Patrick de la Chevardière - Chief Financial Officer

Theepan Jothilingam - Nomura International Plc Martijn P. Rats - Morgan Stanley & Co.

International Plc Oswald Clint - Sanford C. Bernstein Ltd.

Alastair R. Syme - Citigroup Global Markets Ltd.

Guy Allen Baber - Simmons & Company International Thomas Y. Adolff - Credit Suisse Securities (Europe) Ltd.

Nitin Sharma - JPMorgan Securities Plc Biraj Borkhataria - RBC Europe Ltd. (Broker) Jon Rigby - UBS Ltd.

(Broker) Lydia R. Rainforth - Barclays Capital Securities Ltd.

Anish Kapadia - Tudor, Pickering, Holt & Co. International LLP Irene Himona - Société Générale SA (Broker) Lucas O.

Herrmann - Deutsche Bank AG (Broker UK) Gordon M. Gray - HSBC Bank Plc (Broker) Rob West - Redburn (Europe) Ltd.

Christopher Kuplent - Merrill Lynch International

Hello. Patrick de La Chevardière here.

Before we go to the Q&A, I have a few comments about the quarter. Operationally, all the segments are performing very well.

As promised the Upstream is delivering the new major projects. In addition to the three start-ups in the first quarter, Termokarstovoye in Russia started in the second quarter.

The Downstream is performing at levels we haven't seen in years. We are reducing CapEx in line with budget and costs are continuing to come down.

We reported $3.1 billion of adjusted net income or $1.34 of adjusted earnings per share for the second quarter 2015. Compared to the first quarter, this is an increase of 19%.

And this reflects the benefits of our ongoing self-help programs and the generally more favorable second quarter environment. European refining and petrochemical margins remained strong and we are fully capturing this benefit.

The dollar was also strong and this is favorable for us. Turning to the business segments; we start with the Upstream.

In the second quarter despite the situation in Yemen and the start of the seasonal maintenance, production decreased by only 4% compared to the first quarter, and it was up by 12% compared to a year ago. The seasonal maintenance impact is temporary.

In the coming months, we will start three additional major projects, Surmont Phase 2, Laggan, and GLNG, making seven major start-ups for 2015, including the four that are already producing. Vega Pleyade will start-up around the turn of the year.

So even without the restart of Yemen LNG, we are confident that we will achieve our target of more than 8% production growth for 2015. Adjusted net operating income for Upstream was $1.6 billion, an increase of 15% compared to the first quarter.

Brent was up by 15% quarter-over-quarter to more than $60 per barrel. Gas prices were weaker affected by lower oil-linked LNG prices as well as lower prices for NBP in Europe, but on balance higher liquid prices more than offset lower gas prices.

OpEx fell significantly and our cost-cutting program is on track to exceed the $800 million of Upstream savings targeted for this year. Exploration expenses were down by more than $200 million quarter to quarter, and this is another sustainable benefit related to the action plan we launched at the beginning of the year to mitigate the fall in oil prices.

One note on the Upstream results. For ADCO, we have reclassified certain taxes for income tax to production tax to more accurately reflect the performance of E&P.

And this change has been made retroactively to the first quarter. On the restated basis, the effective income tax for the Upstream was 49% in the first quarter, and 47% in the second quarter.

Last point on the Upstream. We recently started up Dalia Phase 1A.

This is an infill drilling project on deep offshore Angola Block 17. It produce 30,000 barrels per day at 100% and helps to maintain the 9-year old Dalia FPSO at production plateau of around 200,000 barrels per day.

This is a good example of a deep offshore brownfield project that has strong economics even in this lower price environment. Now, moving to the Downstream.

The European Refining Margin Indicator or ERMI averaged $54 per ton for the quarter, a level we haven't seen since 2008. The ERMI was strong reaching high well above $60 per ton in the second quarter.

The average for July is above $50 per ton. We can see that we underestimated the positive impact that lower prices would have on demand and it is the same story for petrochemicals and marketing margin.

We had a lower level of turnaround in Europe. And this increased our refinery throughput.

So our Downstream has been very well positioned to capture these benefits. We are continuing to strengthen the underlying profitability of the Downstream by reducing the breakeven at each of our industrial sites.

So we anticipate a strong and sustainable contribution even if margins does not stay at this level. The Downstream generated $1.8 billion of adjusted net operating income in the second quarter, an increase of 25% from the first quarter.

Two points worth making. First, more than half of our result for this quarter were generated by the Downstream; and second, we are very happy to have the resilience that come with being an integrated company.

This leads me to the corporate section. From a strategic perspective, we have learnt many valuable lessons from the Downstream restructuring program that we are implementing in other parts of the company.

Across the Group, we are focusing on reducing costs, increasing reliability, and improving operational efficiency. Second quarter adjusted cash flow from operation was $5.3 billion, a 15% increase from the first quarter.

The Group's effective tax rate was 40% for the quarter and 39% year-to-date. And this is largely due to the higher proportion of Downstream results.

Organic CapEx was $5.1 billion in the second quarter, in line with the budget year-to-date; and this is on a downward trend over the coming year as we continue to start up new projects. Acquisitions were $282 million in second quarter 2015, asset sales were $733 million mainly for closing the sale of Totalgaz LPG business in France.

This morning, we announced the sale of 20% of Laggan-Tormore for about $1 billion. I can also say that we are discussing significant bids on other assets, so we are continuing to push forward with our strategy of active portfolio management.

Gearing was 26% at the end of the second quarter, down slightly from the end of the first quarter. Starting in the second half, the scrip dividend will begin to have a positive impact on cash.

The take-up on the scrip dividend was 54%. So at this rate, we should reduce our cash dividend outlay by about $750 million per quarter or $3 billion on an annual basis.

Going forward, we have the strongest production growth among our peers. Our company-wide cost reduction plan is gaining momentum and we are reducing CapEx.

Our second quarter result demonstrate our integrated model is working very well. We are continuing to execute and deliver on our growth project as well as continuing to reduce the breakeven in both the Upstream and the Downstream.

We generated $10 billion of adjusted cash flow from operations in the first half of the year despite the drop in the price of oil. And our strategy is to continue to improve the underlying profitability of Total even in a relatively weak price environment.

Please keep in mind that we will make our strategic outlook presentation in London on September 23. So there are certain questions that may have to wait.

So with that proviso, I am ready to begin the Q&A. And as usual, ask that you limit yourself to one question at a time.

Yeah. Hi.

Good afternoon, Patrick. It's Theepan here.

One question just on the impact of disposals and the successful sale of Laggan, I think you made previous sales. So I was just wondering, could you talk about that in the context of the 2.8 million barrels per day target in the medium term?

And I also wanted to understand where the portfolio is now in terms of sort of PSC sensitivity to lower oil prices? I know you had a benefit this quarter.

Thank you.

Yes. Thank you, Theepan, for your question.

There are positive effect, of course, from the new start-ups, negative effects from the loss of Yemen LNG and Libya. All in all, our production grew by 11% this quarter compared to first quarter 2014.

Basically, 2015 is a great year for start-ups. We have four major new projects in production and three more underway this year.

Vega Pleyade, as I mentioned in my speech will start at the turn of the year. But honestly, I'm quite confident that we will achieve our target to increase production by more than 8% this year in spite of the security issue we face in Libya and in Yemen.

As regard to 2017, we were not explicit about the production target in February, but we will provide some guidance in September. Honestly, we have to take into account the difficulty we face in Libya and in Yemen.

Total growth portfolio is unmatched by its peers, honestly, in terms of relative size and diversity, and we are delivering these new projects in a strategic priority to increase both cash flow and to generate value. The impact of the disposal were already included in our target.

So the 20% Laggan sale we announced this morning was already included in our target, but we will update you in September.

Okay.

Your second question was about PSC impact. Basically, second quarter 2014 – we saw the same effect in first quarter 2015 versus first quarter 2014, around minus 3%.

Okay. Perfect.

Don't worry, Theepan, I have not finished (15:11).

Okay.

Since second quarter of 2015, our production is up 12% compared to second quarter 2014, which can be described as follows: 5% from the start-up, notably CLOV; 7% from perimeter effect, basically ADCO; minus 4% from the stoppage of Yemen; and plus 4% from the price effect on our PSC contract, it's basically 3%; a better performance on our field and lower maintenance that more than offset the natural decline which is about 3%.

Okay. Thank you, Patrick.

Very comprehensive answer there.

Thank you, Theepan. I'm paid for that.

Yeah. Hey, good afternoon.

I wanted to ask you two things. First of all, something which isn't always so visible for us in quarterly results, this is not specifically disclosed, but I was hoping you could comment on your LNG profitability and how that has been recently impacted by not only lower Brent prices but also lower spot prices?

And included in that answer, if you could talk about the extent to which you are sold forward on your visible LNG sales over the next few years. And secondly just a sort of short housekeeping question.

Could you comment on the CapEx for 2016 that is already committed? That'll be useful.

Thanks.

Okay. You are right.

LNG profitability is an important question. In second quarter this year, LNG represented about 15% of our production and about 25% of our Upstream result.

LNG has been affected this quarter by the negative impact from the drop in Brent and the effect on the LNG prices linked to the oil price; and, of course, for us, the shutdown of Yemen LNG. LNG sales were down by 15% at 2.3 million ton in second quarter 2015 basically due to the stoppage of Yemen LNG early in April this year.

Another remark is that the number of redirection was also lower this quarter, basically because we have less volume to market because of Yemen. And we had 10 cargos redirected this quarter versus 17 cargos second quarter last year.

LNG, going forward, in the next quarter should be slightly higher reflecting the 15% increase in Brent price second quarter 2015. About the CapEx, we are reducing CapEx, and I can tell you Patrick Pouyanné is pushing very hard to reduce our CapEx for the forthcoming years.

For Total, as we continue to start up our new projects, the level of committed CapEx will continue obviously to fall. Our 2015 budget is between $23 billion, $24 billion; down 10%.

And honestly, as of today, we are more close to the low end of the range than to the upper range. We will come back, of course, in September, and this will be part of our presentation, with an update.

And I can tell you that, fundamentally, our organic CapEx is on a downward trend going forward and should decrease to less than $20 billion per year starting in 2017. The exact figure you asked, about how much CapEx are committed in 2016; I'm sorry, I don't have this figure with me.

But we will make everything we can to meet our target to be around $20 billion or less.

Okay, great. That's very helpful.

Just to revisit the first topic on LNG. The percentage of your LNG sales that you'll have, that is sold forward on the long-term contracts, I remember that to be around about 19%, but that might be slightly a stale number.

I just wanted to see if that's still broadly the case.

Basically, you can assume all of it is sold on the long price term basis.

All right. That's very helpful.

Thank you.

I'm glad that you asked only three questions...

Okay.

...instead of one.

Yes. Thank you, Patrick.

Kind of a question on the future projects. I guess a lot of your peers this week have been getting very excited about some of the initial costs coming in for future projects in the various portfolios.

Could you talk a little bit about what you guys might be seeing there as you start to explore or study some of your future projects, and maybe what that might mean for a kind of reduction in terms of breakeven prices? Thank you.

Thank you, Oswald, for the very simple question. Basically, your question is about do we see deflation at the moment on the market, and how much it can impact our future projects.

We see in drilling rigs, in seismic that costs are going down gradually and significantly on those two items. And, honestly, this is part of the reason for our resilient result.

We are currently seeing some early changes in the market. And the most obvious one is the drilling rate for deep offshore which dropped by 50%.

Significant reduction are yet to be seen in subsea, in fabrication of platform, FPSOs. I think that both – builders of both equipment or platform have currently enough backlog to try and fight for maintaining their price at the moment.

We may need maybe one more semester to see prices going down for both subsea and platform building. In Total, a taskforce has been created with key account negotiators to renegotiate contracts with our biggest provider.

And when you think about it, we are launching some value engineering process, you think about Uganda, Elk-Antelope or Libra which are the three forthcoming project one can think about. We are also looking at early termination of some contract, price reduction, and we are also increasing the number of the frame agreement and supplier.

Obviously, the process is still going on, everything is not achieved. We still have to wait for some progress for platform building FPSOs, but we are confident if the oil price remain at this level that we will see significant cost reduction for our future project.

And, basically, we are ready to wait for that.

Excellent. Very detailed.

Thank you.

Hi, Patrick. Can I just talk a little bit about the 20% reference -the reference to 20% unit cost reduction in the Upstream, about how you break that down?

And, in particular, are there any portfolio effects to consider like AGCO and Yemen in that analysis?

Okay. Maybe I will take this opportunity to explain and estimate the overall cost reduction achieved last quarter, because you cannot read it directly from our books.

Net operating OpEx for E&P is at $5.5 billion. This is the operating expenses for Upstream.

If you deduct – and this include gas and power purchase, gas and power being part of the Upstream. So this include gas and power purchase from third-party projects.

This include production taxes including ADCO. And this also include exploration for about $300 million.

Net of all those elements, the $5.5 billion come down to $1.6 billion. And this $1.6 billion of operating and net expenses for E&P compared to $2.1billion first quarter this year – no, sorry, second quarter last year.

Basically, for Upstream, we have around $0.5 billion. With this $0.5 billion of cost savings this quarter, we have identified that there is about $150 million from FX.

So basically, net of FX, the Upstream saving is around $300 million, $350 million, close to $300 million for the quarter, which is a very good news, because our budget for the year is $800 million; four times $300 million will make $1.2 billion. I'm not suggesting that we will continue at this pace.

But we are in advance in comparison to our cost saving budget for Upstream, and substantially, I would say. In term of technical cost, I'm referring to the specific rules, ASC 932.

Our Upstream OpEx decreased by about 20% from $10 per barrel to less than $8 per barrel. In addition to that, this is to say about $330 million for the quarter.

On top of that, you can add, and you add the transportation cost and other cost of about $120 million. So, all in all, I'm back to the $450 million, $0.5 billion I was mentioning before to you.

That's fantastic detail. And in the $350 million net, how much of that do you think is sort of controllable stuff versus sort of natural deflation in energy prices and consumables?

If I was ready to tell you that, I would have told you that, because I'm quite transparent today; but I don't know. And I'm very cautious about it because this figure, I don't know how much is acceleration of the space for cost reduction and how much is coming on top of the budget.

And, finally, I remind you that the budget give us $800 million for Upstream cost saving and $1.2 billion for the Group. And we are in advance.

Got it. Thank you very much, Patrick.

Thanks for taking my question. Given the strength of the Downstream segment and the fact that that segment has consistently beaten expectations and did again this quarter, I wanted to focus there a little bit.

But, first, can you provide a bit more color on your macro outlook for the Downstream and for refining margins in particular? You mentioned better than expected demand and was just hoping you could put into context for us a little bit what demand uplift you're actually seeing, how that influences your view of margins going forward?

And then, secondly, appreciate the Upstream cost update. Could you just discuss how Downstream cost cutting measures are trending so far this year?

And then, perhaps, if you could remind us just how much underlying cost you've taken out of that business over the last few years, so we can better appreciate and model the uplift that you're really seeing in sustainable profit setting aside the macro environment? Thanks for taking my question.

Okay. Once again, there is one question.

The – in the first half this year, the refining margins, the ERMI indicator was on average at the very high level above $50 per ton. Second, margins are traditionally higher than the first quarter due to seasonal maintenance, but second quarter 2015 at $54 per ton is unseen for years.

A few reasons for that; strong demand on finished product because of the lower nominal prices of those products, selective low supply due to the traditional maintenance as well as some unplanned shutdowns. This is what we have identified in Europe that there were some unplanned shutdowns.

And also which benefit to the margin, the lower energy costs benefiting for refinery operations. I have to say that at the end of the day our target, we are not trying to figure out what would be the refining margin in three months' time, but we are continuously working on reducing the breakeven of our operation in Downstream and in Upstream also, but your question was on Downstream.

And the objective was to reduce below $20 per ton for each unit, the cash breakeven. I remind you that in 2012-2015 period, we saved about $650 million of operating income for the overall period.

2015-2017, we expect an additional $400 million. And, all in all, the expected saving for 2012-2015 could be up to $900 million, which means that for the period 2012-2017, a saving of $1.3 billion for Refining & Chemicals.

For marketing, we are expecting 20% cost saving for the period 2015-2017, which can lead to a saving of about $400 million. That's basically what I can tell you about Downstream costs.

Thanks for the detail.

Hi, Patrick. Thanks for taking my question.

Just wanted to go back to your point on 2017 CapEx of $20 billion or less, you used to say around $24 billion, $25 billion. I wonder whether you can, very quickly, kind of split it into what's cost deflation related, what's project reengineering related, and what's less activity related.

And just a quick clarification on the point you made on decline rates, if I can. I remember you used to say decline rates of 3% to 4% going to 3% over time as more long-lived production comes on stream.

And then you say in 2Q, well, just now the decline rates, portfolio decline rates was about 3%; I wonder given you are spending less on brownfield in this environment, how to think about decline rates going forward, and how to think about it in the context of better fuel performance as well? Thank you.

I'm going to disappoint you, because, for the first question, which is about our 2017 CapEx budget, I am afraid that you have to wait for our September presentation. This – we are working on it.

This will be an important part of our September presentation.

Okay.

As far as the decline rate is concerned, it is true that we are surprised to see, actually on our figures, lower than expected decline rate at the moment, because we are more in the range of 3% than 3% to 4% at the moment. But going forward, less works on brownfield, but more long plateau project, I think we would be able to maintain the 3% decline rate.

Perfect. Thank you very much.

Afternoon, Patrick. Hope you're well.

I gathered from your update that you mentioned underestimating the demand impact of lower oil price. With ERMI around $54 a ton in Q2, is it time to reassess your ROCE target for Downstream based on $25 to $27 a ton ERMI?

So that was my first. And then, maybe quickly explain impairments that you've booked in this quarter around $250 million, please?

Thank you.

So once again, one question. So one question about our refining margin and the expectation we have on the profitability of this Refining & Chemical business.

Today, the results are demonstrating the benefit of our restructuring. Very frankly speaking, the effect of the restructuring is huge and massive.

Of course, there is still work to do to further improve. All efficiency programs have clear target for 2015.

We have launched a new $600 million cost reduction plan for the period 2015-2017. And once again, our objective is to reduce for each of our unit and platform the cash breakeven below $20 per ton.

Your second question was about impairment. There was no extreme impairment in second quarter 2015, and that's it.

Hi, Patrick. Thanks for taking my question.

I just had the one, which was, in the Upstream, you have a number of projects to deliver by 2015 and 2016; and I just wondered if you could give some color on where do you see the biggest risks to delivery over the next 12 months to 18 months? Thanks.

Where I see the biggest risk in delivering our project down through 2017. As I mentioned in my speech, for 2015, we see now Vega Pleyade coming on production at the turn of the year.

We have four major new projects in production yet at the moment and there are three more coming which are GLNG, Surmont Phase 2 and Laggan-Tormore. The potential – because nothing is for sure, but the potential delay of maybe one month for Vega Pleyade is due to bad weather condition, at the moment on site.

It is winter in Argentina at the moment. That's basically what I can see.

For our project down to 2017 – I'm talking about 2017, we are working on a presentation to you in September specifically on it. Surmont Phase 2 is steam-injected since May.

So I see no further delay for GLNG, Surmont Phase 2, and Laggan. But on 2017, you may have to wait till September.

Thanks very much, Patrick.

Thank you. Hi, Patrick.

Can I ask – you know how much I like your scrip dividends, so I was going to ask what conditions have to exist for you to consider stopping that scrip dividend? You talked a lot about the cost reductions and assuming macro changes somewhat.

So what...

Thanks, Patrick. Just one question if I could on the – coming back to the cost saving.

Are you able to give us more examples of where those cost savings are actually coming from, whether it's in the Downstream or the Upstream on the efficiency side? Thank you.

Yes. I can give you a few examples, but those are only examples for the purpose of giving you some granularity.

In the Upstream, I remind you that our OpEx fell from $10 to below $8 per barrel. Basically, we are asking fewer works to be performed by contractors and we optimize logistics.

I'll give you an example, for instance, in Angola, we are reducing the speed for our service boats which give a substantial saving in gasoline. Globally, I'll remind you that we are reducing our head count for E&P down to 15,500.

In Congo and Angola, we have renegotiated our maintenance contracts. In Brunei, we are optimizing the planning of drilling operations and are reducing the number of vessel used for transportation.

In Indonesia, we have released one storage tank, one out of six, which is a saving of about $5 million. In the Philippines, we concentrate and mutualized our IT and general services.

We are on the Downstream optimizing the catalyst change, reducing the number of those catalyst change, making some synergies in the maintenance. I'll remind you, it is a bottom-up exercise where every manager is incentivized.

So I can tell you, there are plenty of new ideas.

Perfect. Thank you.

Hi. Good afternoon.

I actually had a question on Angola, in particular, on Block 17. Now that you've got the next phase of Dalia on stream, is it right to think of Block 17 production peaking in 2015 and then moving into steep decline?

The reason I ask that is, it doesn't seems that they – it doesn't seem like you've got any further sanctioned phases of development over there. So just wondering how you see that production profile over the next five years?

Thank you.

I'm not the field manager of Block 17. Block 17 already produced 2 billion barrels.

Dalia is still at 200,000 barrel per day, 100%. I don't know into deep detail what is the production profile for Angola for the forthcoming five years, but it is true that on Block 17, many, many field has been already developed and production.

I'll remind you that CLOV is above plateau and at a record of production. That's basically all I can say to you.

Thank you. Good afternoon, Patrick.

My question was on tax. You mentioned how low the Upstream tax was in Q2 at 47%, the Group overall tax below 40%.

If you can just perhaps give us a firm guidance on what we should be assuming for this current environment? And then, just a question of clarification on the cash flow.

Because of the timetable on the scrip, you saved effectively $750 million of cash by not having to pay the dividend in Q2. Can you say whether you expect this year to pay $2 billion or $3 billion cash-out on dividends, please?

Thank you.

Okay. First question about tax.

Second quarter this year, Upstream effective tax rate decreased slightly from 49% to 47%, mainly thanks to field allowance accounted for this quarter on some UK field namely Edradour and Glenlivet. On top of that, we had various tax credits in Myanmar and Norway; and on the other way, an increased rate applying to exploration charges.

Looking forward, the Upstream average tax rate that can be expected from our portfolio should be around 50%, including ADCO. And I remind you that we reclassified ADCO main taxes as a production tax.

At the Group level, the tax rate will obviously depend on the contribution on Downstream in comparison to Upstream. So the scrip dividend that you seem to like very much, with the scrip payments moved back by a few days to allow for the option period, which is about 15 business days.

Therefore, in 2015, we will only have three payments, the fourth payment will be paid actually beginning of January, with amount reduced by the scrip itself. So we will have 3Q 2014 dividend paid in March, July 4Q dividend, and October 1Q 2015 dividend.

And on top of that, you have to take into account the take-up of about 50%, which I think is a low rate, but let's assume that, for the scrip dividend, which means basically about $750 million in cash for each dividend payment. So if you have three dividend payments, you may easily do the computation.

I remind you that the year we stop the scrip dividend, we will have five payments.

Thank you very much.

Patrick, Good afternoon. You're doing well.

It's going on. A few if I might.

Just, firstly, deferred tax, Patrick. A couple of years ago, from recollection, things were so bad in refining that you had to take a lot of deferred tax write-offs or assume you couldn't recover.

Given the profitability or the improvement over the past year, what's the – is there the opportunity to recover that tax previously written-off and consequently I guess lower the charge that goes through the corporate line? Secondly, I just wanted to make a comment on the trends in DD&A in the Upstream where the per-barrel numbers on a subsidiary basis seemed to be falling, which I guess surprises me given the volume improvements we're seeing and the nature of the production that's coming on.

And, thirdly, was there any hedging this quarter in the Downstream business, which I guess in effect would have cost you rather than benefited you?

Okay. On the hedging, we hedged last month in July and we lose $20 million, basically.

I don't know how much we hedged for June. But if there is any hedge, this is the size of the magnitude of the effect.

On the deferred tax, you are right. We were unable to give value to some deferred tax.

You remember also that under French law, whatever is your taxable income and your taxable losses coming back from the past year, 50% of your tax has to be paid in cash. Without this element, we will not be in a position to pay taxes, but we are paying – we will be paying taxes because 50% of the cash – of the tax have to be paid in cash, not using previous losses.

But we are benefiting from our previous losses in order to avoid 50% of the taxable income tax for the forthcoming months. And it is true that we haven't recognized all of those tax assets in the past and it seems to be that we will be able to use them if margin remain at this level.

Okay.

Then you have a third question on the DD&A.

Yeah. It was just – I'm surprised – I guess I'm slightly surprised, for example, the – if I look at the trends in DD&A in the Upstream, the absolute number in dollars, it feels as though it's heading south rather than north, whilst production is heading north rather than south, and the cost of new barrels in depreciation terms I would have thought was probably higher than old.

Is there a currency impact in any way in DD&A, Patrick?

There is one for Norway, basically. It's a translation, I would say, effect because Norwegian krona is lower than the U.S.

dollar. And DD&A was also lower, thanks to the increase of production and some past impairments.

Right.

And also because, due to lower price in oil, we have larger reserve due to the price effect.

Okay. Thanks very much.

That's very helpful.

Thank you.

Have a good break.

Yes. You can hear my Ferrari...

I'm waiting for the vroom, vroom.

Thanks. Hi, Patrick.

Quick one. You announced a good appraisal result on Elk-Antelope in the recent past.

So just wondering how your thinking is developing about the resource available, in particularly how to monetize that asset? Thanks.

On Elk-Antelope, we have to be clear, we are first to sell the gas to third-parties to be in a position to FID this project. We are currently working on the legal framework of the project – to figure out the legal framework of the project itself.

We will start, maybe, to estimate the overall cost of the project. But it is a very early stage at the moment.

But in my view the main question we should ask is, are we going to sell this gas and when we will be in a position to secure the sales of LNG. We will be a in a position, hopefully, to sanction this project.

I guess that raises the question as well about the state of the market for trying to enter new long-term contracts.

There is – keep in mind that there is no rush. We need to see the cost going down.

Yeah.

So please give us some time to market this gas and wait for cost to adjust.

Okay. Thanks.

Fair point.

Hi there, Patrick. Thanks very much for taking my question.

I'm going to try and win the prize for the most boring accounting question of the quarter. Specifically, there's an adjustment on the Upstream affiliates of about $191 million.

Sorry to be really specific here, but just some detail on what that is would be interesting. Thanks.

I have maybe one – I'm not sure it is true and then you will revert to the higher cost year-on-year but there is a charge taken in our LNG portfolio because of the loss of LNG volume from Yemen.

Why would that result in a charge, just out of interest? That's not an impairment but...

Of course. I'm afraid that I'm unable – I'm not a very – I'm not the best accountant in the room.

Okay. Thank you.

Yeah. Thank you and sorry for keeping you even longer in the office.

Just two questions, hopefully very quick. The first one, I just wanted a confirmation what you said earlier about the duration of the scrip, sorry to go back to this question.

Previously I thought you said this is a four-quarter policy. So does that policy now extends to whenever you reach free cash flow neutrality?

Just wanted to get confirmation on that. And secondly, keen to find a little bit of strategic background behind buying barrels in ADCO and selling barrels in Laggan-Tormore.

Is this about just farming down projects where you've got 80%? Is this about reshaping the long-life/short-life balance within your project portfolio?

Anything you can give us here in terms of how you're thinking, also along the lines for further disposals. Thank you.

Basically, the sale on Laggan was due to the fact that we own 80% of the field and we were overexposed in my view to this particular field, and we wanted to reduce our exposure, maintaining the strong exposure of 60% remaining the operator. For ADCO, I remind you this is a 40-year concession.

So even my grandson will enjoy it. There is upside in the contract.

It's a low-cost contract and there are many benefits in the Middle East to be part of this project. I remind you also that being the asset leader for two fields, we enjoy an extra fee on this ADCO project.

So – and the first question was the duration on the scrip. I remind you that the AGM gave its consent for only one year by law.

So if we were to continue the scrip beyond 2015, for 2017, and thereafter, we shall obtain another approval from the AGM. All in all, we have the objective to cover a cash dividend fully in cash by 2017.

This does not mean that for sure we will maintain the scrip dividend in 2016. And we will see it at the date of the AGM.

Okay. Very clear.

Thank you, Patrick.

Thank you for joining us today and you follow very carefully my rule of one question per person. The main takeaway messages that I would like to close with are these: Total is performing competitively in this environment; we are delivering the new project start-ups; and we are reducing our operating cost and investment.

And I hope I gave you sufficient granularity so that you can figure out how much we make our effort. We have a strong balance sheet and we are ready to cope with the volatile commodity price and margin.

That is for today. We look forward to seeing you in September where some of the question you asked will be answered.

This is our September Investor Day in London. I hope you will all enjoy some time off as I will.

Thank you.