TotalEnergies SE (TTE) 2009 Q1 法說會逐字稿

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

I now hand over to Mr.

Patrick de la Chevardire, Chief Financial Officer.

Sir, please go ahead.

Thank you, this is Patrick speaking, and as usual, I will comment rapidly on the first quarter results 2009 and then go to the Q&A.

In the first quarter 2009, the environment was weak with a drop in the oil price and weak demand for refined products and chemicals.

From that perspective, our performance was very resilient and good related to our peers.

Adjusted net income was $2.8 billion, a decrease of 44% compared to the first quarter 2008, and 27% compared to the fourth quarter.

Earnings per share was $1.23 per share, a decrease of 43% compared to the first quarter 2008 and 27% compared to the fourth quarter.

Among the other major oils, BP, Chevron, Exxon and Shell, earnings per share declined on average by 60% year-on-year, and 40% compared to the fourth quarter.

In terms of profitability, the ROACE for the past 12 months was 24% and the annualized first quarter ROACE was about 15%.

This is clearly at the best level, when you compare to our peers.

In this weak environment, it shows the strength and the sustainability of our model.

In times like this, we are focused on managing our cash and gearing.

Excluding acquisitions, CapEx was $3.6 billion in line with Q1 of last year.

Asset sales were close to $500 million, mainly from selling Sanofi shares.

Free cash flow after CapEx and asset sales was $2 billion.

We did not make any buy-backs in the first quarter.

As a result, our gearing at the end of the first quarter was 19% compared to the 23% at the end of the fourth quarter.

We issued bonds three times during the first quarter raising more than $4 billion to refinance some debt at attractive rates in the current environment, and for longer maturities.

Another point is that the impact in the fall in the stock market on our pension plans is not significant, less than EUR100 million of an overall cash contribution in 2009.

Our exposure to the US and UK is limited, and in fact, most of our pension assets have been invested in bonds.

Now I will make some brief comments on each segment.

In the Upstream segments the average Brent price fell by 20% to $44.50 per barrel and our average hydrocarbon realization including natural gas fell by 18% to $38.80 per barrel for oil equivalent.

We have low exposure to the US and this works to our advantage, particularly in terms of natural gas prices.

Compared to Q4 2008, adjusted net operating income from the Upstream segment decreased by 27% to $1.9 billion, mainly due to the price decrease.

Compared to the other majors, our Upstream portfolio is resilient.

Our net income per barrel of oil equivalent is at the best level.

And our Upstream ROACE was 31.2% for the past 12 months, and 17.5% on the annualized-basis which is also among the best.

Another positive point is our exploration success, which is key to our organic growth strategy.

Exploration expenses were $226 million in the first quarter, a decrease compared to the same quarter last year, and also to the previous quarter.

Also, we slightly spent less money.

We were in fact very successful in terms of finding new reserves.

We have just announced the discovery of more of Moho Nord in offshore Congo that is close to being a new giant field.

In addition, we have made other discoveries, but they are not public yet, notably in South America and North Africa.

Operationally, production was down by 1.4% or about 30,000 barrels per day compared to the fourth quarter 2008.

The main reason is OPEC cuts.

The impact on us was 90,000 barrels per day in the first quarter compared to 15,000 barrels per day in the fourth quarter 2008, a comparative decrease of 75,000 barrels per day.

So the OPEC cuts alone represent a decrease of more than 3%.

I should remind you that on average, these are not high margin barrels.

It is important to know that the impact on net operating income from the OPEC cuts was less than $50 million.

There were many of the right ends positive and negative that have a combined affect of increasing production by about 1.5%.

Mainly, these were the price affect plus underlying growth from ramp-ups and the restart of Al Jurf in Libya.

What can we expect going forward?

In March, we started up the Akpo field in Nigeria, which is expected to reach full production of 225,000 barrels per day late this summer.

Second quarter maintenance compared to the first quarter will be seasonally higher and include the 30-day shutdown of Alwyn.

We have just announced the start-up of Tahiti and in the coming weeks, we should have Yemen LNG.

And later this year we should have Tombua Landana and Qatargas II.

So excluding the OPEC cuts, I am confident about Upstream production volumes.

In addition to new start-ups in 2009, we are continuing to secure opportunities for future growth.

Last month, we announced a deal with Cobalt to jointly explore the deep Gulf of Mexico.

Cobalt has an established track record of discoveries in the deep Gulf.

They will operate the exploration phase.

We have five very interesting subsalt prospects and we will begin drilling this year.

This has also been a good quarter for us in terms of existing production.

We signed a very important 20-year extension for Gasco in Abu Dhabi.

We also renewed contracts in Libya and signed a ten-year extension for concessions in Argentina.

And also, we signed a head of agreements with Japanese buyers to extend some contracts for Bontang LNG.

Of course, we do not get everything that we go after.

I am referring to our bid for UTS in Canada.

At the end of the year period, we did not have the participation that we wanted.

This was our last and final bid, so we close it.

This is proof that we are consistent with our discipline.

The Upstream segment is strong.

We have a high-quality portfolio in producing assets that will develop when oil prices were below $50.

You may recall from our presentations in February, that our cost per barrel of oil equivalent is lowest among the majors.

Nonetheless, we have launched a major cost reduction program in the Upstream.

We can already see the first affects of lower price for materials and services on our costs, as well as the affect of our own efforts.

Our first quarter 2009 OpEx as per FAS-69 has decreased by more than $1 per barrel of oil equivalents compared to the average of last year.

We should be able to give you more details on our progress when we report on the second quarter, so I am confident again that the Upstream is adjusting to this environment and facing the challenge.

Now I will comment on the Downstream and the Chemicals.

The main point is that weak demand in the first quarter had a severe negative impact.

Downstream net operating income was $0.8 billion down 23% from the fourth quarter.

The fourth quarter included the lag affect on the marketing side that we did not have in the first quarter and this exaggerated the decrease.

The TRCV margin indicator was down 16%, throughput volume was down by 6%, mainly because of higher turn-arounds for maintenance, and our big decision to shutdown the [Coof] refinery in March because of very depressed margins on the Gulf Coast.

These negative effects were somewhat balanced by good resistance of marketing and a strong heating oil season.

Plus very favorable market conditions for supply optimization at the beginning of the quarter that increased net operating income by more than $100 million compared to the previous quarter.

Chemicals, however, were hit even harder than Downstream.

Chemicals had a net operating loss of $42 million in the first quarter, compared to net operating income of $233 million in the fourth quarter.

Base Chemical margins fell below breakeven, mainly due to a lack of demand.

Normally, the contribution from our Specialties would provide some cover, but our Specialties are leveraged to automobiles and construction, so they also suffered from weak demand.

We are consolidating our refining and base chemicals and concentrating our activities at our best sites.

In March, we announced plans to invest more than EUR1 billion to upgrade our refining and petrochemicals in France.

As part of this plan, we will reduce scheduling production by eliminating 4 million ton per year of European distillation capacity when we close down some units.

And further upgrade others at the Normandy refinery.

In January, we started up what is now of Europe's largest and most efficient styrene units at our facility in Gonfreville after a very significant revamping And expansion program.

On the corporate side, at the Annual General Meeting next week, we expect the shareholders to oppose a EUR1.14 per share remainder of the 2008 dividends for payment on May 22.

The next dividend date for the ordinary share is May 19 and the next dividend date for the full year is May 14.

If we annualize the first quarter results and consider the 2008 dividend.

This will imply a payout ratio of about 60% and the yield is guaranteed above 6%.

It is important to note that in the first quarter, Total was net cash flow positive after CapEx and after a theoretical dividend allocation through the quarter.

On CapEx, the budget for this year is $18 billion.

Falling costs and potential project delays may allow us to spend less.

However, there could be new opportunities to add.

What I can tell you now that we are working hard to optimize the development cost of all our pending projects.

I think we will be able to do more with less.

We will provide an update in September.

Since the end of the quarter, oil prices have fluctuated around $50 per barrel, slightly higher than first quarter 2009.

Refining margins are depressed in Europe and chemicals continue to suffer with weak demand and low margins.

While we do not know how long it will take for the global economy to recover from this recession, we are pursuing the strategy to emerge from this period as an even stronger player.

More than ever, we are prudent and very disciplined.

We are implementing cost reduction programs and will continue to divest non-core assets.

We will invest through the low end of the cycle to capture good opportunities.

Our intent is to maintain gearing in the 20% to 30% range and we are committed to the dividend.

And now I think we can go to the Q&A.

(Operator Instructions) We have the first question from Mr.

Theepan Jothilingam from Morgan Stanley.

Please go ahead, sir.

Hi, good afternoon, Patrick.

Good afternoon, Theepan.

Just a couple of questions, actually.

Firstly, with the expiry of your offer for UTS, I wondered if you could make some comments on sort of what the next milestones are in developing your heavy oil business in Canada.

And secondly, just in terms of, I think you talked about maintenance in the Upstream for Q2, I was just wondering whether you could give any indications on what you expect in the Downstream.

And then lastly, just on the corporate tax rate, with the lower oil prices clearly that's been coming down.

At a sort of $50 environment for this year, would you -- what would you sort of anticipate that tax rate to be?

Would you, you know, are we looking around the 52% mark?

Thank you.

Okay, first question about our Canadian strategy, I mean, what happened to UTS it's over.

We continue on the Joslyn project to reengineer this project in order to mitigate costs and in order to be able to make a decision to invest in this project by, let's say, 2010.

On Surmont phase 2, we are working together with the operator in order also to reduce costs.

Basically, I would say that our overall objective is to produce by 2020 something like 150,000 barrels per day in this area of the world.

That was for the Canadian question.

On the maintenance in Upstream for second quarter, usually the second quarter maintenance is higher than the maintenance in the first quarter, as you know.

On top of that, as I mentioned in my speech, there will be the shutdown of Alwyn.

And those are, I think, the two elements you should consider.

On Downstream maintenance, I think we have two refineries having some maintenance during the second quarter, namely Donge and I really don't remember the other one, and it's in the UK.

For the corporate tax rate in this $50 per barrel environment, I think you were right with the assumption you made.

In Q1 it was due to the fall -- the tax rate was due to the fall of the oil price.

When the oil price is lower, the tax rate is lower.

Your estimate of the potential tax rate of the group was correct.

Great, thank you.

Thank you.

The following question is from Mr.

Jon Rigby from UBS.

Please go ahead, sir.

Hi, Patrick, it's Jon Rigby from UBS.

Hi, Jon.

Hello.

Two questions.

The first is on the Downstream, can you go into a bit more detail and sort of characterize what the exit conditions were in March or perhaps even just sort of compare January to March so we can get a better idea of what the shape of the quarter was in the Downstream around your TRCV, the marketing performance?

And the second question is, it goes back to the comments you made about startups and confidence for the outlook on production.

I mean, obviously your production has been up and down, positive and negative, and a lot of that's been impacted by OPEC and maintenance issues, etc.

But also one of the key drivers is also your ability to drive growth above decline.

So do you see that growth above decline or new additions above decline increasing significantly over the next three quarters or the controllable element of your Upstream business improving?

Thanks.

Okay, your first question about refining margin.

What we saw during the first quarter is that in January and February we had pretty good margin, let's say between $40 and $50 per ton -- the TRCV.

So pretty good margin.

And both margins were falling completely in March, down another rate of about $15 per ton.

So this gives you the shape of the curve.

Coming back on the production, something you have to keep in mind is that on this first quarter, we had no startup for production.

As both started in April.

The second comment I would make is that you know that we are more exposed to OPEC than the others.

Yes.

If I look at our program of launching projects in 2009 this year, we should be able to beat the decline.

Right.

And then we can make our own minds up about OPEC effects, etceteras.

Yes, well, OPEC is -- they decide by their own and then that's it.

Keep in mind also that when we were cut by 90,000 barrels per day by OPEC this quarter, this only has an effect of $50 million on the bottom line, because those margin -- those barrels are low margin barrels.

Okay, useful number, thank you very much.

Thank you.

We now have a question from Mr.

Mark Gilman from The Benchmark Company.

Please go ahead, sir.

Patrick, good afternoon.

I had a couple of questions.

First, with respect to the downstream restructuring which you referenced in France, it has almost seemed to me given the government's rather harsh reaction to this announcement that there may be some quid pro quo with respect to your involvement in -- your involvement with Electricite de France in the nuclear power segment.

Is that an accurate characterization of the way the relationship with the government is working?

I mean, when we decide our restructuring and modernization of our refining and the petrochem sector, we decide it on our own and that's it.

This has nothing to do with any approval, prior approval by the government.

Of course, when the decision was made, we make the announcement to the government so that it is aware of it.

But we were not asking for any approval for that.

And our participation in the nuclear power plant, it is the first move of a long-term strategy which is to try and step-by-step increase our exposure to this nuclear sector.

Okay, let me follow up if I could with just two others.

Could you give me an idea where things stand with respect to the negotiations to extend the East Kalimantan concession in Indonesia.

Also, could you address the liquefied natural gas LNG realizations which you had during the quarter, either in absolute terms or relative to prior periods?

Thanks, Patrick.

I mean, for the extension of [Vama] account we have started the discussion.

I remind you that the expiry date is late 2017 so we have time to discuss that.

And I think there was -- the first initial talks started in 2007 if I will remember.

I think things are going smoothly in that respect and I am not particularly concerned about it.

And the LNG price realizations?

Let me see.

This is a difficult question.

What --?

That's why I asked it.

What you should know is that -- I'm sorry, I don't have the figure, but what you should know is that for our LNG mainly produced, for instance, from Bontang, we have large lag effect for three to four months because all those formulas are related to or tied back a quarter about.

Is the lag for your other LNG deliveries and the price realizations comparable to that three to four months, say for an LNG in Nigeria?

I don't think we can say exactly the same.

There is a lag effect, but I can't tell you if it is three to four months, but there is one.

Okay, thank you Patrick.

Thank you.

We now have a question from Mrs.

Lydia Rainforth from Barclays Capital.

Please go ahead, madam.

Thank you, good afternoon, Patrick.

It's Lydia Rainforth from Barclays Capital here.

In terms of the cost savings, I think you mentioned a $1 per barrel cost saving compared to last year.

That's quite a significant saving.

Can you just talk us through how you achieved that so quickly and how much further you see costs being able to come down?

And then secondly, just going back to the sort of timeline on the natural gas realizations, are you able to quantify what sort of impact that had on your upstream profitability this quarter?

For the cost reduction, I mean, the action to reduce costs started late last year.

And as I mentioned, I think the actual effect of the environment and of our cost program reduction was about $1 dollar per barrel of cost reduction.

And we can measure it, and we saw it in the first quarter.

And I can tell you that there is no one in this [company] who is not working on cost reduction.

Everyone is dedicated to that.

Great.

Second question was again on LNG realization.

I think what you should and -- what you should know is that the average gas price -- this quarter the average gas price was roughly at oil parity, if you take both LNG and gas price.

Okay.

And just going back to the cost saving data, I mean, if you've achieved $1 per barrel so far, what do you think you can achieve by the end of the year?

Is it $2 per barrel, $3 per barrel, or is $1 per barrel sort of where you think it will end up?

The objective, and everybody is working on this objective, is to reduce the operating cost of the upstream segment by $850 million.

Okay, great, thank you.

Thank you.

The following question is from Mr.

Jason Kenney from ING.

Please go ahead, sir.

Hi, Patrick, Jason from ING.

Hi, Jason.

Just following up on an earlier question on the TRCV, you mentioned January, February, and March, you may as well give us some detail on April, I suppose, if you can.

And then secondly, on the equity in income and affiliates and other, I can understand the Upstream/Downstream division a bit, but the corporate part of that was quite strong.

I was just wondering if you could maybe give some color on that one.

Your line was very bad actually, Jason, but I understood the first question.

The TRCV in April is in line with the one, unfortunately, with the one we had in March as of today.

Okay, the second part of the question was on the equity affiliates contribution in the quarter, wanted to understand the corporate part of that.

Okay.

Sanofi made very good results, and I think that most of the equity impact we had this quarter.

What's kind of the repeatability of that kind of support?

You know we are selling Sanofi shares on a daily-basis, so gradually the impact of the Sanofi net income on our result will go down.

And on top of that, it is difficult for me to comment on Sanofi as I am a board member.

Okay.

We now have a question from Mr.

Paul Spedding from HSBC.

Please go ahead, sir.

Hi, good afternoon.

Two quick questions.

Firstly, in terms of the cost cutting you're seeing coming through is there any evidence yet that you are seeing the cost for deep-water rigs and subsea work beginning to come down?

And the second question is on demand trends, whether you're seeing any stabilization in the weakness in demand for refined products or for the chemicals?

On deep-water rigs, what we see is some contractors are able to extend the duration of their contract at the lower rate, coming from about $700,000 per day down to something like $500,000 a day.

For the demand, very frankly speaking as of today, and I am discussing this matter with our people from the supply, we see eventually going up again.

So it seems that the market, there is another overflow for oil in the market currently.

That's what we saw at least until late March.

You should remind, remember that the inventories are product plus oil, are up to 60 days of consumption today where OPEC target is at about 53 days of consumption.

So 60 days is a very high number.

And in chemicals?

And in chemicals, currently what we see is that the capacity is used at about 80%.

Thank you very much.

Thank you.

We have a question from Mr.

Ian Reid from Macquarie.

Please go ahead sir.

Hello, Patrick.

I have two questions.

Firstly, I think you talked in the Downstream part of your speech about supply optimization about $100 million.

Can you confirm that this is effectively a trading gain due to a Contango affect and it will be less repeatable with a flatter oil curve going forward?

And secondly, on your LNG volumes, you have say a 9% decline year-over-year.

Can you say what the reason for that was?

Was that a function of the market or the customers not taking or was it some plant related shutdowns?

On trading, your assessment is right about the Contango and it is less repeatable now.

That's why we make it clear to the market the figure is like not normal I would say.

On LNG, the main decrease is due to Nigeria LNGs because [Nigeria was aware] of some unrest and Nigeria LNG was not running at full capacity.

That is most of the explanation.

Can you just say what the situation is on the Bonny at the moment?

Is it coming back up to full capacity again or is it still running at lower capacity?

It is ramping up.

People are working to reestablish the pipelines in order to feed the plant.

It is ramping but it is not at full capacity today.

I can't tell you how much they are today but the ramp up is quite slow actually.

Okay.

Thank you very much.

Thank you.

The following question is from Ms.

[Katie Risen] from Sanford Bernstein.

Please go ahead madam.

Hi.

Good afternoon.

I just wanted to ask quickly, have you seen any knock-on delays in Qatargas Train V from the delays we saw in Train IV and can you give an update of when exactly you're expecting it to come online, later in the year?

And then secondly, just going back to the Downstream, what is your outlook for the European diesel margin this summer and what's the risk of lower utilization having a knock-on effect for potential gasoline export to the US in the summer?

On the first question on Qatargas II, actually in Qatargas II we are still lengthening our project to have our train starting by late this year and for further details you should ask the operator.

Okay.

But we are expecting and we believe this startup will take place probably at the end of this year.

Thank you.

And on the impact for lower utilization in Europe this year because of diesel margins, do you think that's going to have a knock-on effect for gasoline export to the US?

What we saw for the last few years actually the gasoline demand in the US was not as bad as what we initially sold.

So it might be that, well I can't be sure of that, it might be that we will be able to again export gasoline to the US.

But this is very premature and I will not rely on it.

Okay.

And then finally, can you just confirm what you're Sanofi stands at the moment?

We are at about 8%.

Great.

Thank you very much.

Sorry, 10%.

Okay.

Thank you.

We now have a question from Mr.

[Herman Vickers] from Deutsche Bank.

Please go ahead sir.

Patrick, hi.

It's Lucas Herrmann actually from Deutsche Bank.

A few if I might.

Just going back to costs quickly, just to make sure I understood, were you talking about the running rate being 850 million at the year end or by year end, or were you talking about 850 being the actual achievement?

And either way, given you're producing about 800 million to 850 million barrels a day and you're telling us that a dollar is basically what you've taken out production costs so far, the objective doesn't seem unusually ambitious at this stage given what you've achieved to date.

Staying on cost and the environment, CapEx, I just wondered if you can give me some better guidance on the phasing of CapEx.

Again, if I look at the run rate through the first quarter it's clearly well below $18 billion for the year and given that the majority of the projects drop out through the next three to six months the question becomes how realistic is 18 billion or so dollars of CapEx spend for the year as a whole at this moment?

Well, on cost the $850 million figure I gave, again, was for operating activity on the full-year-basis.

On CapEx, the figure you show for first quarter '09 was the same than first quarter '08.

So the realization is quite comparable to the one last year.

And last year we roughly matched our budget.

Nevertheless, thanks to cost reduction and to the fact that when you want to push the cost down you take time to renegotiate the contract with the contractor.

It might be that some projects will be pushed in the agenda.

So in [Treaty V] I would say that there is a probability that the overall budget is not matched.

But it will be for a good reason.

Okay.

So we should view your 850 million target as being, on cost savings, as being pretty conservative at this stage given what you've achieved to date?

Yes.

Yes.

That's great.

Thanks.

I have a question from Mr.

Mark Gilman from Benchmark Company.

Please go ahead sir.

Patrick, just two follow-up questions if I could.

On the joint venture with Cobalt in the Gulf of Mexico, did any cash change hands as a result of the formation of that venture?

Could you repeat the question?

Was there any what?

Yes.

Did any cash, did cash change hands, either a payment by you or cash which you received in the formation of the joint venture with Cobalt?

It works by carry.

I'm sorry?

It works by carry.

We will carry Cobalt partially on the new wells to be drilled.

How long did that carry continue or how many wells, Patrick?

I think we are five wells to be drilled prior -- in 2010.

Okay.

One other question on Libya.

Can you give me an idea what the production volume impact of the conversion to EPSA 4 was based upon current producing rates and what the $500 billion payment for the year, a conversion and extension of the contract, was that made in the fourth quarter or the first quarter?

Can I ask you to refer to the IR, because I don't have the exact figure with me.

Thank you, Patrick.

Thank you.

I have no more questions at the moment.

(Operator Instructions) We have a question from Mr.

Neill Morton from MF Global.

Please go ahead sir.

Hi there, it's Neill Morton from MF Global.

Just one question left for me.

These new Venezuelan heavy oil projects seem to be moving slowly towards a conclusion.

Can you perhaps give us an indication of when you expect a timing of an award?

Could you perhaps confirm that you are in talks with the Chinese and also what sort of oil prices do these projects need to find economically?

Thank you.

On both Venezuelan projects I can confirm we are in talks with some Chinese parties.

The partnership is a key element of the strategy of Total.

So we are currently discussing with [SMP].

But nothing is confirmed at that stage.

That agenda, the exact agenda for discoverable project, I'm sorry I don't know it exactly.

I don't know when the Venezuelans will award these licenses.

And for economics for oil prices required, etceteras.

I mean, this must be depending on our price and we are currently making the rest of these to prepare the bids, so it's a little bit too early to say what is the profitability of that.

Okay.

I'll leave it there.

Thank you.

Thank you.

We now have a question from Mr.

[Jean-Luc Romain] from [Tribby and Company].

Please go ahead sir.

Mr.

[Romain] you have the floor.

Sorry I didn't quite hear.

It was not pronounced the way I'm used to hearing it.

Are you finding that your trading activities in terms of the trade embargos and whether crude or product are more profitable in these times or have they simply been not produced as a profit center, but simply as more of a defensive center in these times?

The supply team is completely integrated in the Group.

It is in charge in selling the position of the Group and to the supplier or refineries.

It has been this quarter particularly profitably because of the Contango, as it was mentioned by one of your predecessors.

But that is the overall [extra] income made by those people was about $100 million for the quarter.

Thank you.

I also had one other question on the (inaudible) that fluctuates rather strongly and I was wondering as to whether your firm had found it's tanker position and working to its advantage or whether it had been in fact having too large a tanker position and therefore it had been hurt by the current volume metric, and changes?

What I can tell you is that I follow quite carefully being also in charge of the shipping the visit made by all the fleet and currently it is a slightly positive income.

So our exposure is I would say something less than half of our needs and it is quite balanced.

Got it.

Thank you so much.

Thank you.

I appreciate the help.

Thank you, Jean.

The following question is from Ms.

Irene Himona from Exane BNP.

Go ahead madam.

Good afternoon, Patrick.

I have a number of questions.

First of all, I think you mentioned that you're cost cutting applies to operator production.

Could you just remind us how much of your volumes is operated?

My second question concerns Argentina.

I think you referred to it in your prepared remarks.

Argentina is 2% to 3% of your volumes but can you say something about the financial results of your Upstream business given the high export taxes and low local prices?

The third question concerns minorities.

It's a very small number but in Q1 there was a 63% drop in the minority on the P&L.

I wonder if there was something special or whether the trend will reverse?

And my final question concerns your comments about the inorganic root to growth.

In Q1 obviously we were at a low point in the energy cycle, $45 oil, loss making chemicals, you ended up with gearing below your targeted range, $13 billion of cash, you're delivering free cash flow.

Can you just remind us of your criteria for M&A in terms of portfolio gaps, potential size, and caps, hurdle rates?

Thank you.

Okay.

Your first question about cost cutting, we are operating about 50% of our production.

I moved directly to the inorganic growth, as you call it.

Currently we are facing a world where many people are still thinking in a world of $80-plus barrel scenario.

And they are not ready, I mean UTS is one example, they are not ready to accept an offer based on $50 per barrel.

Nevertheless, we continue and review potential targets.

There are many of them.

I am not saying we will do something, I am just saying it is normal business to do so.

And there are many areas where we have some gaps to be filled, namely Canada.

Unconventional gas, Gulf of Mexico as we did tie with Cobalt, if a new opportunity in Brazil of course that's -- maybe other like in Australia, there are many potential areas where we could be interested in.

But the main question is the seller even thinking in an $80 or $100 per barrel scenario, there is no transaction visible.

On the Argentina reserves, the (inaudible) is slightly below the other rate of the portfolio, but not so bad.

But you know that usually we do not comment country-by-country, but the cost are very low in Argentina, everything is good.

And this time the size of the gas is sold at quite a low price.

The 60% drop on our minorities mainly come from Total Gabon.

Thank you very much.

Welcome.

We have a question from Mr.

Robert Kessler from Simons Company.

Please go ahead sir.

Hi Patrick.

A couple of clarifying questions if I could on the OPEC exposure.

Of the 90,000 barrels a day effect for the first quarter, were there very many of those barrels in Angola, in particular?

And then secondly looking forward at the second quarter, any thoughts on your part with respect to the likelihood of that curtailment?

Obviously, we have to be able to project OPEC volumes through the quarter but I'm more interested in the ratio of your share of the OPEC curtailment.

In other words, was there any extra catch up in the first quarter that would not persist into the second quarter?

Very frankly speaking, I am strictly unable to assess what would be the next decision of OPEC.

On Angola, on the 90,000 barrels per day, Angola represents something like 20,000 barrels per day.

The other country being Libya, Nigeria and Abu Dhabi.

Okay.

Thank you very much.

Thank you.

We have no questions at this time.

(Operator Instructions).

We have no further questions.

Thank you very much all of you.

Ladies and gentlemen, thank you for attending.

You may now disconnect.