TotalEnergies SE (TTE) 2017 Q2 法說會逐字稿

Good day, and welcome to the Total Second Quarter 2017 Results Conference Call.

Today's conference is being recorded.

At this time, I'd like to turn the conference over to Patrick de La Chevardière, CFO.

Please go ahead, sir.

Hello.

Patrick de La Chevardière here.

We are very pleased to report a strong set of second quarter and first half results.

We are making excellent progress toward achieving our objectives.

Compared to last year, Total has far outpaced the 9% increase in Brent and delivered a 14% increase in adjusted net income to $2.5 billion and a 33% increase in operating cash flow before working capital changes to $5.3 billion.

On a sequential quarter-to-quarter basis, second quarter adjusted net income of $2.5 billion or $0.97 per share is at the same level as the first quarter despite 8% drop in Brent.

And operating cash flow before working capital changes increased to $5.3 billion from $4.7 billion.

On the first half, we generated organic free cash flow of more than $3 billion, so we are close to covering the full cash dividend at $50 Brent and more than $5 billion of free cash flow, including net asset sales.

The main takeaway from the second quarter and first half results is our demonstrated ability to adjust to this volatile environment and effectively reduce breakeven by delivering the new cash equity barrels, as announced.

Oil price volatility has dominated the environment.

After finally breaking through $50 per barrel in the first quarter, market sentiment reversed course, sending the average Brent price down by $4 per barrel or 8% to $49.60 per barrel in the second quarter.

European refining margins, however, adopt well in the second quarter, averaging $41 per ton.

And petrochemical margins have continued to be good as well.

Regardless of the environment, we remain relentless in our pursuit of cost reduction.

At midyear, we are close to our OpEx target of $5.5 per BOE for 2017.

Year-to-date, organic CapEx was $6.9 billion for the group, and we are capturing efficiencies there as well.

We will continue to cut costs, and these efforts continue to make us more resilient in any environment.

Now I will review the numbers by segment, and then we can go to the Q&A.

Starting with E&P, second quarter 2017 adjusted net operating income for E&P was $1.4 billion, unchanged from the previous quarter despite the weaker environment.

Our average hydrocarbon price realization was $35.5 per BOE, down from $37.9 per BOE in the first quarter.

Production was 2.5 million barrel per day, representing 3% growth compared to a year ago, but a decrease of 3% compared to the first quarter, in part due to seasonal maintenance as was the case a year ago.

We are confident that production growth for 2017 will be more than 4%, so no change in thinking here, mainly on the strength of adding the Al-Shaheen field in the second half plus Kashagan, Moho and the other ongoing ramp-ups, which far offset the natural decline and the OPEC quota impact.

Operationally, we are continuing to execute and deliver.

We sanctioned Vaca Muerta in the first quarter and Halfaya Phase 3 in the second quarter, which will increase production there to 400,000 barrel per day.

In July, we signed the IPC contract for South Pars 11.

Effective July 14, Total took over as the operator of the giant Al-Shaheen field in Qatar, and this will contribute 90,000 barrels per day net to Total starting in the third quarter.

And we are pleased to report that recent start-ups, including Moho Nord and Kashagan, are ramping up as planned.

The main driver for increasing E&P cash flow are production growth for new project and cost reduction.

Second quarter operating cash flow before working capital for the E&P segment was $3.2 billion, an increase of 7% compared to the first quarter despite a drop in Brent.

The new start-ups are making a strong contribution to the average cash flow per barrel, so we have a positive mix effect that will be ongoing as we continue to start up more projects.

Also, cash dividend from equity affiliate increased by about $200 million compared to the first quarter, which is partly a timing effect, as it includes the semiannual dividend from Novatek as well as other affiliate like Nigeria LNG.

It is important to note that with Brent around $50 per barrel, the E&P segment operating cash flow covered its organic CapEx for the second quarter and first half of this year.

CapEx efficiency is improving, and we are able to fund growth with a lower level of investment.

As a last point on E&P, the effective tax rate was 36% in the second quarter compared to 42% in the first quarter.

This reflects a mix effect and sensitivity to hydrocarbon prices.

As a result, the effective tax rate for the group was 28% compared to 31% in the first quarter.

Moving on the Gas, Renewable & Power segment.

GRP contributed $95 million of adjusted net operating income in the second quarter compared to $61 million in the first quarter thanks to better results from gas and power.

Turning to the Downstream.

Refining & Chemicals contribute $861 million of adjusted net operating income in the second quarter.

ERMI averaged $41 per ton compared to $39 per ton in the first quarter, reflecting a combination of a strong product demand and the impact on supply from seasonal shutdown.

For Total, second quarter availability was affected by shutdowns as announced last quarter, mainly at Normandy, Antwerp to implement a modernization program at Leuna.

And for Leuna, the shutdown was unfortunately followed by a fire in one of the unit undergoing maintenance, but the refinery is fully back in operation now.

Despite the shutdowns, Refining & Chemical generated a strong $1.4 billion operating cash flow before working capital in the second quarter, bringing its year-to-date contribution to $2.4 billion.

Cash dividend from equity affiliates increased by about $300 million compared to first quarter, with the semiannual dividend from our petrochem business in Daesan, South Korea representing half of the increase and the rest coming from SATORP and other affiliates.

For Marketing & Services.

Marketing & Services contributed adjusted net operating income of $433 million in the second quarter, well above the first quarter level, reflecting normal seasonality.

For the first half, Marketing & Services adjusted net operating income was $734 million, an increase of 4% compared to the first half last year, thanks to favorable margin and steady growth in the high-return retail and lubricant businesses.

The combined Downstream segment, Refining & Chemical plus Marketing & Services, generated operating cash flow before working capital of $2 billion in the second quarter and $3.4 billion in the first half, in line with our guidance for the full year.

For the first half 2017, Downstream contributed $2.5 billion of free cash flow after organic investment.

Finally, on the corporate number.

We have strengthened the balance sheet, and at the end of the second quarter, gearing was down to 20%.

So this clearly give us a flexibility to implement our strategy to benefit from low-cost environment to sanction projects and to acquire resources.

Organic CapEx was $3.9 billion in the second quarter and $6.9 billion for the first half.

We are in line with our 2017 organic CapEx budget of $14 billion to $15 billion.

Keep in mind that when we close the Strategic Alliance in Brazil, it will represent close to $2 billion.

A quick update on our activity in Brazil.

For the Strategic Alliance, all of the partner have approved the transfer of operatorship on Lapa to Total as well as our entry into lara, and it is now being processed by the authorities.

And for the (inaudible) FPSO, we are well into the commercial bid process.

We expect to make formal announcements on both projects in the fourth quarter.

The group generated operating cash flow before working capital of $5.3 billion in the second quarter and $10 billion in the first half, bang in line with our target.

Year-to-date, with Brent averaging $52 per barrel, our organic free cash flow is more than $3 billion or more than $5 billion including asset sale proceeds.

So we are far better off than we were a year or 2 ago.

All in all, we feel very positive about the results and the cash flow breakeven.

And now I am ready to begin the Q&A.

(Operator Instructions) We will take our first question today from Michele della Vigna from Goldman Sachs.

It's Michele.

I had 2 questions I wanted to ask.

The first one is, what should we expect in terms of tax rate for the group now that you are consolidating the Al-Shaheen production?

And then the second one is related to the scrip.

You had clearly indicated that you wanted to remove it with an oil price at $60 per barrel.

We're clearly far away from it.

But in the meantime, your business keeps improving.

The cost reduction keeps going well.

Deflation continues in the sector.

Would you consider removing it even with a lower oil price, given how well your underlying business is performing?

Thank you, Michele.

Let's start with the scrip dividend because it is a question that was expected, by the way.

Remember that in May, the AGM renewed the scrip dividend policy for 1 more year.

And we wanted to keep the flexibility of the scrip dividend to face volatility, and this is exactly what's happening now.

The oil price was at $45 2 weeks ago.

So we reduced the discount to 5% on the past 3 interim dividends.

And by the way, the take-up has remained strong.

As you can see, looking at our result, our cash position is solid.

And we improve further as project start-up and cost come down.

In 2017, operational cash flow will cover CapEx and the cash portion of the dividend at $50 per barrel.

But I repeat that the AGM renewed the scrip dividend policy for 1 year.

This is to say until May next year.

Question on tax rate.

The effective tax rate for the group was around 28% this quarter, 3 points below 1 quarter, first quarter 2017.

And that was in the lower oil price environment, so there is a relation between the oil price itself and the tax rate.

The E&P tax rate dropped to 36%, 5 point below the first quarter 2017 as it was affected by lower oil price.

This is normal.

Remember that the group tax rate was abnormally low 1 year ago at 22% because of a very low oil price at that time.

So if you're asking me guidance for the tax rate going forward, Downstream should be pretty stable around 30%.

With Brent in the range of $50, we would expect E&P tax rate to be between 40%, 45%, I would say, and the group tax rate up to 45%.

Al-Shaheen doesn't change this guidance.

And thank you for your question, Michele.

We'll now go to our next question from Brendan Warn from BMO Capital Markets.

It's Brendan Warn from BMO.

If I'm just following on from that question on scrip, I appreciate you've got another year of the actual scrip being maintained, but can you just talk around what you need to see before you eliminate the discount that you currently offer?

Is it still sort of the $60 a barrel or considering how well the underlying business is going?

Think I barely already answer the question for on the scrip, but in order to reduce the discount, I need to see a higher oil price.

Okay.

So your still wedded to the $60 a barrel to eliminate discount.

I say to higher oil price.

Okay.

Okay.

And just follow-on question, if I can just ask, you flag about taking FID on projects.

Is there anything further you need to see in Uganda to move that project to FID?

So let's talk to Uganda a little bit.

So you know that we own 37.5%, if I will remember, post government backing.

We are progressing well, I have to say.

The pipeline FEED contract has been awarded.

While for the upstream portion, the competitive FEED process is underway between (inaudible).

Uganda and Tanzania on May 26 signed the Inter Governmental Agreement, setting the legal and tax framework for the midstream activities, which was an important milestone.

And this represents, of course, another step forward.

So overall, we remain on track to be on a position to take FID sometime around the turn of the year.

Total CapEx is estimated to be around $8 billion, including the pipeline, of course.

So this is a resource base, which is less than $10 per BOE what we expect.

We will now go to our next question today from Theepan Jothilingam from Exane BNP.

I just wanted to ask a quick question just in terms of project execution for the next 6, 9 months.

If you could just give an update in terms of Kaombo and Ichthys, please?

And then secondly, I think you flagged in the outlook piece how well the Downstream is performing.

I wanted to understand in that Downstream number, how much self-help do you think has been achieved in the last 12 months or 2 years?

So let's talk, Theepan, on the project execution.

And let's start with Kaombo, where we own 30%, and we are the operator.

First oil from the first FPSO is expected March, April 2018, and the second FPSO, let's say, 6 months later.

The FPSO Norte is more than 90% complete and will sail away from Singapore later this year.

Start-up is planned in 2018.

The second FPSO is more than 75% complete, and start-up is planned in 2018.

Currently, 2 rigs are on site at the moment.

And this is a PSC, I remind you, and the cost recovery will make the cash flow per barrel very attractive.

Let's move to Ichthys.

So Total, 30% again.

We are not the operator.

We are technical advisers to the operator.

This is INPEX, the operator.

And as per the statement from INPEX, the FPSO sailed away from the shipyard in Korea on July 18 and should reach the Australian coast in approximately 1 month.

The moving of the CPF was completed on site on June 20.

All the subsea installation is ready.

All flow line and major structure has been installed.

Underground, all LNG plant module have been delivered and installed.

The onshore works are more than 90% complete.

So overall, we can say that the Ichthys project is making steady progress.

The operator, INPEX, maintained its schedule, as communicated in April, start of production of offshore condensate before the end of 2017 and start-up of LNG production before the end of March 2018.

This is as per INPEX statement.

Then you have a question on self-help.

We obviously are very well on track to deliver $600 million saving in Refining & Chemicals over period 2016/2017.

The same, up to $400 million for the Marketing & Services.

And honestly, we are happy with the Downstream contribution, which as we gave the guidance of $7 billion of CFFO for 1 year.

The breakeven is reducing, and we are fully capturing the margin.

I remind you that this quarter, we had a huge maintenance program, and on top of that, some kind of incident in Leona.

But all in all, this is basically a huge maintenance program that we face second quarter 2017.

Thank you, Theepan.

We'll now go to our next question today from Irene Himona from SG.

Two questions, please.

Firstly, you mentioned, obviously, the cash accretive nature of your new barrels.

I wonder if you can tell us something about the cash margins in the current, obviously, oil price environment, cash margins at Al-Shaheen in Qatar but also Kashagan, please.

And then secondly, thinking about second half cash flows, can you please remind us in terms of your announced deals, what do you know you will be paying and receiving for asset acquisition and sales?

I'm not sure I fully understood your second question.

As about the cash margin, if you remember, the cash flow from ops margin per barrel in 2020 should be around twice the level of the current margin we are facing or rendering at the moment.

This effect, all in all, the portfolio is a mixed, long-plateau asset and high-margin deepwater project.

That is our portfolio.

And I'm sure you know that.

And for example, Moho is running very well since its start-up in first quarter this year and generates about $40 per barrel of margin this quarter at $50 per barrel, a little bit more than $50 per barrel.

On Al-Shaheen.

Al-Shaheen is currently producing 300,000 barrels per day.

For us, as we are the operator since the 14th of July, this will add 90,000 barrel of low-cost production for 25 years.

I remind you that we have very little capital employed, and that investment will be recovered very quickly from the existing production.

I remind you also that we pay a $35 million bonus, which is fine when you enjoy 90,000 barrels per day of production.

So all in all, Al-Shaheen is a good project, you know that, and we are very happy to have it in our portfolio while the oil price is in the $50 per barrel at the moment.

Sure.

My second question was very simply, you have announced various acquisitions in Brazil, et cetera.

So of those announced deals, can you just remind us what you're due to pay out in the second half of the year?

And the same for any disposals that you have announced.

Brazil, we expect to pay around $2 billion.

I think this will be last quarter this year.

We have not announced yet our -- the result of the process of the sale of our Italian Downstream business.

We are currently negotiating the final term.

Basically, for the disposal plan, we have now achieved about 90% of the disposal program.

We announced the sale of some major asset in Gabon for about $350 million; the sale of a pipeline, whose name is SPMA pipeline, product pipeline in France for $150 million.

So clearly, we are at the end of our program at the moment.

Total leg in Italy is currently being monetized.

I can't tell you the number, but we are very close to finalize something.

We still have major FEED and midstream asset that we can sell, but basically this is the end of our program.

Sure.

And sorry, have you paid for the Ugandan deal with Tullows yet.

A small amount.

We will now move to our next question from Christyan Malek from JPMorgan.

Firstly, several of your competitors talked about a low-forever oil price outlook.

Could you provide us an update on how you think oil prices are going to evolve over the medium term?

The second relates to your investment in South Pars, Iran, and apologies if this is perhaps a bit more sensitive.

But how would you frame your long-term strategy in Saudi in light of the geopolitical tensions between both countries?

Is there a plan longer term of taking an oil-related investment in Iran?

And third question, I understand the flexibility you want to provide the capital framework with a fresh alternative to scrip at $60.

But in light of the fact that you're leading the sector now with achieving cash and charity close to $40, is it fair to say that in essence, you're choosing to prioritize growth CapEx ahead of paying full cash dividends?

I don't agree with your last statement, but I will stick with my comment.

I already answered 2 question on the scrip, and I think this is enough.

Going back to, Christyan, your first question on oil price outlook, I think that instead of predicting oil prices, we remain focus on the things we can control, like reducing the breakeven.

This is the best way to face volatility.

And this is how Total outperformed its peers since 2014.

However, consistent with our view, oil price has been volatile this year and unlikely, in our view, to remain so until the market has more clarity on the supply-demand equilibrium.

For the short term, we don't see any reason, which could explain substantially higher oil price.

Nevertheless, the agreement between OPEC and Russia last year is an historic agreement.

The recent announcement to extend the cut for 9 months is a good news.

It demonstrate their commitment to sustain prices.

Nevertheless, we see volatility between $45 and $50 per barrel at the moment.

And as I told you, there needs a catalyst.

This catalyst could be lower inventories level in the U.S. that we don't see actually at the moment.

So far, stocks remain high at more than 3 million barrel, according to the IEA, notably due to the strong shale production.

And on top of the shale, there is the increase of Libyan and Nigerian volumes.

So we maintain the idea that oil price will remain volatile.

And I refer to my comment on the scrip.

This is a good reason why at the moment we are happy to be permitted by the AGM to use a scrip dividend.

Your question about Saudi and Iran, I think those people are pragmatic.

I'm talking about the Saudi and the Irani.

We are not making politics.

We are not politician.

We are doing businesses.

And the Saudi knows and we make them aware of before signing with Iran.

So the Saudi knows that we were ready to sign an agreement with Iran, and they gave us the go ahead because this is business.

This is not politics.

And there is no conflict between -- in our portfolio between those 2 assets, the one we have in Saudi, the one we will have in Iran.

On top of that, I remind you that our first project in Iran is related to domestic gas, and I insist on the qualification domestic.

On top of that, we have broad presence in the Middle East.

We have been transparent with our activities and strategy in Iran, mostly everywhere, in Qatar, U.A.E.

and of course, Saudi as we talk about.

We believe that they understand our position.

And once again, we are doing business and not politics.

Just to be clear, would you consider investing in oil and sort of oil production-related exports in Iran in the longer term?

Or is that something not on the horizon?

There is no ban on project leading to export oil on Iran as far as I am aware of.

We'll now go to our next question from Biraj Borkhataria from RBC.

I had a couple, please.

The first one is on your entrance to new acreage in Mauritania.

I was wondering if you could talk about the rationale there and the next steps you'll be taking going forward.

And then the second question is one of your Canadian operations, Suncor just announced that they were in a commercial dispute with you.

I was wondering if you could talk about or give any color on what that relates to and any details there.

Let's start with Mauritania first.

We acquired Block C7 in Mauritania, which lies northeast of our existing C9 block, and we have 90% equity share in this block.

At the same time, we entered into a block in Senegal.

I think that for exploration, you should wait for our presentation in September where there will be a dedicated presentation to exploration.

And McLachlan will be, of course, at your disposal to answer all of your question.

But you will have more detail in his presentation.

That's what I am aware of.

Fort Hills, if you will remember, first half conference call, I said that we were writing off a portion of Fort Hills because of the cost increase of this project.

And this was done first half this year -- first quarter this year.

Basically, we are not ready to accept a substantial cost increase on the Fort Hill mine from the operator.

That leads to what is called a commercial dispute by Fort Hills, who is the operator of this field -- mine.

We'll go now to our next question from Thomas Adolff from Crédit Suisse.

Patrick, a few questions for me, please.

Just firstly on Papua New Guinea.

Perhaps you can comment on some of the early discussions you have had so far with Exxon: encouraging, tough to deal with, or not much has happened so far.

Secondly, going back to disposals.

You said you're almost complete with your disposal plan.

So how should I think about your noncore Hutchinson stake in today's world?

Would you only consider selling it part or in its entirety if you think about a bigger deal elsewhere to high grade your portfolio?

And a very cheeky, last one, if I may.

Moving away from scrip, but talking about the dividend currency.

Have you made up your mind how you can keep the U.S. dollar dividend steady?

I know under French law, you have to set it in euro terms.

Okay.

Let's start with Hutchinson because this is very clear, Hutchinson is part of the group.

This is fully integrated.

It is perfectly managed at the moment by the current management of Hutchinson, and it's part of the group.

And we want it to be kept within Total group.

So I make it clear so that all the bankers we are talking with do not come again in my room to present some possibility of selling Hutchinson because sometime, I am a little bit fed up.

Dividend in U.S. dollar, honestly, frankly speaking, we look at it very carefully.

It's such a nightmare.

We need -- basically, we need to convince the French government to allow us to be permitted to maintain social books in U.S. dollar to be permitted to pay a U.S. dollar-denominated dividend.

If not, it doesn't work.

Sorry for that, but that's the law in France.

But we are ready to make the point to the new government.

Let's then start working, and we will make the point.

Papua New Guinea, it's a low breakeven, very competitive project.

Synergies will make it better, but there is no emergency at all.

And I think that's it.

We are, of course, coming back on Suncor question.

We, despite the dispute, we are making discussion -- we are in discussion with Suncor to reduce those cost.

It is not only a position to say no.

It is also behavior from us to help Suncor and reduce its cost.

We'll take a question now from Martijn Rats from Morgan Stanley.

I have one question, which relates to the credit rating.

S&P has had you on a negative outlook now already for some time, and they recently wrote about all the global majors and reiterated their view.

At the same time, your cash flows continue to be quite strong.

And I was wondering, well, first, in your view, do you expect that perhaps you can actually maintain that A+ credit rating, which is the strongest amongst your peers?

Secondly, if not, whether that actually has much implications for how you run the business and the financials?

To make it very simple, Martijn, usually, we do have our meeting then review by Standard & Poor's and Moody's late October.

I want both meetings to be held as soon as possible returning from vacation, let's say, September, because I think that we demonstrate our ability to generate cash flow from ops that they have to valued in the assessment they make of our rating.

So I want to speed up the process of discussion with them.

All right.

But do you think, given what you're currently seeing, maintaining that A+ rating is a possibility or even a likelihood?

I think so, but I am not in the mind of those people.

Lydia Rainforth from Barclays has our next question.

I have 3 very quick question for you.

Can you just walk through where you think the net debt to equity ratio will be at the end of the year, so just given all the moving parts within that?

And then secondly, can you just update us on where refining margins averaged year-to-date?

So I know you say, but just for July.

And then just finally, on the CapEx numbers.

There was a bit of a step-up in 2Q versus 1Q, and I appreciate it's averaging out to the budget for the year.

But just in terms of, if there was anything unusual in this quarter for spending?

Well, the first question about gearing, yes, our gearing is low at the moment.

But keep in mind that we haven't paid the $2 billion for the acquisition of our Strategic Alliance in Brazil.

So it's about $2 billion, so let's say, 2% of additional gearing.

So all in all, if the working capital is stable, we should reach gearing of about 22%, 23%, if everything remain in the $50 oil price environment.

The second question was on refining margin.

European refining margin was at $41 per ton second quarter, and this is obviously benefiting from the seasonal maintenance as well as continued strong demand that we have in Europe and elsewhere.

So far, this quarter, the refining margin remain around $40.

We enjoy a strong gasoline and fuel oil tax as we see less fuel oil export out of Russia following upgrading projects.

Going forward, I would say that strong product demand is directionally positive, and that the International Energy Agency just revised its growth forecast to 1.4 million barrel per day in 2017.

So all those information are good information for the benefit of refining margins.

For petrochem, the petchem margin remains very favorable, second quarter 2017, benefiting from strong demand and also cheaper feedstock prices.

We are taking full advantage of the margin, notably thanks to strong operational performance and our -- and of course, thanks to our large integrated platform in Asia and in the Middle East and in the U.S. And all those platform are running pretty well.

So you had a third question, Lydia.

As usual, you ask 3 question.

That one was about CapEx guidance.

At group level, organic CapEx first half stood at $6.9 billion, well in line with our guidance, and we don't change it.

For the group, we plan to invest $14 billion to $15 billion organic CapEx in 2017, excluding resource acquisitions, so you have to add around $2 billion as I mentioned to you on Brazil.

Financial discipline is the core of our response to the environment.

We are investing through the cycle taking, currently, of the advantage of a low-cost window.

We will, of course, update you in September.

We'll now go to our next question from Alastair Syme from Citi.

I thought I might ask you another question on the scrip dividend, but I won't.

So I'm going to ask you about deepwater FIDs instead.

You've got 3 in your project queues: Zinia Phase 2, Libra and Bonga South West.

Could you just maybe give us an indication of timing on FID, or at least in terms of how you think they order in terms of timing and their relative economics?

So let's talk about FIDs, Libra, Bonga and so on.

Basically, we are making good progress, and let me give you this update on our different projects.

In Argentina, we sanctioned the first phase of the Aguada Pichana Este development in the giant Vaca Muerta shale play, and we increased our share to 41%.

We also launched the expansion of the gas treatment plant in Tierra del Fuego.

This is the first step towards taking FID for the Fenix project next year.

In Azerbaijan, we sanctioned the first phase of Absheron.

In Uganda, we, as I told before, we awarded the FEED for both upstream and pipeline.

In Thailand, we recently took the FID for the expansion project on the Bongkot North field.

In Brazil, we are currently evaluating the commercial bid for the Libra.

In Nigeria, the project team has been mobilized for the EKK project.

On Libra, the call for tender process is moving forward, and the commercial bids are being evaluated, as I told you.

This is obviously an excellent project, and we are confident that we can lock in low development cost.

Northwest panel alone is similar in size to Angola Block 17.

Bonga, I think if you were listening to the Shell conference, you had information about that.

So Alastair?

So did you mention -- sorry, did you mention Zinia Phase 2, Patrick, of...

No, sorry.

You're right, I forgot about Zinia Phase 2. We own 40%.

Discussion are still ongoing with Angola authorities to give you the fiscal term of this project.

We would be in a position to take FID once all discussion has been completed, which is not yet the case at the moment.

So just a follow-up, do you think we'll likely to see a sanction on Libra or Zinia before the end of this year?

Or we can see them as 2018?

For Libra, yes.

Jon Rigby from UBS has our next question.

Two questions.

The first is, I think you acknowledged actually in the second quarter about the effect that dividend payments can have on your cash flow timing.

So I just wanted to ask a question around Ichthys and Yamal as they come online.

How should I think about any difference -- or the differential between what you're showing as net income, the pickup of affiliate income, on what you get in terms of cash out from those affiliates, given the quite significant amount of project financing that sits in there?

And then my second...

Please go for your second question.

Yes.

So my second question was, I think you've been very realistic in the way that you frame your CapEx outlook, which is to include and acknowledge the fact that there is going to be some inorganic as -- in addition to the organic spend.

And we're sort of into that phase where you've been making quite a lot of builds and formulating of builds.

So I just wondered, as we move forward, are you able to sort of characterize what is likely to be the type of new entry and new project that you are seeking to introduce into the portfolio through that sort of inorganic element of your CapEx spend?

On the second question, we make clear that every year, we will include, in average, about $2 billion of acquisition of undeveloped resources.

And we will continue like this.

It might not be exactly $2 billion every year.

But in average, that is what we believe is necessary to maintain our growth in the future.

And basically, we are pragmatic.

We will buy the most attractive in term of return.

If there is a large opportunity, we will take it.

If there is no opportunity during 1 year, we will keep silent, and that's it.

About dividend payment and project financing, I saw some confusing comment in the market.

We are using project financing.

It's a financing as the other.

I mean, it's a financing attributed to one asset, wherefore, the other project, you have the financing belonging to the mother company, for instance.

And I think this is well-known, including in our reference document, and well-known to people familiar to Total also.

Often, those type of financing, like the one we had in Ichthys or the one we had in Yamal, is the best way for some of our partners to fund in their share.

And we want, in order to implement our projects, of course, that each partner be funded.

It is also, and I insist on that, project financing is a very good test to assess the strength of a project.

It is, of course, also an efficient way to optimize capital.

All the target we gave you in term of cash flow, and I remind you, we gave a target of cash flow from operation in Upstream of more than $7 billion in 2020.

That is at $60 from new project.

And this is taking into account the structure of the financing allocated to those projects.

And we -- the dividend will be paid after reimbursement of some debt.

We sometime participate to the financing themself, so we recover some cash for reimbursement of debt.

I think we explained last year in September, our new start-up will add more than $7 billion, as I told you.

And this is, obviously, on that basis that we gave this figure.

This is cash flow net to Total.

We'll go to our next question now from Oswald Clint from Bernstein.

I wanted to ask about the other Middle Eastern project that you -- I think we've heard a lot about Al-Shaheen being a good, strong project; Iran, also with robust economics.

What about this Phase 3 at Halfaya?

Can you just talk about the attractiveness of that additional expansion at that project, please?

And also, if Iraq wanted to expand further, would you be willing to do so in that country?

And then secondly, I mean kind of related to last question, I noticed the JV with Cobalt has stalled or been canceled.

Is that -- should we read that -- should I interpret that as Cobalt's got some issues?

Or these joint ventures, to access resources through exploration JVs, doesn't really work for Total, and we should expect Total to really start drilling some bigger, more -- kind of much bigger wildcat-type wells going forward?

On Cobalt, this is very simple.

Cobalt is facing financial difficulties, and it was not the best partner for us to continue on those kind of joint venture.

I hope that Cobalt will recover, but at the moment, they are facing difficulties.

On Halfaya, you know that we own 22%.

We sanctioned Phase 3. This will raise the production plateau from 200,000 to 400,000 barrels per day.

This will include the construction of a new central processing facility and the drilling of more than 100 wells.

So it's a big project.

The operator awarded the contract in April and work has begun.

We are pragmatic this Phase 3 project is good, and we participate in the sanction of it.

Iraq, again, we are pragmatic people.

If we see good opportunities, making good return, why not participating in it?

And we, on this particular Halfaya project, are very happy with the ability of NPC to operate this field.

Our next question now comes from Rob West from Redburn.

I would also like to ask about the project level financing and that number you gave a moment ago of your $7 billion Upstream cash flow target.

What you said was net of all of the repayments of debt in those joint ventures.

Can you tell us in that year what repayment of debt are you assuming in those joint ventures?

So is it, for example, $1 billion being repaid and your $7 billion is net of that?

That would help me understand how to think about the quantum there in your guidance.

The second is on a country with big resource potential that has been remarkable in stabilizing over the course of this year, and you mentioned a bit earlier.

It's Libya.

And interestingly, I think the latest agreement between Haftar and Sarraj, the 2 main power brokers in the country, took place on French soil.

I was wondering, could you comment on appetite to reenter and look at resources within Libya in the future?

And what would you need to see, to the extent that you have looked at it, to move back into operating in that country on new projects?

And then the third question, really, really quick.

You said that Moho was getting $40 a barrel of cash flow, which is fantastic because that's quite a lot ahead of the cash flow model I've got.

Could you tell me how long do you expect it to run at that sort of $40 a barrel level assuming $50 oil stays flat?

I need to come back to some accounting principle in order to avoid confusion.

If it is an incorporated subsidiary, where we own less than 50%, basically, we use the equity method to consolidate the affiliate.

And then in term of cash flow, we only have access to the dividend.

If it is an unincorporated JV, we have the full access to all of the cash flow whatever is the financing in term of accounting.

That to make things clear according the IFRS rules.

And I repeat, all the target we gave you in term of cash flow from ops and CapEx are, of course, consistent with this principle.

We include in our guidance for cash flow from ops our best estimate of the dividend and capital reimbursement we will receive from the equity method affiliate, after, of course, repayment of debt, if there is some order in the allocation of cash flow in those subsidiaries.

But sometimes, you have equity affiliate bearing project financing, where you reimburse your project finance.

And it's still remaining cash available so that you can pay dividend.

A good example is SATORP, where there is a huge project financing available on this company, and SATORP was able to pay a dividend first half this year.

That's great.

That's the first one, I think.

You will see more than that.

Libya, we are glad today to recover some production from our field of [Mozuk] operated, I think, by Repsol.

Unfortunately, our Mabruk field has been destroyed, and we need to rebuild the field itself if we were to want to recover the production of Mabruk.

We are not yet ready to do it now under the instability we see in this country.

I hope it will be better.

I hope that peaceful period will start in Libya, and the sooner will be the better for the people living there.

But for us, reentering on Mabruk at the moment is difficult.

On Moho, remember Moho, it's a production sharing contract.

So we will recover our cost and enjoy a share of the profit oil.

Of course, currently, we are in a recovery mode of our past CapEx.

In the current oil price environment, we will keep for quite a while a lot of barrels from the cost recovery because we are recovering our CapEx.

So we will stay, I think, quite long at $50 with high margin.

Okay, that's great.

I didn't get -- I'm not 100% sure I understood how much equity-level debt you are assuming you're paying down in your guidance, but I'm happy to wait or to follow up on that offline.

But if you did want to give a comment on the quantum of debt that's been repaid within the Ichthys and Yamal JVs in 2020 in your guidance, I would be interested.

Okay.

It's noted.

We'll now go to our next question from Anish Kapadia from TPH.

Couple of questions for me, please.

On the Middle East, given your significant investments in the Middle East and some of the issues that we're seeing in the region at the moment, I was wondering if you could give some idea of your exposure, kind of what percent of your cash flow or capital employed you see coming from the region.

And what you're doing to maybe mitigate some of the risk?

How comfortable you feel with your exposure?

The second question is looking at the outlook for LNG.

I was just wondering how you rank the current projects you've got within your portfolio.

I'm thinking of NLNG, next trend there; PNG; the U.S. JV with [Tororian]; and kind of how those compare with you may be going into some newer projects in like lower-cost countries, such as Qatar or Iran.

First question about our exposure, honestly, I don't have exact figure with me.

Qatar is around $3 billion capital employed.

This is the largest country exposure in the Middle East we have.

In Abu Dhabi, we have at least $2 billion, I think.

That's basically the main figure I have, but I ask the IR people to check both figures and to come back to you if anything is wrong.

The ranking of our LNG project and the impact of Qatar.

Qatar announced the end of the moratorium a few months ago, and they stated they intend to grow their production to 100 million ton a year from 75 million.

We see something like 10 million potentially coming from debottlenecking, so very low-cost-base LNG volumes coming from Qatar.

Total is a strong partner of Qatar.

And we will, of course, very positively consider any further cooperation and expansion of our works in this country.

We recently entered in the Al-Shaheen field.

Of course, we are very much interested in participating in the expansion of LNG in Qatar because we believe this is one of the cheapest LNG around the world.

So this one is ranking at the top of the line.

And I can tell you, if you compare a biogas, deep offshore project to Qatar, it's a no-brainer.

A large increase export -- in export volume from Qatar could put pressure on the less-competitive LNG project like, I'm sorry to say that, deep offshore biogas, that's for sure.

If you compare to other project like Nigeria LNG 7, which is either a new train or more debottlenecking, this one is always very well positioned on the curve.

PNG, it's an onshore with project with synergies, very located close to the market.

This one seems to be a good project also.

Lately, we are enjoying a full integrated chain of the shale gas in the U.S. should be a good project also.

We will now take our last question today from Christopher Kuplent from Bank of America.

I'll try and keep it very short.

But not really asking you for a preview of what you're going to present in September, but obviously, not so long ago, BP held its downstream day presenting quite a bullish growth outlook for marketing and downstream in general.

So wonder whether you want to reiterate and highlight where that $7 billion number can go to over the next few years, whether you think you've got access to similar growth prospects.

And just tiny, tiny question on Fort Hills.

Do you think that dispute that you're in right now will delay the schedule of the start-up significantly?

First question, you will obviously have the answer in September.

Downstream is a very important branch in our company.

And in our presentation in September, you will have an update of our target in Downstream.

Fort Hill delay, ask Suncor the operator.

I'm not the operator.

We are working to avoid further cost increase.

And I'm sorry, I can't answer this question, and ask the operator.

There is something strange in all your question, and nobody made complement on us that we were able to cover full cash dividend at $50 per barrel.

This is the great news of the quarter.

I think this was the last question.

We were obviously pleased, pleased with the second quarter and first half results.

All segment are performing well.

The evidence is the cash cover of the dividend, the full cash cover of the dividend, fully cash at $50 per barrel.

Production is growing.

We are managing our cash flow positively in the current environment.

I look forward to seeing you in September at our Investor Day and presenting our latest outlook with the rest of the Executive Committee.

Bye-bye now.

Thank you.

That will conclude today's conference call.

Thank you for your participation, ladies and gentlemen.