TotalEnergies SE (TTE) 2017 Q1 法說會逐字稿

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

Today's conference is being recorded.

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

Please go ahead, sir.

Hello, Patrick de La Chevardière here.

We are pleased to start the earnings season with a strong set of results.

First quarter adjusted net income was $2.6 billion, an increase of 56% compared to a year ago and 6% compared to the previous quarter.

On our underlying business, this puts our return on equity back above 10%.

Adjusted cash flow from operations was $4.7 billion and organic free cash flow was also strong at $1.7 billion.

The first quarter environment was generally favorable compared to the past period.

Brent was $54 per barrel, a 58% rebound on a year ago.

Downstream margins continue to be good but polymer has come down from the very high levels of last year.

And internally, we are continuing to increase production and cut costs.

We maintain the pressure on costs and compared to our 2014 days, our objective is to reduce OpEx by $3.5 billion in 2017 and $4 billion in 2018.

The progress this quarter is in line with our expectation.

Quarter-to-quarter, E&P technical cost are down by 7%, E&P OpEx is at $5.6 per BOE, so we are on target to achieve our cost-reduction target of $5.5 per BOE for this year.

As usual, I will give you the number by segment and then go to the Q&A.

We have now 4 reporting segments.

In the Upstream, we have E&P, plus the new segment Gas, Renewable and Power.

In the Downstream, we have Refining & Chemical, plus Marketing & Services.

We have a pro forma split for 5 periods and I will be referring to these numbers for all of the segments.

Starting with E&P.

First quarter 2017 adjusted net operating income for E&P was $1.4 billion compared to $0.4 billion a year ago and $1 billion in the previous quarter.

Brent, as we covered from a year ago, and our average idle carbon price realization was $38 per BOE in the first quarter, an increase of 44% year-to-year and 6% quarter-to-quarter.

Production increased by 4% on a year-to-year and a quarter-to-quarter basis to 2.57 million barrels per day.

We are targeting position growth of more than 4% this year.

About 2/3 of the increase in 2017 is coming from ramp up on project that started last year, the largest being Kashagan.

Along with the new 2017 start-ups, the main contributor is Moho Nord, which started as planned in March and will add about 30,000 barrels per unit in 2017.

The Barnett acquisition made a positive contribution to production growth in the first quarter.

The Al-Shaheen field in Qatar will begin adding production in the third quarter.

While there may be some impact on the full implementation of the OpEx cuts, the main message is that we have effectively derisked the production growth story for 2017.

As we increase production, all else equal, cash flow from E&P will continue to increase.

Adjusted cash flow from operation in this quarter was $3 billion, an increase of 63% from last year and 5% from the previous quarter, basically, in line with our established 2017 sensitivity.

Operationally, we announced today that E&P sanctions have started of its 10 major projects, phase 1 of the Aguada Pichana Este, development of the giant Vaca Muerta, shale play in Argentina.

Total is the second largest acreage order in the Vaca Muerta, with more than 300,000 net acres and with these the operator of Aguada Pichana Este, with 41%.

The project benefits from the low-cost environment, existing capacity in the Aguada Pichana, gas-producing facilities and an attractive gas pipe set by the Argentina authorities.

So we are very pleased to be moving forward in the next wave of Upstream developments.

Moving onto our new Upstream segment.

Gas, Renewables and Power contributed $61 million of adjusted net operating income in the first quarter, compared to $73 million a year ago and $132 million in the previous quarter.

The bulk of the GRP results are coming from our well-established Downstream gas business, including LNG trading.

These businesses are growing steadily and delivering results.

The results also include our new battery business from the Saft acquisition last year.

And we are pleased with the way it is performing.

We cannot comment on some of our results, but I think most of you know this is a difficult time for Upstream solar cell producers.

Looking forward, I remind you that we are expanding our organic business, including new opportunities with LNG [as a fuel] in Ivory Coast, Pakistan and Brazil, as well as a new partnership in Singapore for LNG bunker fuel.

Turning to the Downstream.

Refining & Chemicals is continuing to perform at a high level, contributing $1.02 billion of adjusted net operating income in the first quarter, in line with $1.13 billion a year ago and $1.13 billion in the previous quarter.

ERMI averaged $39 per ton in the first quarter compared to $35 per ton a year ago and $31 per ton in the previous quarter.

Petrochemicals margin are still good but have come down from the very strong level a year ago.

And remember that under IFRIC 21 rule, we load a full year of property taxes in the first quarter.

First quarter Refining & Chemicals generated more than $1 billion of adjusted cash flow in the first quarter, down by about $0.3 billion on a year-to-year and quarter-to-quarter basis.

Keeping in mind the lower petrochem margins and a one-off payment of about $100 million for the tax related to (inaudible) gain, the first quarter adjusted cash flow is in line with our expectation.

Including working capital changes, cash flow were $1.7 billion, stable on a year-to-year and quarter-to-quarter basis.

Operationally, over the past 2 months, we sanctioned 2 major petrochemical projects.

In the U.S., we formed a joint venture to expand our petrochemical on the Texas Gulf Coast.

Total will add 50% of the venture with polyethylene industrial partners Nova and Borealis.

The main thrust of the JV is to bring the 1 million ton a year ethane steam cracker for $1.7 billion at our Port Arthur site, allowing us to capture significant synergy.

The deal is consistent with our long-term use of gas will be plentiful in the U.S. and provided with advantaged ethane, feedstock and low-cost energy.

We also announced a $450 million expansion project at our site in Daesan, South Korea.

It will take advantage of low-cost operating to produce ethylene for the Chinese market and capture significant Bond Seal CNG.

These new projects are examples of our strategy to get advantage of existing world-class platforms to capture profitable growth opportunities linked to advantage feedstocks and to benefit from the low-cost environment to sanction cost-competitive projects.

From Marketing & Services, just a reminder that the New Energies are being moved from here to GFP.

Marketing & Services generated adjusted net operating income of $300 million in the first quarter, an increase of 4% compared to the same quarter last year, a positive start for the year.

In March, we finalized the acquisition of the GAPCO marketing network in East Africa, and we should see a positive effect this year.

The main assets are 2 logistic terminals in Mombasa, Kenya and Dar es Salaam, Tanzania, that provide increased opportunities to supply our network.

We also add more than 100 retail station in Kenya, Uganda and Tanzania, which strengthens our leadership position in Africa and supports our goal to grow our high-return retail position by 4% per year.

The combined Downstream segments, Refining & Chemicals plus Marketing & Services, generated free cash flow after organic investments of $1.1 billion in the first quarter in line with the expected cash contribution to the book.

Finally, looking at the corporate numbers.

The first quarter adjusted results exclude some nonrecurring items, the main one being $2.1 billion gain on the sale of Atotech, which closed in January; and the $1.3 billion impairment on Fort Hills, following a significant cost increase announced by the operator.

The group's effective tax rate was 31% compared to 23% last year and 31% in the previous quarter.

The rate for the E&P is sensitive to change in all times, and it does move from the legacy minus-48% a year ago, to 42% in the first quarter.

The Downstream tax rate is relatively stable around 25%, 30%.

With Brent in the $56 per barrel range, we would expect the effective tax rate for the group to be around 30%, 35%.

First quarter organic investments were $2.9 billion.

This may look a little low, but we confirm our guidance of $14 billion, $15 billion for organic CapEx for the full year, excluding the $2 billion for recent acquisitions.

E&P CapEx was $2.5 billion in the first quarter, essentially in-line with the full year budget when you consider that CapEx tends to be light in the first quarter and heavy in the fourth quarter.

The growth generated adjusted cash flow of $4.7 billion in the first quarter, more than enough to cover investments.

Free cash flow was very strong at $3.9 billion.

On an organic basis, excluding asset sales and acquisitions, free cash flow was $1.7 billion.

The first quarter includes a $3.2 billion Atotech sale.

With Atotech, we are close to delivering on our $10 billion objective and we plan to finalize it for gain in 2017.

We announced the sale of mature fields in Gabon for $350 million in the first quarter.

We are discussing the sale of our TotalErg retail business in Italy and some E&P assets in the North Sea.

Asset sale proceeds increase our ability to take advantage of the current environment and add resources to the portfolio, as we have done in recent deals in Brazil, Uganda and the U.S.

Earnings fell to 22.7% at the end of the first quarter, the lowest level we have seen since 2012.

But keep in mind that we still have to close the Petrobras alliance.

We have the result of the first 2 quarters' scrip dividends that were offered at a reduced 5% discount rate.

So the dividend paid in January and April.

The take under the scrip was around 60%.

Based on the first quarter results, I think takeaway messages are we are fully leveraged to resume our tight environment and generated $1.7 billion of organic free cash flow.

Production is up by 4%, and we have effectively derisked our production growth of more than 4% for the year.

Our cash position and balance sheet are strong, with given the 5-year low.

We are capturing the benefit of the low-cost environment and sanctioning projects, including the Borealis cracker in the U.S, the Daesan expansion in Korea, the Absheron development in Azerbaijan and the first phase of the Vaca Muerta shale development in Argentina.

We are also capturing resources in good conditions because we are in a strong position relative to others.

For example Brazil, where we are very pleased that there was no preemption, and Uganda.

And we will continue to pursue this effective strategy while maintaining discipline and cost and operational efficiency.

So with all of that, I am ready to begin the Q&A.

(Operator Instructions) Our first question today comes from Theepan Jothilingam of Exane BNP.

Patrick, Theepan here.

Just a couple of sort of modeling questions, I guess.

Just in terms of balance sheet gearing, can you just help in terms of sort of outlining the timing on the completion on the Brazil deal, what milestones are left there?

And then I think in the outlook statement, you talked -- there was some discussion around seasonal maintenance and the OPEC quite as impact for Q2, so if you could perhaps quantify that -- that impact, that would be great.

Nice to have you, Theepan, on the phone.

So yes, we had a very low gearing end of this quarter.

Of course, we haven't paid for Brazil.

We believe that this transaction could be completed prior summer, this year.

So potentially, I don't know if it would be prior July or after July, something like this.

We should have an impact on our gearing by second quarter or maybe, third quarter.

About OPEC quarter and effect on production, according to the IEA announced report, compliance for OPEC was about -- was close to 100% during first quarter.

And of course, Total based all request by OPEC and non-OPEC countries to complying with Total.

In Q1, the impact for us was limited.

Looking forward on second quarter, our second quarter could be impacted more.

We stress being fully implemented in OPEC countries, but honestly, we were making computation and we were below or in line with 20,000 barrels at the maximum cut.

And the seasonal maintenance, quarter-on-quarter?

Yes, the level of maintenance was in line with seasonal average in Q1 2017.

For second quarter 2017, production figures should be impacted by some maintenance in line with seasonal average.

Nothing unusual, like for example, Norway and Thailand.

We will now take the question from Michele della Vigna of Goldman Sachs.

Looking at the results this quarter, free cash generation was very strong, the gearing came down materially.

You made further progress in some of your project milestones.

I just wonder, how does this change your thinking about the discount on the scrip?

And does this give you more confidence towards removing it in the latter part of the year?

Or it's just too early to think about it?

Thank you, Michele, for your question.

Obviously, we had a strong free cash flow this quarter but the environment remains volatile.

And we see recently last week, the oil price, it's going down by $7 per barrel.

We reduced the discounts to 5% for the scrip dividend for the last 2 interim dividend payments.

And the take-up was good, I'll remind you, at 60%.

We will remove and we repeat it.

We will remove the discount on the scrip if Brent is at $60.

We are not at $60 and far from $60 today.

By removing the discount on the scrip, we are confident that take-up in shares will be minimal.

But we might buy back some shares if Brent is about $60 and take-up is high, even at 0 discount.

To be complete on this question, we will focus to the AGM in May, to extend the scrip for one more year because of the volatility of the market.

Our next question comes from Jon Rigby of UBS.

You talked about tax rate, so I wonder whether we could just revisit that, and I've got a couple of questions around that.

The first is historically, before this sort of down cycle, the E&P business routinely had a tax rate of 55% to 60%.

So I can see that structurally, you've been changing the portfolio through that time, so -- as well.

So what I want to understand is as oil prices normalize, let's say, above $60 would you envisage a tax rate moving back to that kind of level?

Or is it structurally changed to a lower one because of the mix effects?

And then secondly, and it's sort of tied to that a little bit, I think, is that if I look at your cash flow performance and your earnings performance is that you've been taking quite a lot of deferred tax benefits to your income statement over the last 2 or 3 years.

So as you go forward and things again normalize, would you expect the cash flow and the earnings to have a tax charge or a tax payment that look very similar and therefore, actually probably, the operating cash flow starts to capture more of the earnings increase?

Okay, Jon.

Your first question was about the E&P tax rate.

This quarter, the effective tax rate for the group was about 31%, exactly at the same level as the last quarter.

The E&P tax rate, in my view, has normalized to 42%, I think this quarter.

Remember that the tax rate was abnormally low 1 year ago at negative 48% because of the very low oil price.

Going forward, let's talk a little bit Downstream even if your question was on E&P.

Downstream should be pretty stable at around 30%.

And let's imagine Brent is in the range of $50 to $60 per barrel.

We would expect an E&P tax rate to be between 40% and 50% and the group rate being 30% to 35%, so a more normalized level.

Second question about the effect and I'm not sure we'll be able to answer directly to your question, the effect of the diesel tax benefit we took recently in our future cash flow.

We generate $4.7 billion of operating cash flow during the first quarter, with Brent averaging $54 per barrel.

We spend around $3 billion of organic CapEx, though our organic free cash flow was $4.7 billion minus $3 billion, $1.7 billion.

There were some timing effects in the cash flow in this quarter.

And I could elaborate a little bit more on that.

We had a very good results for instance in Daesan, in Korea.

The dividend was voted but not paid.

This quarter, it was paid just after the end of the quarter.

So result was a timing effect.

We could confirm our cash flow target for 2017.

We are, I think, in a very good position to reach our pay dividend breakeven of less than $40 per barrel in 2017.

And we -- and it is obvious from this recent quarter result, we confirm that at $50, our operating cash flow recover our CapEx and the cash part of the dividend in 2017.

Trying to answer directly to your question about the potential future effect of the deferred tax benefits, those are not big figures.

Those are not big amounts.

We are talking about $50 million to $100 million, no more than that.

So I don't think this will be material in the future.

We will now take a question of Alastair Syme of Citi.

Could you talk a little bit about the LNG market, and how you're seeing the market and maybe give us some guide to the contribution of the earnings that you're seeing in this environment?

I think in the past you have given it as a sort of percentage of the Upstream profits.

First thing to understood is that LNG price remain above the consolidated of the average realized gas price.

At least, that was true the first quarter of this year.

Our price rate guidance was about 20% of the volume and 30% of the results.

I don't change that.

Year-on-year, quarterly LNG volumes are up by 10%, 11%, mainly thanks to Blackstone [on that] and better utilization rates in Nigeria LNG, and we are lucky, Angola LNG, which has started again.

LNG, as you know, is a strong source of diesel for us.

And given the long-term contract we entered into, the associated price lag -- there is a price lag of a minimum of 6 months -- there is a smoothing effect that gives our results added stability.

The market is not so bad for our existing contract today.

What might be more difficult in the future is to market additional production coming from the market.

This may be difficult on deal, I would say, late 2020.

We will now take a question from Iain Reid of Macquarie.

Can I ask 2 questions about LNG development?

Firstly, could you update us on the stage it is, in terms of when you think it will be onstream to likely ramp up into the second train?

And if possible, whether there's any cost uptake in terms of total CapEx.

And secondly, what's the current thinking in terms of developments of Papua New Guinea, in terms of timing of FID and where you are in reserves at the moment?

Yes.

I think you would be disappointed, Iaian, by my answer.

In case, maybe you heard about the sell-away of the CPS from the yard in Korea, this week and this is a very good news, obviously.

And I think that given this event the operator impact may want to update the market on the project sooner.

So I would advise then to wait for the operator comment himself than elaborate more on the things that is in the control of INPEX, that's another story.

In an LNG project like this, you not only need to have the feed completed to supply a diesel project, but it is more comfortable to have marketed the gas itself.

And as I mentioned in the previous question, it might be more difficult to market new LNG production.

I don't know what is the exact status of the market, but it may take some time to market this gas on the Asian markets.

We will now take a question from Oswald Clint of Bernstein.

Patrick, yes, 2 questions.

The first was really the Upstream cash margins on a per barrel basis.

And I guess, if I look at this quarter and I get around, I think around $13 per barrel.

And when look back to other quarters where we had similar oil prices, I can't arrive at that sort of magnitude.

So the question is as you bring through the new projects the last year, this year, '17, '18, with that higher cash margin, is there a point that you're looking at a quarter or a half year?

Or is it at the end of 2018, where we might see the overall Upstream unit cash margin starting -- actually starting to increase?

That was the first question, please.

And then secondly, just a comment.

So I read in the press release about ongoing deflation that you're still seeing.

I wonder if you could be maybe a little bit more specific and say is it particular geographies or particular parts of the construction that you're actually seeing the continued deflation, please?

Well, first question, let's see this question through the angle of our new project.

We add 15 stack up since beginning of 2015.

All these projects contribute to the production growth and cash flow growth obviously.

On average cash equities compared to the production base.

For example, on this first quarter, cash margin for gas project like Vega Pléyade or Laggan were in the range of $20 to $25 per BOE, that's for gas.

And for oil depot shop projects such as Moho Nord, we deliver margins on $30 to over $40 per barrel.

Second question about deflation.

This will give me the opportunity also to talk about our unit cost per barrel.

As of today, honestly, we don't see cost increasing in the medium-term outside of the U.S. Investment levels remain low.

There is less competition internationally, with many U.S. and European independents having gone home.

And the U.S. major focusing more on the onshore U.S., as well.

And the capital cost came down by more than 30% since 2014, that was a peak.

The market may be bottoming out, but we don't foresee any increase in our core areas like deep offshore or LNG.

They are obviously courting our purchasing teams, indications that contractors are extremely hungry for business.

So in our view, it is now the time for us to sanction new project.

We want to harvest the benefit of this low-cost environment.

Just a word, it gives me the opportunity to talk about our technical cost.

Because part of our technical costs are coming from recent market costs going down.

Production cost continued to come down also within Total.

For the first quarter, we are well below the $6 per barrel.

I'll remind you that we were exactly at $5.9 per barrel end of 2016.

And this quarter, we are at $5.5 per barrel now and we are pretty much on track to reach our $5.5 per barrel target for 2017, as we mentioned to the market this year, a quarter ago.

In parallel to that, DD&A is coming down below 2016 level, which was about $13 per barrel.

And exploration is stable compared to last year, close to $1 per barrel.

So all in all, we are benefiting from the environment.

And we are capable to take advantage of this slow environment.

And the ASC 932, which is competency regulated data, shows that.

We now take a question from Rob West from Redburn.

I'd like to ask 2 please.

One is on the Vaca Muerta project that you've sanctioned today.

Now that project is sanctioned, can you give us some detail on the timing of how much CapEx you're putting into it and the overall budget?

And specifically, as you build more infrastructure, can you give us a sense of how you expect the costs to come down within that budget that I'm sure you have as part of the plan sanction today.

My second question just on LNG and the release mention signing a new supply contract with JERA.

Can you comment on whether there's any relaxation of destination clauses in that?

Vaca Muerta, yes, we've announced this morning that we just sanctioned a first shale-gas development on our operated Aguada Pichana block, which was developed conventionally before.

So we will be benefiting from existing facilities and low-cost environments.

This is one of the 10 major projects that we plan to sanction 2017, 2018.

In parallel, we have increased our interest in the eastern portion of the Aguada Pichana from 21% to 41%.

CapEx for the first phase would be, let's say, $500 million for the forthcoming 3 years, 4 years.

And we will be using 3 to 4 rigs on this play.

Produced gas will feed of course, the existing plant with capacity of 100,000 barrels per day -- barrel equivalent per day, which is currently partially filled with conventional production.

And plant will be full by 2020, which is in line with our CapEx program.

The question on the supplier and the JERA contract, honestly, I don't have a lot of detail on it.

It's an important contract for us because JERA is an important player on the market.

And we are the first to sign a new contract with them.

JERA, to know about it, is the world's biggest single LNG player.

We will provide them with 6 cargoes and about 400,000 ton of LNG, most of them under the basis of the traditional oil index price formula.

I think this is another proof of our strong presence and knowledge of the LNG market.

I don't have further detail for you.

We will now take a question from Irene Himona of Societe Generale.

I have 2 questions, please.

Firstly, on divestments.

In the first quarter you realized $2.9 billion.

Is there some guidance you can give us on 2017, in terms of what you have yet to complete perhaps from announced disposals or targeting?

My second question is on the new -- the full sort of reporting segment, Gas, Power & Renewables.

In 2016, that business generated cash from operations of about $538 million, I seem to recall you're investing about $500 million a year.

But last year, the division was cash negative.

Can you just give us some guidance on what we can anticipate there going forward, either in terms of profit or cash, and what the intention is?

So let's talk, Irene, with divestments first.

Basically, we have to take -- we have achieved 80% of the $10 billion disposal program.

On top of Atotech, we announced a sale of some mature asset in Gabon, and we have indicated that we are in the process of selling TotalErg, in Italy, our retail network.

There are still some major fields which are where the dossier are on my desk.

In the mostly, in the North Sea, that can be monetized.

I can't tell you in one month's time or two months' time, but we are moving forward on this issue.

In 2017, at $50 per barrel our organic cash flow covers CapEx, including the $2 billion of asset acquisitions and the cash part of the scrip dividend.

So basically, we don't need any more to sell assets.

We will match our $10 billion disposal program but we are not giving any guidance for further divestments.

So Gas, Power and Renewable, I remind you that the main target is to deliver $1 billion of cash flow from operation in 2020.

Honestly, this will be volatile, but it is normal that it is volatile because it's a new business.

The contribution from gas activity is and has been fairly stable.

In parallel, Saft is in line with our expectations and there is no bad surprise since we made this acquisition last summer.

Obviously, solar is weak.

The Upstream solar industry is facing a difficult environment.

But as you know, SunPower is a listed company, so I can't comment more than that on their results.

So you will have to wait for SunPower's announcement.

We will now take your question from Martijn Rats from Morgan Stanley.

A short question for me.

We've seen a lot of the other international major South Canadian oil sell assets, and I was wondering, like it's not a huge part of your portfolio, but I was wondering whether you're considering the same?

Yes.

So, does that answer your question, Martijn?

That does.

It was a short one, but we try to be efficient.

We will now take a question from Lucas Herrmann of Deutsche Bank.

Patrick, I'm glad that I follow Martijn because your answer was so short, I didn't actually hear it.

I presumed it was yes but I think you actually said no.

So maybe just repeat it a little more slowly for the hard to hearing.

And same with the Fort Hills.

Sorry, can you just better explain the write-down of $1.7 billion that you've taken on the asset relating to CapEx overruns?

Beyond that, I just wonder whether -- part of the very strong base performance that we've seen from yourselves and from others over the course of the last year or 2 has reflected improved efficiency, improved utilization and uptime.

I wonder how much more opportunity you see at this stage following 2 years of, I'm going to coin the phrase, sweating the assets and pushing harder?

And I also -- in line with base spend or whether, what is the level base spend CapEx now?

Is it still $3 billion to $4 billion and is that something that you feel is a sustainable number, going forward?

Okay.

Thank you, Lucas.

Maybe you didn't hear my previous answer, but I don't understand your second question.

So we'll start from the first part of Fort Hills question.

The question was, is Total interested in selling medium-term its assets in Canada?

the answer is yes.

Yes.

Let's explain the impairment.

The operator, Suncor, increased substantially the cost of this project.

And when you run the cash flows, you have to make an impairment.

Is that spend that this is already being incurred?

Or is that spend that you're still expecting to incur?

Expecting to incur.

$1.7 billion, I mean -- okay.

Yes.

Your second question is what is the level of the base spend for CapEx, that's it?

Let's start there.

What's the level of -- I mean, when all of -- when the price first started to roll over in crude, you talked about the level of spend on base assets of about $8 billion, and I think you said you could cut to $5 billion or $6 billion or if things became very difficult, $3 billion to $4 billion.

And last year, my recollection is that you're probably down $3 billion to $4 billion of spend to sustain the base.

Yes.

$3 billion to $4 billion is the correct number to sustain the base.

And do you think that, that $3 billion to $4 billion to sustain the base is still appropriate?

It's still appropriate because remember that we are starting up some long plateau project which reduced, obviously, the level of maintenance to be done on both projects.

Okay.

I'm sorry the other part of the base question, Patrick, was really, I think one of the things that perhaps surprised us is the extent to which decline rates, yourselves and others, have mitigated over the last 2 or so years.

Part of that is being your efforts to better utilize the assets, the infrastructure, get more out of what you've got.

To what extent do you think that process is moving towards an end, and that the uplift, if I put it that way, in production or the reduction in decline?

The gains you can realize from here are now starting to moderate.

Is that something you can answer, or...?

Okay.

Thank you, Lucas, for your very interesting question.

It is not today, the appropriate time to reduce our effort.

We start with the growth and then the efficiency, availability and so on.

We have decided with the Executive Committee to launch a new wave of cost reductions starting next year.

So that will be a new effort, a new program to cut cost in the company beyond the $4 billion 2018 target we have already given to you, thanks to the first program of cost-cutting.

In parallel to that, we are still looking to improve our availability in Upstream and in Downstream.

If you will remember, we are targeting 94% availability.

We are not yet at this level.

So there is still room to improve.

And I think you know Patrick Pouyanné, as I know him, he will not remove the pressure on the company to reduce cost and improve its industrial performance.

Okay, sorry, 2 follow-ups.

Just to be absolutely clear, the new cost-cutting program that you are talking around or launching is completely separate from everything to do with centralizing the human resources and other program that you'd talked about 6 months ago, where you envisaged $1 billion, $2 billion or so of savings.

Of course.

The new organization will provide benefit to this new cost-cutting program.

I cannot elaborate to tell you how much.

It is true that the $4 billion target saving for 2018 will take benefit of the beginning of this reorganization of the purchasing, for instance.

But the purchasing effort will not be completed by 2018.

There would be further efforts to be done and we will launch this new program next year.

Okay.

I'm sorry.

Finally, you mentioned 94% of the target.

Remind me where you think you are today?

92%.

We will now take a question from Lydia Rainforth of Barclays.

I will just keep it to one.

Can you just talk about a little in terms of refining business in the sustainability of the margins playing out for this year?

Or whether, have you been surprised by the margin so far?

Refining margin, Lydia, currently in Europe, I'm talking about Europe, are good.

And demand for product is high in Europe.

You know that most of our exposure is in Europe but the margin is very good, both $40 per ton currently.

It was certain $47, $49 per ton last quarter, I think.

You also have to keep in mind that margin traditionally benefits from the maintenance season, which is in the second quarter.

And I can tell you that starting from the beginning of this quarter, refining margin were very strong.

But obviously, refining margin are volatile.

And I will make a general comment, as I made to Lucas.

We are completely focused to reduce our breakeven.

We will be the one enjoying the most refining margin, whatever is the result of the refining margin.

Also, I'll remind you that the Downstream portfolio we have, including Marketing & Services, including petrochem, is well diversified, and this could use the volatility of our results.

And the refining represents 40% of the Downstream business.

It's important, but there is other businesses in the Downstream sector.

We will now take your questions from Biraj Borkhataria of RBC.

I just have one on the Upstream.

Could you comment on the level of unproductive capital you have at the moment in the Upstream and how you expect that to evolve over the next year or so?

It's, obviously, dragging down the group return on capital profile.

So it'd be good to get a sense of what the rate of change there is likely to be?

Thank you for your question.

Unproductive cash flow, capital employed is going down.

And we are at the very high level of unproductive, nonproductive capital employed.

And now it's going down thanks to the start-up of the projects that are going on.

At the moment, it is around 30% of the whole capital employed by end of 2016.

It was 35% to 40%, 2 years ago.

So it's going down and it is going down very sharply, I would say.

How should we think about a normalized figure for the unproductive capital?

Obviously, over the next 18 months you said you were going to FID another -- well, 9 projects now in addition to the one today.

So what is the right number for that kind of through the cycle?

Around 30%, I would say.

We will now take your question from Thomas Adolff of Crédit Suisse.

I got a few questions on the Deepwater LNG, obviously, your 2 key themes.

On Deepwater, if we can just talk a little bit about Brazil.

Obviously, you signed the strategic package deal with Petrobras.

Should I think of it as just being a step one with more to come?

And if so, should I think about it in terms of further bought-on deals for discovered resources or rather licensing rounds?

And staying in Brazil on Libra, there's been a bit of an update on local content, whether you get a waiver or not.

Perhaps you can update us on that.

And if you don't, what it means for the project and the project timeline.

The second set of questions is on LNG, if I may.

Perhaps, not on everyone's radar, but there was an article in the industry press recently, that talked about Nigeria, 7-plus; LNG, 7-plus.

That was potentially moved forward.

So I wondered how real this project is?

And as far as Russia is concerned, where you're, obviously, currently developing Yamal LNG, your partner, Novatek, is talking about potentially, another project Arctic LNG.

Is this something that you want to be part of?

Or should I think of potentially a project in Qatar, would be of greater interest in the future?

Maybe about 10 questions from you, Thomas.

First question, about the strategic alliance with Petrobras.

The entering into Yamal and Lapa field, that is a first step of our strategic alliance with Petrobras.

On top of that, I'll remind you that the deal includes the Downstream part.

We have also taken interest in Regal terminal in Biyyam and 2 power plants.

In parallel, we are -- and I think this is important for both parties, we are cooperating on technology and exploration, bringing our extensive Deepwater experience to the alliance and sharing it with Petrobras.

Petrobras has also benefits and knows the deep offshore well also, but we are sharing our experience together.

And I'm pretty sure that this strategic alliance will offer us further opportunities.

Your question about Nigeria, LNG Train 7, if you will remember in our past Investor Day, we show it as a very good and attractive option.

It is obvious that this time make economically sense.

So we would be happy and very happy to progress on this Nigeria LNG 7 train, so let's see.

Yamal, Yamal extension or other project in the Yamal Peninsula, of course we are interested.

The -- I don't know if we can call it a strategic alliance we are with Novatek.

We don't use the same name but we are cooperating together, Total and Novatek.

And we are, of course, interested in participating in further LNG development in this part of the world.

Anything you can say on Libra?

On Libra?

Libra, Libra, Libra...

How important is the local content waiver.

Some information.

We are a little bit late in the [co-effort] there.

There were some issues with unions in Brazil, but the co-effort there is moving forward.

And basically, we intend to receive bids in the upcoming weeks.

We should be in a position to take FID, second half of the year 2017.

With the waiver of local content.

On the operation side we are on the progress of drilling the Southeast funnel.

We will now take a question from Christyan Malek of JPMorgan.

Patrick, two questions if I may.

First, with your gearing now relatively at low levels and balance sheet never been being better, why do you still have such a high oil price risk structure removing the scrip discount?

Is it because you're focusing on deploying the capital and want to sanction projects?

This strikes me that, take the discount off, increase the cash payout, would be a high-order priority in the context of a stronger balance sheet in a fiscal situation.

And I guess, simply, the question is can you not do that because you have to sanction these projects?

Which leads me to second question, which is to what scale do you have to reduce your CapEx, if oil were to head trend towards $40?

Or is it basically $14 is the floor?

We -- I am very happy to see the current level of our gearing.

But keep in mind, that we haven't paid for the strategic alliance and there is $2.2 billion to be paid to Petrobras.

Which lead to gearing around 25%.

We maintain the principle of the scrip because we are facing a volatile environment.

We don't know what would be the oil price second half of this year.

This morning on my screen, the point Brent was just about $47 per barrel.

Not anymore $55 or $56 per barrel.

Is the level of $14 billion, $15 billion organic CapEx the floor?

I don't think so.

If your price go down there will be further deflation and we will reduce our CapEx in line with the deflation given by the market.

But most of the 2017 CapEx level is committed.

So there is no reason to c change our budget today.

And this budget is at $14 billion, $15 billion, excluding resource acquisition, so excluding, for instance the $2.2 billion, we are going to pay for the Brazilian strategic alliance.

And would you consider expediting your new cost-cutting measures that you've talked about in the context of lower oil price?

I mean, it sounds to me there's more funds upon it that you haven't necessarily put through yet.

What do you mean by -- accelerating, you said?

Yes.

This new cost-cutting target, would you bring it forward and actually accelerate it?

You want to make my life more difficult than it is today?

The second question I had was regarding statements by Pouyanne, on considering an acquisition or it's basically taking a steak into the IPO, Saudi Aramco.

Is there any logic or sort of backdrop you can explain behind that comment, this morning by Pouyanne.

Patrick made clear comments that nothing is defined on this IPO today, so it might be a good operation.

We don't know.

We can't press the Saudis to make a good transaction.

We are not committed today to take a stake in Saudi Aramco.

If any, this will be part of so-called strategic alliance with but as of today there is no commitment at all to be part of this transaction and nobody asked us anything as of today.

Our next question comes from Blake Fernandez of Howard Weil.

Patrick, I'll just keep it to one question.

I wanted to ask you about the Gulf of Mexico exploration blocks.

I assume those fall outside of the partnership you had with Cobalt, in which case, this would seem to be kind of a I guess, a reentry into operating in the Gulf of Mexico and exploration.

So just any comments you could kind of give there on the strategy and what you have going?

The general comment first is that we won 4 deep offshore blocks, this is not the 20, it's only 4. During 247 speeding round in March.

Of course, we were interested by both blocks because they are close to north plateau.

The proposal is to consolidate our position in and around the core area of this field.

On the other side of the border in Mexico, we were awarded 3 or 4 blocks.

After the company first completely rounded.

We would be the operator on Block 2. I think, the name of the basin is Perdido and we will have 50% interest.

And we have participating interest in the Block 1 and Block 3. So can we say that we are back in the Gulf of Mexico starting from really nothing?

Yes, it is obvious that we are entering smoothly, in the Gulf of Mexico.

And by the way, we have the know-how to drill deep offshore.

The prices of those blocks and of the adjacent field much more reasonable than the shale oil and shale gas in the U.S. So we know how to do it, and why not try to take benefit of it?

But it will be smoothly done.

There is no emergency, no rush.

We will do it step-by-step.

Our next question comes from Hamish Clegg of Bank of America.

I'll keep it brief.

I just wonder, if you didn't mind Patrick, clearing up your comments on the buyback.

Just, could you confirm first that you would only buy back at $60 to offset the scrip?

Or in the case that you have excess cash at $60 Brent, you would potentially buyback more stock from that as a use of cash?

As I said, next AGM, where we propose again the use of the scrip dividend for one year.

And this will be applicable for one year.

Yes.

The only flexibility we may have is the oil price goes up during this year, starting May, will be to offer a zero discount.

Where we -- what we said is that if the take-up is still high at 0% discount when the oil price is, for instance, at $60, we might buy back some shares.

Okay.

But it's solely a purpose for offsetting if there is high take-up?

Yes, exactly.

We have no other questions.

I will now turn it over to Patrick de La Chevardière, for his concluding remarks.

Thank you very much, everyone, to listening to this conference.

I think the strong result we posted show how good we are today in restructuring the company.

All segments are performing well operationally.

Free cash flow increased significantly.

Gearing is down.

Production is growing and, of course, we are, all of us, very confident that we will achieve our target.

And sorry to have a speech a little bit long at the beginning.

This will conclude today's conference call.

Thank you, for your participation.

You may now disconnect.