Patrick de La Chevardiere - CFO

Oswald Clint - Bernstein Lydia Rainforth - Barclays Henry Tarr - Goldman Sachs Brendan Warn - BMO Capital Markets Iain Reid - Macquarie Biraj Borkhataria - RBC Thomas Adolff - Credit Suisse Irene Himona - Societe Generale Rob West - Redburn Martijn Rats - Morgan Stanley Blake Fernandez - Howard Weil Jon Rigby - UBS Lucas Herrmann - Deutsche Bank Christopher Kuplent - Bank of America Merrill Lynch Guy Baber - Simmons Neill Morton - Investec Bertrand Hodee - Kepler Cheuvreux

Hello, Patrick de La Chevardiere here. I will keep the comment brief, as usual, because we have met with most of you over the past several weeks and I think you know the story.

You know the objective we have set and the first-quarter results show that we are on track for the year. For the first quarter 2016, we reported $1.6 billion of adjusted net income or $0.68 per share.

The results are clean and straightforward. Compared to the previous quarter, the net results decreased due to the weaker price environment for the upstream, and the downstream was once again quite resilient.

Brent has rebounded since February. But I remind you that the first quarter was very tough particularly at the start.

There were 11 days in January when Brent closed below $30 per barrel. The intraday low was $27 a barrel, something we have not seen since 2003.

Brent averaged $34 per barrel in the first quarter, a decrease of more than 20% quarter to quarter and almost 40% year on year. The UK gas price fell to $4.30 per million BTU, a drop of more than 25% compared to the previous quarter and more than 40% compared to a year ago.

European refining margins average $35 per ton in the first quarter, down from the strong level we saw in 2015 but in line with our planning assumption for 2016. Despite the lower margins, refining and chemical had a better result than last year, thanks to record availability.

As an industry, we are back to volatility. And Total's response is to continue to execute and deliver on a strategy that makes us more competitive in any environment.

So the key here is to reduce the cash breakeven. Looking at the first quarter, with Brent at $34 per barrel, we came close to balancing the cash from operations with the cash outlay for net investment.

This was $3.7 billion and $3.9 billion, respectively. The results show that we are rapidly reducing the cash breakeven, mainly as a result of managing down the CapEx as we exit an intensive investment period and at the same time maximizing the cash generated from operations by increasing production, cutting costs, and relying on our more efficient downstream.

In February we indicated the per dividend cash breakeven for 2016 should be around $45 per barrel Brent, but in the first quarter the breakeven was around $40 per barrel Brent. I will come back to this point in a few minutes.

Turning to the results by segment, upstream contributed $500 million of adjusted net operating income in the first quarter. Strong production growth of more than 5% compared to the previous quarter and about 4% compared to a year ago partially offset the impact of lower prices.

In the first quarter we started up two new projects, Laggan and Vega Pleyade, plus a ramp-up on nine startups for the last year. So we are in line with our target to increase production by 4% this year.

We are continuing to cut costs in line with our target for a further reduction of $900 million for the Group on top of the $1.5 billion we cut last year. Using first-quarter numbers, OpEx is below $7 per BOE, in line with our objective to reduce OpEx from $7.4 per BOE last year to $6.5 per BOE on average for this year.

What I would like to point out here is that despite the challenging conditions, the upstream generated $1.8 billion of cash in the first quarter. The first-quarter results for the downstream were also resilient, downstream contributed $1.4 billion to our first-quarter net operating results.

Refining and chemicals represent $1.1 billion of downstream net results, an increase compared to the previous quarter despite lower European refining margins, mainly due to the historically high 94% refinery utilization rate and the strong performance of the petrochemicals. The net result for marketing and services decreased compared to the previous quarter.

I remind you that the fourth quarter includes a positive contribution of about $300 million in new energies from SunPower related to the Quinto solar plant. And there were also the impact of asset sales -- mainly the Total gas business compared to last-year results.

Again, the important point is that downstream generated $1.7 billion of cash, in line with the $7 billion objective for the year. Looking at the corporate side, organic CapEx of $4.6 billion in the first quarter supports our new objective to limit investment to below $19 billion this year.

I can tell you that for Yamal, project financing of $4 billion equivalent is being finalized with Russian banks as we speak. And significant progress has been made recently with Chinese banks for another $12 billion equivalent.

In February, we said that about 40% of our 2017 CapEx was uncommitted, so we have a lot of flexibility in our investment and cash breakeven. Net investments were $3.9 billion in the first quarter compared to $4.3 billion in the fourth quarter and $5.8 billion a year ago.

Asset sales were $900 million in the first quarter, mainly from closing the sale of the FUKA pipeline in the North Sea. Acquisition were $200 million, mainly for a marketing network in Dominican Republic.

But the sale of our network in Turkey, which was announced last year, has just closed in the second quarter and more than offset this. So net asset sales for this quarter were $700 million, above our target run rate for the year to achieve the $2 billion objective.

So we are on the right track. Going back to the cash breakeven, in the first quarter operating cash flow before working capital was $3.7 billion.

This is a decrease of only 15% compared to the fourth quarter, reflecting essentially the lower price environment, partially offset by upstream production growth, cost-cutting, and the strong contribution from downstream. In February, we indicated that our cash breakeven before the dividend should be around $45 per barrel Brent this year.

The $3.7 billion of cash that we generated with Brent at $34 per barrel almost covered the net investment of $3.9 billion. So, looking at the first-quarter numbers, you can see that we are at about $40 per barrel breakeven due to our resilient cash flow and flexibility in net investments.

At the end of the first quarter, our gearing was 30%. In this environment we are comfortable around this level.

The scrip dividend is one of the two that we are using; and assuming a 50% take-up, this reduces the cash outlay for the 2016 dividend to about $3 billion for the year, which is within our ability to manage. The [61%] take up on the scrip dividend for this quarter supports our assumption of 50% for the year.

And we are pleased that for the majority of the shares, our holders have demonstrated their trust in us by taking the scrip. We are very focused on managing cost and cash as well as executing and delivering our project.

To conclude my comments, the first-quarter environment was tough, but the results demonstrate that Total is resilient. The net cash flow, production growth, and downstream performance also show that we are in line with the plans and objectives we presented in February.

Final point: last week we announced a new organization that includes the creation of the global services division for the Group. We are continuing to focus on delivering more efficiency, and this move will be the source of new cost savings.

So we will come back in September on new targets. So I'm ready now to move to Q&A and ask that you please limit yourself to one very good question at a time.

I wanted to ask a question about the nine project start-ups, and specifically the kind of cash flow per barrel coming from those nine projects. Are they kind of delivering the cash flow that you expected?

Or is it too early to see the impact, if we were to analyze upstream cash flow per barrel? It doesn't seem to be showing up really yet, but it might be too early.

Or is there some other part of some other geography that's probably more heavily lossmaking as we look at the first quarter? That's my question.

Thank you.

Thank you, Oswald. We are very happy with the nine start-ups that we -- of the project we launched in 2015.

Most of them are in line or ahead of the initial ramp-up. The main project I can figure out for you.

I can give you the cash flow from operations for -- in dollar per barrel for a few of those projects. CLOV is about $24 per barrel.

Moho is about $18. Laggan-Tormore is about $14 per barrel.

Maybe your last one, Vega Pleyade, which just started, is $23, $24 per barrel. Basically, those nine projects will contribute substantially to the growth of production of 4% on average, as we committed ourselves to implement.

The production growth quarter to quarter was above 5%. So basically, we are in line and happy with that.

The question I had was around the announcement earlier this week around the global services set-up within Total. Can you give us more details of how that will actually work?

And when I'm looking at the cost savings targets of -- in 2017 of more than 3 billion, was that inclusive of what that global services division is doing? Or will that be something that we see longer-term, beyond 2017, in terms of the impact?

Thank you.

Thank you, Lydia, for having made your question talking slowly. Basically, the new organization was announced last week.

That has an objective to improve the global efficiency of the Group and position the Company as a global energy leader. The reorganization, just for your information, consists of three elements: a new gas, renewable, and power segment -- that's one side.

And the Total global service you are talking about, which will operate as a service company for our other business segment, providing accounting, purchasing, IT training, HR, and facility management. It is obvious that we have an objective to increase our efficiency.

It's premature today to give you any figure on how much additional savings we can make through these global service companies. In the target we gave the $3 billion target of cost saving in 2017; there were at that time no inclusion of these global services companies.

We will update you basically by September, when we will make our own estimate how much we could save. But just to give you a magnitude, the overall purchase which will be handled by this -- by the purchasing company affiliate could be in the range of $20 billion to $30 billion instead of, today, a few billion dollars which are centralized, so if you can expect a saving of, let's say, a minimum of 5%, you can figure out that we could make substantial saving.

But this will take time to be implemented, of course and we will not have the benefit, the full benefit, the first year.

My question was on CapEx. And as you consider the CapEx budget in a low oil price environment, how do you think about choosing between sort of deferring projects and lower spend on ongoing existing production?

And then I just had a second question on the CapEx outlook for 2017 and how sensitive it might be to the oil price. So what oil price might see you at the low end versus the high end for CapEx guidance for 2017?

Okay. So are we looking at deferring CapEx or delaying project?

Honestly, as of today, most of our projects are launched. And we will deliver them.

As I mentioned already in February, only 60% of 2017 CapEx are committed. You make the math as me 40% for 2017 is not committed.

And we will give you by September a target for this CapEx. Honestly, as of today, I will repeat myself by saying that we are build implementing our strategy and delivering the expected or more than expected result.

That's what we are doing. Two, we will be able to revise our CapEx guidance.

We are capable to do it, technically speaking, and we will decide that during our long term plan exercise, which is taking place in July. And we will update you in September.

Thanks, Patrick. It's Brendan Warn from BMO Capital Markets.

Just one question, I guess related to what seemed to be a bit of progress in Uganda over the weekend. Can you just talk about the route selection?

Can you talk about your interest in the project going forward, and just what your breakeven assumptions are, and when you would look to take FID? Or what will you need to see next to take FID for the Ugandan project, please?

Uganda is a very important project for us. It's a giant oil project.

And this will establish a first brick, I would say, of our new East African region for us. As, the President of Tanzania I think you were referring to that.

The President of Tanzania and the President of Uganda signed, on 23rd of April, a joint communique confirming that the export pipeline from Uganda would go through Tanzania. We need, of course, to press ahead this project and push toward FID.

There is still some design and engineering works to be done, then a call for tender. So we are looking for next year for potential FID, I would say.

What sort of break evens are you seeing there, Patrick?

Being a giant field, such a project resists pretty well in a low oil price environment.

Hi, it's Iain Reid here, Patrick, from Macquarie. Just following up on your comments on Yamal LNG, you talked about the funding of $12 million.

Is there any additional funding required for that? And also, could you update us on the timing of when you see volumes flowing there?

And thirdly, Total is buying a substantial part of the LNG, which I believe you are going to land in Europe. Do you have end users' contracts signed with end users for that?

And if possible, can you tell us what the contract terms are for that?

Okay, my answer maybe a little bit long, and I'm sorry for that. But obviously it is a very important project for us.

Works are going pretty well onsite. As far as the financing is concerned, we are at the moment finalizing both the Russian tranche and the Chinese tranche the Russian tranche being $4 billion equivalent, and the Chinese tranche being $12 billion equivalent.

We may be possibly, I don't want to commit myself on that, but may be possibly signing those transactions maybe even this week. So the financing is going pretty well.

It is the number I give you, the figure I give you are in dollar equivalent; no dollar will be used because of the sanctions. Basically, we are honestly extremely happy in our ability between Novatek, the Chinese parties, and ourselves to move ahead the financing, as we are doing at the moment.

For the production, let's say end of 2017. This is the target given by Novatek.

As far as the commercial contract, 95% of the LNG is already sold, mainly to Asia; and using oil linked formula, a small portion, I have to say it, is also sold to Europe.

Hi, Patrick thanks for taking my question. Just a quick one on the big working capital build in the quarter which impacted cash flows.

I was wondering if you could talk about what was driving that move and how you expect that to evolve through the year? Thanks.

Okay. I think everybody saw that working capital was not performing as well as it was performing end of last year.

There is some good reason for that. The first one is that trading was taking advantage of the contango, and that we had basically physical stocks at the very high level to play the contango.

And this represent roughly half of the $1.5 billion increase of working capital this quarter. The rest of the evolution is mainly linked to also an increase of stock and receivables in the downstream due to the very good operational performance in our refineries.

I'll remind you that our utilization rate was at about 94%. That pushed the volumes and the receivable at a high level also.

And last -- but that has a minor effect in comparison to the effect of the trading and of the refining -- there is a buildup of new energies projects in our affiliate SunPower. And this explains basically the $1.5 billion working capital increase for this quarter.

I've got a question on upstream portfolio and, more specifically, on portfolio depth. The question might sound a bit long.

You can sip a bit of water, but it really is a question on portfolio debt. So you have two definitions for M&A.

One is you call it organic, and it is part of your CapEx, and therefore part of your toolbox to replenish resources. And the other is inorganic.

And specifically to organic M&A, I wondered whether you are seeing some progress. After all, you haven't really done anything recently.

I'm kind of asking this question because when I look at your portfolio and the timing for FIDs for some of the pre-FID projects, there's a bit of a gap, if you will. Veba might be this year; it is a substantial project.

You say Uganda might be next year, but really we're dealing with the government of Tanzania and Uganda, so it might be really early 2019. And Elk-Antelope -- you really are not going to market your LNG anytime soon.

So FID is going to be 2019. So maybe you can talk about the M&A opportunity, but perhaps also about what potential brownfield projects that you have that the market is not really focused on.

For example, at the LNG '18, Louis Bon talked about further upside on Ichthys. There's sort of upside on Kashagan, and its part of ENI's four-year plan.

And so I wondered whether you can kind of talk about projects that you can expand that could be also relevant for the longer-term health of your business? Thank you.

Okay, Thomas. As usual, I see you so confident in our strategy that you even don't need to give your name.

I will recognize you. A few answer to your question.

What we call organic M&A, which is the M&A we like, is being undeveloped resources discovered by others. That's what we like.

We know how to do it. We bring our expertise, and we create value by developing those resources.

And we are working -- and you know that, obviously, I will never give you any name, or field, or whatever in terms of acquisitions. This is the best way to kill any opportunities.

So you won't have any name, obviously, on that. But we are working on some potential opportunities, and there may be some opportunities hiding.

And you will have them known when we will have completed the transaction. Do we see to make inorganic acquisition?

Honestly, I have nothing in mind. And as of today, price are still high and not compatible with a $40 oil price, as we see today.

In terms of debt of our own portfolio, there is not only Liberia, Uganda, El Cante Loupe, but there is also some other project, like Bonga Southwest, Train 7 in Nigeria LNG. So not the same magnitude of the three first projects I mentioned to you, but those are interesting assets that we have.

Finally, I think we are pragmatic. There is no rush for us to launch new project.

Our production growth is already embedded down to 2019. We have time.

We want to tap the market when the bottom will be there. I mean, the market being not only the asset market, but also the contractor market, in order to achieve the best development costs and increase the profitability of our assets.

That's what will be driving the decision of FID. Obviously, when you are seated on very large resources like Libra, it's maybe -- obviously much more easier to launch a project like this or Uganda, which is also seated on large resources.

But we are pragmatic. There is no emergency.

We want to take benefit of the new cost environment when it will be, in our view, the best timing. Thank you, Thomas.

I had a question on refining and chemicals, if I may. Refining margins, which you disclosed, obviously, declined year on year, quarter on quarter.

And consensus was expecting a reduced profit this quarter; actually, you increased your R&C output. And so it was a very strong performance -- helped, as you mentioned, by the sort of record capacity utilization.

Some of your peers were reporting this week also reporting similar record highs in terms of utilization. I wonder if you can talk a little bit about how you perceive the risk of supply increasing as a result of your measures and effectively depressing margins in due course?

Also, if you can update us on what happened to the margin quarter to date so in April? And whether the depressed diesel crackers is of concern to you?

Thank you.

So three very good questions, Irene…

Sorry.

…about refining and chemical. April margin were basically between 35% and 40% -- it was, I think, 43% yesterday.

So a slight increase of the refining margin in April in comparison to the first quarter. Gross margin, which is not bad; I mean, $35 per ton that is our budget assumption for the year.

So we are happy with such a level. Of course it was better last year, but we have to cope with the environment.

What is obvious for us is that a low oil price and a low nominal value of the product leads to a strong demand. And that was driving the refining margin by driving the cost of the project.

It is of use that most of the refining margin were dragged up by the gasoline and not by diesel. And it is true that the diesel crack are currently depressed.

It is of use also that coming soon the seasonal maintenance of the refineries in the area where we are will be helping the market to sustain the product prices and the refining margin, the same about the driving season coming, let's say, in June, something like this, which will support the product demand and the refining margin. So are we concerned about refining margin?

At that stage I would say no. We are lucky to see the refining margin today in line with our budget.

We see some element which will drag the refining margin up, maintenance and driving season. There is of course the risk, as you mentioned, of overcapacity used by the market.

But I have to say that the record refining availability and utilization rate is not sustainable for years. We are very happy with the 94%.

We will do our best to continue and maintain such a level, but we know that it is when you reach such a level it is more difficult. And that's the same applying to our own competitors.

I think that's all I can tell you, Irene.

Thanks, Patrick. I'll ask two questions, and I'll respect your wish to ask them one at a time.

The first one is on African oil product demand. I know it's an important growth area for you.

Can you talk a little bit about what you're seeing there in terms of that end market and the demand? Just asking based on one of the surprising data points in the release this morning I noticed that sort of 25% decline in the petroleum product sales there.

So I was just wondering if you can comment on that a little bit. And then I'll ask my second question afterwards, if you like.

Honestly, if your second question is as difficult as the first one, it will be very short. Honestly, I don't know the answer for the African oil product demand.

And I'll ask Mike to call you back and report to you the figures that I don't have for me. Basically, on a worldwide basis, our retail volume growth at the rate of 4% but I don't have the exact answer for Africa.

And the same growth we face for these lubricant on a worldwide basis of 104%. So make my life easier by asking a very simple second question.

Okay, okay. I'll try to make this one simple; it certainly won't be based on a disclosure at the back of your report.

So apologies for that. Just a general question about the entitlement effect on reserves.

I know for a while now, we've been running with the price effect about 3%, so 3% higher volumes on your production sharing contracts. If I look at, say, a barrel of reserves in 2014, would that does that assume that that barrel of reserves would be worth 1.03 barrels of reserves as booked in 2015, because of the production sharing effect?

Really, I'm trying to quantify how much of an uplift to the average barrel of production sharing preserves has happened because of a lower oil price.

If you call that an easy question, I can't imagine the difficult question. A few words about PSC barrel.

This is true that the price effect, which is more volume to be at the end both of our cost, play some way in our production growth in the first quarter 2015. And the production increase was in aggregate 4%.

And this increase would use 4% from the start up and the ramp up, minus 3% for the shutdown and 3% plus 3% from price effect and field performance. So we.

Specifically, on reserves that are in effect. Can you say what?

So called price effect for production was lower than 3%. I'll remind you also that the sensitivity, roughly, for our volume is $10 per BOE at the moment represents something like 15,000 barrels per day.

So not so much. The sensitivity to that has been dramatically reduced since we reached an oil price below $50 per barrel.

Thank you. I apologize; I wasn't clear.

With the reserves that are booked, how much have reserves increased because of production sharing?

You have two effects which are contradictory. The first one going up, because more volume because of less barrel dollar per barrel.

Second is a cut off of our production project by project. Because when you reduce your price, then the cutoff of the project comes sooner, and then you reduce your volume.

So in aggregate, those effects are going slightly up and down. The price effect in our reserve last year was about 100,000 -- sorry, 100 million barrels.

Hi hello, it's Martijn from Morgan Stanley. I wanted to ask you two things.

First of all, you've sold another 1.5 million tons of LNG to Pertamina and to ENN. So I guess that's giving you another data point on where long-term energy contracts currently sit.

And I'm sure you're not going to disclose to us the full details. But can you say anything about where pricing in long-term contracts is trending in general, and how they broadly compare to other contracts that you've signed in previous years?

And the second thing I wanted to ask related to Kashagan. There was an official from CNBC who last week said that the start-up is now slipping well into mid-2017.

I was wondering how that compares to your own expectations.

So on Kashagan, this is very simple. We stick with the estimate of the operator, saying that we expect the first oil to be produced by December this year.

That -- what we have embedded in our 2017 forecast. So a start-up by December 2016.

The recent contract we signed with Pertamina or the Chinese company for 1.5 million tons -- you know, both contracts enable us to leverage our global portfolio. We also recently signed a cooperation agreement with COGAS.

Obviously, I'm not going to give you the detail of the term and condition, but those contracts are still oil-linked contracts, with maybe some [indiscernible] for part of that. But most of it is oil-linked contract with a coefficient ratio in line with what we had recently.

This is not anymore the 14% we had for Australian project, but we are quite happy with the current term and coefficient to correlate the gas price with the oil price.

Just a point of clarity, really. I know you lowered the cash breakeven from $45 a barrel that you provided back in February to $40.

I think at the time, though, you also provided a 2017 breakeven which excluded divestitures and assumed no scrip dividend uptake. And that was at $60 a barrel.

So I'm just trying to see if it's fair to believe that that has also moved down $5 a barrel toward the $55 range? And is it fair to think, too, that you're still moving toward removing the scrip once you do reach that neutrality?

You are too clever, Blake. You are going too quickly.

It is true that our main objective -- and we repeat it in February -- was to cover a full cash dividend organically at $60 per barrel. And this was using a CapEx amount of $18 billion.

We mentioned to you that only 60% of the 2017 CapEx were committed, and we will update you on that in September. So there is flexibility for us.

But the objective remains of being able by 2017 at $60 per barrel to cover a full cash dividend. Of course, deflation is helping us at the moment.

But we will figure out what will be exactly our 2017 forecast in the budget session.

Hi, Patrick it's Jon Rigby. Two questions, please.

The first is on your upstream tax rates, which have been moving around quite a lot. And I understand, obviously, with this volatility, things change a lot as well.

But I just wondered whether you could give some guidance on what your expectation is at, maybe, let's say, oil prices between here and $60; and where the rates would likely fall. I guess you've got mix effects.

You've got also sort of projections around the economic profitability of fields. And obviously, you're cutting costs, so you're able to swap data on that.

So I just wondered whether you could give us some guidance on that. And then the second is on the downstream, refining chemicals, which for the past sort of 1.5 years to 2 years have been increasingly robust.

Obviously, refining has been strong; we can see that from the benchmarks. But I just wonder whether you're able to give some sort of insight into the split between petrochemicals and refining?

So the chemicals business is X, the specialties -- to give some idea about what might be sort of short-cycle volatility and what is something that's being generated from a European benchmark we can see? Thanks.

Okay, so one very good question. As a result of the oil and gas prices this quarter, we are close to upstream breakeven.

Various tax credit uplifts on investments, for example, in Angola, in Norway, push the upstream effective tax rate into negative territory. So it is -- and I fully recognize that for you it was impossible to forecast the tax rate in such an oil price environment.

And honestly, for us it was also very, very difficult. If we were far from the upstream breakeven, let's say the $60 per barrel back to this level we could trend back to a normal tax rate, I would say in the range of 40% to 50%.

And so the second question is more tricky, actually, because I don't want to give you any figures. So I don't know how to handle it.

Petrochem has been doing very well actually, because of polymer demand, which is strong. And obviously feedstocks are cheaper.

Our polymer business, notably in the U.S. and in Europe, is generating good results.

And that illustrates the strength of the integrated model, obviously. What I can tell you is that petrochem represented around one-third of the refining and chemical result in the first quarter.

This is not only due to the margin, but also due to the efficiency of our plant, which performed pretty Actually, the operational performance has been right in the world of refining and chemical segment. That's what I can tell you, Jon.

Right. Can I ask, just as a point of interest: internally, do those two businesses get reported separately?

Or do you actually look at them as a fully integrated reporting entity from a sort of financial accounting point -- or management accounting point of view as well?

We -- refining and chemical are segregated by region. So we have the result by region.

I'll try and keep it simple. First one, Indonesia -- the Markham license.

Any news? Anything to say at all on extending the license?

Where are you? Where are things at?

Secondly, whether you could give any commentary around utilization of upstream asset. You have talked about the very high utilization of downstream, but where are we upstream at the moment?

And thirdly, just an update on Yemen, if there's anything to say at all. Thanks very much.

So that is three questions, Lucas. Not one.

Yes, but very easy, Patrick. These are not Rob-style questions.

It seems I don't have a figure like this to give you, but I can tell you that our performance index for upstream operation show a plus in comparison to the budget, which is to say that the performance of our asset were better than budgeted. Yemen, we enter into an agreement with the lender to freeze any debt repayment down to, I think, late 2018, if I will remember.

The plant is in a preservation mode, protected. We will be technically ready to start up again the plant.

But obviously, it's a matter of security of our people. And we are unable to take any decision at that time.

Indonesia, this is still under negotiation. We have reopened -- Well Z renegotiation have been reopened by the new administration in place since November.

They have intensified, but honestly, we know the block very well, declining very quickly very, very, very quickly. Everything will depend on the term.

But the amount of money involved in that negotiation is not very big.

And what has declined very, very quickly mean?

More than 20%.

So many good questions have already been asked, so I'm going to keep it short and just wanted to ask you, regarding your free cash flow still being in negative territory, how you see the credit markets in this environment as a CFO with the announcements from the ECB. Are you more likely as a result to try and issue more hybrid bonds this year, perhaps?

Thank you.

We have decided first quarter not to make any issue of any kind, because the market was crazy. Then Mr.

Dragee talked to the market. The credit margin went down, and we are waiting for the moment for the market to stabilize.

I think we are not far from a stabilization of the market, but it is not yet a stable market at the moment. Of course, I would never say to you if I will issue a hybrid bond or not.

I always have the choice to use hybrid or conventional bonds. It's a matter of prices.

It's a decision which the metrics change so quickly on the market that even today, I am unable to answer your question. I don't know what I can do at the moment.

Obviously, we are in a black period, so don't look into deep detail on the market. But in the forthcoming months, we may be able to make issues of conventional bonds, for instance, at a much more reasonable price than it was offered by the markets first quarter of this year.

But it is a very volatile market. It has been pushed down by the ECB declaration, which we will benefit as a borrower.

But you know that we have ample liquidity available to us that we can wait very long to reach a level of issue where we are confident that it is a good price. So there is no emergency for us about $20 billion of liquidity.

I'm fine with that. I can survive many, many months and maybe years without making an issue.

So I will see. It's a matter of opportunity for me given by the market.

It is not driving by our need, which as I mentioned to you, I have ample liquidity available.

Thank you, Guy Baber with Simmons. Thanks for taking my question here.

I had one question but with two parts here on CapEx. So first, just a point of clarification on the objective to limit organic CapEx below $19 billion this year, what do you believe is the key to that, or gives you the confidence in achieving that objective?

Is it primarily efficiencies that you're seeing? Is it deflation capture opportunities?

Or does it relate to project timing that might be shifting around? And secondly, on the CapEx, you have highlighted before the high degree of pre-productive capital.

I think before you'd highlighted around 40% of your capital as pre-productive a few years ago. I was just hoping you could give an update as to where that stands now, and where you think it might be in 2017, 2018 as clearly that amount of pre-productive capital is coming down significantly with your major projects coming on?

I was just hoping to get an update there. Thank you.

So thank you for the question, Guy. Our previous target was around $19 billion.

Now we are able to say below $19 billion, because we have a clearer vision on our investment for the year all across the company. And being frank with you, I don't care if this is due to deflation or this is due to my own effort.

The result is there. It is obvious that the startup of Kashagan, the startup of all of our projects, ramp up of the project, the startup Vega Pleyade, of Laggan, is reducing the overall amount of the so called nonproductive assets.

By basically, I'm thinking that by the end of 2016, we will be in the range still again of 40% of nonproductive CMO capital employed for the upstream division. And let's say something like 35% at the Group level.

Thank you. I know it's early, and there is a lot of uncommitted capital that you've highlighted in '17 or '18.

But do you have any estimate of where that might be in '17 or '18 on your framework?

I'm sorry. I don't have this figure available for me.

I will ask Mike to call you back in that respect.

Thank you, good afternoon. A couple of modeling questions left.

Just firstly, in terms of your upstream affiliate result, it's been sort of reasonably robust through 2015 and then fell away in Q1 of this year. Is that simply sort of LNG lag effects coming through?

Or are there any other factors there? And then just secondly, in the cash flow statement you have introduced a line for payments on the perpetual subordinated bonds.

Clearly that's the coupon being paid on those. Can you remind us -- is that simply an annual payment that will be in Q1 each year?

Thank you.

So for the second question, yes, it is an annual payment. On the equity affiliate, basically the result of the upstream equity affiliate was about $270 million first quarter this year, coming mostly from LNG and also from Novatek.

It is our view that the oil price environment and gas price environment has an effect on the equity affiliate result; and that's the main reason why it is weaker in beginning 2016 than it was, let's say, a year ago. Thank you.

Hi, Patrick. I have one question around your latest project start-ups.

You had many over the past couple of months. Can you highlight those that are not yet at plateau and are still in ramp-up mode, so that we can see what kind of, I would say, additional prediction we could have from those start-ups in coming quarters?

Honestly, I will not go through the entire list of the nine projects that we have launched. Yesterday, obviously, Laggan, Vega Pleyade, Surmont are ramping up at the moment.

Gladstone also the same. The first train started, but not the second train.

So that's basically what I can tell you.

Okay. And -- or can you just concentrate on Laggan, just telling us how close you are already to plateau or not?

Okay, thank you for your time and your questions, because I think that was the last question. We are obviously pleased to begin this year with a clean set of results that demonstrate our resilience and the strength of the integrated model.

The first quarter are in line with the objective we set for the year, particularly in terms of reducing the cash breakeven, which I think is the most important part of the metrics. We are confident that we are implementing the right strategy, and we are delivering it at the moment to make Total a better, a stronger company, regardless of the environment.

And we believe -- and I think this is of use -- that our numbers confirm this. Thank you very much, all of you.