TotalEnergies SE (TTE) 2016 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'd like to turn the conference over to Patrick de La Chevardiere, CFO. Please go ahead, sir.

Hello. Patrick de La Chevardiere here. Most of you know that we had our Investor Day in London last month. Our messages are straightforward. We are committed to be excellent at everything we can control and to getting the most out of our existing assets.

We are delivering upstream production growth of more than 4% this year and continuing to cut costs. And this positions Total for superior cash flow growth. We expect the environment to remain volatile. But, based on our 2015 and first half 2016 performance, Total has been the best-performing major, whether the oil price is raising or falling. And we are using active portfolio management combined with disciplined organic investment to bring the portfolio that will take us into the next decade.

Since the Investor Day, there have been a few highlight. The sale of Atotech was signed for $3.2 billion, about 12 times EBITDA in cash. We anticipate closing the Barnett preemption in the coming days. We just announced a strategic alliance with Petrobras that should open up some new opportunities in Brazil for upstream and downstream gas and power. Kashagan started up this month, and it should add 30,000, 35,000 barrels per day of oil net to Total on average next year. And for the most recent dividend, the take-up for the scrip shares was 64%.

The third quarter 2016 environment remains challenging. Brent was $46 per barrel, stable compared to the second quarter, but our average realized hydrocarbon pipe fell by 2%. And European refining margins were $25 per ton, a decrease of $10 per ton compared to the second quarter. But, they are back above $40 per ton since the beginning of October.

For the results, we reported a solid set of third quarter numbers, broadly in line with the second quarter. Adjusted net income $2.1 billion, or $0.84 per share, a decrease of 5% compared to the previous quarter. However, operating cash flow before working capital changes increased by 13% to $4.5 billion, more than covering organic CapEx of $4.1 billion.

We will achieve OpEx reduction in 2016 of more than $2.7 billion compared to a target of $2.4 billion. And our CapEx outlook for 2016 is $18 billion, or the bottom of our range for the year. Year to date, our predividend cash flow breakeven is around $45 Brent, in line with our guidance. But, this does not include the $3.2 billion from the sale of Atotech.

As usual, we will cover the number by segment, starting with upstream. We are continuing to deliver upstream growth well ahead of our peers. Hydrocarbon production increased by 1% quarter over quarter and by 4.3% year to date. We have started up all five major projects planned for this year, including Kashagan in October, on top of nine startups in 2015. We are on track for a new project to add 350,000 barrels per day in 2017. And at $60 Brent, this represents close to $3 billion of incremental cash flow.

Cash flow is our primary metric. And the important number for the upstream is the operating cash flow before working capital changes, which increased by $470 million or 21% to $2.8 billion in the third quarter compared to the second quarter.

Production from the new project is accretive to cash flow on a per barrel basis. So, we are benefiting from the ongoing shift in the production mix as we add new barrels. In addition, we reduced OpEx by about $200 million in the third quarter compared to the second quarter. And year to date, we are below our target for the year of $6 per BOE. So, you can see that upstream is performing well, particularly in terms of increasing operating cash flow and reducing the breakeven.

Adjusted net operating income for the upstream was $877 million, a decrease of 22% compared to the second quarter. The tax rate was 28% in the third quarter compared to 3% in the second quarter. The contribution of equity affiliated with second quarter was higher than average due particularly to strong results from Novatek in Russia.

Just a few words about our LNG businesses. LNG volumes have grown by 5% year over year for the nine months and represent more than 30% of the upstream net result. And this is part of the reason why we have outperformed our peers.

Moving to the downstream, adjusted net operating income for the downstream was $1.5 billion in the third quarter, a 5% increase compared to the previous quarter. The strong contribution from downstream has been the backbone of Total resilience. European refining margin were lower, but throughput volumes were higher. We are on track to reduce the breakeven to less than $20 per ton. And this will further strengthen our ability to resist volatility in the environment.

Marketing is performing well, generating a return on capital deployed of about 19%. New energies contributed $100 million in the third quarter, reflecting the completion and sale of the Henrietta solar farm by SunPower.

In terms of cash flow, the downstream generated $1.65 billion in the third quarter, equal to its contribution in the second quarter, and represents $5 billion of cash flow generated year to date, so on track to deliver $7 billion for the year, as announced in February, when we also indicated that $7 billion is a sustainable level of cash flow.

Finally, the corporate section. Our predividend organic breakeven is close to our guidance of $45 per barrel Brent for the nine months. Organic CapEx were $12.8 billion. Operating cash flow before working capital changes was $12.2 billion with Brent at $42 per barrel on average year to date. There was no net impact form net asset sale. And the sale of Atotech is not included.

The Group effective tax rate was 22% in the third quarter, flat compared to the previous quarter. This increase in upstream tax rate was offset by a decrease in the downstream tax rate due to the weight of new energies in the results. Gearing was 30.6% at the end of the third quarter, stable since the start of the year, despite of the challenging environment.

To summarize, we are executing and delivering according to plan. Third quarter results were clean and solid. We are continuing to benefit from the integrated model. Production is growing by more than 4%. And we are continuing to cut costs.

So, I am ready to begin the Q&A. And as usual, I am asking you to limit yourself to one, two, three, four questions at a time.

(Operator Instructions). Iain Reid, Macquarie.

Hi, thanks, Patrick. Can I just ask a question about SunPower? The $100 million you talked about in new energies for the quarter, I presume that most of that was SunPower. And can you give us some guidance about how lumpy that kind of level of contribution's going to be going forward? I understand it's because they sold an asset during the quarter. Is this something we should expect to see every quarter, or how should we look at it in terms of frequency?

And second question is on chemicals. Can you give us an indication of what you're seeing in terms of margins and how you see those going into the fourth quarter and into next year?

Okay. Thank you, Iain. I have some difficulties to answer on SunPower because it is a listed company and will broadcast their results on the market and some forecasts I assume at the beginning of November. And as it is a listed company, I don't want to provide any insight to anyone listening to this conference.

Nevertheless, we within the new energies posted $100 million contribution in net operating income this quarter. This is due to the completion and the delivery of the Henrietta solar farm in the US by SunPower. Henrietta is a solar farm of about [100 million] megawatts. I'm sorry, but I can't say more than that.

On the petrochem, yes, the petrochem have remained strong because the polymer demand is strong, and feedstock are cheaper. This is another illustration of the added value of being present for the full line chain. We are taking full advantage of the margin notably thanks to the large integrated platform we have in Asia and in the Middle East.

Just to give you an idea, the order of magnitude given for the first half year remains valid. Petchem represents a bit more than a third of our refining and chemical results for the first nine months. I think this gives you an idea of how strong were the margin. And we don't see any margin going back at the moment.

Okay. Thanks.

Theepan Jothilingam, Exane BNP Paribas.

Yes, hi, good afternoon, Patrick. Two questions, please. Firstly, could you just maybe give a little bit of color on what's changed to bring the CapEx to the lower end of the range, whether -- what the moving parts are, whether it's project phasing, [deflation] refreshes, or FX?

And then my second question is, just in the context of the strong progress you are making on CapEx costs and also disposals, could you just talk about how you think about the process on removing the scrip? Thank you.

Okay. Theepan, I'm glad to see you back on the market. First question about CapEx. I remind you, despite the few weeks you were not attending the market, that the financial discipline is the core of our response, the core of our response to the new environment. And we continue and invest through the cycle to taking advantage of the deflation.

We are well in line with our target. We gave the target $18 billion, $19 billion before. We are at the lower end of this target. This is true. We have spent a little bit less than $13 billion CapEx in the first nine months of this year. And we should invest $18 billion in 2016.

You -- I shall recall you also that, currently, the deflation we are enjoying on CapEx is at about 30%. So, there are two effects on the CapEx new figure. The first one is, obviously, we are able to [harvest] the deflation. And second, we have a better visibility on year end at the moment. And the second is I think we are more efficient in handling our operation.

A few example, on [Agina], the drilling campaign is honestly going very well with the average expected number of days per well reduced by 20%. This is part of all those CapEx going down.

So, the key question about the scrip dividends, which is not difficult to answer. We make clear that, at $60 per barrel in 2017, we will remove the discounted scrip dividend. And we are committed to remove this dividend -- not the dividend, sorry, the scrip dividend at $60 per barrel.

The decision itself and the discounted scrip dividend for 2017 will be validated during first half 2016 -- 2017 and will be sanctioned by the annual shareholder meeting, which is in May. So, let's assume that, for (inaudible) we enjoy an oil price above $60 first quarter next year. My view is that the Board will ask the shareholder meeting to remove the scrip dividend. Actually, it doesn't need to ask to remove. It just needs not to ask for another scrip dividend.

Of course, if we are in a very volatile environment at the beginning of next year, let's say between $50 and $55, the decision to maintain the scrip dividend will be going through the shareholder meeting. And then if the oil price bump up later on, we can remove the discounted part of the scrip dividend in order to reduce the take in share of the dividend.

Okay. Thank you.

Brendan Warn, BMO Capital Markets.

Yes, thanks, Patrick. And good afternoon. Thanks for the opportunity to ask a question. Just two questions, if I may. Just in terms of Nigeria and the wildfire impacts in Canada because -- what do you expect in terms of impact in fourth quarter in terms of the security situation in Nigeria?

And then just secondly, in terms of -- just I know we've just had the Capital Markets update, but just so I'm clear on the project delivery in 2017, and particularly Ichthys, how that's going in terms of delivery in 2017 rather than flipping into 2018, please.

Okay, Brendan. Thank you for your question. First question about the impact of the fire in Canada, which is currently over, it was the impact on the third quarter was neglectable. I think it was 4,000 barrels per day in aggregate at the end of the quarter.

On Nigeria, the security condition impacting production are mainly related to periodical shutdown on the onshore pipeline due to illegal connection and bunkering. The impact for this quarter was about 30,000 barrels per day.

I have to say that the offshore facilities are not impacted. Very frankly speaking, I don't have any perspective to see and to know what's going to happen next quarter. It seems that the situation is improving. But, that's it. It's just a feeling, and I will not beat on that.

The question on the project delivery, mainly your question about Ichthys, where we own 30%. The overall progress is about 90% at the moment. According to the operators, the startup is scheduled in second half 2017.

Construction of the TPF and the FPSO in Korea is complete. And commissioning work are ongoing, ready for sail away by end of 2016 and then sail away to the field at appropriate timing. Exact timing is yet to be confirmed by the operator. But, according to this operating, works are ongoing to keep startup date unchanged. All modules for the LNG plant has been delivered to Darwin. And commissioning is in progress. And the pipeline I remind you was completed in 2015. That was for Ichthys. Thank you.

Thanks, Patrick.

Thomas Adolff, Credit Suisse.

Hi, Patrick. Two questions from me as well. Shall I blame you or someone else in the finance department for Total's working capital management so far this year? What has gone wrong? And when should we expect the full reversal of the working capital you've built in the second quarter?

Second question, on LNG, you are developing a number of LNG projects, Yamal, Ichthys. GLNG is ramping up. And obviously, you have some greenfield optionalities Elk-Antelope, or Papau LNG you call it now. But, in your view, for a company like yourself or for anyone, what is the critical mass needed really to hit the sweet spot of value and risk in LNG? And do you think you have a gap there right now? Thank you.

So, the working capital, I know it is not a big figure, but working capital improved by around $200 million this quarter. Basically, all branches getted better, but one, which is the E&P division. And now, we are going to tackle this issue in the E&P division.

The point is that, when you recognize that you have an issue in the working capital, it is not a matter of weeks to reverse it. It takes months. And I have no doubt that we will continue and improve this working capital figure in the fourth quarter.

We are working on it. I recognize that the effect of this work at the third quarter is not tremendous. We are not disappointed that -- because we know it will take some time. And all teams are working to reduce this impact at the moment. And obviously, we expect [more even] by year end.

On LNG, Thomas, I like to remind you that LNG representing 15% of our production is making 30% of the upstream net income. So, it is a good business, whatever you can earn as well. I remind you that, when we sign and launch an LNG project, we have contracted all the volumes produced or 95% of the volume produced by this project. This is the case for Ichthys, for GLNG, for Yamal when it will start. All the volume are contracted.

And I think we already have the critical mass. We are number two in the world. That's not so bad. What matters is the portfolio size in trading and downstream. And I think we have both. So, we are profitable now and I would say very profitable because our scenario is different than other companies. We contracted long term. We don't play spot market. And we are profitable now, and we will remain at the same level being profitable.

Okay. Thank you.

Oswald Clint, Bernstein.

Yes, thank you. Thank you for the question. I wanted to ask about LNG as well, please, the -- your comments on the good volume growth you've had this quarter and across 2016. I guess some of the big Asian importing countries have been a bit soft in terms of their imports. So, my question is, are you still -- is Total still placing your volumes into those legacy countries, or are you having to place them elsewhere, despite some long-term contracts? That's the first question.

And then yes, you mentioned the critical mass in LNG. I note the other comments on -- in marketing and services to that, but parts of the business lacking critical mass. Is there a big portion of the marketing and services business that's lacking the critical mass, and it could be for sale at some point? Thank you.

So, back to the LNG, yes, we had good volumes and good results. And usually, we were selling long-term volumes to Japan, Korea, Taiwan. We enlarge our marketing activities to mainland China, then to Indonesia. And I think this is part of our business to provide LNG to those new countries willing to buy LNG.

And I think we are flexible enough, and we have a large portfolio which enable us to sell long term or medium term volume to those so-called new countries in the market, like for instance Indonesia. And I remind you we started to sell to mainland China also, obviously, which is a great importer at the moment.

On marketing and service, is marketing and service lacking critical mass somewhere? I would say that there is one country where -- in Europe we are ready to sell, which is Italy in our operation with Erg. So, we have launched a process, Total and Erg together, to sell our affiliate in Italy.

I remind you also that we had the same feeling because of the difficulty of the country itself. That was not a question of critical mass. But, that was a question of difficult to -- we face in our marketing and service business. We sold our affiliate in Turkey.

At the contrary, we increase our operation in Africa by what we call the Gapco operation when we buy assets in Africa, in Kenya, Uganda, and Tanzania. So, we are rotating the portfolio where we believe we have a plus to add and where we could make some money and exiting the countries where basically we think we are no more able to improve our business.

Understood. Thank you.

Rob West, Redburn Partners.

Hi there. Thanks for taking my questions. I'd like to ask two, please. One's on Nigeria and the comments in the press about NNPC leaning more on partners and JVs for cash flow. And I was wondering, with the working capital question that Thomas was alluding to, are there any JVs around the world where you have more cash sitting in the -- helping your partners at this time which we should think of as coming back in future quarters? That's question one.

And question two, I'd just be interested to understand a bit more of the difference between the P&L tax and the cash tax this quarter. Find that one a bit harder to back out from your disclosures. So, any numbers you could give around the specific cash tax paid would be super useful. Thanks very much, Patrick.

So, Rob, don't worry. We will always took your question in the future. Your question about Nigeria potentially having not paid its share of some cost, for instance, has it happened elsewhere? I have to say that our unpaid exposure in Nigeria is mostly covered by what we call carry agreements, which are in place, where we recover our debt through taxes and oil offtake.

Of course, this creates some working capital impact. But, that's not explaining the whole working capital effect we have at the Group level at the moment. This is a small part of it.

The question about the P&L and the deferred tax and so on, the effective tax rate for the Group was about 22% this quarter, stable in comparison to last quarter. The upstream tax rate is back in third quarter to a more standard level. I mean by that that the 3% tax rate we had last quarter was not normal. It was impacted by a deferred tax asset booked in some countries, which has a positive effect on the income, but no cash effect.

In the downstream, the tax rate has been lower this quarter, mainly thanks to heavier weight of new energies, which is benefiting from a lower tax rate. I don't have the exact answer for you how much exactly we pay in cash and how much is deferred. But, Mike Sangster will call you back on that matter.

But, I would say that, in some countries, we are close to the tax breakeven. So, some months, we are paying taxes. Some months, we are not paying taxes and making some tax losses. So, it's quite difficult to answer, but we will answer you.

That's really clear. Thanks very much.

Biraj Borkhataria, RBC.

Hi, Patrick. A few quick questions. First one was on Brazil. I was wondering to get your thoughts on your strategic alliance with Petrobras and how you expect that to play out over the coming years. In terms of what you're looking for in terms of new JVs or assets, are you looking for early-stage appraisal activity or expiration, or would you be interested in volume also?

And then the second question would be on the Barnett shale acquisition, which looks like a good opportunistic deal. Can you talk about what level of CapEx is required to keep production flat at that asset? Thanks.

First question on Brazil, honestly, we at Total are very happy to enter into such an agreement with Petrobras. We do recognize Petrobras as being a good operator. They have great assets. And we like to work with them.

We are -- we have just signed this MOU for this strategic alliance. Obviously, [depends] new opportunities for us in Brazil. We know Petrobras well, as I told you. For instance, for our participation in Libra, where things are going well, we are in a call for tender process for the first FPSO or the number two if you consider the early production scheme being one FPSO. And we look forward to build our relation with Petrobras on that.

We pursue opportunities with Petrobras. We are discussing with them at the moment. The alliance is perfectly fitting our strategic target. We are building our portfolio on technological strength that we can bring to Petrobras.

And we are -- I would -- as I repeat, very happy to expand our exposure to Brazil because, not only due to the quality, the high quality of the assets that you can encounter in this country, but also to the fact that we are glad to work with Petrobras, who is, I repeat, a good operator and a good company. And they are, Petrobras, getting out of the mess they were facing in the past. And I'm glad to see that Petrobras is back to work with a major oil company like us.

Let's talk about the Barnett. Yes, we took this opportunity to preempt 75% from the Barnett. As I told you, we owned 25% before, which enabled us to preempt the deal. It has been -- this transaction has been negotiated by a first reserve affiliate for more than a year. The term and condition were extremely attractive.

We believe that this deal is excellent. And it's rare for me to use this word excellent. Acquisition is $500 million. Midstream contract will be restructured. The Barnett is cash positive now at less than $2 per million BTU [and we have] through this new set of contract.

We will establish a new operating company, basically hiring people coming from Chesapeake and some managers that we will hire from the US market. There will be no expats in this business. And I think that basically we are basically hiring from Chesapeake about 150 people to operate this transaction. And this deal is opportunistic. And we recognize it. And this new operating company dedicated to the Barnett will be fully dedicated to this asset.

Is there anything you can say on the level of CapEx you expect to spend on that asset over the next year or so?

Honestly, I don't know. I have an idea that it was very limited. Basically, that was related to well intervention and some workover to maintain the production I think. So, it's a limited number, but I don't have the exact figure for you.

Okay. No worries. I'll follow up with Mike. Thanks.

Lydia Rainforth, Barclays Capital.

Hi, Patrick. Two questions, if I could. The first was just on Libya and whether you can give us an update on what Total is seeing there.

And the second one was coming back to the scrip dividend idea. Given the progress that Total is making on the cost savings and given that downstream margins seem to have improved a little bit from where we were back in September, is there a scenario you can see where, actually, there might be a chance of removing the scrip earlier than if the oil price -- or at a price lower than $60? Thanks.

Lydia, on your last question, only stupid doesn't change their mind. I recognize that. But, on this matter, I will stick on what we said. I agree with you that next year, we see our breakeven after dividend at $55 per barrel. But, I maintain my statement that the discounted scrip dividend will be removed at $60 per barrel. We need some caution in that matter because we are facing a volatile environment.

On Libya offshore, we are operating offshore Al Jurf as usual, normal operation. Offshore, we have had some damages on our assets. So, basically, and we have no people on the ground I would say at the moment. So, it's too early for me to say anything in that matter.

The production overall in Libya is reported to have increased to about a little bit less than 600,000 barrel per day I think. The National Oil Company has announced a 900,000 barrel per day target. This would include the restart of El Sharara field in the south desert in which Total has a stake. El Sharara would represent about 30,000 barrels per day net at plateau. But, I have no more to say.

The current situation is difficult to assess. It's a civil war situation. We noted this positive statement by the National Oil Company. And we will follow closely what they are doing to recover operation on both field.

Thank you.

Irene Himona, Societe Generale.

Good afternoon, Patrick. I had two questions, please. First, on the upstream, with 14 new startups since 2015, can you say roughly what proportion of production is currently PSC, please? And has there been a noticeable change in the last sort of couple of years?

And then secondly, I know you would never comment on market rumors. But, thinking about your targets in the downstream in marketing in particular of growing and expanding your African sales and market share, theoretically, if a set of downstream assets were to become available in South Africa costing roughly $1 billion, would that be in line with strategic targets in that business? Thank you.

So, your first question about the new projects started and the share of PSC, I would say that, basically, this at PSC represent 30% of our contract. And that will be applicable also to the new production coming on stream.

So, your other question about downstream, I'm not going to comment on press rumor because, if I started to do so, I will spend my time at the phone. We are reviewing every month I would say opportunities in the market. Sometime, we pursue that, like what I mentioned in Tanzania, Kenya, and Uganda. Sometime, we don't. This is our own decision. And I will not comment further. Sorry, Lydia.

Okay. Thank you.

Martijn Rats, Morgan Stanley.

Hi, hello. It's Martijn. I have only one question left. I wanted to ask you about Iran. And my understanding is that you're looking at a large petrochemical project. And I was wondering what the attraction of that project was.

Sorry, first, I have to apologize. I say thank you to Irene and for the last intervention.

So, your question about Iran, of course, we are interested in Iran. And once again, I repeat, I do not comment on rumor. And I'd just like to remind you what our CEO said, that we look primarily to gas and petrochem projects, but nothing is signed yet. This is the situation today. We are discussing with Iran. And when there will be some news that we can give to the market, we will give it.

All right. Thank you.

Henry Tarr, Goldman Sachs.

Hi. Thanks. The main question was just around CapEx. So, I think you've talked about $18 billion for 2016. That implies still a substantial pickup in 4Q, so the $5 billion. I just wondered whether there were sort of specific items coming in 4Q or whether there's an element of prudence to the guidance.

And then secondly, just to come back maybe on the working capital in the upstream. Sorry, this is probably the third question. But, is this primarily related to receivables or inventories? And are they kind of specific countries or projects that you're focusing on, or is it kind of a broad based issue? Any color would be great. Thank you.

Your first question about CapEx estimate for fourth quarter, you have to know that -- and you can see that if you review our figures historically -- that the fourth quarter tends to be the heaviest quarter in terms of CapEx every year. So, the $18 billion target take into account this [human BA] view of spending more money at the end of the period than at the beginning.

The second question was about working capital in the upstream. It's a broad issue. It's not only, as I said, a matter of unpaid amount by National Oil Company, both the question of receivable and payable. So, we can leverage on those two aspects of the working capital. And we started to do it. I recognize, as I said, that the $200 million improvement is not enough. But, I am sufficiently comfortable to see more benefit of this view that we need to improve this working capital in the fourth quarter. It will (inaudible) I'm sure.

Great. Thank you.

Anish Kapadia, Tudor Pickering.

Good afternoon. Couple of questions from me, please. Firstly, I was wondering if you could talk a bit about the political and fiscal climate in Nigeria with regard to thinking about sanctioning projects. You made -- you increased the size of one of your discoveries that was announced today. And also, I think you have another number of operated and nonoperated projects within Nigeria. So, just wondering, how do you see the political climate? Are the fiscal terms attractive enough at the moment to be able to go ahead with projects?

Yes, you know that basically in Nigeria, we are facing a so-called political issue onshore because of the unrest situation that we face onshore within the SPDC joint venture we have with Shell.

It is obvious also for me that Nigeria is a great country. And I mean by that that those people are handling their operation in a manner which prevents people like us to leave the country. So, we are very happy to stay, and we will stay.

There are some unpaid amounts from NNPC. We are not the only one. We are negotiating and putting in place agreement to recover this money. And I think that's it for the moment.

I would remind you that, in Nigeria, Exxon -- we know the operator on the Owowo field that we discovered a few years ago. Exxon drilled another well and completed this well a few days ago and confirmed a potential of a giant field between 500 million and 1 billion barrel according to them, which is comforting our view that we had at the beginning.

And I would say that you know Owowo is on the same block than Usan. And when we were unable to sell Usan, part of that was due to the fact that we were unable to have buyer recognizing the value of Owowo.

And everything is fine now. We had a great asset, a giant field with a good operator. We own I think 18% of this field. And it will go on. And I'm glad to see that we will be enjoying deflation to sanction this project, which will for sure be sanctionable in the current condition at the moment.

Thank you. I had a quick second question. On the cash flow statement, you have the line of noncurrent liabilities, valuation allowances, and deferred taxes. And it's generally significantly negative. I just wanted to kind of clarify. Is the vast majority of that impact the deferred tax impact, or are there other kind of significant things in there that you're able to split out?

Let me take the cash flow statement. On which page are you of the press release?

It's on page 21, the third line.

Yes, I would say that most of it is deferred taxes, valuation of allowance for sure, and some noncurrent liability. I cannot [foreseen] some at the moment. But, we will check on that. And Mike will call you back if any noncurrent liabilities appear on this line.

Thanks very much.

Christopher Kuplent, BofA Merrill Lynch.

Hi, good afternoon. Thank you for taking my questions, two. I'll try and keep it short. Considering your guidance for $55 cash flow breakeven and perhaps exiting from the scrip next year, how do you feel about hybrid bonds? Do you feel any more need of issuing additional hybrid bonds?

Do you think that's an attractive tradeoff in this environment, or would you argue actually, when we exit from the scrip, we also are no longer concerned about our credit rating, our gearing because we are obviously producing positive free cash flow, and at that stage, you wouldn't want to issue any more hybrid bonds?

And the second question, I think it was touched on by a number of people already today, is on tax rates. You've had a few quarters now for the Group in the low 20s. And I wonder, obviously, looking back at history, we've been above 50% fairly consistently, how quickly you think we will return there, and to what degree that is linked to $55, $60 oil, thinking about your effective tax rate over a number of years, not looking for any specific guidance.

Chris, the first comment I would say on hybrid is that this is very cheap equity. The last seven non-call -- seven-year non-call hybrid we launched was at the rate of 2.7% a year. And hybrid is one of the tools we are using to manage the strength of our balance sheet. And the market offers this opportunity, and I will take it.

And honestly, as I used to -- the way I used to manage the issuing of bonds or hybrid, I issue when I don't need the money in a preemptive manner. So, I'm not saying that I am going to issue for sure any hybrid, but I don't want to forget about it if there are other opportunity on the market.

Honestly, today, I don't need to issue further hybrid, but if the market is mad again, I will take the opportunity.

Okay.

About the tax rate, and I fully understand that it is difficult for you guys to forecast our tax rate, not mentioning that the last quarter we had on the upstream a tax rate of 3%, and now, we are back to 28% in the upstream division.

Just to try and give you some not guidance but some idea, you can see that, on the first quarter, our upstream result was just above the breakeven for income when Brent was at $34 per barrel. That was first quarter this year.

Of course, the breakeven varies field by field, but this is an average. Basically, at $35, you are where most of the field, a large part of the field are as the breakeven in terms of taxes.

When you -- whenever you are close to the breakeven, the tax rate can change dramatically. And that's why it is difficult to predict. And I fully recognize that it is difficult for you. And your model will be very difficult to run assessing this tax rate. Nevertheless, at $45, $50 per barrel, the burden of the tax at 20% is not very high. So, the effect on the overall net operating income is not big.

Basically, I would say that upstream tax rate could trend back to a more typical level of, let's say, 40%, maybe 50% at an oil price at $60 per barrel.

Perfect. Thank you very much, Patrick. That's very helpful.

Jon Rigby, UBS.

Yes, hi, Patrick. I'm going to ask a question which I suspect you haven't had for a couple of years, which is that, if you look at your activity rate, and you've talked about ongoing CapEx of $15 billion to $17 billion I think. So, what is the rate of sanction activity that you need to get to over 2017 and 2018 for you to ensure that you are actually spending that level of CapEx?

So, you've obviously not sanctioned a project for a couple of years. So, I'm just trying to gauge what the inflection point is going to be and the pace at which your sort of sanctioning and development activity will start to pick up over the next couple of years that implied was in the CapEx figures that you're giving. Thanks.

We do have some flexibility in our CapEx for 2017. That does not answer directly to your question, but this is part of the answer. For 2017-2020, we expect to spend in the range of $15 billion to $17 billion, $15 billion if the oil price is low, $17 billion if the oil price is higher. But, we are in the range of $60 per barrel.

The split is as follow: $3 billion to $4 billion will be spent in the downstream and gas and renewables. Then this leads to $12 billion to $13 billion left for the upstream. $3 billion will be used to resource renewal, either exploration CapEx for $1 billion or $2 billion for acquisition of resources discovered by others.

We need to spend about $3.5 billion, and this is valid under the current cost structure given by the market with the 30% deflation we enjoyed. $3.5 billion is needed for maintenance and [integrity], which needs for $6.5 billion for growth projects. So, in aggregate, for growth project, to renew let's say our production decline and to add 1% to 2% new production, we need to spend $6.5 billion, maybe $7 billion for growth projects.

We will work and sanction world-class projects, like Libra, like Papua New Guinea, like Uganda, and do not forget about [Bon fields], which were not viable in the previous cost environment, which are now validate. A good example is Zinia, a tieback project, $100 million -- million barrel reserve asset. This asset Zinia was not bankable I would say three years ago. It is now viable, and we will sanction it. So, there will be further development of one field asset in the future.

Right. But, is it fair to say that we should expect some visibility on further projects emerging so you start to fill that sort -- the 2018 and certainly 2019 as things like Four Hills and Yamal and so on begin to fall off to the spending?

Jon, you know we are currently discussing with Iran. We are currently discussing with Brazil. There will be project coming from both sources of discussion.

Okay. Thanks, Patrick.

Kim Fustier, HSBC.

Hi, good afternoon, Patrick. I had two questions, please. Firstly, I wondered if you could give us a bit of color on the incremental cost reductions, given the 10% increase in your cost savings targets, particularly as it relates to the breakdown between efficiency gains and any other factors.

And then secondly, just coming back to Libra in Brazil, could you talk about the progress towards FID on that first FPSO? From what I've seen, you need to bring the breakeven down to about $35 a barrel and cut costs by about 35% before you sanction the project. Can all of this realistically be achieved by the first half of next year? Thanks.

So, Kim, first question about incremental reduction, we don't make my life difficult when I announce that we are increasing our cost cutting targets. We were announcing $2.4 billion cost cutting for 2016, and we are now at $2.7 billion. I -- most of it is coming from our own work. There is some limited part of coming from the deflation, but most of it is coming from our own capability to improve our operation.

It is true that it looks like an acceleration of our cost saving. We are working more and more on it. We recently launched what we call the Total Group's shared services, which will provide services to the company branches in IT, in human resources, for instance. And this will be a source of new saving in the future.

This new organization will be put in place next year. And just to give you an example, what we did on IT on the limited scale, we save $100 million last year on IT, thanks to this reorganization that we will continue to implement now on purchasing, on accounting, and so on.

Libra FID, there will be several FPSOs on Libra, maybe four, maybe five, seems that we are more inclined to say four today. We expect the FID for the main FPSO beginning next year. It's -- the FPSO is a (inaudible) and operate. So, the CapEx outlay for us and for Petrobras and for the other partner will be limited. The first FPSO is expected to yield an IRR above 20% at $50 per barrel and, of course, even higher if the oil price goes up. That's basically what I can tell you about Libra.

Thanks a lot.

And, Kim, I'd like to remind you that the devaluation of the currency in Brazil may enable us to cut costs further.

Great. Thank you.

Thank you. We have no other questions now. I would now like to turn the conference over to Patrick de La Chevardiere for his concluding remarks.

Thank you very much, all of you, to join us today. I repeat the main takeaway messages that I would like to close with. Total is on track to deliver production growth, as you see, of more than 4%, and by the meantime cutting costs more than what we initially thought. Cash flow is improving. And our priority is to continue reducing the breakeven and improving this cash flow.

Through active portfolio management and disciplined organic investment, we are building the portfolio on top of that that will carry us into the next decade. I mentioned Iran discussion and the discussion in Brazil. The balance sheet remains strong. And we are well positioned to be the most profitable European major oil company. Thank you.

Thank you. This will conclude today's Total third quarter results conference call. Thank you for your participation, ladies and gentlemen.