TotalEnergies SE (TTE) 2009 Q3 法說會逐字稿

Ladies and gentlemen, welcome to Total third quarter 2009 results conference call.

I now hand over to Mr.

Patrick de la Chevardiere, Chief Financial Officer.

Sir, you have the floor.

Good afternoon, and good morning to you across the Atlantic.

Let me begin with some short comments, and then we can go to the Q&A.

Before we start on the results, I would like to point out that our main operating objective for this year was to launch five major projects in the Upstream.

All five have been started and are producing now.

For the results, we have reported a solid set of numbers for the third quarter and we continue to be very competitive compared to the performance of our major oil peers.

Looking at the third-quarter results, compared to the second quarter '09, adjusted net income was $2.7b, an increase of 14%.

Earnings per share was $1.20 per share, an increase of 14%.

Adjusted cash flow was $4.9b, compared to $4.4b in the second quarter, and our gearing at the end of the third quarter was down to 21%.

We presented our media update in September, so not much has changed since then.

Our objective is to maintain a strong balance sheet and manage our cash flow to provide a competitive return for our shareholders and fund an investment program that will provide long-term profitable growth.

So now I will comment on each of the segments.

In the Upstream, the average oil price was up by 15% in the third quarter, compared to the second.

Our liquid price realization increased by about 19% in the third quarter.

Our average gas price realization increased by 4% in the third quarter, despite the 3% decrease in the US Henry Hub prices.

Compared to the other majors, we have very little exposure to the US natural gas.

Upstream production increased by close to 3%, compared to the previous quarter.

Mainly, this reflects the contribution from the new field startups.

In addition, OPEC has a slightly smaller impact on the third quarter than the second, and gas demand shows some improvement, but these were offset by the negative price effects.

Seasonal maintenance was still heavy in the third quarter.

Compared to the other majors, we had the best sequential production growth, but, to be fair, the second quarter was a low base for comparison.

Adjusted net operating income from the Upstream segment increased by 9% to $2.1b, mainly as a result of higher prices and volumes.

The annualized third-quarter Upstream ROACE continues to be very competitive, at 17%, and our Upstream results for the quarter show that we are very resilient compared to our peers in this price environment.

Regarding the five major projects that we have started up this year, we are at or near plateau production on Akpo and Tahiti.

Tombua Landana is producing, but it will take a year or so to reach plateau.

Qatargas Train 5 is ramping up well and the first LNG cargo was at the end of September.

Yemen LNG is producing from the first of two trains.

The second train should start up next year.

The first cargo should leave this month.

We are continuing to add new projects to the portfolio, including an agreement to join KazMunaiGas in October on the Lukoil operator development of Khvalynskoye gas condensate field in the Caspian Sea.

This follows an agreement in June with Novatek to participate in the development of the Russian Termokarstovoye gas and condensate field.

In Nigeria, we received approval last month to develop the Timimoun gas field with Sonatrach.

In Bolivia, we have five declarations of commerciality of the Itau gas field and we plan to start production next year.

In the North Sea, we acquired an interest in the deepwater block where the Tormore discovery was made, and this fits nicely with our plans to develop the Laggan and Tormore field, provided that we can reach an agreement on the tax terms.

In the coming year, we expect to make the final investment decision to launch the next wave of major projects, assuming we can negotiate reasonable CapEx costs.

We are the operator on Laggan-Tormore in the west of Shetland area and CLOV on Block 17 in Angola, and both of these look promising.

We are a partner on the Surmont field in Canada and we expect to report phase two of the SAGD development sometime in the coming months.

Certain other projects, including Shtokman in Russia and Ichthys in Australia are still in the feed process.

Exploration continues to be an important part of our Upstream strategy.

We just announced our first discovery on Angola Block 17/06, called Gardenia, and we are pleased with the way the drilling campaign is going there.

In the deep Gulf of Mexico, we have started the drilling campaign with Cobalt, but it's too soon to announce any results.

Managing costs continue to be a high priority.

DD&A is increasing, mainly because of the new fields we are starting up.

We are continuing to work on reducing the OpEx.

Market effects are still positive year on year for basic supplies and services, but the rate of improvement is slowing.

Foreign exchange has been a big factor so far this year, but because that the dollar was much stronger at the end of last year, so the fourth-quarter comparison will be affected.

Our strategic view has not changed.

We believe that Brent will trade around $60, $80 barrel range for the medium term and then move higher as supply and demand converge by the middle of the next decade.

We have been surprised by the speed of the recovery in oil prices, but we would not be surprised by continued volatility.

For the long term, we are optimistic about oil and gas prices.

Our goal is to maintain capital discipline and position the Company with secure growth to profit from rising commodity prices.

Now I will comment on the Downstream and Chemicals.

In contrast with the Upstream segment, the market environment for the Downstream has been very challenging.

The combination of rising oil prices and weak product demand squeezed refining margins down to very poor levels, and our refining activity posted a loss for the third quarter.

The TRCV margin indicator was down 47% sequentially to less than $7 per tonne.

Despite some voluntary throughput reduction, inventory levels remain high.

Supply optimization and marketing have continued to perform well, more than offsetting the negative results from refining.

Adjusted net operating income from the Downstream segment was $0.2b, down only 3% from the second quarter.

Also, operating income was down 47% to $0.1b.

This was mainly due to a lower tax rate for the segment and a higher contribution from equity affiliates that includes a one-off gain of about $50m for the reclassification of an LPG activity in France from non-consolidated to equity affiliate status.

We are confident that the Downstream environment will improve over the long term, as the global economy continues to recover, but it is clear to us that we must reduce our exposure to refining in Europe.

In the near term, however, it is important to recognize that the Downstream segment, as a rule, is very close to breakeven in this type of environment.

In addition to reducing our exposure to European refining, we must also keep up the pressure for cost cutting.

This is part of a Company-wide effort to improve efficiency and reduce costs.

For example, we are shutting the production at the Dunkirk refinery and the distillation unit at the Normandy refinery until the market recovers.

On a more positive note, our Chemicals segment has posted two quarters of sequential improvement since recording a small loss at the beginning of the year.

Adjusted net operating income from the Chemicals segment more than doubled to $200m in the third quarter.

To put this into perspective, we are still about 40% below the adjusted net operating income of the third quarter 2008, so there is room for more improvement.

Petrochemicals are still under pressure in Europe and the US, but we have seen a benefit from increasing demand from China, at our Samsung plant in Korea.

In the rest of the world, demand remained weak, but margin improved in the third quarter.

The recent increase in oil prices, however, is putting additional pressure on margin, with higher naphtha prices.

Specialties has been very effective at cutting costs and this has helped to preserve their margin.

And, finally, on the corporate side, adjusted cash flow from operations for the first nine months was $13.8b, investments excluding acquisitions for the first nine months, $12.2b.

Basically, we are in line with the 2009 CapEx budget of $18b.

Divestments of $2.9b through September 30 were essentially the ongoing sales of the Sanofi shares.

At the current market value, we have more than $8b remaining to sell, and I can confirm that we expect to complete the process by 2012.

Two weeks from today, we will pay the 2009 interim dividend of EUR1.14 per share.

The dividend is stable compared to a year ago in euros, but in dollar terms this represents an increase of about 20%, due to the decline of the dollar.

If we annualize the dividend and the third quarter results, this indicates that the payout ratio is relatively high, but manageable, at between 60% to 70%.

Our gearing was 21% at the end of the third quarter, down 4 points since the end of the second quarter, reflecting our positive cash flow performance.

The interim dividend payment in November will increase the gearing by about 5 points, so we should end the year in our announced 25%/30% range.

The balance sheet is strong and we are easily able to fund our investments and dividends.

Looking at the fourth quarter, lower maintenance activity and the ramp-up from the five major new fields should be very positive for Upstream production.

Oil prices are holding about $75 per barrel, and our gas price realization should continue to increase in the fourth quarter, due to the lag effect.

So we are pretty confident that Upstream will be in good shape.

Downstream and Chemicals are more difficult to predict.

Refining margins have remained very weak through October, and the Downstream segment, as a rule, is operating at close to breakeven.

The Chemicals have demonstrated good resilience.

For Total, we will continue to balance the optimistic view with a prudent approach.

We will enforce strict capital discipline on all new projects that are launched, and we will look for efficient ways to add new opportunities to the portfolio.

And now we can go to the Q&A.

(Operator Instructions).

We have a first question from Mr.

Jason Kenney from ING.

Please go ahead.

Hi, Patrick.

It's Jason Kenney from ING.

Hi, Jason.

Good.

I'm just wondering where you expect gearing to be at the end of this year, 2009.

And then, if oil were to stay above $65, do you see any reason for an increase in gearing through 2010, because it doesn't look the case from my perspective?

And then, maybe a related question, you've got a very well-defined set of major projects and activity levels through to 2012.

I just wondered if you had any clarity on CapEx guidance for next year.

Okay.

First question, on gearing, my estimate is that we will be in the range of 25% to 30%, maybe in the higher part of this range, but the working capital effect is something unpredictable, so I will be cautious by telling you that it will be in the range of 25% to 30%, and I think in the highest part of this range.

If the oil price remains above, let's say, $70 per barrel for next year, I expect the gearing end of the year to be close to 30%, something like this.

As far as the CapEx guidance for 2010, as you know, we have our budget session starting in two weeks' time, so I don't have exact figures, but I am expecting CapEx for 2010 in the same level than 2009.

Okay.

Many thanks.

Thank you.

We have a question from Mr.

McMahon from Sanford Bernstein.

Please go ahead.

Hi.

I've got a few questions.

First is on Angola.

It's obviously somewhat similar to what you've been drilling in Angola around Block 17.

Can you go into the rough sizes of the prospects there and what we should expect going forward?

There have been two discoveries made in Angola.

One is Gardena and the other one is Cabaca Norte on Gardena.

Or Gardenia, sorry.

We have 30%.

This is on Block 17/06.

And the Cabaca Norte, we own only 15%.

I don't have exact figures on the size of each of those two discoveries, but I am assuming this is more than 100m barrels of reserve for each of them.

But this is only one well being drilled, so we need confirmation for that.

Okay.

But the outlook is not for some reasonable-size discoveries above 100m.

You expect them to be in that sort of ballpark?

Yes, honestly, at that range.

This is between 100 and 500, so it's very difficult to tell you.

Okay.

The second question is really in terms of the development along with Lukoil in Kazakhstan.

Can you give us any idea of the terms of that agreement?

And, secondly, what do you actually bring to the table here?

It doesn't seem that you get an especially significant upside, or Lukoil gets anything special with your involvement in this field, so maybe you could just give us some color on that.

We signed an Head of Agreement with Lukoil at that date.

I think what -- and this is very important, for us to be involved in this development.

You must -- I remind you that we helped Lukoil to acquire a percentage in a refinery and this was a very good opportunity for us to establish extremely good relationship with Lukoil.

And it is not a surprise for us that Lukoil called on us.

We know that we are known as very good operator in -- and our know-how is very well appreciated, and I think Lukoil appreciated both our know-how and our ability to discuss with them.

Okay.

There may be a potential to get rid of most of your refineries to Lukoil, then, if such a relationship flourishes.

Just a last question on starting up Yemen LNG.

Any startup issues associated with that, or is everything ramping up smoothly?

Everything is ramping up smoothly.

You know that we faced something like 15 days delay at startup, which is I don't think catastrophic.

This is at least mainly good news and everything is going smoothly now, and the first cargo is by end of this month.

Great.

Thank you very much.

Thank you very much, Neil.

We have a question from Mr.

Theepan Jothilingam from Morgan Stanley.

Please go ahead.

Yes, hi.

It's Theepan from Morgan Stanley.

Patrick, three questions.

Firstly, just on operating expenses, just looking through your P&L, you've got a couple of billion euros reduction there on a nine-month basis versus last year.

I'm just wondering if you could split that, firstly between the Upstream and the Downstream, how much of that is perhaps, in your view, sustainable going forward.

Secondly, I think you mentioned refining was loss-making, but just to give some sort of clarity, can you talk about how resilient marketing was, or how negative refining was in the quarter, trying to get a split there?

And, lastly, just on DD&A, with the projects ramping up, could you give any sort of guidance on what you think DD&A will be next year, relative to 2009?

Okay.

Your first question was on OpEx and our costs.

When I am talking about costs, I don't like words and I like figures.

If you have a look to our income statement, on the line Other Operating Expenses, you see on a nine-month basis a reduction of the other operating expenses by $2.3b, roughly.

I would say that two-thirds of that is foreign exchange and one-third, about, is [self help].

And the split amongst the branches, 25% is the Upstream and the remaining part is half and half Downstream and Chemicals, so that was for the OpEx.

Your second question was our resilience for the marketing.

Basically, our marketing activity offset the losses of the refining business this quarter, with supply optimization.

We see some very good resilience since 2008, even with the very high oil price for products that we were facing.

And even now we have mostly recovered, after the economical crisis, the volumes of 2008.

And honestly, in our network in Europe, we have very good volumes.

I will leave aside the UK, where the volumes are not as good as in the rest of Europe.

So that was on marketing.

The last question was on DD&A.

Obviously, when you launch new projects, the DD&A are higher than before starting those projects.

Basically, what I can tell you is that our objective for this year is to try and stabilize the technical costs, so that the OpEx reduction will offset the DD&A effect, basically, roughly.

That is something we maybe could achieve this year.

Is that okay for you, Theepan?

Yes.

I was wondering, though, where do you see that going next year?

Is it a $1 increase per barrel for DD&A for next year, as the new projects come on or is there any guidance you can give there?

As I mentioned to you, we are in the budget process now and it's honestly too soon to give you any figures at that stage.

Okay.

All right.

Thank you.

Thank you.

We have a question from Mr.

Jon Rigby from UBS.

Please go ahead.

Yes.

Hi, thanks.

Two questions.

The first is to do with your LNG business.

You've got significant offtake agreements I think with both Yemen and Qatargas.

Should we expect an increasing feature of your Upstream earnings, I guess like we saw in the third quarter, that your gas realizations start to come under pressure as a result, or are you able to place those volumes in attractive markets?

The second question is to do with your Downstream.

It looks to me that every time anybody looks very hard at their refining portfolios and makes some decision about closure or sale, that an impairment follows.

Is it likely that we will see something in that regard by the end of the year, or is it too early for you to have made a firm decision, which would then be a catalyst for some form of impairment?

Thanks.

First question, on LNG prices.

We are not only selling LNG on the spot markets, but we also sell LNG under long-term formulas, in Korea, for instance, so it's a mix of spot prices and long-term prices.

Honestly, I don't have the mix of the first cargos which are going to be sold from Yemen and Qatar, so very frankly speaking I am not able to give you any specific figures for last quarter this year.

Over the long term, my view is that by being able to sell maybe forward volume of LNG and taking advantage of the contango that you see currently on the Henry Hub may be helpful.

We haven't made any decision in that respect, but when you see that today the spot Henry Hub is between $4 and $5 and the forward one year is between $7 and $8, this gives you some ideas.

On the Downstream, you know that any type of decision in that respect must be put first to the union, and at that stage nothing has been decided in that respect.

It is obvious for us that the current situation is not favorable to the refining business, that the refining is losing a huge amount of money currently in Europe, and also in the US, by the way.

It is -- and we are considering reducing further our exposure to the refining activity.

That's all I can say at that stage.

Okay.

Thank you, Patrick.

We have a question from Mr.

Dave Thomas from Citigroup.

Please go ahead.

Yes.

Good afternoon, Patrick.

And I've got three questions, please.

Firstly, on Iraq, I wanted to ask, other oil majors are obviously happy to go ahead on revised terms of around $2 a barrel.

Could you just say what Total's position is in that country, where you've obviously felt in the past you have a favorable position?

Secondly, can you provide perhaps more detail on the timing of the FIDs that you're talking around the three main projects, and also on Shtokman and Ichthys?

And, finally, you mentioned about a slowdown in cost improvements.

I just wanted to see what you feel about how much further you need to see costs come down to justify some of your new project sanctions.

Thanks.

Okay.

About Iraq, it is obvious that Iraq is a very important country for the oil industry.

And on the first bid, we were interested in the West Qurna field, and I remind you that only BP has been awarded a field during this process.

We are at that stage very interested in two fields which are under auction at the second auction, which are namely Majnoon and Bin Omar.

It all depends on the terms and conditions we can have for those fields, which are different than the fields which were in auction first, because those fields are growing fields.

So we will see the outcome of this bidding process and if we are able to obtain reasonable terms and conditions, but I repeat, Iraq is a very important country for the oil industry and for us.

For the next FID, we expect to launch shortly Surmont phase two in Athabasca and the same with CLOV in Angola.

For Laggan-Tormore in the North Sea, it all depends on the tax regime which will be applicable to us.

And depending on cost estimates, then you have Ofon 2 that you know we were ready to launch and that we didn't launch due to a cost estimate we had a year ago.

And then Shtokman and Ichthys, Shtokman and Ichthys, this is something for late 2010.

And I am sorry, Dave, I have no more projects for you.

Okay.

And there was the final point, just about the cost improvements and just how much further you need to see those come down in the current sort of $60 to $80 environment.

Okay.

The most tricky projects are in Athabasca.

For deep offshore projects, of course it's always good to obtain better costs and conditions and we are working on that.

But even with the level of costs we were facing a year ago, and I remind you that the cost inflation was down by something like 15% to 20% this year, but even with the costs we were facing in 2008, both deep offshore and ultra-deep offshore were giving us reasonable return.

For Athabasca, we had cost estimates for the Joslyn project a year ago, basically, and this project was not matching our investment criteria.

Basically, roughly, on the basis of the cost estimate we had a year ago for Shtokman, we needed -- not for Shtokman, for Joslyn in Athabasca, we need a cost reduction of 30% to 40%.

I remind you that for the Jubail refinery we obtained such a kind of cost reduction.

For Ichthys and Shtokman, we don't have yet any cost estimates, so I can't disclose anything in that respect.

Okay.

Thanks, Patrick.

Thank you, Dave.

We have a question from Mr.

Alejandro Demichelis from Banc of America.

Please go ahead.

Yes.

Good afternoon, gentlemen.

Alejandro Demichelis from Banc of America.

One quick question.

You have been talking about restructuring your Downstream portfolio, but are you also thinking about doing some kind of restructuring on your Upstream portfolio?

We have seen some companies putting some of their assets in North Sea or Nigeria up for sale.

Alejandro, just on Upstream, basically, I remind you that we have the lowest costs, technical costs, of the industry and that basically our operations are quite well managed.

At that stage, there is no need for us to sell assets, as we don't need money.

We have enough cash flow coming from operation, plus the cash coming from the sale of Sanofi.

So, in the current oil price that we are facing, there is no rush for us to sell any assets and we are not contemplating at that time any sale of Upstream assets.

Okay.

That's good.

Thank you.

And just on a different subject, you have been talking about the cost base, particularly in Athabasca and so on.

When are you going to start looking at what you have spent there and should we start expecting some kind of provisioning for some of the projects that you have there?

We spend very little money in the Joslyn mine and we already write off some small SAGD developments we have made on the Joslyn mine.

The mine itself is at its book value and it's fine.

And on Surmont we are contemplating a further development, so there is no reason for any provision.

Okay.

Thank you.

Thank you.

We have a question from Mr.

Mark Gilman from Benchmark Company.

Please go ahead.

Patrick, good afternoon.

I had a couple of questions, if I could, please.

First, could you just comment whether the Gardenia discovery on 17/06 in Angola is a play type different from that which you had been exploiting up to this point on the original concession block?

Secondly, I was interested in whether there was any upfront payment at all involved with respect to the acquisition of the interest in the Caspian block with Lukoil.

Thirdly, it appears, just based on the math, that the sensitivity of your entitlement volumes to changes in oil price under production-sharing contracts seems to be diminishing, and I was wondering if you could talk a little bit about the reasons for that.

Fourth and finally, it has appeared over the last several years that in the Downstream and Chemicals portfolios the Company has been subject to an unusually high number of potentially significant incidents.

And I was wondering what steps management is taking going forward to try to reduce the recurrence of such incidents.

Thank you.

Okay.

I'll start with the last one.

On the so-called incidents, which for some of them are accidents and some people lose their lives in those accidents, we took it very seriously.

We established a group of experts in order to audit all our plants in France, first, because this was mostly concentrated in France.

The result of that will be known by beginning 2010, January 2010, and we will let you know.

First, we will let know the union and the Board, and then we will let know the market what the result of this inquiry is.

The sensitivity -- the low sensitivity on the price effect, it's quite difficult to understand.

I acknowledge that.

If you see -- if you try to play the sensitivity third quarter versus second quarter, it's more in line with our guidance.

What's something which can explain the difficulty we have is that [cost oil] was saturated last year, and it might be that it is in some areas still saturated now.

Basically, I am telling you that despite the lower oil prices, the cost oil volume has not increased, because the cost oil is saturated.

That may be an explanation.

As far as I know about the Lukoil, there is no bonus related to this agreement we signed with Lukoil, and the agreement is with KMG and not Lukoil, I remind you.

Lukoil is a partner.

On Gardenia, Gardenia field is similar to CLOV.

Thank you, Patrick.

I recognize that you have always very tricky questions, Mark.

Thank you very much.

Thank you.

We have a question from Mr.

Colin Smith from ICAP.

Please go ahead.

Afternoon, Patrick.

I just wanted to come back on Laggan and Tormore.

Are you actually looking for a change in tax terms before that project can go ahead?

And I wonder if you could maybe just comment on what sort of gas price you think you need to make it economical.

Thank you.

We are currently discussing some kind of tax treatment with the authorities and I am sorry, I can't elaborate more.

And I would rather to keep my comment for the tax authorities.

Some people can think about some kind of uplift for depreciation and things like this.

And on the gas price you need for it?

Honestly, I don't know.

This project has not been through the Executive Committee, so I haven't seen the dossier itself yet.

Thank you.

We have a question from Mr.

Iain Reid from Macquarie.

Please go ahead.

Hi, Patrick.

It's Iain Reid from Macquarie.

Two questions, please.

Firstly, on the Downstream, coming back on that, please.

You may not want to talk about individual refineries, but could you give us some indication of the target for the volume reduction in refining you might be thinking of in Europe, by what sort of percentage perhaps you might want to exit from or close?

Iain, I cut you immediately.

I'm sorry, I can't answer your question.

Okay.

I understand.

For obvious reasons.

Okay.

I understand that.

Secondly, then, on cost reduction, you've talked over the last couple of quarters about a $1 per barrel reduction from technical costs.

Is that still what you're aiming at for the full year, or is there any further to go on that?

As I mentioned previously, we had in the Upstream a cost-reduction program of $850m.

This is done already.

We have same kind of program for the Upstream -- for the Downstream and the Chemicals.

On the Upstream, our objective is to maintain the technical costs roughly at the same level of 2008.

Okay.

Thanks.

Thank you.

We have a question from Mrs.

Lucy Haskins from Barclays Capital.

Please go ahead.

Good afternoon, Patrick.

I wondered if you had any update in terms of how the Cobalt joint venture was progressing, and also whether there are other joint ventures you might be prepared to look into.

On Cobalt, as I mentioned in my speech, which was not maybe very clear, is that we were unable to disclose any data in that respect as there were [talks] progressing.

And on top of that, Cobalt is under IPO, so I will make no comment.

The only thing I can tell you is that there are five wells to be drilled, down to late 2010, and that we have good hope for those prospects.

I'm sorry, I can't comment so much, basically due to the Cobalt stages.

Any other JV, why not?

Once again, when we are discussing with potential people for potential partners, I am not going to give you any names or any targets.

But, yes, we are, as we are doing at any time, looking for any opportunity and we are currently discussing, yes.

Perhaps I can understand your sensitivity in terms of talking about specific companies.

Are there specific geologies or -- that you're contemplating?

If I give you the geology, it is better for me to give you the name.

Doesn't cost you too much to try.

Thanks, Patrick.

Thank you.

We have a question from Mr.

Alastair Syme from Nomura.

Please go ahead.

Hi, Patrick.

Just a point of clarification on the gas price.

I think this was in response to Jon's question.

Am I right in thinking that the consolidated gas price you show is mainly lag effect, with maybe a bit of spot UK pricing in there, and that Qatargas and Yemen and Nigeria, which I guess are your main spot sales, are all coming through the equity line?

That's correct.

Right, okay.

Thank you.

That was all.

We have no further questions for the moment.

(Operator Instructions).

We have a question from Mr.

Morton from MF Global.

Please go ahead.

Yes, good afternoon.

Neill Morton, MF Global.

A couple of quick numbers questions.

The first is actually a repeat of what I asked Eni last week.

Would you care to split your Downstream result, your operating result, of EUR83m into the refining loss and the marketing gain?

And, secondly, could you tell us what your exit rate of production was at the end of the third quarter?

Thank you.

Sorry.

I did not understand the last question.

It was just your -- effectively your current rate of production, either at the end of September or an average for October.

Okay.

For your first question, I am sorry, but I think you will be disappointed from my answer for both of them.

But we don't split and we don't give details for the refining versus the marketing.

All I can tell you is that the marketing is offsetting the big losses made by the refining currently.

And, again, on the -- we do not give production rates month per month, so you should have to wait for the quarter result.

Okay.

No luck.

I'll give it up.

Thank you.

Thank you.

We have a follow-up question from Mr.

Mark Gilman from Benchmark Company.

Please go ahead.

Yes, thank you.

Patrick, was Akpo at the plateau levels for the entire third quarter?

Close to, but not completely at plateau.

For the entire quarter?

No.

It was not for the entire quarter.

It is at plateau now, but it was not completely at plateau for the full quarter.

Okay.

Could you clarify your comment regarding the reclassification of certain LPG -- or a gain on an LPG asset, I believe, that you commented on, reclassification from consolidated to equity?

I didn't quite understand what you were talking about there.

It was a non-consolidated affiliate, and through a reorganization of this participation it became an equity affiliate.

For the first consolidation as an equity affiliate, you recapture all the net income which was in the company accumulated and not distributed in the past.

This was the $50m that we get it back from this change in the consolidation process.

And this is reflected in your Downstream equity earnings in the third quarter?

Is that correct?

That's correct.

Thank you, Patrick.

Thank you, Mark.

You have been very reasonable.

We have a question from Mr.

Paul Spedding from HSBC.

Please go ahead.

Hi.

It's Paul Spedding from HSBC.

Just an observation that, obviously, a growing amount of your assets and hence earnings and cash flow are beginning to come from associates or joint ventures.

Would you consider giving us additional detail, perhaps unaudited, about some of the other financial parameters associated with these joint ventures?

In particular, I'm thinking of perhaps some guidance or indication on cash flows.

I am sorry to say, I just gave you an example on Nigeria LNG, which is an equity affiliate.

We don't have access to the cash flow of this affiliate, so we are not going to report it.

And, on top of that, I don't know it.

I don't know what is currently the net cash flow of this affiliate.

Maybe I could ask for that, but as I do not have access to the cash flow, I do not report it.

So you don't have any management representation on NLNG?

Yes, we have, but as I mentioned to you, I have no myself -- Total has no access to the cash flow.

It is not for me a big interest.

I just check that the company is able to fulfill its commitment, mainly against the banks and for the use of the cash flow and to pay the dividend, and that's it.

Okay.

We have no further questions.

(Operator Instructions).

There is no other questions.

Thank you very much, all of you, and have a good day.

Ladies and gentlemen, this concludes the conference call.

We thank you all for your participation.

You may now disconnect.