TotalEnergies SE (TTE) 2009 Q2 法說會逐字稿

Ladies and gentlemen, welcome to Total Second Quarter 2009 Results Conference Call.

I'll now hand over to Mr.

Patrick De La Chevardiere, Chief Financial Officer.

Sir, please go ahead.

Thank you and welcome everyone, and thank you for turning us on a Friday afternoon.

As usual, I will make some comments on the second quarter results, and then go to the Q&A.

Compared to the first quarter 2009, the second quarter environment was not favorable despite the rebound in oil prices on very low levels.

The context of depressed demand, gas price continued to fall, and refining margins were very weak.

Taking this into account, our results were weaker this quarter than in the previous quarter, but our performance on a year-on-year basis still compares favorably with our peers.

Looking at the second quarter results compared to the first quarter, adjusted net income was $2.35 billion versus $2.75 billion, a decrease of 15%.

Earning per share was $1.05 per share versus $1.23 per share.

Adjusted cash flow was $4.4 billion, stable compared to the first quarter.

CapEx, excluding acquisitions, was $4.2 billion compared to $3.6 billion.

Acquisitions in the second quarter were $654 million, linked mainly to Libya and our deal with Cobalt.

Asset sales were $1.1 billion in the second quarter compared to $468 million in the first quarter, affecting an increase in the sale of 10 officials.

And our giving at the end of the second quarter, after paying the dividend was 25%, slightly below the level a year ago, and at the bottom of our target range of 25%, 30% for 2009.

In the second quarter, non-recurring items had a negative effect on net income of $300 million, mainly from restructuring charges in the downstream and chemicals.

We are well into the implementation of a company wide cost cutting program.

We are continuing to review the feed and contract structures of pending projects in order to reduce CapEx, specifically on large LNG and Oil Sands projects, as well as other projects that should be ready for our final investment decision next year, such as CLOV, Egina, Laggan and Tormore.

We recently announced that contracts were being awarded for the Jubail refinery project, after a second run of bidding, and the important point here is that we were able to reduce CapEx by about 25% from the initial estimates.

Now, I will comment on the segments.

In the upstream, the average blend price rose to $59 per barrel, an increase of 33% compared to the first quarter.

Our natural gas price realization decreased by 21% to $4.7 per million Btu.

This decrease reflects the impact of weak demand on spot gas prices, and the lag effect on our formula based contracts.

However, relative to our bills, we benefited from our low exposure to US natural gas prices.

Our average hydrocarbon realization increased by 14% to $44 per barrel of oil equivalents.

Adjusted net operating income from the upscale segment increased slightly to $2 billion, as the effect of higher oil prices, lower gas prices and lower production volumes essentially upset one another.

The annualized second quarter we achieved for the upstream is 16.5%.

This continues to be very competitive with the other major oil companies.

Our net operating income was $10 per barrel of oil equivalent.

This is at the level of the best among the majors ones, demonstrating the resilience of our portfolio.

Production in the second quarter averaged 2.18 billion barrel of oil equivalent per day, a decline of 7% compared to the first quarter, mainly due to the following elements.

Additional seasonal maintenance, including a full shutdown of following for one month, had an impact of minus 3.5%.

Weak gas demand was minus 1%.

The SC price effect was minus 1%, and the combination of normal decline and security issues in Nigeria more than upset the contribution from new fields.

Looking forward, here is what I can tell you for the rest of the year.

OPEC quota, GSC price effect, and market demand will continue to be large factors beyond our control in determining production volumes.

In the third quarter, maintenance will remain at seasonally high levels, including the completion of following maintenance, plus full shutdowns of Bruce and Elgin/Franklin.

Contributions from new fields will be mainly Akpo and Tahiti.

For the fourth quarter, the seasonal maintenance would be finished, and this effect on production should reverse.

One of our goals for this year was to start at five major projects.

Akpo and Tahiti are online and contributed about 30,000 barrels of oil equivalent today, net to total in the second quarter.

The three remaining major projects, Le Yemen LNG, Qatargas II, [Trendish] and Tombua Landana should all startup this year, and a year from now, the five major projects should be contributing about 200,000 barrel of oil equivalent per day in net.

I would also like to say a few words about two LNG projects that are starting this year.

We expect Yemen LNG to start production by end of August or beginning of September, and Qatargas II should start early in the fourth quarter.

So, they should have a positive impact on projection in the fourth quarter and ramp up in 2010.

Yemen and Qatargas II are two of the last low cost LNG projects that the industry has launched.

Yemen for example cost only about $4.5 billion for 6.7 million ton per year capacity.

Mainly because of this, LNG from Yemen and Qatargas II will be really competitive with unconventional gas in the US market and another edge will be profitable when [Enriag] is between $3.00 and $4.00 per million Btu.

Another project that I would like to comment on is our joint venture with Cobalt in the Gulf of Mexico.

We spread the first well about two weeks ago.

We plan to drill five wells over the coming year.

We are pleased to be working with Cobalt, and also pleased that the joint venture combines the talent and the strengths of each companies.

Access to resources is a constant challenge for our industry, and we believe this joint venture with Cobalt is a good way to expand our portfolio.

In June, we agreed to form a partnership with a Russian company Novatek to develop the onshore Termokarstovoye field located in the Yamalo-Nenets region.

This field has a potential reserve of about 350 million barrel of oil equivalent of gas and condensate.

Total and Novatek will carry out appraisal and development of these with a target launch date some time in 2011 for this project.

These partnerships represent a fast and efficient way to add opportunities to the portfolio.

We are also continuing to find oil and gas through exploration.

In the second quarter, we had a positive appraisal well in offshore Congo, the north of the Moho-Bilondo field.

And we also had a significant gas and condensate discovery on Niscota in Colombia.

Our strategic view has not changed.

We remain convinced that oil prices will trade in the $60, $80 per barrel range for the medium term, and then move higher as demands become constrained by supply.

Our goal is to maintain capital discipline and position the company with future growth to benefit from hygiene commodity prices.

Now, I will comment on the Downstream & Chemicals.

The TRCV margin indicator was down 64% sequentially to $12 per ton.

Refining margins were squeezed between increasing oil prices and the report demand, in particular from middle distillates.

Consequently, we decided to reduce refinery runs in Europe and the US.

So, our utilization rate was 84% compared to 88% in the second quarter last year.

Downstream-adjusted net operating income was $213 million in the second quarter, reflecting the poor refinery margins, and the less favorable environment for supply optimization.

Marketing adjusted well, even if demand was poor.

Despite the challenging environment, our strategy is to anticipate long-term market trends, and focus on increasing our middle distillate yield by investing our best refineries in Europe, like Leuna, Antwerp and Normandy, modernizing the Port Arthur Refinery on the US Gulf Coast, and building the new Jubail Refinery in Saudi Arabia to supply the Middle East and Asian markets.

Refining is a core activity for Total.

It is a cyclical activity, and we have the resources and the commitment to take the steps necessary to position ourselves for the recovery.

Moving to Chemicals, the story was slightly better there.

Compared to a net loss in the first quarter, Chemical posted net operating income of $97 million in the second quarter.

This improvement was mainly due to the successful cost cutting that we start last year as part of consolidation and restructuring plan.

We are also seeing the signs of demand recovery, particularly in Asia.

For Petrochemicals, volumes were slightly higher, but margin remained poor.

For specialties, the improved performance resulted from an increasing product demand during the second quarter from the very depressed levels we had at the start of the year.

For both Downstream & Chemicals, the environment will remain difficult until demand recovers to a more substantial level.

Particularly in this segment, we recognize importance of our ongoing cost reduction and optimization programs, so this will remain a high priority.

And finally, on the corporate side.

In May of this year, we paid the remainder of the 2008 dividend, EUR1.14 per share.

This brings the full year 2008 dividend to EUR2.28 per share, an increase of 10% compared to the previous year.

At its meeting yesterday, the Board of Directors approved the payment of an interim 2009 dividend on November 18 in the amount of EUR1.14 per share.

The ex dividend rate will be November 13.

For the [eight years], the ex dividend rate will be November 9.

Setting the amount of the interim dividend, the Board reiterated its confidence in the future of the company, while recognizing the need to be prudent in this still difficult environment.

In terms of our CapEx needs, it is too soon to say if we will spend our $18 billion budget this year.

CapEx costs are trending down, and the launch date for certain projects may be delayed as we continue to work through the feed and look for ways to improve efficiency and returns.

But other factors, like foreign exchange, may have a reverse effect.

On the subject of our stake in Sanofi, you can see that our participation was down to 9.7% at the end of the second quarter, and we are continuing to sell the share inline with our plan to monetize this position by 2012.

Ordinarily, the environment today is very different from the one that we had at the beginning of the year.

Our full demand has not yet recovered.

We are no longer in free-fall.

Regarding oil prices, they appear to be holding above $60 per barrel on average, and this is a fairly comfortable level for us in terms of managing cash flows, considering our CapEx dividend and divestment program.

OPEC has demonstrated the discipline necessary to ship up prices in their target range.

For Total, we have better visibility, and we are more confident now than we were in the first quarter that we believe it is wise to remain cautious.

We will continue to work hard on cutting cost.

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.

[Eli Bowman] from the Benchmark Company.

Please go ahead sir.

Hi guys, good afternoon.

Is there any upfront or entry payment associated with the Novatek agreement?

No, there is none.

Okay, thank you, that's all I got.

That's all?

Bye-Bye, Eli.

We now have a question from Mr.

[Teepen Chopalingam] from Morgan Stanley.

Please go ahead.

Hi, Patrick.

Just a couple of questions actually, firstly in the downstream.

Could you give an update on sort of what's the environment you're seeing in July, and what you potentially see as the utilization like through Q3?

Do you think you'll have to cut more rungs?

The second question is just on cost.

Firstly on Jubail, could you perhaps give a little bit of a breakdown on how you've managed to reduce those costs?

Was it -- they just raw materials, or was there anything else involved?

And on the cost question.

You provided a chart in February talking about the cost trends for the major components on CapEx.

I was wondering whether you could give an update on what you've seen so far in the first half?

Thank you.

Thank you, Teepen for your question.

On the Downstream environment, I will focus on Europe because this is where we are mainly.

Refining margin are currently very low between $10 and $15 per ton.

I think this morning, they were on $10 per ton.

In this environment, it might be interesting to reduce rungs again, and reduce our outflow from refineries, and we are studying that currently.

Obviously, the market is fully supplied currently.

There is too much product on the market, and there is too much production coming from the refinery.

So, we have the instinct to temporarily maybe shutdown units in some refinery.

That was your first question.

The cost in Jubail.

We unfortunately are not going to give you any detail in contracts that we have signed with contractors, but I can tell you that any particular contract, all contract has been reduced, and some of the contracts have been reduced by more than 40%.

In average, it leads to a cost cut by 25%, which is a tremendous amount of money.

It's a mix of things, but every line in the initial budget was cut very, very deeply.

And can you repeat your third question?

Yes, I was just wondering, you showed a chart in February of some of the cost trends for the components of CapEx, and looking at those LNG offshore pipes, I was just wondering if you had any data on how H1 has -- how the movements we've seen in H1 have progressed?

Okay, in terms of cost cutting, we launched a large cost cutting exercise, and roughly costs are going down.

You won't see that immediately on CapEx because there is a lag effect of maybe 18 months, something like this.

But we are already seeing that in OpEx.

Our OpEx costs are going down, and we anticipate that our technical costs for this year could be lower than the technical costs we had last year.

Currently, our technical costs are $1.00 per barrel below the average of 2008 last year.

So, we are seeing cost going down on OpEx, and for CapEx, do we see the effect in the forthcoming, I would say, one year to two year.

And of course, we will give you more detail in our September [or two].

Okay, perfect, thank you.

Thank you.

The following question is from Mr.

Jason Kenney from ING.

Please go ahead sir.

Hi there, it's Jason from ING.

Hello, Jason.

Just on the volumes if I may.

At the full year '08 results, you mentioned that the combination of Akpo and Tahiti could give you a 75,000 barrels a day net 2009.

You say there are 30,000 barrels a day net as of Q2.

What kind of contribution are we seeing in the second half?

And then, for the five key projects this year, in full year '08 results, you said they were at 230,000 barrels a day net in 2010, yet I think in earlier in your commentary today, you said only 200,000 barrels a day net for those five projects.

So, maybe just a bit of clarity there if possible?

I mean, see -- you know that Akpo and Tahiti will be at plateau at 4Q this year.

So, we will enjoy the full benefit of Akpo and Tahiti by the fourth quarter of this year.

And in aggregate, we've Tombua Landana started, Yemen LNG and Qatargas II.

I anticipate that the contribution of those projects for this year would be something like 70,000 to 80,000 barrel per day.

There is no change in that.

I did mention that the overall five projects, Akpo and Tahiti, Tombua Landana, Yemen and Qatargas II will contribute by 200,000 barrels per day in 2010.

That's the average contribution for 2010, but not the full plateau of production of those projects.

And the Akpo is -- will be a plateau at 225,000 barrels per day, Tahiti at 125,000 barrel per day.

In Akpo, we own 24%, in Tahiti 17%, I mean you just [transcend] a few years and I think you will find your way to do it.

I think the point of the question though was the -- and the full year results, you were thinking 230,000 there.

I mean, is it just the phasing issue here or is there a 30,000 barrels a day difference?

Let's say that it is between 200,000 and 230,000, I am not precise enough.

Okay, I've got a follow-up question if I may.

Can you just put some color around the resource and development task after they turn up the gas development and the Russian move, please?

Okay, I think the idea of Novatek was to bring the expertise of Total in developing a gas field, and that's the kind of joint venture we like, because we bring expertise, and they bring some resources.

And together, we can achieve to develop the field.

If you only restrict the comment on Novatek's [success], I like and I take this opportunity to make a comment on the Shtokman project, which is in Russia also, where we bring expertise with Total to the gastrom.

DFID is not for tomorrow, we will FID by 2011, something like this, maybe late 2010.

I am assuming more than it will be 2011.

But both are the evident that Total is moving forward to Russia step by step with no emergency, and try to bring its expertise to enlarge its exposure to Russia gas assets.

Okay, thanks very much.

Thank you Jason.

We now have a question from Mrs.

[Nalia Rainfall] from Oxis Capital.

Please go ahead, madam.

Hi, it's Lydia Rainforth from Barclays Capital actually.

Just in relation to -- you mentioned CLOV and Egina would be sanctioned next year.

Is that a delay from the original target?

And if so, how much are you hoping to save on those?

And then secondly, on my calculations of the volumes that you lost in the quarter looks like being lower margin than average for your portfolio.

Is that sort of a fair assessment?

Thank you.

Yes, on CLOV and Egina, currently we do not anticipate any delay, but as I mentioned to you, we are in a very strong and efficient cost cutting exercise.

And if and when needed, we did launch another bid, if we are not happy with the result of the initial bid.

I'm sorry but I'm not going to give you any date, any specific date for those two projects, but keep in mind that if needed, in order to reduce the cost, if we think that the cost and the prices quoted by the contractors are not good enough, we could launch a second deed to reduce the cost.

And could you repeat your second question?

Yes, just in terms of the production volumes were a lot lower, but in terms of the margins of barrels that you've had, I think it was improved relative for their group.

Were they low margin barrels that you actually lost the quarter?

Yes, mainly we are OPEC cuts are related to low margin barrels, and I think that's the explanation.

Okay, thanks.

And the same on Nigeria.

We lost some barrels in Nigeria due to security reasons, and those are low margin barrels.

Okay, and just longer term, given that those are low margin barrels, do you want to keep those in your portfolio?

Oh yes.

There is no -- every money is good to take everywhere, I would say.

Okay, thank you.

We now have a question from Mr.

Neil McMahon from Sanford Bernstein.

Please go ahead.

Hi, I've got a few questions.

The first is really when you look at your production profile, especially this quarter.

You've had significant effects from OPEC quota cuts etc.

Have you decided what's the move for Cobalt to really focus on non-OPEC countries to start thinking about exploring, and now to rebalance the portfolio?

And related to that, could you give us a drilling outlook for your joint venture with Cobalt this year and next, in terms of when the wells are going to be -- the exploration wells are going to be drilled?

Okay, the Cobalt venture we had, first of all I will make some comment, is that it is by doing this joint venture, we have knowledge the fact that we were not good in the Gulf of Mexico, that we need to team up with somebody having the ability to choose the right blocks, and to drill the wells in a way which could be successful.

The project with Cobalt is to drill five wells for the first year.

The first well has already started.

So, there will be five more wells in the coming year, and thereafter we will see.

I remind you that any blocks which will be taken by Cobalt, we will join them.

So, it's an ongoing business, I would say.

Okay, just in terms of maybe any comments on the US versus other areas, do you see your exposure to OPEC now being more of a problem from your production profile point of view than you may have done in the past?

Well, I don't see it as a problem, it is a fact.

It is a fact also that we are willing to enlarge our exposure to OECD countries like the US, where we are not.

And it is, I would say, a weak point that we would like to correct by being successful with the Cobalt joint venture.

Okay, just one, a real final one.

Maybe you could give us some reasonably specific quarterly startups for the LNG plants that are coming up this year, both in Qatar and Yemen, and when you think they'll -- both plants will be up to full capacity?

Yemen will start late August, beginning of September, and I think Qatar will -- and I follow the operator comments yesterday or this morning.

We'll start third quarter this year.

Great, thank you.

We now have a question from Mr.

Colin Smith from ICAP.

Please go ahead, sir.

Good afternoon.

I wondered if you could just comment on E&P, which actually despite the weak volume, seemed to perform very well financially compared to your peer group.

Just you mentioned a $1.00 a barrel less on technical costs so far year-to-date.

And I wonder if you could give us some guidance as to where do you think that might go for the balance of the year?

And the second question was just the pace of Sanofi disposal has been sort of quite variable quarter to quarter, since you've sort of committed to sellout by 2012.

And I just wondered if you could give us a little bit of insight into your thinking about the pace of quarterly sales.

Thank you.

Okay, I start with Sanofi.

I don't want to give a rate for the quarter because I don't want the market to anticipate my sale.

So, I am selling when I want, and the only objective is to have complete our sales program by 2012 late, and that's it.

It's happened that the market was favorable this quarter, and that we enjoy it, and we take this opportunity to sell large amount of Sanofi shares this quarter.

So, it is an opportunistic way to manage our sale and that's it.

There is nothing defined in advance.

As far as OPEC's per barrel is concerned, my estimate is that by year end, the technical cost should be -- in 2009, should be lower than the one we had in 2008.

But there is some foreign exchange effect that I do not control, so I have to wait until for the second half to be sure of what I'm going -- of what I was selling you.

Okay, thank you.

Thank you.

We have a question from Mrs.

Irene Himona from Exane BNP Paribas.

Please go ahead, madam.

Good afternoon, Patrick, I had two questions please.

First, on the Q2, I note that the tax rate on both chemicals and R&M has practically halved sequentially.

I wonder if we should anticipate a continuation of that in the rest of the year, or any guidance you can give us would be helpful.

Secondly, a more general question.

Your peer group is responding to the weakness of the environment with a combination of reductions in CapEx, cost cutting and now dividend cuts.

You are obviously working hard on CapEx and cost reductions.

Could you just remind us of how you approach something of the dividend policy, please?

Thank you.

Okay.

Coming -- starting with the tax rate for Chemical & Downstream.

Obviously, there is mixed effect.

I pretty well reviewed the Downstream and not so much on Chemical, so I will concentrate my comments on Downstream.

It's a combined effect of our trading group tax rate, and refining and marketing tax rate, so -- and it is difficult to anticipate.

Basically, we are paying less taxes in [trading] than we are in refining and marketing when we are making profits.

I'll remind you that some time in refining, we are losing money, which has guaranteed the status of our activity in refining.

Normally, it should be in the range of 30%, fisio.

That would be normal average sustainable tax rate for our activity in Europe I would say, and basically as you know, we enjoy global tax system in France, by which any income made in any country which is taxed at a lower rate than 33% is then taxed in France.

So, the average tax rate should be about 30%.

On dividend policy, you saw that the Board of Directors maintained the interim dividend at EUR1.14 per share, showing its confidence in the company.

You know that we are in a very volatile environment.

The oil price was at 35% beginning of the year, $35 beginning of the year, and it is now close to $70.

I think we are on the 31st of July, it's quite premature to anticipate anything for dividend which would be decided by the Board in February.

So, they do have time to think and to see what would be the environment at that date.

Okay, so just one supplementary one going back to trading and R&M.

Can you quantify this quarter the trading profit, please?

As usually, Irene, we do not comment on that, you know that.

Okay, thank you.

We have a question from Mr.

Jon Rigby from UBS.

Please go ahead sir.

Yes, hi, it's Jon Rigby from UBS.

I've got a couple questions.

The first is just on your production and production growth, because I don't think you were unusual in this, but if I look across the profile since perhaps 2004, it's basically been falls, not rises.

And the reason why I pick it up is that I think concept will have used this little growth, the Asia certainly I'd think you would like to place yourself there.

So, and production has not really risen as prices have risen.

It's not really risen as prices have fallen.

So, is there something structural that you got a problem with, or you can identify that's held you back?

Because it's not like you haven't had projects coming on stream in the last four or five years.

That's the first question.

The second is about Qatargas and Yemen.

Does the fact that you're an incumbent gas producer in the North Sea selling into the UK market come into the equation when you decide where you're going to take LNG cargoes, because presumably the price effects of LNG coming into the UK will have a knock on effect into your incumbent TMP position?

Okay, coming on your first question of production growth.

You've figured out correct, and the profit you figured out France since 2004 is correct.

There are many factors.

It is the combination of portfolio changes, of our larger pack exposure, and of course, for our large exposure in Nigeria, which cost us more than a 100,000 barrels a day.

On top of that, we had to face some kind of harsh nationalization, I would say, in Venezuela and in Libya.

Unfortunately or fortunately, we are not in OECDs, very little exposure in OECDs, and the result of that is what you have seen in our production profile.

Technically speaking, keep in mind that we have always delivered our project in due time.

And if there is any delay in any project in the forthcoming year, this would be because of the cost reduction process.

Right.

So, the underlying growth exists.

I'm sorry to say that again, but it exists.

So, it's more of an issue of the portfolio spread of your existing production as opposed to what you're adding into it over time?

Yes.

When you look at our portfolio, and the next project we are going to launch, you have Egina, CLOV, Block 32, Laggan and Tormore to be launched in 2010.

So, we have a bulk of new projects coming again.

And as I mentioned to you, the project which will be launched this year, or which are already launched, which are Akpo, Tahiti, Tombua Landana, Yemen and Qatargas II.

We considered by 200,000, maybe 230,000 barrels per day next year.

So, I hope that we will not going to face any new adverse effect from anything that are not in our control, that we could show again growth of production.

Right, okay.

Okay, thanks.

And on LNG and whether you have any commercial thoughts there where you would take it as it interacts with the rest of your portfolio?

It obviously interacts, and we see the gas prices in the UK as low as in the US currently.

What you -- and we saw gas demands going down, and we were reduced by lower gas demands, by something like 1% of our production this quarter.

So, we see some effect.

And the UK gas price is an anticipation of the coming LNG cargoes.

So, we see obviously the effect of this LNG project coming on stream.

Keep in mind also that even due to the low cost base of those projects, even with gas price in the UK or in the US between $3.50 and $4.00 per million Btu, both Qatargas II and Yemen LNG are still profitable.

Right.

And this is -- sorry, just as a follow-up, this, the low UK gas price, the summer encouraged you to do more maintenance, suddenly you found a bit more painting to do on the platforms and so on?

Because the volumes are just not worth producing or not producing as aggressively as you might have done before?

We haven't planned it like this, because we did not anticipate such a big drop in gas price now.

Fortunately, we have large maintenance when the gas price is low, but this is by coincidence.

Just coincidence, okay, thank you.

Sorry to be honest.

No worries.

(Operator Instructions).

Question from Mrs.

Kessler Roberts from Simmons and Company.

Please go ahead.

Hi, thanks, it's Robert Kessler.

Just a quick clarification, Patrick, on your $3.50 to $4.00 LNG profitability requirement.

Just if I recall correctly, that includes some return assumption.

Is that right, and any thoughts on producing in between the cash cost, which I would assume is much lower in that figure, which includes the return requirement?

Yes, this includes the return requirement.

At $3.50, $4.00 per million Btu, the IRA of our project are above our threshold rate.

And you would produce even if you did not match that return requirement, is that right?

I think I have never seen an LNG plant put on hook because the gas price is low.

So, I have no experience of that.

Great, thank you for that.

And then, just a quick -- any additional comments on the chemicals demand?

I was interested in your commentary there and some bottoming in the Asia Chemicals.

Is there any restocking effect or would you expect that to be a sustainable improvement?

Well, I am not the chief economist of DINF or whatever it is.

From what I see from some business located in Asia, we saw Asia starting again.

This is true for petrochemicals, and we see that through our joint venture with Samsung in Korea, where we are selling product in China.

So, there is a slight recovery, but there is a recovery.

And the same, we noticed that with some specialties, we see some slight recovery or some recovery in Asia for the raisings and the other specialties.

Great.

Thanks for the additional color.

The following question is from Mr.

Bertrand Hodee from Kepler.

Please go ahead, sir.

Hello, gentlemen.

I have a question about your neutrality cash flow point for 2009.

At the beginning of the year, you expected to be value cash flow neutral at $70.

Obviously, it was under I guess a higher downstream and petrochemicals expectation.

Where do you see your cash flow neutrality point in 2009 if downstream and chemicals stay weak, as they are today?

Currently, we see -- and I can tell you, we monitor it very carefully on a monthly basis.

Currently, we see refining margin as the Chemicals, but keep in mind that the chemical are getting better today, yes.

With the refining margin, our breakeven cost price is between $70 and $75 per barrel.

And I'll remind you that we can sell Sanofi shares, and that's something like EUR2 billion of Sanofi shares per year, which would be roughly our rate of selling Sanofi shares, is lowering our breakeven cash by $15 per barrel.

Okay, I have a follow-up.

This is a $75 or $70, $75 range, your earmark is totally inline with your Q2 achievement if we exclude this very negative working capital movement.

Is there something special with this minus 2.4 cash flow impact negative in Q2?

It is partially coming from supply optimization, and from high oil price, which increased the cost of our inventories.

I think that's it.

If the oil price remained in the range of $60 to $70, the working capitals are not move too much next quarter.

Okay, thank you very much.

Thank you.

We now have a question from Mrs.

Kim Fustier from JP Morgan.

Please go ahead, madam.

Hi, good afternoon, gentlemen, I have two questions please.

Firstly on Nigeria, you said you'd like to keep low margin barrels in your portfolio, but obviously Nigeria has been a serious drag on your production.

So, under what scenario would you consider exiting onshore Nigeria, and can you still be involved in LNG and [Tipo] if you're not in the onshore?

And secondly in Iraq, what's your thinking around access to Iraq and the second bidding round?

I think you bid unsuccessfully for West Kerna in round one.

So, can you give us some color on your intentions there?

Thank you.

Okay, on Iraq, it is obvious that Iraq is a very important country for us.

We were unsuccessful, but I would say many people were like us.

And I am not sure the successful one is the one you think.

The commercial terms offered by the Iraqis was not acceptable by the industry, and therefore, the bidding process was not a success for the Iraqis.

And it is unfortunate because I think the industry can bring a lot to the country.

And we are still interested, and we are still continuing to discuss things with the Iraqis, like I think other companies are, we are not the only one doing so.

On Nigeria, there is a huge potential on onshore, and on offshore.

You cannot forgive an asset like this, just because you are facing difficulties at one point in time.

Yes, we are facing difficulties.

Production is going down onshore, and [shales and net] are suffering a lot in our production profiles due to that.

But we still maintain our interest for these offshore assets.

Also, I'd like to remind you also that most -- all of them, of our new project are offshore.

Right, thank you.

We now have a question from Mr.

Herrmann from Deutsche Bank.

Please go ahead, sir.

Thanks very much.

Afternoon, Patrick, most have been answered, just one left.

You described your dividend policy at the start of the year as one of being competitive growth.

Do you feel that that policy is -- clearly environment's important, but do you feel that policy is still intact?

It's obvious that if you have a look to a figure like this, we are facing a difficulty, which is because of effect which are -- of action which are not in our control, OPEC, Nigeria, price effect and so on.

I repeat what I mentioned.

We are delivered all power project in due time, and the underlying growth is there as scheduled.

Unfortunately, they are external effect.

Sorry, is that -- so, should I start worrying much more about a policy of competitive growth, whatever in your dividend surrounding your ability to control or otherwise your production?

Sorry, I was thinking about our policy to increase the growth of -- to maintain the growth of production.

So, on dividend, we have to deal with the environment.

You -- our payout ratio today is 66%, we can live with that for a certain period of time.

And it is still our target in average to increase our dividend, and this policy remains.

If you compare us to some US companies, they have low payout ratios, so they can increase their dividend, even in most current situation.

Where for us, we have a 66% payout where the US companies are more in the 50s.

It's more difficult for us currently, I acknowledge that, Lucas, but we -- if you follow us, and believe that there will be a recovery, and that the oil price will rise again in the forthcoming years, you will see this policy maintained.

Okay.

Patrick, thank you very much.

Thank you, Lucas.

We have no further questions.

(Operator Instructions).

Thank you.

Maybe we can make a closing comment prior everybody's leaving.

Just a few comments that on a year-on-year results show that we are quite resilient.

I would say very resilient and competitive with our bills.

In this challenging environment, the announcement of the incurring dividend confirms our confidence in the future, and I stress I would our strong words and ease our balance sheet today.

Second in term of operation, we are delivering five major projects that we say would start up this year, and I maintain that.

In the second quarter, Akpo and Tahiti contributed again by 30,000 barrel per day net to Total.

And a year from now, all those five projects will contribute by 200,000, 230,000 barrel per day.

And at last, I'd like to reassess that we are continuing and pursuing an important program of cost cutting and project optimization.

Of course, in mid September, we will give you more color on our strategy.

Bye-bye, everyone.

Ladies and gentlemen, thank you for attending.

You may now disconnect.