TotalEnergies SE (TTE) 2019 Q3 法說會逐字稿

Ladies and gentlemen, thank you for standing by, and welcome to Total's Q3 2019 Results Conference Call.

(Operator Instructions) I must advise you that this conference is being recorded today, Wednesday, the 30th of October 2019.

I would like now to turn the call over to Jean-Pierre Sbraire, Chief Financial Officer.

Please go ahead, sir.

Thank you.

This is Jean-Pierre Sbraire.

Total reported strong third quarter results demonstrating the ability of our diversified portfolio to resist volatility in the markets, particularly in terms of strong cash flow generation.

Debt-adjusted cash flow was $7.4 billion, a slight decrease of 2% compared to the same quarter last year despite the 18% drop in the average Brent price and a decrease of more than 50% for spot gas prices in Europe and Asia.

The resilience was due mainly to cash equity volume growth of more than 8%, strong contributions from integrated gas and Downstream and company-wide efforts to cut costs and reduce the breakeven.

Adjusted net income was $3 billion or $1.13 per share, down 23% compared to the same quarter last year mainly due to the weaker environment but also benefiting from the growth and the Downstream revenues.

Looking at the first 9 months compared to the same period last year.

Debt-adjusted cash flow increased by 6% to $21.1 billion.

Adjusted net income was $8.7 billion, down 17%.

OpEx was $5.3 per barrel in Q3, reducing the 2019 year-to-date OpEx to $5.50 per barrel, which is a decrease of 5% compared to OpEx of $5.80 per barrel for the first 9 months of last year.

With additional cost reduction of more than $0.5 billion this year, we raised the cumulative savings target to more than $4.7 billion for 2019 compared to our 2014 base.

Operationally, the group's production hit a new high of more than 3 million barrels per oil equivalent per day in the third quarter, and production growth should reach 9% for the full year.

It was 8.7% by end September.

Q3 benefited from the ramp-ups of Ichthys, Yamal, Egina, Kaombo Sul and Culzean.

(inaudible) started up early, so we will benefit the first quarter.

And Iara 1 in Brazil should start before year-end.

We are continuing to high-grade the portfolio and delivering sustainable cash flow growth.

We completed the acquisition of Mozambique LNG in September, and we should close the remaining parts of Anadarko portfolio, Algeria and Ghana, in 2020.

We sanctioned Arctic LNG 2 in Russia.

We participate in our second Guyana discovery, so we have a good start in this promising new basin.

And we won a new high-potential exploration license as operator in pre-salt Brazil.

We maintain strict capital discipline in line with our commitment for return to shareholders.

An example of this was the termination of our agreement to acquire parts of Tullow's stakes in Uganda as we disagreed on the tax treatment of the transaction.

Also, we confirm that we will not participate in Brazil transfer price as the underlying price deck for the bonus does not fit with our criteria.

Looking at the results.

The E&P segment generated cash flow from operations before working capital, which I will refer to hereafter as CFFO, of $4.5 billion in the third quarter 2019, a decrease of 14% compared to the same quarter last year.

In a deteriorating environment, this performance reflects the resilience of the CFFO, thanks to the higher cash flow generation from new project start-ups and ramp-ups.

Adjusted net operating income in the third quarter was $1.7 billion, down 29% from $2.4 billion in the same quarter last year, reflecting higher DD&A from new projects.

The iGRP segment increased CFFO by more than 50% to $0.8 billion.

Adjusted net operating income in the third quarter was $0.6 billion compared to $0.7 billion in the third quarter last year, again, reflecting the weaker environment.

Year-to-date, iGRP CFFO increased by nearly $1 billion, thanks mainly to the 55% increase in equity LNG sales, in particularly, fueled by Yamal LNG and Ichthys.

In the LNG business, in addition to the acquisition of Mozambique LNG and launching Arctic 2 LNG, Cameron train 1 ramped up in the third quarter, train 2 and 3 are under construction and we start next year.

We took over Toshiba's 2.2 million [tonne] LNG portfolio in July, which came with a cash inflow of $800 million.

We announced the expansion of a strategic partnership with private conglomerate, Adani, to develop access to fast-growing gas and LNG markets in India.

We signed a gas agreement in Benin that includes FSRU, floating LNG regas units.

And we launched our first LNG bunker refueling the salt, which will operate in Northern Europe, supplying the next generation of containerships.

In the renewable business, we added 500 megawatts of new solar and onshore wind farms in France.

We sanctioned our first solar farms in Japan.

We reached our 1,000th service station with solar panel.

This is part of our ongoing plan to solarize 5,000 service stations globally and part of a broader plan to leverage renewable energy at our facilities throughout the group.

And we joined forces with Envision Group to develop on-site distributed generation solar projects to B2B customers in China.

Turning to the Downstream.

CFFO for the combined Downstream was very strong at $2 billion in the third quarter, an increase of 14% compared to a year ago.

Adjusted net operating income for the third quarter was stable compared to the same quarter a year ago at $1.4 billion.

In Europe, cracker margins again benefited from the supply limitation as a result of a heavy turnaround season.

In the U.S., petchem margins benefited from lower feedstock prices, notably (inaudible) but also LPG with new supply coming online.

The diversity of our Downstream business units, including the countercyclical and noncyclical elements, is an important part of delivering sustainable performance.

Year-to-date, Downstream CFFO increased to $5.1 billion and is well positioned to reach close to $7 billion for the year.

Refining & Chemicals generated CFFO of $1.4 billion, an increase of 17% compared to the third quarter 2018, mainly thanks to higher petrochemical margins.

Adjusted net operating income was $1 billion, a slight increase compared to the third quarter last year.

European refining margins, [MVC], were $47.4 per ton, stable compared to last year.

Marketing & Services generated CFFO of $0.6 billion, an increase of 7%, notably due to higher margins in Africa and Europe.

Adjusted net operating income was $0.4 billion in the third quarter, down 13% compared to last year.

Year-to-date, CFFO increased by 10% to $1.8 billion.

In terms of profitability, return on average capital employed for our best-in-class Downstream was 25% for the past 12 months.

At the corporate level, based on a rolling 12-month average, return on equity for the group was about 10% at 10.3% at the end of the third quarter.

Year-to-date debt-adjusted cash flow for the group is $21.1 billion, up 6% compared to last year.

Net investments, including acquisition and asset sales, were $13.2 billion for the first 9 months, and we expect the full year 2019 to be less than $18 billion.

Net acquisition and asset sales for the first 9 months of 2019 was $4.1 billion.

This includes mainly $3.9 billion for the Mozambique LNG acquisition and the $800 million that we received for taking over the Toshiba LNG portfolio.

Year-to-date, we have completed $1.6 billion of sales or about 30% of the $5 billion target.

In addition, we have sold but not yet closed around $1 billion of assets, including material U.K. North Sea assets, the Trapil pipeline network in France and the sale of nonoperating block in Brunei.

So we are well in advance in the process.

The organic pre-dividend breakeven is below $25 per barrel.

Maintaining a strong balance sheet is one of our top priorities, and gearing at the end of the third quarter was 17% excluding capitalized leases and 21% including them.

The closing of the Mozambique LNG acquisition added about 2.5% to gearing.

One of the main messages from the Investors Day is that we are accelerating dividend growth.

Previously, our guidance was an increase of 10% over the 2018-2020 period, and we have been growing the dividend at more than 3% per year.

Given our outlook for strong cash flow growth of about $1 billion per year over the 2020-2025 period, the Board has decided to accelerate the dividend growth for the coming year with a guidance of 5% to 6% per year.

In line with this, we confirm that the third interim dividend for 2019 will increase by 6%.

Buybacks through September was $1.15 billion.

Given the strong cash flow generation, we will end the year with $1.75 billion of buybacks, exceeding our 2019 target of $1.5 billion and will complete $5 billion program next year.

Finally, we announced that we will open a digital factory in Paris in early 2020 that will pool the talents of 300 engineers, data specialists and other experts to generate an estimated $1.5 billion per year in value by 2025 through increased revenues and reduced costs and investments.

Summarizing the third quarter results.

Total's integrated model is working well, and our efforts to reduce breakeven and high-grade the portfolio are paying off.

Despite weaker oil and gas prices this year, we increased cash flow generation from our diversified portfolio, benefiting mainly from integrated gas and Downstream.

We're on track to grow cash flow over the coming years.

We are disciplined in our capital investments, including net acquisitions.

The balance sheet is strong, and we are committed to returning value to our shareholders.

That's it for my prepared remarks.

And now we can go to the Q&A.

(Operator Instructions) And the first question comes from the line of Lydia Rainforth from Barclays.

Two questions, if I could.

The first one, just come back to the asset sales.

And can you just walk me through why the Toshiba LNG part is included in asset sales?

Just in terms of -- [it seems to all be] given that there is a liability associated with that.

And then the second one was just around the low carbon business, and the highlight in the progress being made there.

Can you give us an indication of where the returns might be for -- across the different regions, whether it's France, Japan, China?

Thank you, Lydia.

Regarding Toshiba.

So you know the deal.

So we acquired the Toshiba LNG portfolio.

It was in August this year.

The rationale behind that is that, of course, for Toshiba, Toshiba saw negative value in this contract and decided to exit from this noncore business.

They have paid us $800 million for that.

So in fact, it's an acquisition, but at the same time, we captured this $8 million of cash for this portfolio.

Since we received cash, obviously, in our cash flow statement, it's considered as a [fair].

The second question regarding low carbon.

So you know and I think we are very well -- we are transparent in September during the Investors Day.

The typical renewable projects deliver an internal rate of return, I would say, 5% to 6%.

And of course, it's not in line with our criteria to sanction projects.

So to boost our equity in low carbon project and particularly in solar farms or wind farm, we leverage the projects.

So typically, we use a debt-to-equity ratio of 70%, 30%.

It could be higher because, of course, at present time, money is very cheap.

So in some cases, we can achieve 80%, 20% debt-to-equity ratio.

So that's the first step.

And second, we farm down our shares and we keep more or less 50% of the share.

And so doing that, we can achieve a higher equity above 15%.

Low carbon business, in our view, includes LNG as well, of course.

It's -- and you know that's growing along the value chain is a key priority for us.

And the next questions come from the line of Biraj Borkhataria from RBC.

Two, please.

The first one, on the buyback.

The increase in the run rate is encouraging, but you obviously maintained your guidance as flat into 2020.

I would have thought with growing production, you got flat CapEx and then you have the benefits of IMO 2020, that the 2020 buyback potential would be a little bit higher at least than 2019.

Could you just talk about how you're thinking about that run rate as you go into next year?

And then the second question is on Guyana.

You divested part of your stake in the block to QP 2 or 3 weeks ahead of the discovery.

Could you just walk us through what drove that decision?

Because presumably well was either being drilled or had been drilled when that decision was made.

Okay.

So first question regarding buyback.

So in last year, we bought back the equivalent of $1.5 billion.

And for this year, in September, we bought back the equivalent of $1.15 billion.

And so we announced that we will buy $1.75 billion for the full year.

So that means an additional $600 million for the -- during the Q4.

The strategy is very clear.

We will deliver the 2018-2022 $5 billion program that had been announced in February 2018.

Beyond '20, I think we will act according to our priority of cash allocation.

So first, dividend growth of 5% to 6% per year.

I think it was the main message from the Investor Day that we'll accelerate dividend growth.

Even though that before, our guidance was an increase over 10% over the period 2018-2022.

And we have been growing the dividend of more than 3% per year.

Now the Board has decided to accelerate the dividend growth for the coming years with a guidance of 5% to 6%.

As you mentioned, we -- the Board had decided to implement this increase immediately.

And so the third interim dividend, you -- for this third interim dividend, you will see the 6% growth.

Second priority is to delever the company.

I think we are very clear that we want to maintain a very strong balance sheet, and gearing is key in our strategy, in our views.

And buyback, of course, we used to share extra revenues above $60 per barrel.

Regarding your question on Qatar Petroleum and the farmdown to QP on Guyana.

Total is a long-term partner of QP in Qatar, and we support -- we therefore support their international developments.

The -- you mentioned the Guyana wells.

So at the time, the partnership -- we decided to let QP farm into some exploration and creating [block] in Guyana but also in some other countries of Kenya and Namibia.

The well was not drilled.

The next questions come from the line of Oswald Clint from Bernstein.

Just 2 small ones on the 3Q results.

The third-party LNG sales were down sequentially quite a bit.

I just wonder what's going on with that line item or if there's any LNG cargoes you're not actually lifting at the moment.

And similarly, in affiliate earnings for Refining & Chemicals and also Marketing & Services, both down quite a chunk sequentially on year-over-year.

Could you just talk to what's happening in those?

And maybe just a follow-up to Guyana, you have had 2 discoveries on the block recently.

How are you thinking or how interesting is this block turning out to be from your perspective?

Okay.

So regarding the Q3 results and third-party LNG sales.

Yes, so that's true that the sales from equity production and third-party purchases were down quarter-to-quarter, and it's clearly linked to less volumes of spot in our sales.

I can say that there was a higher focus this quarter, so in Q3 quarter, Q3 '19, on using our European regas capacity instead of selling on spot markets.

And so you can -- you will see that on 9 months, the sales from Total are increasing by 75% compared to the same period last year.

So second question regarding Downstream.

Yes.

Okay.

The equity affiliate contribution to net operating income was around $520 million this quarter.

It's below last year.

Last year, the same figure was on the same -- the equity affiliate contribution to net operating income was at $860 million.

It's in relation to a weaker gas price environment, impacting Novatek in particular.

And on one side and on the other side, we faced lower ability in the North -- in South Korea, in our JV with Hanwha; and in SATORP, our JV with Saudi Arabia in -- with Saudi Aramco, sorry, in Saudi Arabia.

However, Q-to-Q, I would say, we are benefiting notably from Novatek and the Yamal LNG.

On exploration in Guyana, I would summarize by saying that it's a promising start in Guyana because we are successful in drilling 2 wells.

So we have the first well to Jethro.

It's a high-quality sandstone reservoir.

The second well that has been drilled, Joe, it's a play opener.

And so I would say that our explorators are very excited by these 2 wells.

And we hope that in the coming year with additional wells, we'll confirm that definitely Guyana is -- will contribute positively to our exploration results.

And the next questions come from the line of Thomas Adolff from Crédit Suisse.

A few questions for me, please.

Just going into iGRP.

You've seen a sequential improvement in earnings.

Perhaps you can kind of talk about the moving parts in this division.

What's driven the increase?

And how did the integrated gas business perform on a quarter-to-quarter basis?

Secondly, in Refining & Chemicals, there was a recovery in throughput in your refineries, but you still remain fairly low at 82%.

And you've highlighted there's been some maintenance at Normandy and some issues around Grandpuits.

I wondered where runs are in the fourth quarter and whether you have any major maintenance planned for 2020.

And perhaps finally, if I may, just coming back to your comment on shareholder distribution and, again, going back to the Management Day and the message on the Management Day.

In 2021, assuming your macro scenario $60 Brent, are you likely to return 30% of cash flow to shareholder or 40% of cash flow to shareholders?

Okay.

So first, I have the question regarding Refining, the situation in our French refinery, Grandpuits.

Yes, the Grandpuits refinery was shut down end of February because of the detection of a crude leak in the pipeline supplying the refinery.

So now the Grandpuits refinery has restarted operation and the restart of operation occurred in mid-July.

iGRP, the environment was weaker, obviously.

We have low gas price -- we have -- we faced low gas price environment.

But at the same time, the CFFO for this business segment increased by more than 50%, so 53% year-on-year at more than -- to almost $850 million.

It's definitely due -- or it's -- the main driver for this increase is the cash generated by Yamal LNG and Ichthys and with the ramp-up of these 2 projects.

If I consider the first 9 months, I think one of the main takeaways of our third quarter results is that we are able to increase the cash flow generated by iGRP by -- we are able, sorry, to deliver our cash flow around $1 billion driven again by this LNG business.

And at the same time, the LNG production, as you noticed, was up by more than 55%.

Can I stop you, though?

I mean can you comment on 3Q versus 2Q?

Because earnings are up quarter...

Sorry.

We have the higher contribution from Ichthys, but at the same time, for low carbon [acidity] as well, to address your question.

The last question regarding the shareholder return in '20 or '21.

In February 2018, we announced how we'll allocate our cash flow, our CFFO, our cash flow generated by operation.

At that time, obviously, we are lagging our competitors.

It was in 2017.

And so it has been said -- we said with the Board that, of course, we needed to -- we joined the pack and we did catch up since there.

And now in 2018, we returned to our cash -- to our shareholders the equivalent of 38% of the CFFO.

Eventually, we'll get to the 40%.

I remind you that with our guidance of 5% to 6% increase per year of dividends, we will increase the dividend by about $500 million.

And at the same time, we will increase the cash -- the CFFO by $1 billion.

So that means that we'll return more or less half of the added -- of the cash we will generate.

Our CEO, Patrick Pouyanné, gave that indication of 30% CFFO, it was in July, but it was not a commitment.

It's a medium-term maturation.

And the next questions come from the line of Irene Himona from Societe Generale.

I had 3 questions, please.

Firstly, in the third quarter, looking at Marketing & Services, [now about] $430 million.

I mean it fell sequentially, and year-on-year, it fell about 13%.

I wonder if you can explain what drives that relative weakness.

Secondly, tax rate in Q3, the tax rate in E&P, I thought looked quite low.

Can you just remind us, in a world of $60 Brent, roughly what we can expect for E&P tax in the fourth quarter and into next year?

And my final question, looking at the coupon payment on your hybrids, your perpetual subordinated notes, in Q3, that payment jumped about 77% sequentially from $74 million to $131 million.

In the 9 months, you paid about 17% more than a year ago.

I know you issued some more hybrids in the year, but I didn't think you issued 17% more.

So I wonder if you can, again, give us a sense of what the payment schedule for these is because clearly it impacts the EPS calculation.

Okay.

So first question regarding Marketing & Services.

First of all, I think the net operating income year-on-year is more or less stable.

It's remained above $400 million.

So that's the slight decrease, it's not very significant.

And at the same time, if you look at the cash flow -- CFFO generated by Marketing & Services, you will see that this cash flow increased by more than 7%.

So it's completely in line with the guidance we gave to increase Marketing & Services cash flow more or less by $100 million per year.

Tax rate, the effective tax rate for E&P in Q3 was more or less 40%, 39.7% to be precise.

It's in line with the weaker environment.

In -- last year, in Q3 2018, the effective tax rate for E&P was 47%.

So it's very difficult to comment the tax rates on a quarterly basis, but it's in line with the figures we have in mind to have more or less an E&P tax rate between 40% to 50% depending on the Brent price in the range between $60 to $70 per barrel.

Hybrid.

First, that's true that we refinanced a part of our portfolio.

It was in -- I think it was in March or in April of this year.

But we haven't increased the total amount of hybrid.

It's a refinancing, so we issue a new hybrid but at the same time, we have decreased for the same amount the level of hybrids in our portfolio.

So I would say the total level of hybrids is exactly the same.

I do not have the exact payment schedule in mind regarding the coupon.

What I can mention is that in my view, I consider hybrid as being very cheap equity.

And the coupon overall for all the different tranches we have in our portfolio, the coupon are below 3% before tax.

So that means that after tax, it's around 2%.

I can -- I will add something, through the refinancing, we are able, by the way, to reduce the coupon.

So it was a very, very successful refinancing.

And the next questions come from the line of Jon Rigby from UBS.

Two questions, one on the Downstream and one on M&A.

So on the Downstream, just to go back to Thomas' question, you noted that throughputs in the refining were running low -- actually low year-over-year.

We're obviously seeing a pickup into the year-end with IMO.

So are you able to just talk about where you think -- I mean should we be expecting, by historical standards, relatively high utilization rates and throughputs through 4Q and into 2020 to take advantage of what might be a good opportunity?

And just on that Downstream.

Was there any decent or notable contribution from oil trading in the quarter?

Some other -- your peers have noted some benefits, and I guess that might be related to these changes.

That's on Downstream.

On M&A, you've obviously still got some outstanding payments to make around the Anadarko Africa transaction.

So are you able to say kind of as of right now, what you would be likely to pay?

And let's say, if it were to be -- we stay at $60 and you close it mid-year next year, what the delta would be on the consideration that you'd expect to pay?

So first of all, I will not change the tradition, so I will not comment on trading contribution in the results, in the Refining & Chemical results.

Regarding -- so question regarding IMO, I'm not sure to have really understood your question.

Could you elaborate a bit?

Yes.

I mean if you look at the refinery throughputs year-over-year, they are actually down.

I mean they're up sequentially, but throughputs are down.

I'm just asking whether this -- the plan to run the network hard through 4Q and into next year with the assumption that refining margins are helped out by IMO, so to make sure you get the full leverage for that.

You know that our refineries are really for IMO.

So regarding maintenance program for Q4, normally, we -- there is a plant maintenance that will impact Q4.

And -- our -- once again, our refinery, all the investment has been done in our refineries.

So we are ready to benefit from IMO next year.

And of course, to be able to capture potential additional margins, so we will plan to run as much as possible in our refineries.

Once again, it's very difficult to have -- to anticipate the refining margins, but our objective is to be ready, to be in a position to capture additional value.

M&A, so you know we closed the Mozambique LNG acquisition.

It was end of September.

By the way, it was a very good achievement because we signed the SPA with [Occi].

It was in August, so we are in a position to close this part of the lease in less than 2 months.

Once again, Mozambique -- we consider Mozambique LNG as a jewel in this acquisition.

So we are more than happy to have been in a position to close this Mozambique part of the deal.

Regarding that additional assets.

So Algeria and Ghana, so we -- the discussions, I would say, with the authorities are still ongoing.

And so we expect to be in a position to have the closing in 2020.

So later we will see the result of this discussion.

We are, by the way -- we are, of course, familiar to this kind of discussions when we acquired the Maersk portfolio.

We have this type of discussion, in particular, in Algeria.

So we'll see to -- and we expect to have the closing in 2020.

Regarding the cash generated by these new assets, the cash flow that we anticipate at $60 per barrel is more or less $700 million a year over 2020-2025.

Okay.

And you could expect that to be reduced off the consideration between the effective dates and closing?

Would that be fair to assume as we think about that?

Of course.

The price will be adjusted according to the cash flow generated between the 1st of January 2019 and the date of closing.

So it's a normal way of managing acquisition in E&P -- the E&P business.

And the next questions come from the line of Jason Gammel from Jefferies.

Jean-Pierre, I just wanted to come back to the strong production performance in 3Q.

And you did make reference to the strong contribution that you had from the 5 big major capital projects that have recently started up.

I was hoping you might be able to address how near plateau-production or peak-production each of those projects are.

And then my second question, in the LNG business, you made reference to the start-up of the first commercial -- the first train at Cameron LNG or first commercial operations there.

I was hoping you might be able to address the attractiveness of exporting LNG from the U.S. Gulf Coast currently given gas price environments as a general statement and then how Total's regasification and shipping assets might help to enhance that profitability.

Okay.

So for the first 9 months of this year, so the production is up by almost 9%.

So it's -- the figure is 8.7% compared to the same period in 2018.

As I already mentioned, the main contribution came from Yamal LNG; from Ichthys; but also from Kaombo, so our deep offshore asset in Angola with 2 FPSOs; Egina, so deep offshore well -- [factory] in Nigeria; and of course, the contribution of all the Maersk Oil assets.

So we confirm -- we gave a guidance of production growth of 9% this year.

So yes, we confirm this guidance.

Regarding the big projects.

So if you have in mind, it is on Yamal.

I think for Ichthys, the 2 trains, they have started, respectively, in October and November 2018.

And so production, I would say, is currently at plateau.

Regarding Yamal, as you know, the 3 trains started already.

We are above the nominal capacity, and the first train is supposed to come onstream in the coming months, I think.

But it's -- it will contribute marginally to increase the production on Yamal LNG assets.

Regarding other assets.

So Egina and Kaombo that I mentioned are big contributor to production increase.

The [output] will continue, but we are, well, I would say, close to the plateau.

Cameron and -- yes, in terms of ramp-up, I could add that Johan Sverdrup came into production very recently.

And so, of course, we benefit from the ramp-up in Q4, and we have at the same time the startup of Iara 1 in Brazil that will contribute to our production in Q4.

And the next question comes from the line of Lucas Herrmann from Exane.

Brief question if I might.

Just on associates and associate dividends moving forwards.

Clearly, an increasing proportion of your growth on net income growth is going to come from associates.

I just wondered whether you could give us any thoughts guidance on how you see payout of that income progressing over the next short term and medium term, i.e., when will we move to a point where your equity associates are paying out in line with the contribution they're making towards your earnings?

And can you give us any profile or idea of what the quarterly profile of pay you might anticipate or we should anticipate might be?

That's in our portfolio.

So the growth is coming from iGRP mainly.

It's from [secure] ones with our strategy to develop LNG business and Yamal and Ichthys are big contributors in terms of cash flow growth through dividends.

And of course, in the coming years, we'll have Arctic 2 as well and Mozambique LNG.

So definitely, the portion of the result coming from equity affiliates will grow.

But it's how much -- how we should model the cash that comes from that?

Because if I look at the numbers today, for example, there's a very large adjustment -- negative adjustment to cash from profits from associate that is not received as dividend.

Part of that looks to be in the exceptional Novatek.

But can you give us any steers?

It's clear once you compare the net operating results with the cash flow generated.

You have to take into account the DD&A and the fact that on -- it is now in particular, given the level of CapEx that we have to spend to deliver the project.

The performance in term of net operating result is not the same compared to the performance in term of cash.

So it varies.

It's a bit difficult to reconciliate net operating income with cash flow.

Of course, our objective, I would say globally, is to be in a position to generate as -- to accelerate or to maximize dividends we can get from Yamal and from Ichthys.

And I can confirm to you that Yamal, for example, started to deliver comparable cash flow since the beginning of this year.

And when should we expect Ichthys to start delivering dividends if it's not already?

Ichthys -- I say yes.

You have to remember that Ichthys project you are, in fact, to -- you have to be aware of the structure of the project.

So you have the Upstream that is consolidated in our balance sheet.

So you have direct access to the cash flow.

And the Upstream is a strong contributor to cash flow because, of course, the -- this part is generating all the condensate production.

So you have direct access to this cash flow through the consolidation of the Upstream.

So the Downstream, so it is LNG, so it's another study.

It's consolidated on an equity basis.

So of course, the cash you generated from this asset is -- will come either from dividends or from reimbursement of shareholder loans.

And by the way given that the contracts are good, the contract were signed when the prices were high and so we have oil-indexed contracts.

So that's the main driver why we are very -- that's why we're compatible.

We think that definitely, it is LNG we contribute to our cash flow generation in the coming years.

And the next questions come from the line of Christopher Kuplent from Bank of America.

Jean-Pierre, just -- sorry, I think my line got disconnected a little earlier.

So please, apologize if that question had been asked already, but just wondered whether you can comment on the change in language regarding the full year production growth guidance from above 9% to now should reach 9%.

What's the reason behind that?

No reason.

So we are at 8.7%.

Once again in Q4, we'll benefit from the (inaudible) start-up.

We'll benefit from Iara 1 start-up in Brazil.

So there's no message, I would say, behind this one.

And 9%, by the way, it's huge.

We benefit from 8% last year, so 9% this year.

And I can add that we are focusing on value rather than on volume.

So...

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

One question on U.S. LNG.

You are taking some volumes from Sabine Pass train 5 right now.

You are taking some volumes from Cameron LNG train 1. You will get some volumes from train 2 and 3. How can you mitigate, I would say, your contractual terms to make profit if those cargoes goes into Europe at current prices?

That's probably also why I think Toshiba realized they will not be able to make any money on those contract and they pay Total $800 million.

But just wanted to understand how you are going to mitigate the current environment probably in the next [2] years.

We believe that the U.S. is well positioned to supply cheap LNG.

And by the way, LNG is long term in our view.

We are expanding our exposure, that's true, with Sabine Pass, with Cameron.

For example, Cameron LNG train 1 started up in May so we have 2 additional trains that they're supposed to come on stream next year.

And the takeover of Toshiba LNG portfolio will add the equivalent of 2.2 million ton per year and we saw -- we see that LNG as competitive LNG supply.

And we have a very strong trading.

This is definitely linked to the acquisition we made of Engie LNG portfolio.

We have a global presence.

We are a producer in the main LNG hub.

So once again, the case in the U.S., but also in Qatar, in Australia, in Russia.

And to just give you the main hub.

It's allowed us to make arbitrage between the different markets.

At the same time, we have the capacity, the regas capacity in Europe.

We -- definitely, we think that with a different position as a producer, as a trader, we will be able to capture all the value in this LNG portfolio.

To come back more specifically on your question regarding U.S. LNG, we are short.

Our purchases represent more or less 25% but our sales around only 10%.

And at the same time, we are long oil.

Our purchases represent 25% and our sales around 40%.

So it's a way for us to mitigate the risk you mentioned.

And the next question comes from the line of Henry Tarr from Berenberg.

Just a quick one on CapEx.

So organic CapEx is running quite low through Q3.

I guess we will see a tick higher in Q4, but it would need to be quite a bit higher probably to get us towards that $18 billion figure.

So could you talk about how organic CapEx has come materially lowered this year?

And then perhaps what Q4 might look like from a CapEx perspective.

The capital investment guidance we gave in September, of course, we will -- will be in line with this guidance.

I remind you that for us capital investment, so it's organic CapEx, but at the same time, the net between acquisition and the divestments.

You're right, traditionally, and so it's -- I just have a look at this figure very recently, so it was the case last year.

The fourth quarter is higher than the previous quarter.

So in -- for the full year, for 2019, the -- our CapEx should be in line with guidance we gave in September, less than $18 billion take into account once again the net M&A.

And for the coming years, of course, we will remain in the guidance we gave between $16 billion to $18 billion per year.

I guess while I've got you just a quick other question on what's the potential for the gas partnership with Adani in India?

Our objective is to position ourselves on growing markets and particularly for gas as far as gas is concerned.

So definitely, India gas markets, we see that as an opportunity.

The country has set ambitious targets of increasing the share of natural gas in its energy mix.

At present time, I think the portion of natural gas in the energy mix is around 7%.

And the objective of the government is to increase this portion to 15% by 2030.

So we want to be part of this growth.

Last year, we announced a [firm] deal with Adani Group.

It's a private Indian group.

And it was a JV of 50-50 on LNG, to acquire the participation in Dhamra LNG and in Mundra LNG regas terminal.

We plan to develop LNG marketing in India but also in Bangladesh.

And the supply of the equivalent of 3 million ton a year from our LNG portfolio.

That's true that we recently announced to the reinforcement of this partnership.

Our objective is to acquire 37.5% of equity in a company called Adani Gas Limited, whose business is to market gas and develop [outside] structure through local concessions.

So this move, I would say, this JV with Adani, the acquisition of the share in Adani Gas Limited, once again, is very current with our objective to develop LNG on growing markets and definitely India is part of this strategy.

And the next question comes from the line from Michele Della Vigna from Goldman Sachs.

I had one question left.

Could you give us an update on your discussions for progressing Papua New Guinea and Uganda towards FID?

Papua and Uganda.

Okay.

Papua LNG.

So you know that last year, we signed what we call a gas agreement with authorities that gave the framework for the development and the fiscal term of the tax term for the development.

Very recently with the change in agreements, we have some discussions again with the authorities and the gas agreements was, I would say, challenged at some point.

But now the government has announced and I think it was in September this year that they will honor the deal.

So we are targeting FID for Papua LNG project in 2021.

Regarding Uganda, Uganda is -- the project I would say is technically mature.

We are ready to learn but we face very recently some difficulties with the authority to close the deal we signed in -- it was in 2017.

I think it with Tullow to acquire part of Tullow stake in the project given that we are not able to achieve an agreement on the tax treatment of the transaction, we decided to terminate the transaction, it's a matter of us of discipline in reallocating our CapEx.

So we remain fully committed to move forward with the development but we'll see.

And I think at the present time, it's a bit too early to assess the extent of the -- to assess when the FID could be taken for that project.

And the next questions come from the line of Christyan Malek from JPMorgan.

When I run the cash breakeven at Total for '19 on a 9-month rolling basis, it's $66 a barrel post CapEx and dividend, which is an increase on a like-for-like basis versus a year ago, if my math is correct.

Now I can understand this given the elevated CapEx for Mozambique and clearly you are paying higher absolute dividend.

However, what I struggle with is how cash breakeven fall meaningfully in line with the peer group if CapEx remains higher, which leads me to my question.: How do you plan to increase cash return over the medium term, say, in the form of additional buyback with the current capital frame?

And in this context, do you think disposals need to ramp up?

And would it be fair to say that additional cash distribution over and above the $5 billion buy back beyond 2020 is now directly a function of increased disposals?

And if you could elaborate where you think the opportunities are in divestments, that would be great.

Regarding our asset sales.

We mentioned the program of $5 billion of assets that will be sold over period 2019-2020.

We are on track to deliver this program.

By the way, end of September, we performed or we have equivalent of $1.6 billion of assets sold.

We very recently [in fact] it was today.

We mentioned that we were able to sell parts of our Brunei assets to Shell, and so it will contribute to this program.

So at the end of this year, we will have more or less performed 50% of the program.

So we do not need, I would say, to speed up or to accelerate on this program.

Of course, it's a matter of who -- we will continue to be (inaudible).

So if you have some very attractive deals, why not?

Why not entering into that deal?

But once again, we do not need to accelerate this program.

Our pre-dividend breakeven is below $30 per barrel over the first 9 months.

You know that for us maintaining this low (inaudible) and it's part of our strategy.

So what can I add?

We -- it is true that we increased the dividend so with the new guidance, 5% to 6% and you can do your math, starting from this pre-dividend organic breakeven adding the CapEx, the M&A I mentioned to you and the dividend more or less $8 billion a year before this 5% to 6% increase.

Yes, you can create your positive dividend breakeven.

So just to be clear, I mean, on the post-dividend view, assuming all else is equal, we should -- is it fair to say we should rule out additional buybacks over the medium term?

I was clear, I think, regarding our strategy beyond 2020.

We'll act according to the priority given on our cash allocation.

The main message of the Investor Day, once again, was the acceleration of the dividend growth and for us is the production -- of the demonstration that we are very confident in our capacity of delivering additional cash.

Once again having a strong balance sheet to see is another priority and having your gearing below 20% is a priority.

I have a very strong takeaway from Patrick de La Chevardière, my predecessor.

And so he told me in 2015, we enter into the downturn, having a gearing above 30%.

So I think at that time, it was 32%, 33%.

I do not want to be in the same position.

I want to keep my agility to act competitively if we can see some opportunities, so that's why the balance sheet is the priority.

But at the same time, we are clear that the buyback will be used beyond 2020 to share extra revenues with our shareholders above the $60 per barrel.

And by the way in 2019, we bought back the equivalent of $1.15 billion of our share end of September and we'll accelerate the program over the fourth quarter, with an additional $600 million buybacks.

And we are committed in delivering the $5 billion program announced in February 2018 over the 2018-2020 period.

And the next questions come from the line of Alastair Syme from Citi.

I just have one question.

Yesterday, one of the leading players in European wind stood up and admitted that essentially all their economic models are wrong.

And it feels very symptomatic of the market that's probably chased more and more aggressive assumptions in low carbon to make marginal economics work.

So I just wanted to get your perspective.

Really the question, as you look at the low-carbon space and your ambition to grow, do you get a sense that there's still many people out there that have very low hurdle rate thresholds or aggressive assumptions to try and grow their businesses?

I will not comment on BP, but I can tell you that...

It's not BP.

Our economic models are right.

But we are clear that we will allocate more or less 10 -- more than 10% -- around 10% of our CapEx in low-carbon businesses in the coming years.

And wind farm, offshore and onshore, are part of this strategy.

And we will use for this capital light model.

I've already commented how we leverage, how we plan to leverage on this project to obtain, I would say, an acceptable profitability as far as our equity is concerned.

But yes, with wind farm, both onshore and offshore, they are part of our strategy.

Yes.

Maybe just for reference, it wasn't BP, it was [Olmstead] that is so held up there as being one of the leading players in European wind.

We participated to the bid in Dunkirk offshore wind very recently.

By the way, we (inaudible) it, so we are not successful but we are not disappointed.

By the way, because if we are not successful, that means that the projects could not fit with our economic criteria.

So we see, we are not in a hurry.

We are sure that we have very profitable projects that could meet our criteria.

It will come in the coming years so we have to be patient.

Can I ask on something like Dunkirk?

Are you close to being a winning bid do you think?

Or are you far away from where the market's at?

I will not comment on that.

And the next question comes from the line of Jason Gabelman from Cowen.

Yes.

I wanted to ask the equity affiliate dividend question a bit differently and specific to the LNG projects.

Are the dividends that you receive from these projects once they're fully ramped, are they kind of on a straight-line consistent basis?

Or is there a phasing element because the projects have to pay down project level financing at the project level first?

And then as that gets paid down, you get an increase in cash streams from the projects.

And then just 2 quick other questions.

Firstly on the other African assets that have to close.

Is there a point in time next year where if the assets don't close, you can walk away from the deal?

And is that something you would be looking to do?

And then just on the financials.

There was a large ForEx impact this quarter.

I think it was over $1 billion.

Can you just talk to what that was related to?

And if that's expected to persist or reverse going forward?

Okay.

So regarding equity affiliate dividend, I think each project is different from -- I think quality is different depending on the project financing.

But in most of the cases, you're allowed to pay dividends.

Of course, at the same time, you reimburse the debt.

So it depends on the documentation.

In fact.

Regarding free current assets of Anadarko, I'm not sure to really understand your question.

What do you mean?

Yes.

If the asset sales don't close in 2020 because there's -- some reason they're being held up maybe on the regulatory side in Ghana or Algeria, are you able to walk away from buying those assets given kind of the crown jewel of the Mozambique part of the sale already closed?

And if you do have the ability to walk away from buying those assets?

Is that something you would be willing to do?

As I mentioned already, so the discussion with the Algerian and Ghanaian authority are still ongoing.

So I cannot anticipate the outcome of the discussion even if, of course, we are optimistic.

So let's wait and see.

We continue to expect this closing in 2020.

But of course, I cannot preempt the authority -- the decision from the authorities.

So let's wait and see.

Once again, in our view, the jewel of the Anadarko assets, it was Mozambique LNG and so the deal was closed.

So it's very, very good achievement to us.

The [return] exchange effect in Q3.

You mean for the result or for the cash flow?

Yes, on cash flow.

On the cash flow, the main impact is in fact for our dividend because you know that our dividend is denominated in euro.

And so of course, depending on the parity between euro and dollar, the amount in dollar could change.

I could add that, that's for the result itself, the sensitivity to the euro/dollar is very limited.

And so by the way, you have all the sensitivities in our documents but it's very -- once again, it's very, very low.

Sorry.

Is that the dividend payment from past periods or in future because there was no dividend outflow for 3Q.

Sorry?

You said the ForEx impact was related to the dividend, but there was no dividend outflow in 3Q.

So I'm wondering if that's related to a past period dividend outflow or future period?

In Q3, there was no dividend but we -- by the way, we cleared the situation and in the coming quarter, you will have one payment per quarter.

That was the last question.

So perhaps to summarize our results, so I would say that once again, this quarter -- during this quarter, we demonstrated that our strategy to reduce the breakeven and to upgrade the portfolio for our long-term sustainability worked well.

The project we have in hand provides clear visibility on strong cash flow growth for the coming years.

And based on this, we are confident that we can create value for our shareholders.

Thank you for your time and attention.

That does conclude our conference for today.

Thank you for participating.

You may all disconnect.