TotalEnergies SE (TTE) 2015 Q2 法說會逐字稿

Good afternoon and welcome to the Total second-quarter results conference call.

Today's conference is being recorded.

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

Please go ahead, sir.

Hello, Patrick de La Chevardiere 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 startups 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've 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 remains 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 startups for 2015, including the four that are already producing.

Vega Pleyade will start up around the turn of the year.

So even without a 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 produced 30,000 barrels per day at 100% and helps to maintain the nine-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 tonne for the quarter, a level we haven't seen since 2008.

The ERMI was strong, reaching high well above $60 per tonne in the second quarter.

The average for July is above $50 per tonne.

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 margins.

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 generates $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 results for this quarter were generated by the downstream and, second, we are very happy to have the resilience that has come with being an integrated company.

This leads me to the corporate section.

From a strategic perspective we have learned 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 years as we continue to start up new projects.

Acquisitions were $282 million in second quarter 2015.

Asset sales were $743 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 companywide cost-reduction plan is gaining momentum and we are reducing CapEx.

Our second-quarter results 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 downstream.

We generated $10 billion of adjusted cash flow from operations in the first half of the year despite a 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, I ask that you limit yourself to one question at a time.

(Operator Instructions) Theepan Jothilingam, Nomura International.

Good afternoon, Patrick.

It's Theepan here.

One question.

Just on the impact of disposals and 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.

Thank you, Theepan, for your question.

There are positive effects, of course, from the new startup, a negative effect 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 startups.

We have four major new projects in production and three more on the way this year.

Vega Pleyade, as I mentioned in my speech, will start up at the turn of the year.

But, honestly, I am 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 will have to take into account the difficulty we face in Libya and in Yemen.

Total's growth portfolio isn't matched 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.

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 this (multiple speakers).

Since second quarter 2015 our production is up 12% compared to second quarter 2014, which can be described as follows: 5% from the startup, 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 contracts.

Basically 3%.

A better performance on our field and lower maintenance that more than offset the natural decline, which is about 3%.

Thank you, Patrick.

Very comprehensive answer there.

Thank you, Theepan.

I am paid for that.

Martijn Rats, Morgan Stanley.

Good afternoon.

I wanted to ask you two things.

First of all, something which isn't always so visible for us in quarterly results, because it's 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.

Secondly, just sort of a short housekeeping question.

Could you comment on the CapEx for 2016 that is already committed?

That would be useful, thanks.

Okay, you are right.

LNG profitability is an important question.

In second quarter of 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 tonnes 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 the 10 cargoes redirected this quarter versus 17 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 Pouyanne 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 ask 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 will have that is sold forward on the long-term contracts, I remember that to be around about 19%, but that might be a slightly 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 instead of one.

Oswald Clint, Sanford Bernstein.

Thank you, Patrick.

I had 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 reduction in terms of breakeven prices?

Thank you.

Thank you, Oswald, for this 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 results.

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 reductions are yet to be seen in subsea, in fabrication of platform and FPSOs.

I think that both builders of those equipment or platforms 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 task force has been created with key account negotiator 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 projects one can think about.

We are also looking at early termination of some contracts, price reduction, and we are also increasing the number of the frame agreement and suppliers.

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 remains at this level, that we will see significant cost reduction for our future projects.

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

Excellent, very detailed.

Thank you.

Alastair Syme, Citi.

Patrick, can I just talk a little bit about the 20% reference or the reference to 20% unit cost reduction in the upstream, about how you break that down and particular are there any portfolio effects to consider, like ADCO 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 includes Gas and Power purchase from third-party products.

This includes production taxes including ADCO and this also includes exploration for about $300 million.

Net of all those elements, the $5.5 billion comes down to $1.6 billion and this $1.6 billion of operating net expenses for E&P compared to $2.1 billion first quarter this year.

No, sorry, second quarter last year.

Basically, for upstream we have around $0.5 billion.

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; 4 times $300 million will make $1.2 billion.

I am 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 terms of technical costs, I am 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 stay about $330 million for the quarter.

On top of that, you can add, and you add some transportation costs and other costs for about $120 million.

All-in-all, I am back to the $450 million, $0.5 billion I was mentioning before to you.

That is fantastic detail.

And in the $350 million net, how much of that do you think is controllable stuff versus natural deflation in energy prices and consumables?

If I was ready to tell you that, I would've told you that because I'm quite transparent today, but I don't know.

And I am 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 savings and $1.2 billion for the group, and we are in advance.

Got it.

Thank you very much, Patrick.

Guy Baber, Simmons & Company.

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 are 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 have taken out of that business over the last few years so we can better appreciate and model the uplift that you are really seeing in sustainable profit, setting aside the macro environment?

Thanks for taking my questions.

Okay, once again there is one question.

In first half this year the refining margins, the ERMI indicator, was an average at a very high level, above $50 per ton.

Second margins are traditionally higher than 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 operations in downstream.

In upstream also, but your question was on downstream.

And the objective was to reduce below $20 per tonne, for each unit, the cash breakeven.

I remind you that in 2012-2015 period we save about $650 million of operating income for the overall period.

2015-2017 we expect an additional $400 million.

And all-in-all the expected savings for 2012-2015 could be up to $900 million, which means that for the period 2012 to 2017 a staging of $1.3 billion for refining and chemicals.

For marketing, we are expecting 20% cost savings for the period 2015-2017, which could lead to savings of about $400 million.

That is basically what I can tell you about downstream costs.

Thanks for the detail.

Thomas Adolff, Credit Suisse.

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 is cost deflation-related, what is project reengineering-related, and what is 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 rate 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.

As far as the decline rate is concerned, it is true that we are surprised to see actually on our figures a 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 will be able to maintain the 3% decline rate.

Okay, thank you very much.

Nitin Sharma, JPMorgan.

Afternoon, Patrick; hope you are well.

I gathered from your update that you mentioned underestimating the demand impact of lower oil price, but they remain around $54 a tonne in Q2.

Is it time to reassess your low-key target for downstream based on $25 to $27 a tonne ERMI?

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

Thank you.

Once again, one question.

So one question about our refining margin and the expectation we have on the profitability of this refining and 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 targets 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 units and platforms the cash breakeven below $20 per tonne.

Your second question was about impairments.

There was no upstream impairments second quarter 2015 and that's it.

Biraj Borkhataria, RBC.

Thanks for taking my question.

I just had the one, which was in the upstream you have a number of projects to deliver over 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 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.

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 conditions at the moment on site.

It is winter in Argentina at the moment.

That's basically what I can see.

For our projects down to 2017 -- I am 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.

That's on 2017.

You may have to wait till September.

Thanks very much, Patrick.

Jon Rigby, UBS.

Thank you.

Can I ask -- you know how much I liked your scrip dividend, so I was going to ask what conditions have to exist for you to reconsider stopping that scrip dividend?

You've talked a lot about cost reductions and assuming macro changes somewhat so --?

I remind you that our objective is to cover the dividend and the CapEx in cash by 2017 at the latest.

Would you remove it at that point or would you continue with it and maybe use the cash --?

No, if we cover it by 2017 depending on the oil price of course but we were assuming something like $60 per barrel, we will be in a position to cover the dividend in cash and pay it in cash.

Then it would stop.

Yes.

Thank you.

Lydia Rainforth, Barclays.

Thanks, Patrick.

Just one question, if I could, coming back to the cost savings.

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 a barrel.

Basically, we are asking fewer works to be performed by contractors and we optimize logistics.

Give you an example.

For instance, in Angola we are reducing the speed for our service boats, which give a substantial savings in gasoline.

Globally, I remind you that we are reducing our headcount 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 reducing the number of vessels 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 neutralize our IT and general services.

We are on the downstream optimizing the catalyst change, reducing the number of both catalyst change, making some synergies in the maintenance.

I remind you it is a bottom-up exercise where every manager is incentivized, so I can tell you there are plenty of new ideas.

Thank you.

Anish Kapadia, TPH.

Good afternoon.

I just had a question on Angola, in particular on Block 17.

Now that you've got the next phase of Dalia onstream, 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 seem to be -- it doesn't seem like you've got any further sanctioned phases of development over there.

So I was just wondering how you see that production profile over the next five years.

Thank you.

You know, I'm not the field manager of Block 17.

Block 17 already produced 2 billion barrels.

Dalia is still at 200,000 barrels 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 fields have been already developed and production.

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

Irene Himona, SG.

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 little bit of firm guidance on what we should be assuming for this kind of environment.

And then just a question for clarification on the cash flow.

Because of the timetable and the scripyou 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.

First question about tax.

Second quarter this year upstream effective tax rate decreased slightly from 49% to 47% mainly thanks to a field allowance counted 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 increase rate applying to exploration charges.

Looking for forward, the extreme 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 seemed to like very much, with the scrip payments moved back by a few days to look 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 amounts reduced by the script itself.

So we will have 3Q 2014 dividend paid in March, July 4Q dividend, and October first Q 2015 dividend.

And on top of that you are to take into account the take up of about 50%, which I think it is a low rate, but let's assume that for the script 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.

Lucas Herrmann, Deutsche Bank.

Patrick, good afternoon.

You are doing well.

It is 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, 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 wonder if you could comment on the trends in DD&A in the upstream where the per barrel numbers, on a subsidiary basis, seem to be falling, which I guess surprises me given the volume improvements we are seeing and the nature of the production that is coming on.

Thirdly, was there any hedging this quarter in the downstream business, which I guess in effect would've cost you rather than benefited you?

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

I don't know how much we hedge 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 had 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 has to be paid in cash, not using previous losses.

But we are benefiting from our produced 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 margins remain at this level.

Then you have a third question on DD&A.

Yes, it's just I'm surprised -- I guess I'm slightly surprised.

For example, if I look at the trends in DD&A in the upstream, the absolute number in dollars 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've 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 translation, I would say, effect because the Norwegian kroner now is lower than the US dollar, and DD&A was also lower thanks to the increase of production and some past impairments.

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

Thanks very much.

This is very helpful.

Have a good break.

Yes, you can hear my Ferrari.

I'm waiting for the vroom vroom.

Gordon Gray, HSBC.

Thanks.

Hi, Patrick.

Quick one; you announced good appraisal results on Elk-Antelope in the recent past, so just wondering how your thinking is developing about the resource available and particularly how to monetize that asset.

Thanks.

On Elk-Antelope, we have to be clear; we have 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, how 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 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 in a position, fully, 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.

Keep in mind that there is no rush.

We need to see the cost going down, so this gives us some time to market this gas and wait for costs to adjust.

Okay.

Thanks for that point.

Rob West, Redburn.

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?

Not an impairment, but --?

Of course, I'm afraid that I am unable.

I am not very -- I'm not the best accountant in the room.

Okay, thank you.

Christopher Kuplent, Merrill Lynch.

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

Just two questions, hopefully very quick.

The first one I just wanted confirmation of 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 extend to whenever you reach free cash flow neutrality?

Just wanted to get confirmation on that.

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 are 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 a strong exposure of 60%, remaining the operator.

For the -- 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 as being the asset leader for two fields we enjoy an extra fee on this ADCO project.

And so 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 as the date of the AGM.

Okay, very clear.

Thank you, Patrick.

We have no other questions.

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

Thank you for joining us today and you follow very carefully my rule of one question per person.

The main take away messages that I would like to close with are these.

Total is performing competitively in this environment.

We are delivering the new project startup and we are reducing our operating cost and investment, and I hope I give you sufficient granularity so that you can figure out how much we make our effort.

We have a strong balance sheet and we agree 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 questions you ask 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.

Thank you.

That will conclude today's conference call.

Thank you for your participation, ladies and gentlemen.

You may now disconnect.