TotalEnergies SE (TTE) 2015 Q4 法說會逐字稿

So, good afternoon, everybody. It's a pleasure to welcome in the same room here in London on September -- you know, we love traditions in Total. By the way, if the tradition is bad, you have to tell that to Mike. So if you don't hear us well, please tell us at the end of the meeting.

I would like to start this meeting by saying first that, as you know, we have a change of governance in the Company, and to say thank you to Thierry Desmarest for his long and outstanding service to Total, including this past year as Chairman advising the young CEO.

In line with the rules of the age limits, Thierry de Maray stepped down as Chairman in December 2015. And, consistent with Total history and with the idea that in oil and gas business it's good to have one number one in front of it as the head of states of producing countries, the Board has elected to recombine the roles of Chairman and CEO. And, on my proposal, the lead independent director, Mrs. Patricia Barbizet, has been elected. And, of course, I can tell you that I'm proud to follow in the footsteps of Terry and Christoph Margery and try to do as well as they have done for the last 15 years.

Still, starting the job, these challenges have been staying the course despite the oil price collapse. As I told you in September, we are in a commodity business, and volatility is inherent to this business. So even if we meet every six months, you don't have to expect today to have huge news. We will not change every six months all the guidelines that we give you. And, in fact, what we intend to do today is -- with Patrick -- is, of course, to comment to you the results of 2015, and then to give you some guidelines for next year, 2016, but keeping what we say to you for the medium-term as a basis.

And I think it's, by the way, a good philosophy not to go up and down according to the price of oil but to try and keep a stable strategy. And this is what we will try to do -- a sustainable and stable strategy for the medium-term.

The second message is that one year ago in February, I told you -- and again September -- in front of such volatility there is one target, which has to be at the top of our table, which is to look carefully how we can lower our cash flow-breakeven. And to do that, we have to be excellent at what we control.

What we control is safety, is our capacity to deliver operational excellence, project execution. We control our costs, to be disciplined on OpEx, to be disciplined on CapEx. We control our technology.

And I should add also today we control also -- even if the word control is maybe not the best -- we control also our people. We train them, we select them, we motivate them. And if I have one lesson over the last year within Total, is that the strength of the people of Total and their capacity to execute the message and directive of the management is absolutely astonishing. And if we are today very pleased to present you, of course, and I'm quite proud to present the results of 2015 -- being the most resilient among the majors -- the first reason is the quality of the work of all the teams of Total.

It's also the result of decisions which we have -- have been taken before, in the past. We were a first mover on CapEx and OpEx reduction. We timed restructures Downstream. We, of course, benefit for our portfolio of major projects starting up now, including growth; plus began a strong emphasis on operational performance across all segments.

So I'll say you, I'm satisfied with the good progress we've done. And, in fact, I'm satisfied also because we took some commitments last year in February and we delivered today on these commitments -- which I think is the best way we put to offset some aggressive but realistic targets. I remember a discussion with some of you in February; at the end of the day, I'm pleased to see that we have been able to reach these targets, and Patrick will comment that to you.

Then, in the introduction, of course, I will comment safety. The small video that you've seen is an example of what you should not do, but unfortunately it happened like that. It happened like that in all our life, but it should not happen like that in a Company like Total.

We were -- we have with the tradition to tell you safety is a first priority. Safety is no more the priority -- first priority. Since January 1, I declare safety in the Company as a core value, which is much more than a priority. It's permanent, a constant priority. You not discuss it; it has to be embedded in a company as a core value. And if you understand that, that means that there is no question about compromising about costs. It is about everything else. This is the way we want to approach safety, not only -- and we are pleased with the results of improving again by 12% per year the Total recordable injury rate. But to go beyond that, it's a question of culture.

A new, central HSC organization will be put in place in Total by September 1, and all central team of all divisions will be put together in a single, central organization with one objective, which is to develop across the board of the whole Company the same safety culture. And this is one of the answers that we will bring on this core value, which is developing the same culture -- safety culture across the Company.

Safety is important, of course, because it's a way to protect people and assets. It's also important because, as you can see on the right-hand side of the slide, safety and operational performance go hand in hand. Safety is the cornerstone of operational efficiency, and Refining & Chemicals division last year's reserves demonstrate that statement, in which I am a strong believer. You can see, of the Refining & Chemicals TR IRR has dropped, while the availability of the plans have improved. And this has been translated in less accidents and better reserves, as Patrick will present that to you.

And the last point on which I insist on safety, I told you about in September -- local safety is at -- is a question, is a matter of human resources and basically of leadership. And to face such volatility, you need some leadership.

It is true that in 2015 we have been resilient, if I have to use one word. Last February, I described to you the program with four keywords, which were safety, delivery, costs and cash -- which, again, are the translation of what we control, what I believe we need to focus, by the way, whatever the price is, and not to -- because this is in our hand. And in 2015, we had three reasons why our performance are resilient.

The first one is that because we benefit from the integrated model. With all the strategy of the group since last 15 years and before has been to keep, to maintain in the Company the full value chain on oil or on gas from exploring, producing, transforming, distributing. And this model, which sometimes was discussed, is proving today its full efficiency. Because, of course, part of the value of we which have lost in the Upstream has been recovered in the Downstream business. And the main figure which illustrates that is that the Downstream cash generation in 2015 has been of $8 billion, which is quite an improvement compared to the $3 billion that Downstream was delivering in 2011.

And the second engine of this resilience was the production growth. We have invested heavily in intensive CapEx program, 15 major projects. 2015 was the first year to start some of them; 9 of them have been started. And we will continue to ramp in 2016, and new, other projects will come. And so we have this production growth at a very high level, and historical record, I think, for a major company in the last 15 years, 9.4% of growth. And this, of course, is delivering additional cash flows.

And the third engine of the resilience has been our programs of cost reductions, of targets. We have spent on CapEx and, more importantly for me, on OpEx. We have exceeded the targets which were, again, aggressive but realistic. They were not realistic because the teams have been able to do more than that. And, of course, this is part of the recipe of 2015, and the story today will tell you that we will just continue the recipe in 2016 because I don't have another magic wand.

So, then Patrick will deliver to you and explain to you more precisely, then, the 2015 results.

Good afternoon, everyone.

Let's move first to the macro. I'm pretty sure that you are fully aware of that, but what you see basically is a collapse of the oil price, which basically fell by half of its value. This is not the first collapse we are facing, and maybe not the last one, but this one is important.

We are just over one year in the cycle. Brent fell by exactly 47% to $52 per barrel. Our liquid realization also fell by 47%. On the same part of the slide you see that the refining margin, in blue, increased by a factor of more than 2.5 to $48 per ton.

On the right side you see the evolution of the gas price on the three main markets. Total average peak gas realization it is minus 33%.

You see that the end of the year dropped dramatically, between $2 and $2.50 per MBTU currently.

LNG prices dropped less than the oil price because of lag effect on one side and also on the S-curve type of price formula. Honestly, we are quite happy to have little exposure to the US gas market at the moment.

So, 2015 was a rough year for commodities because of the oversupply. For Total, strong Refining & Petrochemical margin offered some mitigation. And at the same as Patrick mentioned to you, more broadly of course, costs have been coming down across the industry, and specifically within Total.

We were actually extremely resilient in 2015, if you compare us on the right side to our peers where they have the result going down by 48% to 64% when the Brent goes down by 47%. Total net result decreased by only, I may say, 18%.

We generate $10.5 billion of adjusted net income. Downstream increased by close to 80%, to $6.6 billion mainly due to the high availability of our installations. Upstream contribution obviously decreased by 55%, but still contributed $4.8 billion. We suffered less actually because we had a resilient portfolio, because of production growth and of cost cutting.

In this environment, we are more focused on cash. Cash is our main objective, and we focus that image on it.

On the right side, again, you see that we compare very favorably to our peers by cash flow from operations, going down by 22% -- by far, the most resilient performance among the majors. In absolute terms, and I think this is important, we generate more cash flow from operations than either BP or Chevron.

Clearly, we have benefited from more stronger Downstream. That increases cash contribution by 40% to almost $8 billion in 2015. These reflect, of course, the good margin we enjoy, but also reflect years of improving the underlying business, mainly the main criteria being the reliability of our plant, the lower cash breakeven we have in our installations.

Net asset sales, that I will cover later on, added $2.6 billion. In aggregate, we generate $22.6 billion in comparison to organic investment of $23 billion at the lower end of our initial target, which was $23 billion, $24 billion. Honestly, we are very satisfied with those extremely robust set of numbers.

Portfolio management is definitely part of our strategy. The target for the three years 2015-2017 is to sell $10 billion of assets. In 2015 we announced the signing of $4 billion. For 2016, our objective is also to sign for an additional $4 billion of asset sale. This figure of $4 billion achieved in 2015 demonstrate our ability to find strategy buyers and to realize good value.

This strategy is also very helpful in optimizing the portfolio by monetizing non-core assets. And I give you a few examples -- two of them, Fort Hills and [genec Krog], that we sold in 2015, and therefore we saved CapEx by about $1 billion.

I think you know the asset we sold in 2015. You have forecast the pipeline network in the North Sea, so you can now see. You have Schwedt stake we have in the refinery in Europe, in Germany. And we have also sold our network in Turkey.

You don't see on this list, Usan. We were unable to obtain a reasonable price for this asset and therefore we decided not to sell it.

So far this year we already started our program by selling a stake in our field in Russia, Kharyaga.

Reserve replacement rate was 107%. It is our way to secure our future. We have more than 11 billion barrels of proved reserves. On a 2P basis we have more than 20 years of production. Reserve replacement is vital to support our long-term growth. Of course, we were helped by the ADCO license renewal -- by the way, with better, improved terms.

We also benefited as the others, but maybe to a larger extent because we have more production-sharing contracts than the others. We also benefited from a positive price effect.

Our three-year average replacement rate increased to 118%.

Our financial strategy is to maintain a strong balance sheet through the cycle. And I have to say that as a CFO I'm quite happy to show you that we actually in 2015 reduced our giving from 31% end of 2014 to 28% end of 2015. Each point of giving is about $1 billion of debt.

We have plenty access to the financial markets. You know that we are prudent. We have currently about more than $15 billion of cash, we have more than $10 billion of credit lines and we believe this is enough to get through a very difficult period, if any, if it goes to two years or more. This is not our scenario, but we are prepared to face it if it goes.

As a last point, we recognized $5.4 billion of impairment coming basically from GLNG in Australia, our LNG asset. Impairment made on Fort Hills in Canada. Also, the effect of the reclassification of Usan in Nigeria. Some exploration discoveries have been written off also because we don't see how to develop them in this new environment. And we impair, for obvious security reasons, Libya and Yemen.

Can you switch your slide, please?

That's an exercise I'm also quite happy to do. We on this slide are comparing our performance to the commitment we made previously.

We knew that responding to the weaker environment would require a very disciplined approach to cash management. We had a target for CapEx of $23 billion, $24 billion; we realized $23 billion of CapEx in 2015. OpEx saving target was increased at $1.2 billion; we realized $1.5 billion. Exploration budget was reduced by one-third to $1.9 billion; we did it.

On asset sales, we missed the target by the -- for the assets sales signed in 2015 by roughly $1 billion; this is Usan.

Production growth -- we delivered production much higher than the initial target of 8%; we delivered 9.4%. And for reserve addition we added more than 2 billion barrels for about $2 per BOE.

We are satisfied by those realizations. However, given the very difficult environment that we are in, we recognize that there is still a lot to do.

You may think that we have selected the KPI where we are good at; honestly, all of them on this slide. Although Brent went down by 47%, our adjusted net income went down by 18% only. Cash flow from operations, minus 22%. I know that you are already creative to explain both figures, but I think the main reason is that the bigger difference was careful preparation.

We were the first to move on CapEx reduction. We started in 2013. We were the first to say that OpEx must be controlled, and you see the achievement we made last year.

When you look at our 2015 results it's clear that the strong performance of the Downstream played a major role, but keep in mind that we completely restructured this Downstream business starting in 2012.

Production growth was one of the key to reducing our cash flow breakeven. And for 2015 and the year ahead, this is a result of projects launched in the past.

I will leave the floor to Patrick, and I think Total is well-prepared to perform competitively in any environment.

Thank you, Patrick.

Just to comment this slide, I love this slide, obviously. And I think it will be popular in the oil company quickly to motivate if we have any justification that we are going in the right direction. Again, we set ourselves aggressive but realistic targets; we have delivered them. And we are outperforming our peers, which is, of course, a way to differentiate yourself because, in fact, if we want to deliver to our shareholders is to be able to differentiate Total from our main competitors.

I just -- we would like before to enter in 2016, I (inaudible) remember what I told you in September as well. We are transitioning from an intensive investment phase, and so the level of commitment CapEx is falling off. We are delivering our production, a growing production. And so all of that is giving us increasing financial flexibility.

It's not fully the case in 2016, and you will see that we are still engaged in many projects even if we manage to adapt ourselves to the new environment at $40 per barrel. But it will be more and more the case in 2017 and beyond. And if on the top of that, transitioning from the intensive investment phase, production growing, you had OpEx savings across the board and will continue that. We understand why we are continuing to lower the breakeven.

For 2016, of course, compared to September meeting where the price was about $50, $60 per barrel, we are facing a $30 environment. So we had to adapt ourselves to strengthen some weapons. At the same time, we were on the track and we didn't want to derail from what we think is the right way to maneuver.

So you will see that we have seen on the asset sales that we have made some adaptation on CapEx, on exploration, on OpEx savings as well. But, again, the main strategy there is to keep on the track, to stay the course compared to (inaudible).

We have also in mind that we need to maintain and to preserve the long-term competitiveness of the group despite this environment. It's very important. And one of the results -- because we speak about reducing CapEx, we speak about asset sales -- but as you've seen, we are also able in the same time to renew our reserves by taking bold decisions. And we will continue to keep that in mind. It's not only a question to reduce the size of the Company in my mind; I still want Total to continue to grow. And I think -- and I will come back to that -- that we will have opportunities in the coming months and years.

So, first, again like in September, strong discipline on CapEx. On CapEx, as you saw, we have lowered the CapEx from $26 billion to $23 billion. We are transitioning again from this investment level, investment phase. We'll go down in 2016 to $9 billion, $10 billion. $9 billion, $10 billion is under the guidance that we gave you, which was the only guidance for 2016. I'm not sure we gave you any more guidance in September for the year after. Because, there, we are going down to $9 billion, $10 billion compared to $20 billion, $21 billion we gave you.

In fact, you have to link this $9 billion, $10 billion to the other guidance we gave you in September, which is that we think the sustainable level of CapEx, if we want to preserve the long-term competitiveness of the group, is between $17 billion and $19 billion. So we are at the top end of this guidance as soon as 2016.

To go down, there are many effects. One part of it is coming obviously from the market, because the market is reacting to the low price; under $30 rather than the $50, obviously. But the reality that Arnaud (inaudible) and his teams are just observing, they are also acting to activate this reduction. But there is also some choices on mature assets, because on mature assets, again, we have a policy to invest. If we have a two-year payout time at $30, it's not the same as the $50.

And so these are the reasons there is no miracle, again, why we are at around $19 billion for 2016. As you can see, we'll invest $3 billion in the Downstream. So the rest of it, but more than $10 billion, being dedicated to Upstream assets under development, and $4 billion to Upstream producing assets.

The second recipe is in our OpEx, of course. So there again, like Patrick told you, the initial target for 2015 was $800 million. We increased it beginning of last year, to $1.2 billion -- more than $1.2 billion, we told you. The Upstream teams -- it was mainly on the Upstream because most of the effort -- in fact, every divisions were concerned. But the increase of OpEx savings has been delivered by Upstream, which is obviously the division which is the most under stress because of the low oil price. They managed to deliver a savings around more than $1 billion, which was the initial program for three years. So in one year we have been able to deliver more than what we were promising for three years. So you know it's a question of willingness and a priority, and mobilization and motivation of the team.

And the Downstream has, of course, delivered what was planned, which means around $500 million -- $400 million, $500 million -- billion of savings.

In September I told you about the target of full 2017 as a three-year cost-saving program would be -- was improved or increased from $2.0 billion to $3 billion. I will not change this today. We are just adding about $3 billion. You will see next time what could be meant above. But today we have concentrated on efforts on -- in fact, it's our last month, of what we could deliver in 2016. And what's the target for 2016, as you can see, is more than halfway between 2015 and 2017; it's $2.4 billion.

I read some statements from some of you in September that you were wondering if we could reach the $3 billion. I hope that today you are convinced. I can tell you I'm fully convinced that we do more than $3 billion. And the teams are mobilized on $2.4 billion, again, the main increase being on the Upstream.

Arnaud Breuillac described it to you how he was managing this cost-saving program in September, so I will not repeat. Obviously he gave you details to show you, to give you some notion about how we organized some operations, or we have -- we allude to the design of wells.

What I can tell you is, contrary to some other companies, we don't make headlines with staff reductions. I learned something when I was in Refining & Chemicals: if you want, really, people to be motivated of improving the operational performance, on delivering your cost-saving program; and if they are afraid for their own job, you will obtain nothing. So you just have to know what is your priority. And our priority today -- and we are delivering it -- is to increase the operational efficiency and to deliver the cost-saving programs.

So I don't -- we don't have to defray them. And, by the way, they are doing the job, which is the best answer they can have given us. What we have put in place is a policy where we are recruiting less people -- which is true, but on the perimeter of Upstream Refining Petrochemicals and the (inaudible) we have recruited only, worldwide, 400 people compared to 2,000 one year before, which has an effect at the end of the day on the headcount. But, again, it's not a target, per se.

The objective is to keep the motivation. And there is another argument to this policy, because these today maybe the price is low, but tomorrow the price will rebound; I will not tell you when -- it's tomorrow -- and I will need, we will need all these people. So this is a policy, and I'm quite convinced that this is the best way to continue to maneuver in the Company. And our teams are delivering these savings for us.

This savings program -- I don't know, nothing is moving -- just to focus on -- which is important, in fact, for the Upstream division -- but the Exploration and Production OpEx per barrel; you know there are some metrics, and I will comment some of them.

The operating costs -- and there's a new rule, of the SEC rule, ACC-932, which is in fact consolidated affiliates up to the Upstream point, without taking into account evacuation and transportation costs. We are at $9.90 per barrel in 2014; went down by $2.50 per barrel, which is quite an effort in one year. Half of it is coming just a translation of the savings program. A quarter of it, this reduction, is coming from ADCO barrels, because they are low-cost barrels and they have some advantage in such an environment.

And the last quarter of the reduction is coming from foreign exchange; so we know we are very transparent to give you the explanation. But we are continuing to work at the savings program, but E&P is putting in place for 2016 will lower us to lower these operating costs to $6.50 per barrel. So, a decrease of 35% of dollars per barrel in two years.

Another figure which is not written there which is maybe also of interest, I asked Arnaud to (inaudible) me across the whole portfolio of barrels that we are production, the 2.5 million barrels per day that we would produce in Consolidated Affiliate and in Equity Affiliates, taking all-in cash costs, which OpEx, which means not only production costs but also transportation costs.

We have -- and it's an important figure for me -- owning/operating costs for all these barrels of the Company is under $10 per barrel today, under $10 per barrel. It means above that, we are making cash. So, we hope it will not drop down so much; I don't give a message to the markets today, but it's a way to explain why, probably, we are so resilient compared to our peers. Because we have a cost base which is lower, and the breakeven is lower than our peers.

You can look at it also on the right-hand side of this slide, which is technical costs. And there's a same normal norm of, SEC norm, which is not only the OpEx per barrel, but you add the DD&A per barrel and also the exploration costs per barrel. And this today is going down to $23 per barrel in 2015 compared to more than $28 per barrel in 2014.

As you can see on the graph we are the best among the majors, and I'm sure with these reserves we will maintain our leadership of this one; it's very important.

Of course, it's coming not only for $2.50 per barrel reduction are coming from OpEx, but $1.00 is coming from exploration, because we reduced the efforts but you have seen we also beat reserves. And part of it also is coming from DD&A, which is probably more surprising because we are putting onstream some new projects with historical high CapEx. But we are also benefiting from the ADCO barrels there.

Then the growth of second engine, a third engine of our resilience is strong production growth. Again, in 2015 we have delivered more than 9%, 9.4% despite the loss of (inaudible) LNG since April, which cost us around 3 points of cost -- of production increase, to 2 to 3 points, 3 points exactly, in 2015.

So, again, performance is there. We have delivered the nine starters which were promised, and this is an achievement.

For 2016 -- and you will see why we are targeting an increase of 4% -- these figures are consolidating both the guidance we gave you for 2019 of 5% per year from 2014 to 2019. And I can also confirm, if anything is not written there, that from 2014 to 2017 we'll be above 6% as we increase per year, as we told you in September.

So, this growth will come from new startups, again. So the first one of the year has been celebrated last Sunday. We are in the UK, no? We have a very controlled organic Company. We think today -- we just developed a start-up two days before to please us as we are coming in. So Laggan-Tormore, even if it's honestly a little delayed or not a little -- it has been delayed compared to our plan -- is not under production. It's an interesting development, 90,000 barrels per day. We have 60% and being operator west of Shetlands, with new fields to be connected with (inaudible) in Glenlivet in coming years. So it's full -- will be delivered.

We have also in 2015 other operated projects which we've started. Vega Pleyade in Argentina -- it's a gas project; like Incahuasi in Bolivia, both Vega Pleyade by first semester, probably by March or April; and Incahuasi by middle of the year.

Then two of the big projects, but none operated by us, will start in 2015; Angola LNG will restart. In fact, these two projects will restart. They were not covered when we start. (inaudible) LNG, the operator, announced us April, let's say by the middle of the year. And Kashagan, all the construction is clear on December 2015, so I just repeat to you what -- 2016, sorry, yes -- 2015, yes? Nobody really knows. So, 2016.

So these additional start-ups plus -- and it's more important, in fact, in terms of volume -- the ramp-up of the 9 2015 startups, but I will not give you again but you have a chart -- will give us an additional production of 7.5%, 180,000 barrels per day. We have a decline of around 3.5, so you can find back the 4% increase of production.

A word about the exploration, because it's also important to prepare the future. As you know, we have refocused the exploration. I would say under the leadership of Kevin McClellan and that you met in September, and his team, his new exploration team, it's not only a question of budget; it was, in fact, a question of strategy as well. As Kevin told you, we have no strategy where we allocate 50% of the budget to core and emerging areas, 25% of the budget to near-field exploration, and around operated asset at 25% on high-potential (inaudible) targets.

I'm pleased today because these policy begins to deliver some reserves, and in particular some large discoveries to which we have done in Myanmar on the block A-6, Shwe Yee Htun, if I'm reading correctly this language. It is -- in fact I'm pleased because it was the first license which we've farm in, and there's a leadership of Kevin McClellan and his new team. So it was the first one, and it's the first discovery. So I hope it will continue; so I encourage them to give us other advice to farm-in in some licenses.

It's a new gas province, Deepwater in Myanmar, and there are -- we have a domain there, around. And we are quite excited about it.

We have also discovered gas in Argentina; I just mentioned Vega Pleyade starting up. Leo is a new discovery; it's a fairly conventional gas field which could be connected to (inaudible) installation like Phoenix.

And as Patrick told you, we did not -- we decided to stop the sale of Usan for two reasons. First reason but -- it's true, but we had an offer which was just diminishing month after month. So in October I talked and we decided to stop all that because we don't want to lose value on such a nice asset as Usan. We are not in a desperate situation, not at all.

The second reason is that in fact we are making discoveries around Usan, and (inaudible) or West, so I think there is a big potential. So I think all that in front of us, we decided to stop the sale because we prefer to keep the asset.

Then we have some appraisals which we are giving some reserves. In Vaca Muerta in Argentina is a shale gas play. Clearly, we have in our hand quite a big portfolio of shale gas. We have agreed to launch our first phase of development, of $500 million. It's linked to a gas-pricing policy from the Argentinean government, so we are discussing with the new government and I'm optimistic we could have some good pricing, gas-pricing policy, which would allow us to launch with first phase of gas (inaudible) Argentina, quickly, in 2016.

We have also appraised Libra, and Libra Northwest wells are all confirming one after one. But we are just in the northwest of this license, around 3 billion barrels to 4 billion barrels, which means more or less a block 70 (inaudible).

So, it's a key asset, and I'm convinced that this type of asset, thanks to the low cost we can obtain to the industry, is an excellent project, and we are working out with Petrobras to be able to sanction it, if not by year-end 2017, by the beginning of -- by year-end 2016, maybe by beginning of 2017.

So, Libra is confirmed. And then, appraisal in El Encanto in PNG is also positive, confirming the figures on which we acquired the assets.

Then I will move to the Downstream. Obviously, I can tell you if four years ago somebody would have told me that the Downstream part of the (inaudible) Total would have a watch he of 32%, I would not have bet a single penny on it.

We were the laggard of the industry; it's clear. This is why the soft margin we decided to restructure, and to ask Philippe and myself if I've had time to take this part of the Company and to lead it.

It's not only of our job; it's the job of everybody. But at the end of the day today, we have (inaudible) here of more than 40% in refining Refining & Chemicals, more than 20% in Marketing & Services. So, it's -- and I can tell you -- but the teams, the Downstream team today in Total are very motivated, maybe even too much. I know you have to cool down them sometimes, but it's better than before. And they can compete with the leaders of the Upstream leaders, you know? So -- which is very good to have all these two Downstream and Upstream divisions being proud of working in the Company and delivering results.

In terms of cash, as you say, as Patrick told you, cash is the most important -- the blood of the Company. At the end of the day, they delivered $8 billion. On this chart on the left side, what is interesting is to compare -- we just put the refining, European refining indicator as a basis to compare some years. If you compare 2011, 2013, 2014, which are more or less the same margins -- 17%, 18%, 19% -- you can see that there is an improvement in cash delivery of $2.5 billion.

If you compare 2012 with $36 and 2016 anticipation at $35, which is the same margin, there again raised $2.5 billion of additional cash. So this is not only a question there again of link to -- it's not only depending about the margins; of course, better if the margin is good. And, again, we think that 2016 could stay around $35 per ton.

In the previous presentation we were using the conservative approach of $25 per ton. I don't change my view on the medium- and long-term; I've heard $25 per ton. We still keep that assumption to plan our investments in refining. It would be a mistake to change it. And we said that on the short-term, the gathering spreads remain quite good, and since the beginning of the year the average is $41 per ton. We'll see; we still have a lot of months to say. But we are -- with $35 per ton we will be able to deliver $7 billion. And just to give you an indication, $10 per ton represents $500 million cash. So, we are clearly in the Downstream, able to deliver cash.

So if I speak a little more about these two divisions, first, Refining & Chemicals, we continue to work on Refining & Chemicals on several projects. First of all, this is not because the margin has been good that we stopped our restructuring work. On the contrary, we will accelerate it. And in 2015 we could have the temptation, because the budgets were good, not to make all of these restructurings. But we launched them, we launched it in the UK on the Lindsey refinery last February. And in France, in South France, in La Mede, where we decided to transform the refinery in the bio-refinery.

And this will allow us -- we will be implemented in 2016 and this will allow us to reach our target, to lower our European capacity by 20% by end-2016 instead of end-2017. So this is a lesson; when -- it's not because we have good times that we need to stop your efforts. On the contrary, because this is when you have good times, that you can prepare the low -- the best and the worst time.

And so we are doing that. We are also -- in Refining & Chemicals in 2016 will deliver the investment in Antwerp, with new conversion units. And we are also working in Saudi Arabia on the capacity creep of SATORP. SATORP is running perfectly with 400,000 barrels per day, a very high-value (inaudible) today. It's a brand-new plant. But we are beginning to discuss -- and we are more than discussing, we are studying and will invest for enhancing the capacity.

So all these projects will deliver from 2017 an additional $500 million of cash. And we are thinking to the new wave of refining and chemical projects. We've (inaudible) in Port Arthur, with de-bottlenecking of two crackers in Qatar, and with upgrading of refinery of Donges. All these projects (inaudible) and the feed and will be sanctioned in the coming year.

On the Marketing & Services, there again before results this year have been excellent -- $1.8 billion of cash flow from operations was delivered, and we are targeting next to $2.0 billion, which was the target that Philippe sent to his teams in 2012, if I remember. We have $2 billion of cash flow company, so we will reach that very quickly.

It's -- the results again, you can see yourselves, you can see our sales (inaudible) sales have increased by 6%, which is more than the 4% we targeted in the market -- which is growing by 2%. It's quite an achievement.

It's linked to a repositioning in Europe, in particular France and Germany. It's also linked to the development of our market share in Africa, where in particular (inaudible) in Egypt where the accretion we've done two years ago are beginning to deliver excellent results under our leadership.

In Lubricant as well, which is presenting more or less a further result, we have an improvement, an increase of 3%. Philippe (inaudible) is a little disappointed; he was targeting 4% but I told him, it's a good result -- 3%. It's more than the market there, again.

But -- so, we have started a new plant in Singapore in Lubricant, a big plant which will allow us to deliver -- to grow in Asia.

So then if I come back to probably the slide which will be most commented by all of you, about the group cash flow breakeven which is, of course, important -- let's begin by the left side of the slide. What do we show you there? We show you the free cash flow, which is cash flow from operations plus net asset sales minus CapEx.

You can see that in 2015, that $52 per barrel and $49 per ton, we were almost at cash flow -- free cash flow breakeven, minus-$300 million; which means that normalized refining and where month where we gathered free cash flow breakeven around at $55 per barrel.

In 2016 we gave you two indications: one at $50 per barrel, which was the first budget; and then we changed it to $40 per barrel. So we are adapting ourselves. And you can see that we have an assumption, which is a conservative assumption, of net asset sales of $2.0 billion. So even if we have an objective of $4.0 billion of asset sales, what is important for the global balance of the cash flow is the net asset sales because we plan to acquire assets. We need to continue to preserve the future, there again.

The net asset sales -- and $2 billion is conservative; this year we made $2.7 billion, and the year before $2.6 billion. With $2 billion of net asset sales, at $50 per barrel we would be, if -- we'd have free cash flow positive of $1 billion,. It would be negative of $1 billion and $40 per barrel. That means that the breakeven free cash flow is at $45 per barrel, with the assumption on the refining margin of $35 per ton.

For the years after, I just remind you, and there is no change there; what we told you in September for the organic free cash flow, which means that there is no impact of net asset sales in these aggregate. We told you that at $60 per barrel, in 2017, we would be able for organic free cash flow to cover a cash dividend. And if I'm going late beyond that in 2019, it's $45 per barrel, which is organic free cash flow breakeven.

All these explain you why the Board of Directors is confident, first of all, to maintain the dividend but also to maintain the (inaudible) dividend in 2016 as we see this balance of cash flow for the Company.

And as I told you as well, and it's the next line, at $60 per barrel from 2017 -- I'm sorry, something is going -- yes -- at $60 per barrel we will be able to cover 100%. Could you --? This one stopped; thank you. We will be able to cover the dividend in cash at $60 per barrel.

So (inaudible) this director of Total is comfortable, first of all because the payout ratio of the Company as you can see is quite reasonable. It increased from 58% in 2014 to 60% in 2015, despite the collapse of the oil price. So we are still in the range around 50%, and we are again -- we think it's reasonable to maintain the dividend at this level.

The other way that you can see that as a shareholder and through good demonstration that it's good to invest in Total, is that Total shareholder return ranking -- we took it on one year, on two years and on three years. If you put $1.00 in Total compared to $1.00 in our peers, we are number one in -- on one year; we're number two on two years and number three on one (sic) year.

We are very honest, by the way, because we are number two on two years for 0.1% on this, so you know. So it's a clear, good investment, and, again, we are committed to this shareholder return.

Just giving you two slides on what happens beyond, first of all, a slide of macro. I'm unable to give you the price of oil tomorrow morning. I don't know when the price will rebound, but I'm convinced it will rebound. And I will tell you why: it's quite a simple schematic. We just compare 2015 and 2020. You all know that the average decline in this oil industry is around 5%. By the way, this decline will not be lower if we continue to invest less in the oil industry; it will accelerate the decline.

If you take 5% out of a market of 19 million barrels of oil per day, on five years that means that the decline represents 20 million barrels of oil per day of capacity, which will disappear.

If you add on the top of that the fact there is is growth -- and let's take 1%, 1.2%, which is 1 million barrels of oil per day of new development per year. It's not -- it's, again, conservative, and this year, in 2015, it was 1.7 million barrels per day. So if you take 1 million barrels of oil per day of additional demand per year, this means that the new capacity to be invested in the next five years, for 2015-2020, is 25 million barrels of oil per day.

I asked Helle teams to look to the database to know exactly what was being developed, being invested. It's around between 15 and 20; it's in fact the exact figure Helle gave me is 17, I think. But let's -- that means that what is missing in new capacity is 5 million to 10 million barrels of oil per day.

When you look to what we have decided in 2015, the whole industry, it's almost nothing. It's less than 500,000 barrels of oil per day for one year.

So we are in an industry because of the huge volatility that we are facing, of course, everybody is exaggerating their reaction. We tried to do it in Total in a smooth way -- 15% of the increase per year -- because they are exiting the investment -- every investment phase, but we have other players around the world which are even more reactive.

And so we are under-investing in the industry. That means that one (inaudible) is 2020, or maybe before, there will be a lack of supply. And it's not only a question of shale oil in North America; it's more a question of conventional oil around the world. And the news since the beginning of 2016 are not going in the right direction -- or maybe we are going in the right direction for us, which is that we are preparing the rebound. And we will see.

So, that's something we give you [client].

The second slide want to comment for longer view, is, what does it mean -- what means the Paris Agreement of Climate Change for a company like Total? You know, for me, I'm a strong believer as well and with the board of directors and the Executive Committee, and we signed a declaration with overseers in October, but we have to integrate the 2B0C roadmap into our strategy.

By the way, one of the other modifications I will do by September this to have a strategy and climate division, to put -- to integrate these views, these climates challenge into our strategy and to transform it into an opportunity.

If we just look to what -- it's not our scenario; it's the IEA scenario. They are the experts; I'm not an expert. If you look to what does it mean, a 2B0C scenario, it means for businesses that first that natural gas will continue to increase its share of the energy mix. So there is growth in the natural gas.

The oil production should have a cap somewhere and then will not increase any more. Coal is declining, and renewables and biofuels are also increasing their share in the energy mix.

For us, what does that mean as a guidance? It means, first, that, on oil, we need to focus on low-breakeven projects in order to avoid to have any stranded assets. And by the way, this is the best answer to the volatility of the oil price. So economy and ecology will work together, and this is the direction we will take.

We did also -- and we have done that in the last years, prioritize some gas projects because there is a bit of growth. We have exited from coal business; we will fully exit this business by year-end 2016, including in trading. And then we need to look to grow steadily -- I would add, profitably -- in the renewables and biofuels, as this is what we try to do step after step in the coming years.

So, to final -- to conclude this presentation, I think that, again, as I told you in my introduction, we are ramping up our responses to 2016 environment, where is no new recipes, the same recipes, just adapting ourselves -- answering -- the answer to the challenges and staying the course to reduce the breakeven.

Safety is a core value of the Company, and I can show you it's the only matter which can make me not sleeping well. The oil price is not a point for me. I'm confident that we have the capacity to resist and to continue to deliver to our shareholders the value they expect.

Delivering in all segments, reducing of costs and our target of $19 billion CapEx will allow us to deliver the 5% of production growth by 2019. We don't impair the future with such a level of CapEx. And OpEx, I think, to continue to be very serious and to deliver the $2.4 billion. I don't promise you more than $2.4 billion, but I'm sure that Arnaud, Philippe and Philip are ready to do it for me. And then at the end of the day, again, to permanently manage the cash of the Company.

And another message which was important for Patrick: it's very important in my mind and to the Board of Directors that we look permanently maintaining a strong balance sheet, because a strong balance sheet for us means that we have the capacity to weather the storm. And the model of major companies like Total somewhere is even more adapted, I would say, to weather the storm when the prices are low, because we have the capacity to maintain our strategy, to reinvest in new projects whether costs will be low from 2017.

We will add increased financial flexibility and capacities, and the strategy will be to relaunch new projects, to seize opportunities which will come in front of -- on our desks in the coming months, and is apprised to remain visible.

Thank you.

Thank you, Patrick and Patrick. We'd like to open up to questions now. (Operator Instructions)

First one from Irene here, perhaps.

Irene from Societe General.

I had two questions, please. Firstly, what cost deflation did you actually see in your CapEx in 2015? And then, what do you assume in your new guidance for $19 billion between 2015 and 2016?

And then secondly, what proportion of the reserve replacement last year -- the 107 -- was ADCO and the PSC effect, respectively? Thank you.

The second question, I will not answer, as well.

ADCO is a business; if ADCO was not there, something else would be there. So you can make your math and your assumption. But what is important is that at the end of the day, the organic renewal rate is continuing to improve about [100%].

On the first question, it depends what type of CapEx, in fact. Clearly you have some -- the rig market has been much more reactive to the situation, but, of course, over other costs.

So there are in our portfolio, as you see -- as I told you that there is more than $10 billion of new projects being invested, part of that has been contracted in the EPC contract. And when there is little room of maneuver, the winning part of it has been renegotiating. I can't tell you, but Arnaud's teams have done a great job, even canceling some contracts in order to get new rigs. And what we have been able to obtain is more or less a reduction of 20%. But that is implemented.

What we have observed in the market is that you have -- in the Gulf of Mexico today you can find a rig at $200,000 per day -- as low as $200,000 per day if you want to make a project. It's not enough to launch a project, but it is very active. And the assumption of what (inaudible) the market as more or less when I look to the indicator, which is delivered by the CNR, it's around 20%, 25% in the last year, which is quite reactive, by the way, compared to what happened in 2008 and 2009. So a reduction of the costs is going quicker and particularly again in drilling.

Our assumption for the time being in the figure for the future is still -- it was around 20%, so it was conservative. When we show you that the guideline -- the guidance of $17 billion to $19 billion from 2017, the underlying assumptions were 20%, I'm confident we will get them.

Okay, another question? Theepan, same table?

Theepan Jothilingam from Nomura. Just two questions, please.

Firstly, could you just talk about the value of the credit rating, both the tangible and intangible value, and how that may be impacted by a downgrade?

And then secondly, if you could just remind us sort of what your assumption would be in terms of a script-taker for 2016. Thank you.

Patrick will answer you on the tangible value. I will respond on the intangible value. As I told you, we tried -- we have, and Patrick show you, the gearing as a value in the -- is a parameter which is followed by the Board of Directors as representing the strength of the balance sheet. And so we have been pleased to see that we were able to have a gearing end of 50%, 28% would give us some rooms to -- maneuver for future years and particular this year at $30 per barrel. Again, with cash flow breakeven I gave you, if you make some math at $30 per barrel, you can see that this could lead -- is it full-year, is it $30 per barrel? -- to a gearing increasing by 5%, more or less, which makes both the Board of Directors and myself comfortable, and (inaudible) as well.

Yep.

I think we -- up to 33% or 34%. The assumption we use on scrip dividend is 50%, which is what we have observed this year. Again, you know, a scrip dividend in fact is an increase of capital dedicated to shareholders with a discount. So I'm encouraging all the shareholders to follow us and to support us. $1.00 invested in Total is an excellent -- is better than $1.00 invested in other companies, so you should follow more the scrip dividend. But 50% is, you know, it's not -- all the math that you've seen are done with this assumption.

But Patrick will answer you on the tangible impact of credit rating, and other comments if he wants.

Credit rating is important for us.

You saw, I'm sure, the new price deck used by Standard & Poor's and Moody's, which are, I think for Standard & Poor's, $50 per barrel long-term; and for Moody's, $43 per barrel long-term. They -- Standard & Poor's and Moody's will follow, I think.

Standard & Poor's put the oil industry under credit watch. They have already downgraded Shell in Europe, putting them again in their credit watch. I'm not expecting anything special. I think we are currently [DD-]. We may have to move to A+, and I think the whole industry may move down one notch, at least for some of our competitors.

In terms of cost of borrowing, I think this is already embedded into market. We may lose a few basis points, but not so much.

No, I don't think we wish Standard & Poor's auditors to downgrade Total at the end of the week. I hope we maintain AA- rating. We will see that.

He's pessimistic, I'm optimistic. This is the only difference between both of us. (laughter). So there is no other range between AA- and A+. (laughter) (multiple speakers) a good chance to be right.

Yes, please.

Yes, thank you very much. Oswald Clint at Sanford Bernstein.

Slightly longer-term question, but you mentioned the 2P reserve number and the focus for low breakeven oil projects. Can you say kind of what's in that 2P reserve bucket? What was the general average breakeven on the projects, and how is that number falling away as we think about longer-term growth, longer-term competitive of Total?

And a second question -- you've been out signing some LNG contracts, I guess, recently in January with Indonesia and China, a decent 15 years or so. Can you talk about what that's telling you about LNG demand and also what type of pricing is inherent within those plays? Thank you.

Laurent will prepare the answer to the question on the pricing. Laurent (inaudible) is in the room, I think, so Laurent will give you the answer.

First I would like to say, by the way -- before Laurent is thinking to answer, to the right answer -- that we are pleased to be able to expand our customer base in LNG. It's very important, because LNG markets are shifting, clearly, from producing and from a seller market to a buyer market. And so for launching new projects, like the project we have in Papua, New Guinea, which is a low-cost project in terms of -- and very well-positioned -- we need to find new customers. And the effort -- and this is a focus of Laurent's team is to identify new customers, to go beyond the traditional buyers in China and in Southeast Asia, and Laurent will give you some indication on these type of market prices.

Laurent? You don't deliver the contract; you are not obliged to answer fully.

Just to say that it is, in fact, contrary to some expectations in the market, which is quite long, but it's still possible to secure those contracts.

They are very traditional contracts in terms of price formula. It's mostly oil-related at levels maybe slightly above than what has been done just before, and we've been able to put a bit of Henry Hub into it as well. It's very classic oil contracts, oil-related for -- I would say on average -- more than 90%.

The 2P reserves are more than 22 years of production, so it's quite more than 20 billion barrels.

The second question that you asked is complex because, again, what is a breakeven 2P reserves as the projects are -- some of them have already been sanctioned around 2P. So I told you the costs; I gave you what was a technical cost for these reserves is around $23 per barrel. I also told you that the all-in OpEx cash flow was $110 per barrel -- cash cost, sorry -- all-in cash cost OpEx cash cost for all these preserves was under $10 per barrel. With these two figures I think you can derive what you want as what is a breakeven. It's clearly quite low.

A question in the front -- Jon?

It's Jon Rigby from UBS. Just as a follow-up on that last question, maybe I can ask it a slightly different way.

To sort of characterize Total over the last decade or so, I think most people would say that you were early in discussing higher oil prices. To what extent was the portfolio -- I guess it's the 2P, probably even the resource base -- reflecting that view? And to what extent, if any, are you having to re-look at that resource base and positioning in the context of perhaps lower or certainly more volatile oil prices? And certainly in the context of the comment that you made about it being very important to position yourself at the low end of the cost curve in this commodity market?

I know this comment, and the comment is partly right. Having said that, again, the demonstration we gave you is that people are giving this comment, but in terms of technical cost per barrel, we have today at $23 per barrel and we have the best, the lowest technical costs.

So, that's true that we have embarked in some projects, and you know I can -- you have seen this year when we decide to sell 10% of one project in Canada, to look -- at a low price, it's clearly because we were considering about allocating additional CapEx to this project was not totally in line with the strategy I've just described.

Having said that, there is no -- you know, somebody is wrong, somebody is right; we didn't have the same position that a buyer in the context of Canada, because we are less integrated than them. And so we had -- we came to the conclusion that this type of reserves were clearly on the high costs merit curve, and that we want, as I told you, to try to move and to exit from these type of projects in -- with a long-term view.

But the rest of the project, most of the project, again, is low-breakeven cost. When I spoke to you about Libra, with the size of the reserves, I have no problem to move forward on Libra. When discussed about Elk-Antelope in PNG, this is a type of project on which, again, is one of the best energy projects in terms of costs per MM BTU.

So this policy will be applied. The portfolio is what it is, but, again, when we entered into ADCO (inaudible) also (inaudible) ADCO entry, it is exactly with the same strategy a very low-cost oil production. And today at $30 per barrel, by the way, these ADCO barrels are worth more even than before.

So, again, this is the strategy I described to you. We have some assets on which maybe we are, but we don't have so many assets which we consider as high-cost.

The one we -- what we can do as well, which is what we are doing sometimes, is to try to see if we can improve them by trying to renegotiate fiscal terms in some states in order to end this type of projects when -- if the price for low oil price.

So we have the rooms to maneuver on the portfolio, and you will see some decision again like was mentioned by Patrick and another one was (inaudible), we decided to sell because we are not fully convinced that we wanted to allocate it. What is in my head in terms of CapEx is CapEx allocation. So we have to be consistent between what we -- where we put our money and the strategy we want to deliver.

Iain?

Iain Reid, Macquarie.

Patrick, a bit surprised that you didn't lower your breakeven, or at least the oil price at which you could cover your dividend at 17 and 19, despite the fact that you're talking about high levels of OPEC's production and greater efficiency, et cetera, in the upstream and downstream. Is this because you're expecting those really to be kind of completed or normalized away? Or is this a kind of natural caution which you are introducing here?

No, it's just a question, as I tell you, to deliver stable messages. We cannot deliver six-month change or guidance. I do not want to do that. We focused in September was a strategic presentation. We gave you that cadence, telling you at $60 per barrel we'll be able from 2017 to cover the cash dividend. If I can do better than that, you will have to wait for September 2016 to have the good news.

With the last four months, three months we are focused have focused most of our efforts to understand what would be the answer we will bring to the market on 2016. And we will again -- this is a core of the presentation today -- on 2016, as you can see, the free cash flow including net asset sales, breakeven will go down to $45 per barrel. For 2017 and beyond, please wait for September 16 to have either confirmation, which should not be so bad, or our guidance.

Okay, could I try another quick one, then? If I saw here a $30 a barrel or so by September, what sort of actions are you going to have to take in order to satisfy yourself that you can get through that with your current plans for your balance sheet, et cetera?

Again, I told you that from 2017 cash -- or maybe I don't; I may have said it isn't important, but I think I mentioned it in my speech. Out of the $17 billion, $19 billion of CapEx guidance I gave you, 60% are committed, but 40% are not committed. So we have financial flexibility in case of $30-per-barrel oil was remaining there. But honestly, there is also in my mind -- and I insisted in my speech -- a willingness not to impose a future of the Company, so not to overreact.

But, again, if the barrel or price of barrel remains at $30 or $40 in 2017, then we will maintain the scrip dividend if we are not able to cover the cash dividend in cash.

I just wanted to add that I give you the numbers of our liquidity, and we can go through a long cycle of a low oil price with that.

Thomas here on the left.

Thomas Adolff, Credit Suisse. Two questions, one actually linked to Iain's.

So you've kind of presented plan B; you know, 60% is committed out of the 17 to 19. And you have sufficient liquidity, et cetera. But at some point if China goes into a hard landing, the US is in a recession, you don't have the support from strong downstream earnings -- where does the specialty chemicals business sit? Which is non-core, and you can actually monetize and generate a lot of money out of it.

The second question, I guess, is maybe more for Arnaud, and I wanted to know what sort of discussions you're having on fiscal terms and local content. Now, regarding the former, I'm more interested in Angola and Nigeria, because you do have a big reserve and resource base. And in theory, if the terms are right you can extend production for a long, long period of time. And regarding the latter, I'm actually more interested in Brazil, because 60% local content requirement in (inaudible), that's a pretty high number.

Okay, two different questions. Specialty chemicals are non-core; I will not change my position on that. Having said that, they are very good-quality assets. And in my view, it's not the way -- I don't want to sell such assets just to fill some gaps in the balance sheet.

Second question, on Angola and Nigeria, I can't speak about Angola because Angola, maybe you've seen that we have been twice in Angola in the last year, in July and then again in December, and there was mentioned by (inaudible) Angola that some agreements were signed.

Part of these agreements were clearly to -- first of all, I can tell you in this country, a country like Angola, Total represents 50% of the operating production of Angola. So we are very important. And what I've observed in the last year is that in these countries, the major company like Total, which are the old partners, are more and more the right partners because the medium-sized company, which we are coming to take some exploration license, are just leaving this country.

So they recognize the quality of partners. They want us to continue to invest. And so the message has been clear to them, and we had a good project with [Zinnia]. We told them, okay, if you want us to invest, we just have to negotiate the terms. Because we determined that we have today the company we need on one side to work on costs -- which is our industrial work, manufacturing work -- but we need also to discuss the terms, and Angola has been open to discuss the terms.

And we have, today, in our hand some fiscal terms which allow us to consider projects in deep water in Angola. In particular there are -- because you don't have in Angola anymore big fields to be developed but you have marginal fields. And they understood the concept. So we need to adapt that. And we have in our hands some terms which should allow us, providing now that we have to do our work with the engineering firms, to launch projects and to develop this type of marginal resources.

And they have been flexible to give us the terms which would allow us to normally invest at $40 per barrel. So, we are working on that.

Nigeria, as you have seen there is a new government. It's a little slow in Nigeria; it has always been a little different government of countries. So we will see if we are able to do. But, again, I met twice with President Duarte and the message was the same: we have also in Nigeria onshore some concerns about security issues, to be clear, and we have a lot of things to work.

But we have -- you are right -- a good portfolio of reserves to develop. But we have flexibilities in this country, because again, they want us to continue to invest, and a major company like Total are the best possible partners.

Anish?

Anish Kapadia from Tudor, Pickering. A couple of questions, please.

Firstly, in terms of when you're looking at new investments now in this environment, I was wondering how you balance looking at short-cycle investments versus long-cycle in terms of replenishing your portfolio.

So for example, you've got relatively small exposure into the US onshore, where you could ramp up CapEx quite quickly in a recovering oil-price scenario relative to your long-cycle exposure. So I was just thinking about how do you look at maybe getting more exposure to US onshore versus taking on more projects in terms of deep water?

And then the second one: looking forward to 2017, you haven't said much about the projects that are coming onstream. You've got quite a few large projects that you're operating -- so, likes of Icthus, Tempa Rossa, [Cambo], Yamal and [Agena]. I was just wondering if you could highlight how those projects are going and if there's -- what are the key risks in terms of delivering those on time. Thank you.

Okay -- first question, you know, I expressed already the point that I like in my strategy to focus more on my strong points rather than on my weak points. My strong points is clearly not US shale. If you see that's where a lot of people of Total who are experts in shale, you give me the names.

And secondly, I suppose I spend a lot of time on this topic; it's probably the most complex question. But what I observe is that the objective is not just to make short-cycle CapEx, it's to deliver cash at the end of the year -- or the day.

My objective is not just with flexibility in my portfolio; and I recognize the flexibility, but the real objective is to make money, is to be profitable. And I'm afraid that is not so easy to be profitable in such US shale in particular. When I compare all Brazilians to some of our peers, it's because we are not exposed to them.

That does not mean that I close the door, but again, yes, there are some advantage with short cycle, long cycle. But if you want to deliver a value to shareholders, it's better to bet on where I can differentiate myself than to try to be a copycat, a bad copycat of some players which are better than me.

About the projects that you mentioned -- so you want information about all the projects of the Company, so I'm not sure I will be able to deliver all that, but Arnaud maybe will help me. Ichthus first; we announced that the objective is to start it up by September. I think 2017. There's a slight delay; it's a huge project. It's mainly today via big CPF, the offshore component which is being built in Korea, which is on the critical path. The LNG plant is on time, we deliver maybe a little earlier than expected, but it's good. So it's a key project, it's a very profitable project, so we have a lot of -- Arnaud went again to Korea last week to visit it and to take care of that. So, no, I can only -- I confirm today the target of September 2017.

What are the other projects you mentioned? Yamal, I think we are to the end of 2017, which is the target. So end of 2017, that would be back on the production the impact on the production of 2017 would not be, but we have -- we are -- the project is moving on. We are on the way to where we will have invested $15 billion by spring, in Yamal, and the project is progressing.

What are the other projects you mentioned? Asian (inaudible), the target date is around mid-2018, I think. Arnaud, correct me, Arnaud, if I'm wrong.

Yes, so one fiscal quarter, mid-2018, I confirm. Okay, mid-2018.

There's a difference between the CEO and the head of development, but I took note of second quarter. And I will see him in two years together, where we are together with Etienne, and we'll see what I had in mind.

And what else do we have? This is all what you want?

Tempa Rossa and Yamal?

Tempa Rossa is, it's beginning 2018, the beginning of 2018. And [Caiambou], Caiambou you have two vessels, remember. And Caiambou in fact is a two projects: Caiambou One and Caiambou Two, or Caiambou North and Caiambou South. And beginning 2018 as well, I think, for Caiambou North -- for the first one.

And eight -- and 2017, beginning 2018.

There is one question in the back. Neill?

It's Neill Morton from Investec.

A question on M&A. I'm well aware that a question on M&A is usually a waste of a question, but I just wanted to clarify some of the messaging you give out today.

I think this morning, Patrick -- P2 -- was quoted as saying that the recent pitches from investment bankers didn't make sense economically. And you've also talked about preserving the strength of the Company and the balance sheet, et cetera.

But Patrick, you also said during your presentation that you, quote unquote, had to prepare for the oil-price rebound, you needed to make bold decisions and you saw opportunities in the coming months. What did you mean by that?

I just -- to tell the truth, I think the strategy for a Company like Total, that we are -- remember, we are fully aligned on that subject, no difference. We are clearly -- what I think is the best strategy is to invest when you are in the low part of the cycle, because then you can benefit from low costs, or for access to new resources at a low cost as well.

Having said that because -- and the balance sheet can be used to do that. Having said that, we are not in a hurry. We are patient, so I swear we agree together. Today, yes, that's true, but a lot of bankers come to all the offices explaining to us that we need to spend the money immediately and quickly. All of that is very expensive and too expensive.

So we have to be patient. As I told you, [almond oil] is perfectly fitted with that. From 2017 we have more financial flexibility. It's just a question of patience.

We are studying opportunities; that's our job. But again, if we move it's because we have the strong belief that it's worth, so I don't let you -- I don't -- we will not move it again. Don't believe and don't -- it will be again and linked to my answer to Anish, I prefer things that I can't control and in which we are good, but things where they don't control and which will be an adventure.

A question from [Anique].

[Anit Khat] from Exane BNP. Two questions, actually, if you don't mind. The first one is similar to some of the conversations we had earlier. But when you -- I don't think it's an unfair statement to say that over the past few years you've probably given up some of your integration that you had previously, with the chemicals business' sales, et cetera. But is there a plan potentially, given where you are with the low oil price today, to potentially grow maybe marketing even more aggressively than you have done -- even in chemicals, potentially even more aggressively?

And then the second question, on LNG, I think you said two-thirds of the contracts that you had were sort of price review or after-2020 price review in your September presentation. I just wondered if there had been some pressure on those contracts just recently, given the oil price fall.

Okay, no, the first question: we did not -- I mean, frankly, I think we were strong on keeping the integration as a group. But we sold, what we have sold as chemicals, our specialty chemicals like the adhesives, where there was no integration between the adhesive and the rest of the Company, like there is no integration between Atotech energy (inaudible) and the rest of the company. That's why I answered to Thomas that they are non-core.

The integration is what we kept, and when we made it the IPO of [Akima] it was the same idea -- what we kept in Total was basically the petrochemicals, with the crackers and the big polymers which are linked to, I would say, the downstream of a refinery. And when we set together, we put together Refining and Chemicals as a division, was exactly the idea to get the most out of that.

Your question is a good question. All the bankers which group -- come to my office are only speaking to me about Upstream assets. I don't know why. It's a good question, you know? Maybe we can make money as well in the downstream. I have been pressured; this is what we demonstrate.

So, clearly in my view -- and I gave you a signal in September by telling you that we are going to 75/25 spread of CMO, (technical difficulty) different from 80/20. And we have made some true acquisitions in marketing.

So, you know, for me at the end of the day, our mission is to deliver value to the shareholders. And if on my table or the Executive Committee table came projects with good rate of return in marketing, I'm very happy to make -- to search to support them. Sometimes I've even increasing their bids, you know? They are surprised.

So I'm ready to consider my -- the strategy of the Company is clean, and (inaudible) strategy remains to be along the full value chain. So we have businesses. We have in the past some debates because whereas the downstream refining and petrochemicals are the profitable ratio of 5% in 2010 or 2011, of course we are most discussing about do we keep this type of businesses.

But today we manage and it was a purpose of of what (inaudible) do Marjorie decided by restructuring the downstream. We managed to highlight the quality of assets, and to put all these businesses at the same level. By the way, today, what is it? 5% of profitability ratio, unfortunately, is we have three. You know? So let's be -- this is why we have this strategy. So we are continue considering values possibilities -- why not in marketing? Why not in petrochemicals and non-petrochemicals? If we have access to low-cost feedstock, we'll look carefully to projects we look as feedstock, because I'm sure they will be competitive compared to NAFTA feedstock crackers.

So, nothing is forbidden in the Company. At the end of the day what is important for us is what is the value we can deliver to our shareholders.

The second question was energy review. Laurent, again?

A very short answer; nothing has changed. We had roughly two-thirds of the portfolio which is subject to some price review. We were talking about the ENT portfolio, so those are long-term contracts, 20-year contract with partners which are usually integrated companies and are you they are usually as well shareholders in liquefaction plants. So nothing has changed since September. We've had no discussion on specific terms.

But what we told you in September, remember, it's what one third review is after 2020 -- one-third. One-third is no price review. One-third after 2020, and if we had one-third before 2020. So maybe on the focus is more the one before 2020, for your answer.

Marc from the same table.

Marc Kofler from Jeffries. Another question on the Downstream, please. I was just wondering if you could give us an update on the (inaudible) year to date. And then also, just sort of your probably thinking about refining in 2016 versus last year, if there's any sort of more structural observations you might have on the market would be around the strength in gasoline, perhaps, or perhaps any observations you might have on refinery utilizations as we run through the year. Thanks.

Philippe Soquel will answer to the second question; I can answer to the first one. I've done it my speech but I was not clear -- it's $41 per ton year to date since the beginning of the year -- $41. And today, this morning, it was around $36. So, $35 I start up an assumption is not so optimistic. But Philippe could answer, but as you see the gasoline market and the values various components of the product market.

Yes, for -- as you do 2015, we saw, in fact, a sharp increase of gasoline demand, especially in the US but also in Asia and India and China. So the demand was very high in 2015 and the cracks were very high.

So then 2016, of course, remains to be seen. But what we see at the beginning of this year, we have even in the winter some high cracks on gasoline, and what we are seeing, at least on the supply side, is that a lot of project of new capacities have been delayed, mostly by integrated players. And therefore even if we are less maybe optimistic on the demand side, 2016, the supply side is much lower than was anticipated. And this is what we are not too pessimistic, I would say, for 2016, even if 2015 might remain a very historical year for refining and especially for gasoline cracks.

The utilization rate in 2015 was 88%, (inaudible) control, which is quite a high rate. Again, I think you know in this type of business there will be people that will make mistakes, because, against your mind psychology, the margins are good sourcing some people begin to think to invest to increase capacity. But it's less -- it takes two to three years before the mistakes are there. So I think we are, at least from my point of view.

Another point I would like to enlighten of our listeners, petrochemical margins are very strong. We have made an historical year on the European politburo business, for example, and they are still strong. I'm not sure to fully understand why, probably because of products priced us as a natural return of following the oil price, and the part of the additional margin is captured by these downstream businesses.

It's why we think about integration. It's not the physical integration. What is interesting is that when you have as a price of oil is going down, you are able not to give -- to be anchored so much to the full margin along the full chain, and you captured part of it in refiner or in petrochemicals.

Lydia at the back.

Two questions, if I could. The first one on the OpEx side, and there have been some very, very impressive improvements in the upstream OpEx, the barrels side.

Can you talk about where you think that ultimately can go to? Are we looking at a case of we can go back to 2006, 2007 levels in terms of if the oil price stays where we are? And actually is that sort of thing possible?

And the second one, just to come back to that longer-term outlook, you showed the slide on that long-term outlook, one being there's a shortfall in supply on the oil side, and out towards 2020 by the time we get there. And then on the next slide you're talking about gas prioritization and towards the 2-degrees-Celsius world.

Can you just talk about how you're making those decisions and whether policy particularly in carbon pricing is very early on, and that we're not actually necessarily going to have the policy to support that 2-degrees-Celsius world?

I think the OpEx can go as low as where they were in 2005, you know? There is no reason.

You know, it's just, we are in an industry where the cost -- I mean, either the OpEx or the fiscal terms -- are following the price.

Everybody wants us to continue -- we want to invest -- the full system, countries want us to invest. The supply chain wants to invest, even -- we have capacities today which are not used anymore, or which will not be used. So it's a question of finding the right balance. As I say often, where I use the image of a cake, okay, the cake is divided not by three but by nine, in fact, so face of the cake. So the cake is smaller, but it's a question of do you share it.

And this -- and it's a question of psychology -- takes time to find a new balance. In particular in the landscape where there is a collapse and you don't know where you are, exactly. But again, when I discuss with the engineering firms, the big firms, and when I was meeting them by the middle of the year, they were all expecting to see a rebound before year-end. I don't know where the rebound could have come from.

They were -- just because why, because they have some work to be done for 2015-2016. Today when I meet them, they are beginning to complain because 2017 is empty.

So these, of course everybody tried to resist. We resist on those sides, they resist on this sides, countries also, but we will find the right balance.

But honestly, I see no reason why -- by the way, just to give you the answer or was answering, I was waiting the answer but there's a screen in front of me; that's why I'm very bold to answer you -- no face, no more record! -- the OpEx in 2006 in Total was $4.00 per barrel.

But you know, look, we have been from $9.90 to $7.50. We can target $6.50. So if the price is staying there, again, I don't believe it will stay there -- because I think this, we will see more, we will see sooner than later. If costs remain low we will see sooner than later something happening in this market.

But again, if you say this, there's no other way but we find around balance between offsets to share a smaller cake, then to be able to continue to invest. And this is what will happen.

Look, second question that (inaudible), again, the answer that I gave you is very clear. If I'm thinking, yes, there will be better prices in the future, one day or the other, so we are still an oil and gas Company, we still invest in oil and gas. Okay? It will be the core of our business, and not only in marketing -- sorry, Philippe -- but also in Upstream.

You know, I know it has to be, to be too early, because we keep a long-term vision. And we are not investing for three years; we are investing for 20 years. And you saw mission will continue to do that.

Having said that, because we have this broad view of climate change the answer I bring you, I give you, is the best way to answer to that is to reposition assets which will be competitive, and which will stay there and produce like ADCO, for example, in there. Would I be -- again, I am insisting, in 2030 compared to high-cost assets which maybe could be stressed in this type of environment.

Anymore questions? I think one, Chris.

Chris Cooper, Bank of America-Merrill Lynch.

Just two questions. The CapEx cut for 2016 going down to $19 billion -- can you explain where that cut is coming from compared to your previous assumption of $20 billion, $21 billion? Is it because you've not really -- I didn't -- I wasn't aware of any major FIDs that are coming up, so I couldn't see much that you could delay. So just some color on where the reduction is coming from.

And talking of FIDs and thinking about 2017, which one of those projects that you've highlighted in your speech that you are most excited about, you think are the best prospects over the next 18 months to FID? And under what long-term planning assumptions would you be happy to do that?

I tried to answer in my speech, to your first question. The decrease is due first to, clearly, some market effects; for example, the rig, the rig market. So we have taken that into account. As a negotiation which we are led by are Arnaud teams were efficient, and so we have taken part of that.

The second point I mentioned as well is that, again, we have a policy of mature fields which with to invest if we have a two-year payout on that. So we have reduced part of the CapEx. Because of $30 per barrel, we don't have the same payout, but on $50 or $60 per barrel. So we have reduced $30 or $40; we took $40 more than $30, by the way.

We have reduced the level of CapEx and allocated to some metro offices, so some metro assets as well. So there is no -- these things have been done, by the way -- I will tell you it has been done by the bottom-up through the years. And when the division came to the Executive Committee, the addition of all the CapEx required was well around $19 billion.

It's also probably because the teams and the Company are integrating again. The constraints? They are understood -- there was a clear shift to the Company in September. You know, in September when we have looked to the reserves of Total compared to our peers, we have demonstrated to all the teams that we were on the right direction. Because -- and so the people understood that what we were asking them to do since the beginning of the year was the right answer: to focus on the costs, to focus on the personal inefficiency.

And so, in fact as a $19 billion figure was the bottom of figures which came from the teams requesting to us. So this is a better, best answer. It's all of that has been done, I would say, and there is no miracle. But again, the previous guidelines was coming from the business in France which was prepared in spring. That means that mindset in the Company, you know, from all teams are just integrating the new environment -- which is positive; it's why uncomfortable.

The values, FID's -- for the upstream, I think, liberalized clearly quite exciting. You know, we have a huge resource in place, so the resource with this point many more, at least for the first FPS. So we would probably have to build one, two, three, four if DSOs didn't want to develop Libra.

It's a question of costs. We have some technological issue about CO2 injection, but we can cover with them. I'm confident; I was in Brazil with Arnaud last two weeks ago, and we had good discussions.

Then, of course, what we could also sanction will be the site cracker, the cracker, I think, in the US. And also I hope we get on the de-bottlenecking in the downstream. So we have various projects on which we are working. And, again, strategy will be to be able to sanction projects which can be benefiting from low costs in the coming months -- the coming month.

Thank you. Just to clarify on your first answer, it does include $1.5 billion of expiration. And I remember in September you said that is not enough for a 100% reserve-replacement ratio. So that budget still includes room for external (multiple speakers) --?

No, no, no, no. Look, you have all the answer in my answer. If you look carefully to what I told you to do, you have all the answers.

The $1.5 billion explorations, the CapEx part is around $1 billion, more or less. A little less is included -- it's included, as it's shown on the slide in the $19 billion.

Then I told you something else -- that the net asset sales -- the net asset sales minus a purchase -- is around $2 billion. And we have a plan for $4 billion sales, so that means that we are targeting to buy assets for $2 billion somewhere. Not only in upstream.

So, again, yes, we will -- the objective of an oil and gas company, and our motive, is to have 100% replacement rates on reserve. You know that we have to ensure the future, even if you can have years up and downs. But, again, you've seen the slides shown by Patrick. We have improved year after year our capacity through the organic rate of return. So, that's the answer.

Lucas?

Yes, thanks very much, Mike.

You've done most of the forecasting for me, so thank you very much. A couple of points of clarity, and then one which is slightly conceptual. Points of clarity, just in terms of the growth estimates for this year -- I presume that there's no assumption that Yemen comes back in 2016.

No, we are realistic guys. So you could have a good surprise, but I'm afraid this one would be a very good surprise, unfortunately.

Thank you for that. And then just on LNG, a couple of questions. First, whether Laurent might be able to give us what the average realized price for your sales was this year. And how much -- what proportion of the contracts have collars? So to what extent can I feel secure around pricing in the current year?

Yes, that's a good question, this one. The realized price, we gave you through Patrick's presentation; 33% of the oil/gas portfolio. I'm not sure we want to disclose what is the impact on LNG, but it's through this 33% is less than the 47% on the (inaudible).

There are two effects. One is a lag time in the formula. The second effect is that on many energy formulas you have what you call -- it's an S-curve, you know? So you have what you call a floor somewhere. And which could be eight and sometimes we don't like it, of the -- we were not liking the S-curve when it was reaching the high prices. We quite like this one on the low prices today. So it helps to have this gas price being resilient.

I'm sorry, did I hear a proportion that are -- that have built around an S?

I think it's more quite your high proportion, actually. No? (inaudible)?

Yes, most of the LNG-ers deals do have an S-curve. To give an exact point of inflection, it depends on the history of the contracts; so, in states where you have continuum. But the fact that you have those S-curves, the fact you have as well a few constants in the formulas, do help in terms of the resilience of the energy process.

Yes, you have constants as well, which are almost as important than the S-curve.

And then Patrick, I mean, the more conceptual question -- the price moves in the cycle, and I think many of us would disagree with you that prices at some point have got to rebound. But structurally it feels as though we are probably -- and maybe this plays to the point on operating costs -- we're now into a period where the industry is quite possibly going to face an extended period of price deflation, and that the US will help that price deflation along.

So where does that leave you when you think about investing in things like Papua -- whatever -- duration-type projects where the capital up front is substantial? The breakeven today may be $7.00, $8.00 on gas, but in five years' time the breakeven on that same project will be $5.00, $6.00 gas. And the reality -- and the danger is, is a consequence that you find actually what looks competitive today is taken away from you very quickly tomorrow.

But you know, Papua is a good example of a long-cycle investment. So I'm more nervous today on some short plateau on which, even if I benefit from low cost, if as the price remains low I will produce most of my reserves going four, five years at the low price, it is more risky there.

But on Papua, Papua is, as I mentioned and from me first, is to find the customers with good contracts.

But, again, if today I think in 2018, 2020 -- 2018, when we will go to the market to ask for bids, to build a new LNG plant, I'm not sure there will be many projects. And the people, the EPC contractors, will be very happy to come to us. And so we will be in the pricing power position where we could benefit from low cost.

So, if you keep that perspective, I'm confident. But, again, we have to be very serious and disciplined on the cost we obtain in order to maintain the low cost base. But Papua is well-positioned near the markets, so transportation costs are minimal. I think it's a good project.

We will not rush on it. I have no rush. We have first to find the customers, and second to stabilize the scheme. But again, I think it's, in that case uncomfortable, we're investing in long-cycle projects.

Okay, thank you. I think after all of Lucas' questions we have time for one more.

So, Kim right at the back.

Kim Fustier, HSBC. Could you please characterize the current environment for asset disposals? Most people would say it's more of a buyer's market, and yet you appear to have front-end loaded the disposals target for 2016. Or was that rather slippage from last year's target, which you didn't quite manage to achieve? Thank you.

Well, it's clear it's not the best time to sell upstream assets. Again, this year we have made some excellent deals in the upstream in 2015; I will not mention them because the buyer will not be happy. And we have done some deals like Usan where we decided to stop.

So if you want -- but in our portfolio, we still have some non-core assets; not a special specialty chemical (inaudible) downstream. But we have other assets like pipelines, like fertilizers, like things we frankly are not core and which we can try to divest.

So the $4 billion target, we are looking to see if we could have some good offers from upstream mature fields, for example.

You have companies today who try to benefit from the situation to get some mature fields, and maybe it has interest for us to divest some of them. It's a question of, again, of cost base. But, again, if we have the right value, if we don't have the right value, we keep the asset.

So, we have many ideas. And the advantage, with a large Company like Total, we have a lot of assets. And we are discovering new assets sometimes, but we don't know -- including an infrastructure -- and so we are pragmatic. And I know it's not the best time for some of the assets, but when you go to the infrastructure market, you find values.

All right. Thanks very much to everyone for coming today. Thanks to the two Patricks for all the answers. I think all of the executive committee is here. Thanks very much. Goodbye.