I think I'm not so wrong.

I think it's around that.

It's $5 for Europe, I'm sure, $5 for Europe that we use.

But again, and for the refining margin, I think, is around $35 per ton in [MCF].

So I mean...

But let's keep -- you can keep in mind, keep in mind, $40 Brent.

It's enough.

So in the end...

Yes.

Because -- like, why did I answer that?

Because, look, when -- even if the rest is volatile, the things that -- this company is an integrated one.

And so you have plus and minus coming from, I would say, from one part, but the other part is compensating.

So I think -- and this is what is happening this quarter is a good demonstration.

So with a $40 barrel Brent, which is driving, I would say, 75% or 80% of the revenues of the company, you have a good metrics of what we need.

So...

Okay.

That's enough.

Yes.

If I come back to you, and the average price is $41, and I tell you I cut the dividend, you can kill me.

Unless the dollar is at 1.6 compared to euro.

Because there is another assumption which is more fundamental to the $40 Brent is a euro-dollar rate because our dividend is expressed in euros.

And so the euro-dollar Brent rate has obviously an impact.

And -- but again, at 1.1, final 1.2, at 1.25, we have no project.

So it's why I say 1.5, 1.6.

Got it.

And then just a second question on oil price realizations.

It seems like those have been trending lower.

I think, the past few years, you realized something close to 90% of Brent on your oil price realizations.

Last quarter was 88%.

This quarter, it's 80%.

Can you just discuss what's driving that?

And if you expect it to trend consistently at this 80% with lower oil prices or if you expect it to move back towards to 90%?

No, we expect to come back to 90%.

I think there is something which is clearly today.

When you have a very -- market which is very strange, it's not only the number of supply, but it's a very low demand.

Clearly, the marker like Brent might be overestimated because at the end, people have to sell their crude.

There are Nigerian crude, there are Guyana crude, we don't have that, unfortunately, or Asian crude.

And so at the end, you have a weaker demand, which put pressure on the competition in the market, between the cargoes coming from Nigeria, from Angola, from Brazil or from North Sea.

And so what we observed, in fact, and it was well confirmed to us by the traders, which helped, by the way, some trading business around this differential is that when you have a market which is very strange today because on the field of oversupply but lower demand, you can have some impacts on the differential between your crude price that you want to sell and the marker, the Brent markers, the [vertical] marker.

We don't expect that to -- I mean, we think this trend is, I would say, just very linked to the huge drop of oil demand, with dramatic oil demand we have experienced.

When the oil demand will come back to 90% of the pretty to heavy -- more normal way, I would say we should -- this effect, with short-term effect will disappear.

And so we think that we should come back to the more traditional, I would say, it's even above 90%.

The 90% you observed in the first quarter was quite linked to the Canadian discount, the famous oil sands.

We are -- which have an impact despite where we have a lot of beauty in this one.

One of them is discounts, why we are waiting for the pipeline.

Now so honestly, I think you don't take the 80% as a normal.

I mean it would be a -- it's clearly linked to the specific market condition of this quarter.

The next question is from the line of Lucas Herrmann from Exane.

Patrick, 2 quick ones if I might.

I'm not sure how quick the second one is, but the first one, just intrigued that the UAE and the project, there's a very large solar project that EDF was just a part of.

Just intrigued as to whether you'd expressed an interest into that.

And any comments you might make around price and competition.

And secondly, I just wanted to ask how you -- your thoughts around hydrogen and integration into the electricity chain in your business have evolved over the last course of the last 6 months.

The commentary seems much more constructive when I read comments that you've made on the web.

Tell us your observations, please.

Thank you, Lucas.

You observe a lot what we are doing, I say.

Of course, we compete on UAE.

We win in Qatar, we lost in UAE.

There is a certain limit, I mean.

This -- honestly, these projects in the Middle East are big, but if we're competitive I would say, and the profitability.

Again, I answered to Martijn I think before, but there is a certain level under which we don't go.

So we don't go at a certain level, that's all.

So we win in Qatar with that level.

We didn't win in Abu Dhabi.

And if we win, that's life, I think.

And -- but honestly, I think if you want -- there are other places -- what I observed in the Middle East, they are offering very large projects, so you make volumes.

It's a little like oil, by the way.

I can make a sort of parallel between the way the business is developed in the mid -- in the oil business, you have very large fields with low margins.

And in solar business, very large fields, but low business, low margins as well.

So you have other places like India or Spain, which results are -- returns are better.

But again, we are competing, and we'll continue to look to other countries.

We participated as well to the tenders in Saudi Arabia.

We did not win again with it.

Hydrogen, I think hydrogen clearly is -- everybody, I think, is looking to that.

It's not an easy topic because the question mark you all have today is how much capital allocation should we put in that.

There is a very clear logic to me, but the bigger will be in the renewable business.

And so if we have more renewable capacity of production, then there is a certain logic to be -- to try to produce hydrogen simply because you have other capacities that you don't sell to your PPAs, which could be transformed in hydrogen.

So there is a clear link between growing in renewable as a renewable producer and trying to make green hydrogen of the overcapacity, which is not sell for your PPA.

So that's an obvious link, which is -- having said that, all that is then a question of economics, how much -- at which price can you develop your green hydrogen?

So we have this interest on this one.

We are looking as well, of course, as hydrogen becoming a way to green the gas, natural gas, to inject hydrogen in the natural gas because it's a storage, it's a carrier, I would say, an energy carrier in hydrogen.

So this is again an option which, of course, as an interest for Total, We have a very large gas producer, gas sellers.

So we need to think to hydrogen in a way to -- and I wouldn't be surprised, for example, but in Europe, we could see some policies and regulations asking us to inject some percentage of hydrogen and biogas in the natural gas network so to decarbonize the gas, I would say.

So that's something on which we need to work.

And of course, the last part will be hydrogen as a mobility carrier.

On this one, we need to look more carefully.

Clearly, you have the trains maybe on the vessels.

But all that will be a question mark, will be at which pace all this hydrogen economy will be developed.

And this is why I'm thinking fundamentally that if we want to develop it, we'll do it through a low-cost hydrogen.

I don't think we'll develop it with something which would be expensive.

So we are working on it.

We have a team, by the way.

We have [committed] team.

And we -- but we are -- I'm less advanced today, but we are on the low-carbon electricity renewables because we have less projects.

So in our plants, we want to operate a green hydrogen project to supply one of our refineries with green hydrogen.

We are working on it.

And we are also working on a blue hydrogen project to capture some CO2 from SMR in one of our refinery and then to make a full chain, I think blue hydrogen and to reinject the CO2 in an offshore field.

So we are working on 2 projects, I would say for the next 5 years, but fundamentally, where we want to allocate capital to be involved.

And remember that as well, Total is one of the foundation shareholder of the H2Mobility network in Germany.

And so which is a country where today, there is a stronger push in Europe for the hydrogen development.

So it's good to be as well connected to Germany from this point of view.

And the next question is from the line of Jason Kenney from Santander.

Can you remind me of the carbon pricing assumptions that you're using, particularly in light of the rethink on your oil and gas pricing?

I'm just wondering if there's been a change in the carbon assumptions by 2025, 2030.

It's $40 per ton.

$40, 4-0.

And just flat real terms?

No, it's not.

It's 100.

It rises to 100.

No, it's 100 beyond 2030.

I was answering to Jason between '25 and 2030.

So this was a question of Jason, if I understand.

And I think it's real term.

I'm sure it's real term actually.

I don't think.

I'm sure.

For 2025, if you want to know everything or from 2028, so $40 per ton.

And the dollar per term beyond 2030.

Jason, it was your last question?

Yes, that's it for me.

Okay.

And there are no further questions.

So I'll hand back to the speakers.

Good.

So you are lucky because I didn't push a wrong button this time to stop the discussion like last time.

So thank you for all your questions.

And I think I'm happy to be in road with Jean-Pierre to answer to you, and thank you for your comments.

We will have, as I told you the next meeting that we we'll have with you is in end of September.

We think that we'll have 2 sessions end of September.

You have already been invited, I think, to -- on the 30th of September, it will be the strategic session.

It will be on one day.

It will be in Paris or virtual, but if you can come to Paris for the European ones, you will be welcome.

We will take all the precaution that we need to take to invite to, of course, to have you with us.

If you are there, we'll be able to have also a live discussion.

We intend to have, I would say, that day, I think we'll have the strategic presentation like our custom and probably some focused presentation in the afternoon on different topics, biofuels.

And you will see -- I mean we are preparing that.

And the day before, we are planning, and I think we'll be inviting you to have a sort of market views.

We have -- in February 2019, we presented you what we call the Total energy outlook.

We have spent some time to Helle, in fact, Helle Kristoffersen have spent some time with the teams to develop our new vision.

We have introduced a number of things.

And we intend to present that virtually by a virtual presentation so that everybody can be connected on the afternoon of September 29.

It's not directly linked to the strategy of Total.

It's a broader view of the market of the oil, natural gas and electricity market.

Of course, like we can have a vision by 2030, '40, '50.

So long-term vision, of course, and I think it's good for Total to develop and to share with you our own vision of the market.

So Helle will lead that presentation on the afternoon of September 29, virtually, again, not in person.

But on September 30, we'll have this strategic outlook, and we -- and so you will have more answers to all your questions.

So I wish you good holidays for the one who will take.

We are taking holidays because we are a little tired after 6 months of being closed in Paris and office is complex.

So happy day.

Happy holidays to all of you, and stay safe and see you in September.

Thank you.

Thank you.

Thank you.

That does conclude the conference for today.

Thank you for participating, and you may now disconnect.