TotalEnergies SE (TTE) 2015 Q3 法說會逐字稿

Good afternoon, and welcome to the Total third quarter results conference call.

Today's conference is being recorded.

At this time, I would like to turn the conference over to Patrick de La Chevadiere, CFO.

Please go ahead, sir.

Hello.

Patrick de La Chevadiere here.

As most of you know, we had our Investor Day in London last month, which was followed by a successful series of roadshow meetings.

Our main message is that we are exiting a heavy investment phase that will revitalize the Company with new growth assets and, in combination with this, we are placing renewed emphasis on operational efficiency and capital discipline.

Our objective is to lower the cash breakeven for the Group, which will allow us to perform more competitively in any environment, and we can accomplish this by starting up the new projects, reducing CapEx, and cutting costs.

Compared to last year, we are in a different environment.

Brent averaged more than $60 per barrel in the second quarter but fell during the third quarter, hitting a low of less than $45 per barrel and averaging only $50 per barrel for the quarter.

European refining margins have been strong for the past year and they remain high in the third quarter, averaging $55 per ton.

Costs have continued to come down, but we think there is room for more.

Against this backdrop, we report a fairly robust third quarter with adjusted net income of $2.8 billion.

Compared to the second quarter, this is a decrease of 11%, reflecting mainly the impact of lower oil prices on the upstream, partially offset by stronger downstream results.

Turning now to a brief review of the segments, starting with the upstream.

Production increased by 2% quarter over quarter and by 10% compared to the same quarter a year ago.

After four start-ups in the first half, we added two more projects in the third quarter -- Surmont and GLNG -- and we are on track to start up two more -- Laggan and Moho Phase 1B -- by year-end.

Yemen LNG is still offline, but remains unaffected by the conflict there.

At this point, we are confident that we will achieve production growth of at least 9% this year -- so, this is a subtle positive revision to the 2015 target -- and as you know, we have an impressive pipeline of growth projects for many years to come.

Adjusted net operating income for the upstream decreased by 29% compared to the second quarter, essentially due to the 24% decrease in our realized liquid price as well as weaker gas prices.

Our LNG business continued to be resilient.

Its third quarter contribution fell by less than the 18% decrease in the Brent price and represented about 30% of the upstream adjusted net operating income for only 15% of the volumes.

Now, moving to the downstream.

The European refining margin indicator, or ERMI, averaged a very strong $55 per ton in the third quarter.

We have been positively surprised by strong product demand, particularly for gasoline.

Petrochemical and marketing have also done very well in a low-price environment.

Our restructured downstream has been very effective in capturing these strong margins, demonstrated in particular by the 90% refinery utilization rate achieved in the third quarter.

Downstream adjusted net operating income was $1.9 billion in the third quarter, a 5% increase compared to the previous quarter and a very impressive 57% increase compared to the same quarter last year.

The European refining margin indicator in dollar per ton has decreased to the low $30s for October.

We have no way to know if this trend will continue or reverse, but we know that this time of the year can be seasonally weaker because we are between the summer driving season and the winter heating oil season.

In any case, it shows the importance of our strategy in the downstream to reduce the breakeven to less than $20 per ton at each site, and our successful cost reduction program is an important part of this.

Our resilience in a volatile environment is largely the result of maintaining strong, integrated business units that can prosper in a variety of scenarios.

And clearly, we recognize the importance of the downstream contribution to the resilience of the Group.

Finally, the corporate section.

Third quarter adjusted cash flow from operations was $5.1 billion, a 5% decrease from the second quarter, demonstrating that we are resilient in terms of cash, which is our priority in a weaker environment.

The results include the benefit of our ongoing OpEx reduction program.

Year to date at the Group level, we are on track to exceed our cost reduction target of $1.2 billion.

This is coming mainly from upstream.

So, we are really starting to see some strong results from the program we launched nearly two years ago.

There is a small benefit from deflation.

I know you will ask me about this, but it is difficult to isolate this impact.

I can tell you that most of the savings are self-help measures linked to changing the cost culture of the Company, and we believe they will have a lasting impact.

The Group's effective tax rate was 27% for the third quarter.

In the upstream, there was a favorable tax adjustment in Nigeria for about $100 million in the third quarter that reduced the effective rate to 34%.

In the downstream, the effective tax rate is close to 30% and since the downstream represents more than half of the operating income this year, it moves the average.

In corporate, we recognized a deferred tax gain for about $100 million this quarter.

Since French activity generated good results again, we were able to use our tax credit coming from losses we didn't book last year.

In terms of guidance, we were in the $100 per barrel environment; the Group effective tax rate was in the high 50%s.

But given the $50-$60 barrel environment we are in, we think the effective rate for the Group should be in the low- to mid-40%s.

Organic CapEx was $5.4 billion in the third quarter, in line with the budget year to date and continuing on a downward trend over the coming years as we start up new projects.

So, we are on track to come in at a low end of our $23 billion-$24 billion target range for this year.

Gearing was 27% at the end of the third quarter, stable compared to the previous quarter.

The take-up on the scrip dividend was 60% in October, compared to 54% in July.

According to our long-range plan with Brent stable at $60 per barrel, we can cover our CapEx and dividend organically by 2017.

So, we will be able to stop the scrip.

But until then, it is reducing our cash outlay by about $3 billion per year.

Going forward, we have the strongest production growth among our peers.

We are reducing costs, and we are reducing CapEx.

Our third quarter results demonstrate that our integrated model is working very well.

We are continuing to execute and deliver on our growth projects, as well as continuing to reduce the breakeven in both the upstream and the downstream.

We have generated $15 billion of adjusted cash flow from operations over the first nine months of the year, despite a drop in the oil price.

And our strategy is to continue to improve the underlying profitability of Total even in a relatively weak price environment.

So, I am ready to begin the Q&A.

And as usual, I ask you to limit yourself to one question at a time.

(Operator Instructions) Oswald Clint, Sanford.

Just a question on maybe Gladstone LNG, that new project that you have.

Could you, firstly, just talk about the performance of it so far?

Should we expect any real OpEx per barrel upward pressure from that development?

And also, I guess the early cargos probably are going into the spot market.

But can you remind us when they start going onto the oil-linked contract?

Is that something that is going to happen in the next quarter?

Or, is that 2016, please?

That's quite a detailed question, Oswald, just to start with.

The maiden cargo was shipped from Gladstone to South Korea on the 16th of October.

So, the good news -- and this is a very good news -- the project was delivered on time and within budget.

And then, the second train will start up in the first half of 2016.

The plant will produce 7.2 million tons.

As far as the price of the LNG of this specific cargo, I remind you that 100% of the sales are under long-term contracts and they are sold, all those volumes, to Korea and Malaysia.

The first ship was sold to Korea.

Okay.

Perfect.

Martijn Rats, Morgan Stanley.

It's Martijn, here.

I just want to briefly ask you, I know the Strategy Day was only -- not that long ago, but if oil stays at this level and with the deflation that is coming through, how would you think about the risk to the CapEx guidance that you've given for 2017?

In line?

Or, could we even see some downside from that?

And secondly, I wanted to ask you if you could elaborate on the resilience that you were talking about in the LNG division?

Is there any particular factor or factors that contribute to this?

First question, about CapEx, the guidance we gave you, the $17 billion to $19 billion by 2017 and onward, was given under the current cost structure.

It is true if we were to face further deflation -- which as of today I have no idea -- but if we were to face further deflation, we could revise this guidance in the future.

But we are not yet ready to do so, not at all.

And we do maintain our guidance of $23 billion - $24 billion CapEx for this year; $20 billion - $21 billion for 2016; and $17 billion to $19 billion by 2017 and onward.

About the resilience of our LNG business this quarter, this is true that LNG providing only 15% of the production and 30% of the result was a very positive result.

And obviously, LNG is a core business for us.

It's a long-term business and based on our projection for global LNG demand, which we expect growing but at about 4% per year, we expect the market to tighten around again by end of the decade.

Thank you.

Theepan Jothilingam, Nomura International.

Theepan, here.

One question.

I think you mentioned the maintenance at Antwerp, for Q4.

But I was thinking about restructuring and news flow on restructuring of the refining business through 2016.

So, could you just walk us through what you think might be sort of the key milestones in terms of bringing the costs down in refining for next year?

One of the main restructuring we are implementing the year to come and in the past year was our restructuring in Europe.

I remind you that between 2011 and 2014 we reduced our breakeven from $30 per ton to $19 per ton.

But in average and, honestly, this is currently La Mede in south of France, which is our weakest European asset with a high breakeven.

So, we will solve this issue and we will restructure La Mede and also Lindsey in the UK.

But the main asset being La Mede next year.

On top of that, we have a project in Donges, which will reduce the refinery breakeven below the $20 per ton.

And shutting down the crude refining at La Mede, which represents about 9% of our European capacity, will improve our average European breakeven by about $2 per ton.

Is that going to be --?

Do you think that's first half or second half type event?

Second half of the year.

Okay.

That's very clear.

Irene Himona, SocGen.

I had one question, firstly, on ADCO, which is part of the 11% production growth in the first nine months.

Is there anything you can say on the economics, on the margins, of that project in the current oil price environment?

I know it's not exactly a fixed margin.

But if there's anything you can share with us, would be very useful.

And then, secondly, going back to the Strategy presentation, you did say back in September that you were planning the long-term CapEx of $17 billion to $19 billion to approach depreciation.

Do you expect DD&A will be as high as $17 billion in 2017?

Or, is it more likely to be $14 billion to $15 billion?

Talking about ADCO is quite difficult, as we are currently under confidentiality agreement and our friends from Abu Dhabi are currently discussing the entry of other partners.

But as a reminder, our entry was effective beginning of January this year.

It's true that ADCO is part of the strong production growth in 2015.

It's fully consolidated.

It's a long-life and low-risk asset.

And there will be technological upside.

ADCO is very resilient in low-oil price environment, honestly.

I'm sorry I can't say more about that.

Your question about the level of CapEx by 2017 and the DD&A level, as of today the DD&A level we expect by 2017 is below $17 billion.

And you are correct $17 billion is a little bit high for our expected DD&A by 2017.

Thank you, Patrick.

Lydia Rainforth, Barclays.

If I could come back to the cost savings numbers and just looking at the idea of being able to exceed the targets that you've set yourself, is that a case of you're just getting things done quicker than you expected for this year?

Or, are there actually more things coming into that than you might have expected?

And then, just a very quick one on refining, if I could?

The $30 per ton indicator margin that you're looking at for October so far, can I just check that that's still above what you're looking at in terms of the medium-term view?

So, it does still feel that the profitability for the downstream into the fourth quarter will be robust relative to what we might have seen over the last couple of years.

Is that a fair assessment?

Lydia, your question of cost savings, if I was able to answer such type of question, I would be smoking a cigar on a beach today, because I would be very rich being able to answer such type of question.

Honestly, I don't know what is due to the fact that we may grow quicker, what is maybe due to the fact that deflation is going faster.

I don't know yet.

That's why we don't give you another guidance for the year-end.

We just maintain our guidance that we will exceed $1.2 billion for 2015.

The ERMI was yesterday at $36 per ton -- $37 -- $36.6, if I well remember.

But that is still above our planning assessment.

Basically, our breakeven target is to be below $20 per ton for each of our assets.

For the budget and the long-term plan, we use an assumption of $25 per ton.

Thank you very much.

Marc Kofler, Jefferies.

Another question on the refining, please.

Thanks very much for the commentary around how you've seen margins on the ERMI evolve since the end of the quarter.

Are you able to give us any guidance around what that means for throughputs and utilization rate?

We may have some turnaround now that we have postponed in the past because we were enjoying very high margin.

I don't know when this will start, could start.

We had obviously a very high utilization rate of about 90% this year.

Last quarter, the overall refined volume increased by 5% compared to third quarter 2014, to reach close to 2 million barrels per day, which is the evidence that our operations are pretty well run at the moment.

This increase, the 5% increase, was mainly due to SATORP, of course, which raised the refined volume by 13% in the rest of the world and obviously also increased throughput in Europe because we wanted to capture better margin.

And we were able to run our asset at a very interesting rate.

With the current margin at $36, I think our objective will be to run our refineries at the highest utilization rate as possible, as we are still making good profit with this.

Great.

Anish Kapadia, TPH.

A couple of questions.

Firstly, I was just wondering if you could give an update on the Mahakam field in Indonesia?

Just what's happening with your contracts over there, from 2017 onwards?

And then, the second question was on your gas realizations.

I was just wondering at current oil and gas prices, what natural gas price realization would you expect in 2016?

I'm just wondering how you would expect that to move from, say, the $4.5 per MMBTU that you've seen over the last six months, given the changes that you're seeing in the portfolio with the likes of GLNG coming online.

So, just wondering how that moves from that $4.5 level under current conditions?

First question, about Mahakam.

As a matter of principle, license renewals are included in our long-term plan, using a conservative risked approach.

So, we attach a probability to the event of renewal of this production-sharing agreement.

In Mahakam, we have operated the permit which supplies about 80% of Bontang LNG for many years and we have keep a deep knowledge of this complex asset.

And I think we do bring a lot of value there.

I think the state recognize that -- the state of Indonesia -- recognize that and want us to stay.

Of course, it will depend on the offered contractual terms for us, but we are willing to continue and operate this asset provided that the term and condition proposed by the Indonesia is reasonable.

For the gas realization, there is no major change expected next year.

I remind you that the main variable for our consolidated gas is the NBP, which is the UK index.

For LNG, most of our volumes are oil linked, and there is a time lag between an oil price and its effect on the gas formula, which is between three and six months.

So, this quarter I may think -- I'm not sure, but I may think that we have a positive effect of the oil price as we face it the second quarter at around $60 per barrel, which has an effect on the gas price on the third quarter.

That's basically what I can tell you.

Thank you.

Jon Rigby, UBS.

Can I ask just two questions?

One, on Yamal, does the status of any external financing, is that going to affect your expectations for your CapEx spending as recognized in your accounts and/or your balance sheets if you have to continue to make shareholder loans to Yamal?

And would it have any actual effect on the pace of the development of the project if you were to do that?

And then, second, just to circle back -- I think I asked the question last time -- on Yemen.

So, I just wanted to catch up again.

Can you just remind me or go through again -- I think you confirmed that the project was still unscathed -- but how long it would take you to get comfortable to restart and then how long the restart process would take?

Okay.

Yamal, first.

We are working hard with Novatek and our Chinese partner to finalize hopefully a financing agreement by year-end.

We are already currently obtaining some commitment by international banks.

This is a long process.

We are continuing it with the objective of concluding this process by year-end.

It is true that if for any reason that I cannot expect now if we were not able to conclude the financing, let's say, in December, but later, one quarter later, let's say, we will have to finance the project by equity, and this will affect our balance sheet.

This is obvious.

But already achieved and bring the project, we reach about 30% construction already, and the speed at which we are building is not a high speed.

We are building it step by step.

So, a delay of, let's say, one quarter -- which I am not expecting -- but a delay of one quarter, for your information, would not have a great effect on our balance sheet.

The works on site are currently -- on Yamal, I'm talking -- are currently going very well, and I have to say that we are very impressed by the ability of Novatek to manage operation in arctic condition.

Let's move to Yemen now.

So, the plant was properly shut down in April, if I well remember, and it has been in a safe preservation mode since then.

And the installations are secured and technically ready to restart if we were to be in a position to restart it.

The integrity of the Balhaf site and its perimeter remain intact.

A team of local personnel choose to remain on site and take care of the maintenance.

There are also safety consideration around, security consideration, also around the site.

And honestly, Yemen LNG will resume production once the circumstances safely permit it.

So, we need to assess the political situation around the site and along the pipeline prior restarting production.

And honestly, today, I can't give you any date.

Right.

Is it reasonable to say a new LNG plant would take three to nine months to ramp up to full capacity?

And if you were to get the green light on Yemen, it would be something (multiple speakers)?

It would be -- my assumption is that it will take less than three weeks to restart operation and load tankers.

Okay.

Very good.

Christopher Kuplent, Bank of America.

Just a quick follow-up, if I may, Patrick?

I'm assuming -- if you can just confirm?

-- that your guidance that you've increased today for full-year production assumes no return of Yemen this year?

And the other question I wanted to ask, if you have time, would be just to give us a little bit of an update on how you see the E&P world around you?

A few weeks ago at your Investor Day, you told us there is organic exploration that you're doing, but you're also monitoring for inorganic exploration opportunities.

If you could just give us a hint or a picture of how you think the current E&P environment is looking like?

Your first question.

Obviously, the revised production target for 2015 at above 9% does not include any restart of Yemen.

About the E&P world around us, and we obviously, as many other and as we did all the time, we are reviewing potential targets, and we did that for several years.

And basically, we did nothing.

We just acquired assets.

That's what we did in the past.

But if you review the value of the E&P companies listed in the US or in the UK or in Australia, they are valued based on $80, maybe $70, but more likely $80-per-barrel scenario.

If you want to make an acquisition of one of these targets, you need to add a premium, which leads to pay $100-per-barrel scenario.

No way.

We are completely unable to do such things.

That's great.

Thomas Adolff, Credit Suisse.

The thing with equity markets -- overvaluing these companies.

Just a follow-up on Yamal, if we say project funding cannot be secured by, let's say -- well, it will be delayed by six months, would Total be still happy to send money to Russia and develop as planned (i.e., not slow it down)?

The second question I had on refining and your portfolio there, perhaps you can give a bit more color what you intend to do with your refinery in the US, as well as the shareholding you have in a Chinese refinery?

In your assumption, which honestly I can't believe today -- I can't expect six months delay; and I repeat myself, we are working hard to complete this financing by late this year.

But if we were to face some delay, which is not my assumption, we will not stop the project and we will continue and finance it by equity as we are doing today.

Refinery in the US, we make clear that we were ready to find a strategic partner with us to be a partner with Total in Port Arthur.

Will it be a successful attempt?

I don't know, but we are working once again hard on this and we will see.

We are currently discussing with potential strategic partners at the moment, and you may have some news -- I don't know -- in three months' time, maybe six months' time.

Those strategic alliance needs time.

Thank you.

And the Chinese refinery?

Honestly, I don't know, Thomas.

This is so small for me that I don't know.

Mike will come back to you on that.

Okay.

Brendan Warn, BMO Capital Markets.

Just one question, if I may, just in terms of GLNG?

And I apologize.

I missed the first couple of questions of the call.

But just in terms of the current operator, Santos -- and congratulations, obviously, on the successful delivery -- but just if there's any -- are there any change of control provisions if Santos is acquired?

And can you just talk about the ramp-up to plateau in terms of spot volumes versus contracted volumes, please?

And just last question on GLNG, in terms of, I guess, the handover from Bechtel, just how active will Total be involved in the, call it, day-to-day operations, certainly as Santos goes through some difficult times?

We tackled the Gladstone LNG project already as the first question.

So, I am sorry that you were late.

I'm assuming that you were on another call.

Correct.

Apologies.

That's too bad for you.

Basically, the project is going well.

Most of the volumes are contracted volumes sold to Korea and Malaysia.

And those are long-term prices and they are oil linked.

Okay.

And you touched on transfer of control provisions, if Santos is taken out?

I don't know.

Okay.

Biraj Borkhataria, RBC.

Just one follow-up on refining and the French refining road map.

It's obviously been a few months since you put the announcement out.

I was just wondering, what exactly have been the steps taken from then to now?

And then, the second question is on divestments.

You increased pace recently heading into the Strategy Day.

And I was wondering, in hindsight, how you feel about the value generated from the various divestments.

The main step in France was the social discussions which have been successful and which clear the process for us to launch this restructuring.

And as you may know, in France this is not obvious at start, but we complete it and we are ready to implement it at the moment.

Works on site in La Mede are being planned for early next year.

About the value of our asset sales, do you know that we have a program of $10 billion asset sales for the period 2015-2017?

Since the beginning of this year, we have already collect more than $4 billion.

We recently collect $800 million from the sale of our pipeline in the UK.

So far this year, we have signed an additional $3.8 billion of new asset sales.

You have two kind of assets we are selling.

You have those assets which are not core for us and where we want to get value; for instance, a pipeline, the midstream, where we can get good value from pension funds, basically.

This is what we did with the recent example I gave you in the FUKA system of pipeline in the North Sea.

There is also those assets which does not stand pretty well in our merit curve, and where we wanted to reduce our exposure in order to reduce within the next year the burden of the CapEx on these assets.

This is mainly the example of Fort Hills.

That's why we sold Fort Hills at a price which may seem discounted.

But the main objective was for us to avoid further CapEx on this tranche of Fort Hills.

Thanks.

That's very clear.

Lucas Herrmann, Deutsche Bank.

I'm feeling very vulnerable, given your response to Brendan, because I too was late onto the call.

But three questions, if I might?

And please don't beat me up.

The first was on the tax rate in upstream, just whether you've got any comments on the very modest level relative this quarter and how you see it moving?

The second was I just wondered whether you can reconcile the associate's line for me in the refining business between the nine-month result you recorded in 2014, which was $245 million, to the nine months this year, which is $445?

Just what the delta is?

I presume it's predominantly SATORP, but some color on that would help.

And thirdly, whether you've got any observations on S&P's change in treatment of hybrids as regards perception of debt?

I know that the companies listed didn't include yourself, but whether it colors your perception of that instrument as a means of financing into the future?

So, be kind.

For the tax rate, it's quite simple.

We had a one-off impact for deferred tax in Nigeria of about $100 million, which explains the low tax rate of upstream this quarter.

For the refining and chemical equity affiliate, I'm not sure I will be able to answer your question.

But, yes, SATORP is involved for this year.

But we also have a strong Korean contribution this year in comparison to last year.

I'm sorry I can't be more detailed, but I ask Mike to review in detail the figure with you.

About the S&P comment on hybrids, as you properly mention we were not in the list of hybrids which were considered by S&P.

From now on, some hybrid instruments will be considered 100% straight debt by Standard & Poor's.

Basically, this is only affect the hybrid including a call option in certain specific cases of rating downgrades.

We don't have that proviso in our first hybrid program.

We do not intend to have such a clause in our hybrid if we were to launch some in the future.

The market price of hybrids have almost not been impacted by this announcement.

I still see hybrids as a low cost of potential equity.

I have no decision taken -- I have not made any decision to continue and issue some further hybrid in the future.

I am fine with the current gearing we have.

And that's basically what I can tell you.

And for the reconciliation of the refining and chemical, Mike will come back to you.

Patrick, thanks very much.

We'll now take the last question, from Blake Fernandez, from Howard Weil.

I wanted to go back on the Port Arthur question.

It seems like most of the feedback we've had from the US refiners is that they're not interested in taking an ownership stake in a refinery where they don't have operatorship.

I didn't know if there was any strategic rationale for Total to maintain operatorship?

Or, if you may be willing to cede control there?

And then, secondly, I know it's probably early days, but any update on Iran would be appreciated.

On Port Arthur, let's wait for us to move, and you will see what we are able to do.

The rumor you heard may be not what exactly we see on the market.

On Iran, the main answer from me is that we will be able to move to Iran when the sanctions will be lifted.

They are not lifted at the moment.

So, we are prevented to make any project at the moment in Iran.

It is true that we are interested in this oil country.

If you will remember, prior the sanctions were implemented, we had an LNG project in Iran, South Pars.

We are still ready to discuss this project, among others, with the Iranese.

But the main issue is that we need to see the sanctions being lifted, and this is not the case at the moment.

Understood.

Thank you very much, all of you, in joining us today, even for those being late.

The main takeaway messages that I would like to close with is that Total is continuing to demonstrate resilience to a weaker crude oil environment.

We are delivering the new project start-ups.

We are reducing our operating cost and our investments.

We still have a strong balance sheet.

And we are well positioned to cope with the volatile commodity price and margin.

And that's it for today.

Thank you very much for joining us.

Thank you.

That will conclude today's conference call.

Thank you for your participation.

Ladies and gentlemen, you may now disconnect.