TotalEnergies SE (TTE) 2019 Q2 法說會逐字稿

Good afternoon, ladies and gentlemen, and thank you for standing by.

Welcome to today's Total Second Quarter 2019 Results Conference Call.

(Operator Instructions) I must advise you that this conference is being recorded today, Thursday, 25th of July 2019.

I would like to hand the call over to your speaker today, Patrick Pouyanné.

Please go ahead.

Good morning, everybody.

I am pleased to join the call today.

It's not every quarter, but it's a special occasion for the last conference call by P2 and as well for the first conference call with Jean-Pierre as well, our new CFO, which is joining to start the transition.

In fact, this transition has been organized and planned for quite a number of years, Jean-Pierre being the Treasurer before becoming Deputy CFO.

It's also -- I think the time is also right for us and for myself to comment on the acquisition of Anadarko's African portfolio as the merger between Occi and Anadarko is planned for August 8.

The format today will be the following.

P2 and Jean-Pierre will present the results, and then I will comment on the Anadarko deal.

And then we will go to the Q&A session.

Just a few words of introduction.

Since 2015, we have taken broad steps to move Total to become the best-in-class energy company.

And the second quarter results continue to demonstrate this with revenues and, more importantly for all our shareholders, cash flow growth, plus 10% with the same level of production as previous quarter.

The Anadarko assets will contribute to replenishing our resource base and clarify the outlook for the coming years.

And the way forward is now clear to us until 2025 at least, and it will be the theme of our September strategy presentation.

Moreover, this transaction, which is cash additive and cash accretive in dollars per barrel, will allow us to continue to actively manage the portfolio.

Let's be clear, it's not a matter of volume growth for us, but it's a matter of value creation for all our shareholders.

This is why we will sell at least $5 billion of noncore assets over the 2019/2020 period to continue high-grading the asset base, which is consistent with our fundamental goals of keeping our discipline and balancing profitable growth and balance sheet strength with improving shareholder returns.

I will come back on our objectives on this matter at the end of the call.

So now I turn the floor over to Patrick for the results.

Thank you.

We reported, I would say as usual, solid second quarter results that demonstrate the resilience of our portfolio and the benefit of our best-in-class production growth despite an adverse environment in term of gas prices and refining margins.

Adjusted net income was $2.9 billion or $1.05 per share, an increase of 5% quarter-to-quarter.

Debt-adjusted cash flow increased by 10% compared to the first quarter to $7.2 billion.

Organic free cash flow was up by 13% in the second quarter to $3.7 billion and up 9% year-to-date to $6.9 billion.

The pre-dividend cash flow breakeven remains very low at less than $25 per barrel.

The second quarter environment was marked by continued volatility.

Brent was at $60 per barrel in June, down from a high of $74 per barrel in April.

And in July, it has been regaining strength with support from OPEC and geopolitical tensions.

Natural gas prices, notably NBP in Europe and spot LNG in Asia, have fallen sharply in a move that we attribute mainly to mild weather in the face of ample supply.

European refining margin were down in the second quarter but have recovered in July.

Then petrochemical margin have remained fairly stable quarter-to-quarter but are weaker year-on-year.

In this context, we are continuing to reduce costs, and we are on track to increase production by more than 9% this year.

Egina, Kaombo, Ichthys, the major drivers for cash flow growth this year, are online and ramping up.

Culzean started in June, and we expect Johan Sverdrup and Iara 1 to start by year-end.

Production is up by 9% year-to-date, as anticipated.

Looking forward, we sanctioned the second FPSO for Mero in Brazil in the second quarter.

And at the start of the third quarter, we sold for $635 million some nonstrategic North Sea assets that we acquired with Maersk Oil.

So we are continuing to grow and to high-grade the asset base.

The E&P segment, and I remind you this E&P segment no longer includes the integrated gas activity, generated adjusted net operating income of $2 billion in the second quarter, a 17% increase compared to the first quarter.

Higher liquid prices had a much larger impact than the lower gas prices, mainly domestic gas prices in E&P.

Production growth from start-ups was largely offset by maintenance in second quarter, notably in Nigeria, Norway and Canada, so volumes were basically flat quarter-to-quarter.

Cash flow from operations before working capital increased to $4.9 billion, up 15% from the first quarter.

I remind you that the new start-ups have higher DD&A.

You can see this in the accounts.

So there is more impact on cash flow than on the income itself, and the positive impact on the cash flow is very accretive in dollars per barrel.

Turning to iGRP segment.

This cash flow effect from new start-ups is more evident.

Cash flow from operations before working cap increased to $0.9 billion, up 77% quarter-to-quarter, thanks mainly to the ramp-up of Yamal LNG in Russia and Ichthys in Australia.

So these massive projects are starting to deliver cash.

Adjusted net operating income in the second quarter was $0.4 billion compared to $0.6 billion in the first quarter, reflecting mainly the lower gas prices as well as the higher DD&A.

Taking into account the addition of the Engie LNG portfolio and the strong ramp-up compared to a year ago, production increased by 63%, and LNG sales have more than doubled.

iGRP is our fastest-growing segment.

During the second quarter, the first train at Cameron LNG started, and there are 2 more coming.

In addition, we agreed to take over Toshiba LNG portfolio, which came with a payment to us for $800 million; signed a long-term sales agreement with Guanghui in China; and of course, agreed to buy the Anadarko assets, which includes Mozambique LNG.

iGRP nonintegrated gas activity, mainly renewable and batteries, were also profitable in the second quarter.

Total solar started up its second solar farm in Japan in June, and we are building a foundation for the future of the company across the energy spectrum, and iGRP is at the center of this effort.

Before I turn the floor over to Jean-Pierre, I would like to say that I have enjoyed and I am still enjoying my interaction with the financial community, with all of you, and I thank you for that.

Jean-Pierre, this is for you.

Thank you, Patrick.

So let's move to the Refining & Chemical segment performance.

So for this segment, adjusted net operating income was $0.7 billion in the second quarter.

That means a decrease of 5% compared to the first quarter.

European refining margins were down 16% quarter-to-quarter.

Operationally, our refinery in Germany, the Leuna refinery, had to reduce throughputs due to contaminated crude from Russia.

There was a shutdown at the Grandpuit refinery in France and some normal scheduled maintenance as well.

As a result, refinery throughputs fell quarter-to-quarter by 14%, and capacity utilization decreased to 77% from 89%.

Now Leuna and Grandpuits are back to normal.

Despite the lower margins and lower throughputs, R&C generated $0.8 billion of cash flow from operations before working capital in the second quarter.

First half cash flow was stable compared to last year at $1.9 billion.

For Marketing & Services, adjusted net operating income was $0.4 billion, an increase of 23% quarter-to-quarter.

Cash flow from ops before working capital for M&S was $0.6 billion in the second quarter and $1.2 billion for the first half, representing an increase of 12% year-to-year.

So now for the combined Downstream, I mean R&C plus M&S, cash flow from ops before working cap was $3.1 billion in the first half, an increase of 3% compared to last year and ROACE was 24%.

I will come now to the group results.

So at the level of the group, debt-adjusted cash flow was $13.7 billion in the first half, a 10% increase compared to last year.

As P2 already commented, this is a result of strong production growth more than offsetting lower hydrocarbon prices and lower refining margins.

So we are on track to grow cash flow progressively year-over-year as our new projects continue to ramp up.

A few comments on gearing.

So at the end of the first half, the gearing was at 20.6%.

Obviously, there is a slight increase from the first quarter, and we are a little above the guidance of 20%.

But I would like to remind you 3 elements.

So first one is that we made 2 dividend payments in the second quarter.

And in the third quarter, no payment will be done, and so we have cleared the situation.

And in the future from the Q4, we'll have one payment per quarter.

The second element, of course, as you probably noticed, is we increased the working capital.

We have an increase of $0.3 billion this quarter, and we are working to reduce this working capital in the future.

And the third element, of course, is the implementation of the IFRS 16 that has a negative impact on the gearing at 2.7%.

Buybacks were $0.4 billion in the second quarter or $0.76 billion year-to-year, in line with our target of $1.5 billion at $60 per barrel over this year.

Net investments were $6.5 billion for first half, in line with last year.

Finally, in terms of profitability for the past 12 months, the group ROE was above 11% and the ROACE was above 10%.

So now I turn it back to Patrick, P1.

Thank you, Jean-Pierre, and thank you, Patrick.

So I wanted to come back, as we announced it, and give you an introduction on the deal with Occi that we signed in May regarding the Anadarko African assets.

Basically, at that time, it was, in fact, when we announced it beginning of May, just an option as we did not know what would be the outcome of the Anadarko battle.

We did not comment on it until now because this option is obviously subject to the completion of the merger between Occidental and Anadarko.

And -- but even if it's not yet completed as the Anadarko AGM is announced for August 8, I took the opportunity of this call to comment this production transaction today.

Similar to the Maersk and Engie deal, thanks to our GDP, we managed to create an opportunity which obviously was not very obvious at the beginning and so it came clearly as a surprise.

But this opportunity fits exactly with our strategy by playing to our strengths.

I really would like to insist on these points.

It is because we are very clear about our strategy in oil and gas, which is playing to our strengths primarily, but together with our Board of Directors, we could act very quickly to have access to these high-quality assets.

We see these African assets of Anadarko are really a portfolio -- a world-class portfolio of assets in our African stronghold, and we have accessed them at a very attractive price, more than 3 billion barrels of resources for less than $3 per barrel; 100,000 barrels per day of current production, increasing to 160,000 barrels per day by early 2025; free cash flow positive from day 1, including the Mozambique CapEx; and free cash flow growing to more than $1 billion per year from 2025 with the Brent at $50 and next to $1.5 billion of free cash flow at $60 per barrel for Brent.

Strategically, the Anadarko assets essentially light the way to better navigate the coming years, so (inaudible) Mozambique Area 1 LNG, for where we will become operator with 26.5%.

This project is derisked with the FID which has been taken in June for the first 2 trains at a competitive cost of $850 per tonne and will represent 12.8 million tonnes per year of LNG production that is already sold under long-term contracts for 90% of the volume.

We know and we respect the Anadarko team, project team, and we have confidence in them.

And as per our purchase agreement, Occidental is taking actions in order to retain the team at our request.

The first 2 trains developed less than 1/3 of the available resource, which are estimated globally at more than 60 Tcf.

So Mozambique LNG will provide us high-return brownfield expansion opportunities into the future.

And last but not least, it comes and complements our LNG portfolio.

Total is now the second-largest player in this fast-growing LNG market, and adding this giant resource in East Africa will obviously create significant portfolio synergies for us.

Regarding the Mozambique valuation, I would like to raise your attention on 2 figures.

We'll pay around $150 million per percentage of working interest for these assets, a little around $4 billion for 26.5%.

So $150 million and -- for these assets and resource, and we buy them right at a time when sanction is taking place.

So it's derisked for the first trains.

The Exxon/ENI transaction in 2016 was at $110 million per working interest but still some work to be done before sanction, which is not yet taken.

On Area 1, our license, all transactions which took place between 2012 and 2014, PTTEP/Cove Energy, [ONGC Videsh arm], ONGC/Anadarko, took place at between $200 million and $260 million per percentage of working interest.

So to be compared to us -- 2012/2014 to be compared to a price -- or value of $150 million.

So I definitely strongly argue that this transaction is done at attractive conditions and well in line with what we described as a countercyclical strategy that we put in place when we acquired the Maersk Oil company.

We know that there is a WoodMac paper, but it values only the first 2 trains, and anyone who is using this alone is grossly undervaluing these one-of-a-kind assets.

Again, to be clear, this is the operatorship for a giant LNG project that is already under development with its first 2 trains sold on long-term contracts and a lot more sizeable resource yet to be developed in the future.

This asset is really unique and fits perfectly with our strategy of clear set and our asset base.

The Anadarko portfolio in Africa also includes currently producing assets in Algeria, specifically where the operatorship and additional oil -- and additional 24.5% interest is blocked in the Berkine basin, where we are already present with a 12.5% interest after the Maersk Oil acquisition.

So we can anticipate some efficiency gains there.

And these blocks are currently producing more than 300,000 barrels per day.

In addition, the acquisition expands our presence in offshore West Africa with deposit fields in Ghana, notably 27% of Jubilee and 19% of TEN that are currently producing more than 140,000 barrels per day.

And we continue to ramp up in the years ahead, which is an area where oil traders in particular can add some value.

For these 2 assets, we will pay the $60 per barrel value, which is fair and attractive.

Finally, we will get also some exploration license in South Africa near our recent Brulpadda discovery.

May I add that beyond the asset's revenues, we are expecting additional profits come from the trading business, which will be developed around them, either for LNG or for oil trading.

We intend to take some LNG from Mozambique LNG projects, which will complement our worldwide LNG portfolio.

With a location in the Indian Ocean, well located to serve customers in India where we are currently developing a position with the Adani group and in Southeast Asia.

Our oil trading arm, which is the largest trader of African oil, will also benefit by having access to Ghana oil from its arbitrage capacity and for developing relationship with GNPC, the Ghana national company.

Another important price -- point that I'll also mentioned is that this portfolio -- when we consider the portfolio of these 3 assets, it will be -- portfolio will be additive to our cash flow and accretive to our cash flow per barrel.

The cash flow coming from Algeria and Ghana producing assets will more than cover the CapEx required by the Mozambique project, so breakeven is less than $40 per barrel.

We will generate around $300 million of free cash flow between 2020, 2023 at $50 per barrel, and then it will increase to $1 billion at $50 and next to $1.5 billion at $60 per barrel when the 2 trains of Mozambique LNG will be onstream.

As I said, the acquisition, like the others we've done, plays recently -- plays to our strengths: Africa, deepwater, LNG; and fits to our strategy to continue high-grading the asset base and to reduce our breakeven.

It gives clarity on our 2020/2025 profile.

The Anadarko assets will increase our 2P reserve life to well above 20 years, which we consider is more than enough.

So this ensures reserve replacement and provides flexibility for active portfolio management.

Once again, our priority is not volume growth but value growth.

So we will take benefit from this growing production coming from Anadarko assets, 100,000 barrels per day growing to 160,000 barrels per day, to sell some noncore and higher-breakeven assets in order to focus our teams on the most profitable assets on our portfolio and also to continue to lower our global breakeven to be more and more resilient.

This is why we announced that we'll divest at least $5 billion of assets with the majority, more than $3 billion, coming from Upstream on this period -- on the period 2019/2020.

It is part of the necessary discipline linked to our capacity of being agile to seize opportunities.

We have demonstrated since 2015 our discipline on costs.

We have today the lower OpEx per barrel among the majors, $5.50 per barrel; and on profitability, the better return on capital employed while, at the same time, we have been able to grow by taking countercyclical opportunities.

While most of our peers concentrate their CapEx spending on U.S. shale, we are looking to the rest of the world and have been first to move in Brazil on Maersk Oil and Libya on LNG portfolio and now on Anadarko African assets, but always in the framework -- in a disciplined framework we've set to ourselves.

When we will close -- we close this deal in the coming months, it might be possible that some of the assets could be closed in 2019 as we agreed that we could close the assets on a staged manner according to the various approval process by the different countries.

Our gearing will increase temporarily by 4% and rise to 22%, 23% at $50 per barrel.

And consistent with our guidance that I reaffirm today under 20%, we'll reduce debt and restore our balance sheet strength, firstly, because we are continuing to deliver strong cash flow growth as this quarter demonstrates, and there is more to come for the next 3 (sic) [2] quarters in 2019, up 10% year-to-date.

And this acquisition will again be additive to our cash flow.

And second, because we also confirm at the same time -- it's why we can confirm at the same time our 2018/2020 shareholder return policy is not affected by the acquisition, maintaining the 10% dividend increase we announced in February '18 and the $5 billion share buyback with Brent at $60 per barrel that we are clearly implementing and delivering quarter after quarter.

We will go into more details obviously about allocating future cash flow growth at our Investor Day in September.

On investments -- some comments on investments.

You should not expect significant changes going forward largely because even as we grow the portfolio, the organic CapEx is more efficient, and we do more for less.

Since the start of 2015, we have sold more than $16 billion of assets.

So we have demonstrated our capacity to execute our sales program in a disciplined manner and our commitment.

And we will continue to execute it in the same way with our new program for 2019/2020.

We recently announced that we sell some mature North Sea assets earlier this month, and so the high-grading will continue.

Net acquisitions on average over the years have been and will be continued to be managed at a disciplined level, consistent with our goal to combine profitable growth in targeted markets with a strong balance sheet and competitive shareholder returns.

We intend to confirm in September our guidance for CapEx investments, which means organic CapEx plus acquisitions minus sales.

For the period 2019/2023, we should confirm $16 billion to $18 billion as our guidance -- the range of guidance over this period.

And obviously, including the Anadarko acquisition on the combined next 2 years, 2019/2020, it will be closer to the high end of this range.

Total is best in class among the majors, in large part because we have moved faster to recognize and capture some M&A opportunities.

These have been key to lowering the breakeven, improving our resilience, shooting profitable growth.

Given the fundamental nature of our industry (inaudible), we believe a sustainable shareholder value is created over the long term by making disciplined investments, not by avoiding them.

The Anadarko assets are mainly gas, LNG, and we believe in the transition to gas for power generation, particularly with LNG.

So with acquisitions, that's also to take us further into the future.

As a conclusion, I will say that we clearly consider that is a very compelling opportunity to high-grade the asset base with unique world-class portfolio of assets, and we are confident that the value creation will be evident to all our shareholders in the years ahead, like it is with Maersk Oil and Engie.

We'll come back on that in September.

So now we are ready, I think, to start the Q&A.

(Operator Instructions) The line of Irene Himona from Societe Generale is now open.

Thank you very much, Patrick, for your support over the past decade, and all the best in the future.

I had 2 quick questions.

So firstly, on tax.

Group tax this quarter was particularly low but then there are different moving parts in there.

So the tax rate in Marketing & Services in particular is quite high this quarter, and then you continue to have tax credits in corporate.

I wonder if you can give us a sense of any unusual tax items this quarter and what should we anticipate for the rest of the year.

And my second question -- you had mentioned before, I believe, possibly at the Q1 stage, that you would give us some sensitivity to natural gas prices.

I wonder if that is something you're able to do today perhaps.

Sure, Irene.

As usual, I have a question about taxes with you, so we were prepared to answer that question.

Actually, tax rate was quite low this quarter, you were right.

It is not only the fact that oil prices was lower than previous quarter, which is part of the answer, but this is not only that.

In the E&P, we benefit from the Kaombo Sul start-up with a large uplift mechanism, if you remember those mechanism in that country.

In Downstream, we benefit also from a $50 million capital gain on Wepec sale with no tax.

But on top of that, June is a time for us to reconcile our tax estimate made end of the year and the actual number that we have by end of June.

And then in the Downstream sector, we offload one provision that we add on the Downstream provision on taxes, which was put in place previously.

That's my answer on taxes.

Sensitivity to gas price, that's a difficult question.

On 100% of our production, oil plus gas, 75% of it is linked to the oil price.

So let's have a look to the 50% production coming from gas.

Then you have on this 50%, 50% of it, oil linked; 20%, 25% of it, linked to the spot prices, NBP in the U.K. and in Continental Europe.

You have about 20% of prices linked to domestic prices that you have, for instance, in Thailand, in Burma, in the U.K. or in Norway.

No?

No, it's not in U.K. -- in Argentina, sorry.

And that's basically -- and the remaining part is 5% to 10% on Henry Hub.

So even if I'm not fully able to answer your question with full exposure to the different type of gas prices, I think you could figure out what could be our sensitivity.

The line of Oswald Clint from Bernstein is now open.

Patrick, thanks for all the comments on Mozambique.

I just wanted to ask around Mozambique kind of what your thoughts were about actually delaying the -- or actually, you seemed -- if you could re-tender and perhaps get a cheaper construction cost for that plant.

Or if that wasn't possible, your thoughts around sharing some of the onshore work with the Exxon/ENI project as well.

If you could just discuss that side of it.

Is that something that could happen at least from a sharing perspective after the FID of the other project?

And then just linked to Mozambique, you kind of gave a throwaway comment about South Africa.

And I just wonder, was that a throwaway comment or is there something interesting really about this deal?

Have your geologists looked into the Anadarko block and see some type of extension of the success you've had in your own block in South Africa?

That's my first question.

And then secondly, maybe one for the chief financial officers.

Just looking at your Gas, Renewable & Power business and just starting to look at the unit cash flow margins, cash flow per tonne that you're starting to generate here as you split this business out, and you're making around $100 a tonne this quarter.

And I'm assuming there's not very much for renewables or power just yet, but as I think about Cameron and Toshiba and Tellurian coming in, which is difficult for us to model, but also Yamal kicking onto oil-linked contracts over time, just trying to think about the accretion or dilution of that number.

Should we think about this $100 a tonne as a sustainable number?

Does some of these North American contracts coming in perhaps dilute that number?

Or some of your oil-linked contracts coming in, it kind of stays about that number?

That's -- I'm just trying to get a sense of what happens to that unit margin.

Okay.

For Mozambique first.

Let's be clear, our intent -- and this is one of the interests of this project, it has been derisked, it was sanctioned, contracts have been awarded to Saipem and -- mainly.

And we are fine with the way that the project has been engineered and designed.

The teams of Anadarko which is managing the project is a team which builds for BG in the past, most of them, the Queensland project, and it was done with conditions in the end.

So we did not intend at all to re-tender anything.

We want to move forward.

We trust that -- of course, we trust the job has been done properly.

So that's the first point on the project for itself, and it's important in terms of value creation.

We don't want to derail.

We don't come there to put another delay on the project.

The second point, on the same time, yes, we understand -- and I had already an exchange of views with Darren from Exxon.

I think there is probably things to be done onshore.

By the way, there are shared facilities onshore, according to some agreements, and we know we have an experience to potentially discuss and share facilities like in PNG with Exxon.

So I'm very open to that.

As I said to Darren Woods, if it's a matter of efficiency Total is always there to discuss about efficiency.

It's not a matter of ego.

If we can't operate the train, we'll see.

But if we can be efficient together, I think we have joint interest obviously.

It's a long-term story.

It's a form of -- actually, there is more than 120 Tcf, 60 Tcf per area.

So we are speaking of something for the long term.

So it would be good like we have done it in the past in Qatar to be smart, to give us -- I'm very open to that but, of course, without derailing the first 2 trains which will be built according to Anadarko plans.

So there is your second point.

And on South Africa, I mean, let's be clear, it was not a core asset when we buy the portfolio.

I can tell you we spent some time on Mozambique.

We spent some time in Algeria.

We had the data.

We understood the Ghana story.

South Africa was part of it obviously.

[And they] wanted to sell the whole portfolio, and we took it.

But in the meantime, we had a good -- we have access to some data.

We also have the good news because Shell has joined this license.

So it means that it has some interest.

It's not -- it's in the clear vicinity from Brulpadda, so it's exactly the same thematics.

So it's exploration, quite at early stage.

But -- and honestly, it's -- I would say it's an add-on in the acquisition.

It did not impact the price of the acquisition by itself.

But having said that, just to -- I can't just give you an information.

We will be clear on a new prospect in this license next to Brulpadda next year, so we are not operating the first one but going to find -- try to find more gas in vicinity in Brulpadda discovery to try to know how much we have in this license.

So for your questions about dollars per tonne in the middle of something moving, I think I would answer, but it will be better tomorrow, always better.

But I will give the floor to my financial -- my 2 CFOs.

So P2 is ready to answer.

Well, partially actually, because I'm quite tired, this is my last call.

Two elements on iGRP.

First, Ichthys and Yamal are cash accretive, and the volume is going up.

We are ramping up both project.

This increased the cash flow.

On the other side, very high -- well, quite high DD&A because we just started up the assets, and the effect of the lower gas prices had a negative effect on the net operating income coming from iGRP.

But you have to know that our low-carbon electricity business is profitable, is making around $150 million this quarter.

That's basically the information I can give you.

I know this is not sufficient, but I'm sure Jean-Pierre will be able to answer in more detail in September.

Yes.

Just to come to that.

Obviously, as we have created iGRP, I think you'll have more granularity on LNG.

Remember, in February, we gave you more detail.

We'll come back on it.

It's becoming a very important part of the business portfolio, the production as we are doubling the volumes.

We will average next year 20 million tonnes, and more to come in reaching -- by 2025, we'll be around 50 million tonnes in our portfolio.

So I understand why you asked the question.

Remember what we told you, I think it was in February or September, but we target a free cash flow by -- CFFO, sorry, yes, CFFO by 2020 of around $4 billion in that segment.

And like Patrick said, Yamal, we started Yamal early, but the early volumes were going on the spot market in Europe.

Now since this quarter, we have activated the long-term contracts, which are oil-related contracts.

So it's much better.

And so we will have good news from this point of view in terms of cash flows.

I will not add on the comments on net results.

Okay.

The line of Thomas Adolff from Crédit Suisse is open.

A few questions for me, please.

Firstly, correct me if I'm wrong, but I believe your investment criteria is a minimum of 15% IRR at $50 per barrel Brent, and I wondered whether the African deal actually meets this criteria and whether you will also be subject to capital gains tax in Mozambique.

The second, you have so many LNG projects in your hopper.

I don't even know where to begin.

Maybe you want to comment how large a player you are likely to be by 2030.

And then, finally, you've mentioned improving shareholder returns.

Specific on the $1.5 billion buybacks you are doing, do you think that's sufficiently attractive?

In fact, if you look at the overall distribution policy, do you think that's sufficiently competitive, especially as you look out to 2021 plus?

Okay, Thomas.

First, you know that for -- we use strong criteria for LNG projects.

We don't use the IRR.

We use enrichments mostly because they are very long-term projects, and we look to the level of enrichment in capital rather than the IRR.

By the way, LNG projects with the 16% return, I don't think there are many projects like that because it's very capital-intensive upfront, but value creation is on the duration because you have long plateau.

That was the first point.

The capital gain tax, let's be clear, most of the capital gain tax will be carried by Occidental according to the purchase agreement we signed with them.

Secondly, on energy project, yes, we have a large portfolio.

That's clear.

But this is the only segment of the hydrocarbon industry which is really growing quickly, 10% the last 3 years.

So everybody is planning at least 5% in coming years.

I think our large portfolio allow us as well to be a -- I would say, more patient on some projects when we have to negotiate.

We know that sometimes in our very large projects, but in different countries you could have sometimes to be patient in order to obtain the right condition.

And -- but generally, the execution of the projects could face some scheduling compared to the ideal time table.

So I think it's better to have more opportunities in this growing segment than not having enough.

We have.

And we can potentially arbitrate if some of them do not fit with our return thresholds that we have in mind.

Then on shareholder returns.

It's not only a matter of buyback.

When I'm [refusing] to shareholder returns, we look to dividend first and plus the shareholder buyback.

And that's true, when the -- that we were -- we had -- we asked in February '18, the Board of Directors have reviewed all our policy, have decided that we need clearly to be more competitive and growing our returns from something which was mainly 30%, I think, of free cash flow to more or targeting more 40%.

So -- and to do that, we used 2 tools.

One is growing the dividend.

And according to my discussions with my and your investors, they love the growing dividend first, it's their first priority each time I'm asking the question.

So we do it.

We do it regularly.

And you all know that we never decreased the dividend in Total for 30 years.

It's in the DNA of the company, and I repeat that and so we will continue to grow it beyond 2020 even there is a -- we gave a sort of good guideline by giving 3 years in advance the increase.

But obviously, we will continue beyond it because our cash flows will grow, and the deal of Anadarko will help us then to grow.

So it's a good news for all shareholders.

When I'm announcing that the only deal of Anadarko will give more than $1 billion at $50 per barrel of additional cash flow by 2025 and $1.5 billion, $60.

We'll not keep this cash flow just to us, a part of it will be returned to our shareholders.

So first dividend, then the buyback.

We are -- we use buyback in order to share with all shareholders the additional revenues what we get beyond $60 per barrel.

And last year, we've done $1.5 billion buyback instead of the $1 billion announced because the price was higher, the average price of the year.

This year, we are not far from being there at $60 because the gas price is lower than the liquid price, and so we have executed since the beginning of the year with the program and we monitor that quarter-by-quarter.

And my commitment is, obviously, as I described, I think the full shareholder return policy with these comments, and we'll execute the program.

And then beyond it, it's a decision which will be taken with the Board of Directors.

But again, dividend growth first and global retail targeting something in the range of -- something around 40%.

You can keep that as a guideline.

The line of Lydia Rainforth from Barclays is open.

Two questions, if I could.

Firstly, on the $5 billion divestment program, how are you looking at what the criterias of those assets will be which is what you're looking to sell?

And then secondly, can I just follow up on the CapEx number where you talked about that being $16 billion to $18 billion.

Is that simply a reflection of the net acquisitions?

Or has the organic number, or were you looking at a slightly different organic number to what it would have been without the Anadarko assets?

No.

I will not tell you what is the list of assets.

Sorry for that, just because that's never been the policy.

The criteria are clearly as I mentioned in my speech, either noncore.

We have -- one of the characteristics of the E&P portfolio of Total, we have quite a -- people in a number of categories and sometimes for small production.

And so it absorbs some human resources, and one of our objective with Arnaud Breuillac, the President of E&P, is still he is trying to refocus on maybe less countries.

So if we can exit some few countries, we have a list of countries, small countries in terms of, I would say, revenue and production where it will depart.

And the second criteria is high breakeven assets and those are one like we've done in the mature fields in North Sea.

We have sold a little production.

Again, I'm not afraid at all to sell some production.

We have some margin, right?

It's not at all volume-driven.

So these are the 2 main criterias.

And then in the Downstream, we will continue to sell all these infrastructure.

With P2, we were thinking in 2016, we had the list, but we are discovering some piece of pipeline, piece of infrastructure, which, frankly, we do not need to own.

We need to have the rights of transportation of our gas, of our liquids.

So we have still some these type of assets.

And that is last still, but you can -- that I can mention, which is important.

In our policy regarding renewables, it's clear we described -- we began to describe to you in February the business model about renewables, which is a business where we invest in some assets.

We took the risk of completion of the COD, and then we will divest at least 50% of it because they are considered by infrastructure firms.

And at the end, we'll keep 50%.

So we begin to have quite an interesting pipeline of these type of projects with the various subsidiaries we are working.

And so we'll be in position also to divest part obviously renewable assets in the coming -- in this year since from 2019, it will begin.

Then Lydia, sorry, we joke together.

But sometimes, I have difficulty to understand your English, but I think today, you -- I really understand, but it's very difficult to understand the English of a French man.

So I will repeat what I told just before very clearly and loudly about CapEx.

What I said during my speech, I was speaking about CapEx investments, which means organic CapEx plus acquisitions, minus sales.

So it's organic CapEx plus net acquisitions minus sales, to be clear.

This, I guided you, but we should confirm in September, so consider that I should then will see something would happen between today and September, but it's because we are taking some time, but nothing will happen, let's be clear.

I'm going 40 days, likely to, nothing will happen.

So we should confirm $16 billion, not $15 billion, $16 billion to $18 billion for this aggregate on the period 2019-2023.

This is what I told you, and I did.

But for the combined 2 years, 2019-2020, including the Anadarko acquisitions, we will be closer to the high end of this range, $16 billion-$18 billion.

I hope I have been better in English now than before.

The line of Christyan Malik from JPMorgan is open.

First of all, just on -- for the cash margin evolution of the new projects, including Kaombo and Egina, how are they compared to previously sanctioned projects in West Africa?

And we've talked a bit here, your average cash flow about on a portfolio basis is still within the sort of mid-to-high 20s.

Would you say, these projects falling in that range or higher?

The second question, I would just want to come back to, Patrick, your comment that the priority is not volume growth but value growth.

The first is just that you're about a step away from the volume target altogether.

And if so, is there a case to make now that you can -- now you've made the deal with Anadarko, you can potentially prioritize your capital framework around cash return over balance sheet and CapEx?

And finally, linked to that last question, I understand the targets increased returns from 30% to 40% of free cash flow.

When I think about your yield in the context of dividend and buyback over market cap, you sort of fall -- you sort of still sit within the sort of the mid-range of the group and not necessarily towards the top end.

So how do you think of it in that context?

There was cash margin evolution on some projects, if I understand.

Kaombo energy.

Now I think on these projects like [Mero], Kaombo, Egina, which are projects on which we have invested a lot, and it's in our PSE.

But clearly, they are very accretive in terms of cash margin to our portfolio.

It's above $40 per barrel for this type of projects because we have to -- we recoup part of the cost plus we have the additional profits.

So this is clearly cash accretive in terms of dollar per barrel to our portfolio, and we'll benefit of it.

And so it's part of the explanation why we're growing with; we are in the cash flow growing period.

Sorry, I said more than $40 because I don't have all the details.

Somebody is just telling me, it's more $45 to $50.

So it's even more than that.

The second question is about value over volume.

I think the fact that I just explained to you that we are ready -- that we are -- we will -- on one side, we're requiring what we consider as good barrels with the African portfolio of Anadarko and which will be accretive to our cash flow per barrel.

But it's not a matter of volume and sale, I mean, we don't -- I don't want to put an objective of volumes of production.

We are ready to divest some productions and it gives some -- as I said, we have reserves -- 2P reserves which will be largely over 20 years.

So we think that we have -- it give us some space in order to divest part of the assets and -- that we're targeting.

And I gave just before what are the key criterias.

So then about shareholder returns.

I gave you -- it was -- it's not -- I gave you last year, we returned 38% of CFFO to our shareholders.

I think it was very comparable to most of our competitors.

We have a yield and even in the high range of the competitors in terms of return, global return.

So I think we have a -- from this perspective, we have a competitive policy in terms of return to shareholders.

Our yield is around 5.5%, I think today, and I think it's already quite high.

We're in a world where the cost of money is much lower today.

And so, I think that we have a competitive return policy to shareholders.

We intend to maintain it.

As our cash flows will continue to grow, obviously, the share in terms -- absolute terms will continue to grow as well.

And so in absolute terms, the returns to shareholders will continue to grow.

This is what I can tell you.

P2, maybe you want to add something.

Yes.

I'd like to tell you, Christyan, that I don't share the same figures as you because we do benchmark our cash return in comparison to our competitor, the Shell, BP, Chevron and Exxon.

And we did not set the 40% target from nowhere.

It is a competitive shareholder return in comparison to what is made by our competitor.

So maybe we should talk together to reconcile our figures.

The line of Alastair Syme from Citi is open.

Patrick, I wonder if you could just update us on the situations in Uganda and Papua New Guinea.

I think you made it a priority to move these assets [for the sea].

So I just want to understand what the situation is in each country as it stands today.

And then maybe if you could also, secondly, just comment around the LNG market.

We've obviously seen a big move in pricing over the winter.

So what do you think that's telling you about the state of the market?

And are your customers saying anything on the fact that their contract pricing is essentially above where spot prices are today?

Okay.

No.

These 2 projects are -- as you know, PNG we signed a gas agreement with government and PNG in the beginning -- in May, beginning of May.

I was there.

In the meantime, there has been a change of government.

From my point of view, I think that this type of agreements are signed with a country.

So we expect the new government to respect it.

Then while various news in newspapers, but you know we are confident that is the best interest of PNG to respect the agreements which has been signed in order to move forward with the project.

It's like you have seen, there are many projects, energy projects around the world.

We have also many projects in our portfolio, one more with Mozambique.

And obviously, we have to -- I think everybody has to consider the global planning of the LNG industry in order to move forward with various projects around the world.

On Uganda, I think as you know, it has been a long -- we spent a lot of time there.

It's not LNG project.

It's a project which cross -- is crossing borders with the pipeline with Uganda and Tanzania as we are to have put in place if we, like anyone, to launch a project a number of agreements in particular, and strongly, I would say, a legal agreement in order to be sure that we don't want to invest upstream if we're not sure to have the pipeline bringing the oil Downstream to the sea.

So the situation has been that we cannot change the geography.

But Uganda is a country which is not connecting to, I mean, which is landlocked.

So we need to be sure.

But if we want to finance the projects to have all these agreements being ready at the same time.

So it's a lot of work.

We are working on it, and we need the support of both -- all governments, and we are spending a lot of time on it.

So the target is to sanction the project this year.

I hope we will reach it.

Then LNG markets.

It's a market which is moving.

2 or 3 years ago, everybody was convinced there will be too much LNG.

So everybody was pessimistic.

Last year, the price went up and so then we've seen an influence on the long-term plan contracts.

I think the best answer we can bring onto that is our strategy to have a large portfolio.

In our portfolio, most of the contracts are all related still.

And of course, we've seen an influence on what is happening on the spot, on the capacity to negotiate the -- some long-term contracts with some customers.

In Total, we have been quite patient in order to maintain a certain policy not to make any denting.

And by the way, because we are today managing the large portfolio, we can accept also to take part of the risk in our portfolio.

And you've seen that the cash flow from operation from iGRP has almost doubled, I think, in the last -- compared to last year.

And this is largely due to the exceptional job being done by the LNG trading teams.

We begin to really see the impact on our cash flow generation of being -- a team being in charge of a much larger portfolio.

It's doubled, it's plus 77%, which is quite impressive.

And it's linked to the capacity to move around the world the more volumes, not only, by the way, the long-term contract but also some spot volumes, which are generating $0.20, $0.30 per million BTU additional revenue.

So I think -- in fact, my answer to this volatility in the price in the LNG market is clearly that being able to have a large portfolio and to absorb the various -- the volatility is the best way also to benefit from it.

So it's not only, I would say, a producing business, it's also a trading business and a logistical business and a business to customer.

So we are well positioned for facing this volatility.

Can I just wrap up by wishing P2 all the best in his retirement.

Thank you.

The line of Michele Della Vigna from Goldman Sachs is open.

Two quick questions, if I may.

The first one, when I look at your P&L, the associates line has been a bit of a drag in the first half of this year, down about 30%, while EBIT was pretty much flat year-on-year.

I was wondering what were the key drivers there.

And whether we could expect some of this to reverse in the second half as Ichthys and Yamal continue to ramp up.

And secondly, on Mozambique, I was wondering what kind of accounting you will want to use there.

I think some of the companies there are using proportional consolidation for Upstream, but associate for Downstream.

I was wondering if you would go for the same methodology?

Yes.

Let's try to answer on the equity affiliate.

It is true that net operating income from the equity affiliate is below last year, but this is basically due to the weaker gas price.

We started -- this is true, so a few project like Ichthys or Yamal, but the gas price effect, you see it on the equity affiliate.

That's the main reason.

Yes, because most of the equity affiliates are energy affiliates, in fact.

And I think it's giving you an end to the way we generally account accounting method.

Okay, we need to -- it's linked also to the way the financing package will be structured.

So we -- honestly, at this stage, we have spent some time to understand the project itself, financing package we have not been involved, and we could not for obviously a good reason.

We are today -- we just buy an option.

So there we have not been involved in it in any way with, I would say, the ECAs and the final stakeholders of financing package from Mozambique.

This could take time because we will look at it, and obviously, the way this will be structured could influence the accounting method.

So I think it's -- there is a link.

So today, we don't have any position.

You know the way we structure, we generally account LNG -- it for equity affiliates, but we have to -- it's linked.

All that is related links.

So we'll have work to be done in the future months after we are clearly -- we see a job we can only do when we will be -- we will have closed the transaction, before it's not possible to be involved vis-à-vis the various stakeholders.

The line of Jon Rigby from UBS is open.

I have a question just on your sort of CapEx and LNG strategy, now you're adding Mozambique to it.

So it looks like you're taking forward a whole host of projects all at the same time, the U.S. export projects, Nigeria LNG Train 7 potentially, Arctic, Mozambique now, Papua New Guinea.

I think you've spoken in the past of being interested in looking at the Qatari opportunities as well.

Now I take the points I treat with you, you said that not all of these go forward in a smooth way.

So is it your thought that you can do all of these together?

Or do you think it will just work out that they -- the sequencing sort of plays out for you, and you can incorporate those into the kind of CapEx budget that you're talking about comfortably without having to move spending up at some point?

And then sort of related to that just on CapEx, and I guess sort of a more philosophical question as we move into the September events.

When you think about CapEx, it seems to me there's 2 schools of thought, there's those that say that they want to fund every single good project that makes money or makes a good return in the portfolio and those that apply a top-down sort of maximum amount of spending in this sort of spirit of capital discipline.

So when you come to think about CapEx and the sort of medium- to longer-term CapEx, which school of thought do you belong to?

First, let me call, the guidance I gave you, $16 billion-$18 billion of CapEx from 2019 to 2023, is taking into account the developments of most of the projects we -- you have mentioned.

So we have the capacity to take them onboard, and I know -- you know why fundamentally.

It's because of the capital discipline that we had from '15 to '18.

We are spending a lot of money on projects which were sanctioned before '14.

We did not sanction a lot of projects because we were not in a position to add CapEx in the program to keep the discipline, the strong balance sheet.

And so in fact, today, we can absorb these additional, these new projects by keeping the guidelines, which honestly we're on $15 billion-$17 billion, we moved to $16 billion-$18 billion, so we are -- we keep the discipline.

And why do we keep the discipline and it's linked to your philosophical questions.

On my side, I consider that I'm more on the school that we should not finance all the projects.

We should keep a discipline because it's a global balance sheet, and it's not only CapEx.

Of course, we want to develop the company, but it's a mix between the CapEx, the investments, return to shareholders, the giving and finding the right combination.

I think we historically have done the other way from 2010 or 28 (sic) [2008] to 2014, we've seen the impact, in particular, on the profitability because the massive capital employed has grown a lot.

So today, trying to manage this massive capital employed is very important as well.

So I think we're trying to find a way to -- between, I would say, creating more value but also being strong and creating value means for me having a better profitable -- profitability on capital employed.

So this is the right combination.

So if we -- I gave you a new guidance of $16 billion-$18 billion for the next 5 years is because we are willing to maintain this guidance.

The line of Christopher Kuplent from Bank of America is open.

And P2, (foreign language) Interrupt your recovery from whatever made you so tired.

I hope it wasn't us.

And quick question for you, P1, and then one for P3.

Your 40% payout ratio, which is effectively giving us on CFFO at $60 Brent, do you have a view on how much should come from absolute dividend payments when you talk about dividends should continue to grow?

Should they only grow on a DPS basis?

Or do you actually think it's a good thing to increase your $8 billion roughly annual dividend cost?

And any further thoughts you have in terms of prioritizing returning cash back to shareholders via buybacks versus dividends would be helpful.

And P3, the quest goes on.

Net working capital only seems to work in one direction.

I wonder whether you can give us a little more detail on your introductory remarks, how it could actually release a little bit of cash into the second half?

I will not give you the full detail of your spreadsheet to allocate everything.

I mean, let's be clear, I think I've been clear in my answer.

I told you that we want to have a competitive return to shareholders.

As Patrick said, we have the objective but if -- we have the input and we have the strong feeling that if we have hedged it to 30%, we are very competitive compared to peers.

I also said that dividends are clearly when I discuss with our investors their priority.

So we will continue to grow the dividend.

And it might -- yes, it will probably be in terms of absolute value, we could spend a little more for dividends.

Of course, when you make buy backs you eliminate some shares.

But at the end, my priority would be dividend in order to return to shareholders.

I will not go more in the details because then it's a decision which is taken by the Board of Directors about this various ways to do it.

The second question, I think first -- second, Chris, thank you to have find a new nickname for Jean-Pierre.

So definitely, it will be P3.

It's not Patrick.

It's Pierre, but it's not far.

So P1 and P3.

So it's good, Patrick, you have a new -- we will not call you P2 Junior because we are in France, but P3.

So P3 will give you some -- will explain you how we will eliminate with working capital burden like we've done last year.

We have some seasonal effects, but I leave the floor to P3.

So that's true that we have increased the working capital this quarter, it was the case during the first quarter.

We will work on the working capital.

As P1 explained to you, we demonstrated in the past that we are able by year-end to decrease the working capital.

We will give clear guidance in particular, to our trading to reduce the working capital, and so I think I'm quite confident that we will restore the working capital by year-end.

Yes.

You have some inventory effects and things like that, but it's not -- we have the discipline internally to know, but we have some seasonal effect, and then we come back on this figure -- on the right figure by the end of the year.

What is next question?

The line of Bertrand Hodee from Kepler Cheuvreux is open.

Two questions, if I may.

The first one on the LNG market.

Going forward, there's a lot of projects that are getting close to sanction, and you have a lot on your plate, Cameron extension 4, 5, LNG 27, PNG.

You could participate also in Ridgewood, Costa Azul, Rupture, Arctic 2 being -- are almost FID plus, Mozambique.

Do you believe that the market could absorb that?

And that we are not running the risk by 2024-2025 to be supply again like we are today?

And the second question more, I would say, a data point.

When do you expect Ichthys LNG, Kaombo Sul and Nigeria Egina to reach plateau?

No.

We have some.

Yes, we are involved in projects, many projects.

There are some which are very near sanction like Arctic 2, like Mozambique has been taken.

There are some others like we speak about Ridgewood, we are -- today there is no date on the paper.

It's more optionality -- options we have in our portfolios.

And I see on Cameron LNG that we mentioned as well, today's priority is more to start the train 2 and train 3 next year rather than preparing to sanction train 4 and 5, even if obviously it will be a -- I would say, some priorities.

So as I said previously, I think the LNG market -- again, there is quite a large group.

We have served not only China.

India is buying more and more LNG.

Of course, it's linked to the price.

So it's back to what assumption do we take when we sanction a project, and we are cautious.

We take assumptions, which are linked, I would say, to a $50 per barrel world.

We don't take assumptions linked to a high price of gas.

So that's a way to be cautious about it.

This market, by the way, you have the feeling today it's oversupplied.

Last year, it was considered under supply.

You know you have the weather effects, which is quite important.

And according to all analysis, by '22, '23, there would be a lack of supply in these markets.

So we expect on the contrary, to see again prices moving up in future years.

By 2024, 2025, yes, there are today many projects around the world.

The way to arbitrate a project for me is purely based on the cost rate curve.

Our criteria is that to be sure we don't want to invest in projects which are, I would say, third or fourth quartile in cost rate curve.

So if our project in the positive returns is -- I mean, and competitive -- is competitive from a cost curve, which means more competitive than other projects around the world, then we move on and we invest.

And this is a common characteristics to the projects in which we want to invest in future years.

Okay.

For the plateau, Egina and Ichthys are at plateau, and Kaombo plateau is scheduled on Q3 and is currently producing 200,000 barrels per day Sul plus Norte.

The line of Jason Gabelman from Cowen is now open.

I just want to clarify the free cash flow guidance you gave for the Mozambique project.

Is that including interest and post tax?

And if not, can you please provide what that number is?

And then secondly, just on Mozambique, what are the -- do you guys have concerns there with regards to security?

And are you taking any measures to shore up your security around the project site?

Okay.

The guidance I gave in terms of free cash was for the portfolio of the 3 African assets: Nigeria plus Mozambique plus Ghana.

It was not only -- and obviously, it was a guidance in net cash flows.

So after-tax and interest.

That's clear.

Second question, security, yes, we have, of course, made a full due diligence on it.

And security of our people is the highest priority in our company we have.

And the situation there is -- we know that it's -- we have to take it seriously.

I think we have ways to manage it as we've done in other countries.

It's one area, by the way -- somebody mentioned to me already to cooperate with Exxon, I answered, yes.

And obviously, on security I think we share the same values together with Exxon and the same ways to tackle this type of situations in Africa.

We have some operations in (inaudible), Nigeria and elsewhere.

So we obviously will put the level of investments, which is required to ensure the security for all the people we will work onshore in Mozambique, but a clear priority.

The line of Henry Tarr from Berenberg is open.

I think most my questions have been answered, but just very quickly, on the Toshiba LNG acquisition.

It looks a bit like a sort of directional bid on LNG pricing.

Would you characterize it in this way or do you see it a bit differently?

And then secondly, just on the gearing target, how much of a constraint is it?

So if the right opportunity comes along, now would you go above that target near term?

Or do you think, I know you talked about the sort of countercyclical M&A strategy, you're probably now more likely sellers than buyers of E&P assets looking forward.

No, Toshiba was -- honestly, I think it's just a matter of very different situation for both companies.

Toshiba is not really involved in the LNG business.

It's not an energy company.

We have, by the way, other businesses which we have difficulty.

So I think they were -- they decided to sell.

It was considered then their border as high risk.

Honestly from us, we are a big player in LNG.

I think on the -- in our portfolio, additional 2 million tons of LNG in the U.S. on the standard pricing does not afraid us.

We have more to -- we have that.

And -- but getting the benefits of the $800 million, if you divide $800 million by 2.2 million tons over the number of years, you will discover that, in fact, it's lowest was access to LNG from the U.S. at a super competitive price.

So I think it's really a different risk -- approach of the risk of the LNG market.

We are a strong LNG player.

Toshiba was not, and have decided to exit, and so we were agile enough to take this deal, and I'm quite happy that my teams were able to convince Toshiba, thanks, by the way, to the strong balance sheet of Total, that we could close the deal and receive $800 million.

So it's 2 million tons.

So I think it's a pure risk management approach and different -- in fact, it's a core business to us.

It was not to them.

Gearing, no it's -- for me, this target is really a clear target.

It's more than a target.

I strongly believe that the business model of an oil and gas company facing the volatility of a market required to be stringent on the gearing level.

We said the 20%.

I was maybe not convinced in 2014, but you know what?

The events convinced me quickly.

But we were by that time about 30%, and we made a lot of efforts.

And so we have used part of the, I would say, flexibility we had on the gearing, we had 15%.

We had to use it.

Anadarko will represent 4%, so that means clearly that you will not see Total will make a pause in this type of deals as because the gearing is for me an important target.

And we will do -- I will come back another 20% as more -- as quick as we can, and so we -- which was a question, by the way, to us at the board level.

I can tell you.

Okay, we have a good opportunity for Anadarko.

But if we do this one, we use part of our flexibility.

So if we use this one, we'll not have the flexibility for another one.

And as I don't see a better deal to be done for coming years, we decided to do this one.

The line of Jason Kenney from Santander is open.

P2, thanks very much for your support.

JP, all the best for the coming future, and P1, thanks for your input today.

I had a question for P2 probably.

I think you said in a previous call, there's no bump expected for the IMO for second half '19 or 2020.

I just wondered a quarter on, if you were seeing any potential support from IMO dynamics.

And if so, that was -- if that was confirming your belief in refining margin assumption in second half '19, 2020?

The answer is yes.

So I think Patrick wants to conclude.

And yes, sometimes concluding for you.

I understand a lot of call, but I understand that sometimes the last call of July before holidays, Patrick has one priority, which was to go to holidays.

Today he wanted to go to retire and to retire, to retire.

No, but I think, yes, the answer probably the IMO will be a support to refining margins.

It's difficult to appreciate how much.

We have already explained many times, but let's look to the market, and we will benefit.

But we are in a good position, we have organized a company in order to take benefit from these more threshold.

But just this gave me opportunity to joke.

I think there was no more call, if I understand.

So you were, Jason, the last one.

Thank you.

I think I would like, first, to thank all of you for all of your questions.

I think -- I hope you have a better clarity about the business case of the company and the logic of this Anadarko deal, but also all that being supported by the strong results.

And I know we don't make headlines because we continue just to be -- to reach all the consensus quarter-after-quarter even if this quarter, we have been better on cash flows, which for me is really the nerve of the war it's because we have more cash flows as we can in this age to continue to develop the company and high-grade returns for shareholders.

I would like to thank you again, Patrick, for the outstanding contribution to Total during his 12 years as CFO.

And to pay tribute to Patrick and to demonstrate to John, which sent me a sort of joke yesterday.

But yes, there are definitely bold people at the helm of Total.

Now it is time to say vroom, vroom.

Have good holidays all of you.

Ladies and gentlemen, that does conclude our conference for today.

Thank you for participating.

You may all disconnect.