TotalEnergies SE (TTE) 2010 Q1 法說會逐字稿

Welcome to Total's first-quarter 2010 results conference call.

I will now hand over to Mr.

Patrick de la Chevardiere.

Please sir, go ahead.

Thank you.

Hello, everyone, and thank you for calling on a Friday afternoon.

First, I will comment on the results, and then we will go to the Q&A.

I will not take too much time on the first-quarter environment.

Globally oil was trading around $75 per barrel, but supplies of gas remain low, and the refining environment was still difficult even if margins recovered.

Looking at the first-quarter results compared to the fourth-quarter '09, production was 2.43 million barrels of oil equivalent a day, an increase of 2.1%.

Adjusted net income was $3.2 billion, an increase of 3% compared to the fourth quarter, and I would remind you that Total was among the most traded (inaudible) companies in 2009 in terms of results.

Underlying ROACE for the business segments was 15%, which compares favorably with our peers.

Net cash flow was $3.6 billion compared to a negative $1 billion in the fourth quarter, and our gearing at the end of the first quarter was 21.5%.

So now I will comment on each of these segments.

In the upstream the five major projects that we started in 2009 are performing well and in line with our expectations.

The second train at Yemen LNG started up in March in advance of our summer target date.

First-quarter production was 2.43 million barrels of oil equivalent a day, an increase of 4.5% compared to the same quarter last year and more than 2% compared to the previous quarter.

Part of the increase is coming from our LNG volumes, which grew by 38% year over year.

Also, another point to make here is that the improvement in Nigeria and the reduction related to OPEC friction was positive compared to a year ago, but roughly in line with the fourth quarter.

We confirmed that we expect production to grow by 2% on average over the 2010 to 2014 period, and we confirm that 2010 growth will be above the 2% average at current oil prices.

In terms of commodity prices, the average for Brent in the first quarter was $76 per barrel, up slightly compared to the fourth quarter.

Our average realized liquids price was up by about 5% compared to the fourth quarter.

Our average realized natural gas price in the first quarter was about $5 per Mmbtu, down slightly from the level of the fourth quarter.

The price does not include sales of LNG from our equity affiliates, notably the new production from Qatar and Yemen.

In Europe our average gas price for spot and contract sales was modestly higher.

Over the long-term contract prices in Asia and South America were flat.

But there have been some changes in the [possible use] that reduced our average realized gas price, including mainly the addition of the Barnett Shale and of the Tabiyeh contract in Syria.

Adjusted net income from the upstream segment was $2.7 billion, a decrease of 5% compared to the fourth quarter.

Given the higher average price realization and higher production volumes, this explanation for this is mainly an adjustment in upstream taxes.

In the first quarter, the upstream tax rate was 60% versus 58% in the fourth quarter.

The fourth-quarter tax rate was below the 2009 average, and the first quarter includes some adjustment from last year.

The annualized first-quarter upstream ROACE continues to be very competitive at 20%.

We are continuing to actively manage the upstream portfolio.

In the first quarter, we acquired a 20% share in the Barnett Shale with sanctions and development of Surmont Phase 2 in Canada and the Laggan/Tormore project in the UK North Sea.

The growth project, deep offshore Angola, has been sanctioned internally, and we expect our partner to [report] very soon.

These three projects should start positioning in the 2014, 2015 period and contribute close to 200,000 barrels of oil equivalent a day net to our long-term growth.

We announced the sale of mature and non-core assets in the US and in Norway for a combined amount of more than $1.1 billion.

The current production from these fields is about 14,000 barrels per day net to Total.

Exploration remains a key element of our upstream strategy.

In particular we are pleased with the success we have had this quarter in deep offshore Angola with one discovery in Block 1706 and two discoveries on Block 1506.

Also, we added exploration opportunities in Kazakhstan and in France.

In addition, as you know, we are well advanced in negotiations to enter a giant new play in Uganda.

Managing costs will continue to be a priority.

We were one of the very few in 2009 to succeed in keeping our technical costs per barrel flat, and we have the lowest technical cost among the major ones.

Going forward our challenge will be to control the (inaudible) per share on costs related to raw materials and energy costs.

Overall our goal is to position the Company for future growth and to maintain capital discipline so that we can surely benefit from the increasing commodity prices.

Now some comment on the downstream in chemicals.

Our European refining margin indicator averaged $29.50 per ton in the first quarter.

This reflects a recovery for the (inaudible) levels of the second half of last year.

The increase is positive, but here reflects a difficult environment for refining.

Adjusted net operating income from the downstream segment was $0.2 billion.

This is an improvement from the fourth quarter, but refinery throughput and marketing volumes were both lower.

Specifically in addition to some strike effects, we had unscheduled maintenance in the first quarter that affected [revenue on this abnormally].

And this cost us about $100 million.

Operationally these three refineries are back on track for the second quarter.

For the long term, we are confident that the downstream environment will improve as the global economy continues to recover.

But it is clear that there is too much capacity in the group oil system today.

Total's response to this situation has been to manage costs and reduce refining capacity.

We have decided to close our one distillation unit at the Normandy refinery.

We are in the process of shutting down the Dunkirk refinery and selling our reserve refinery outside of France.

So we can confirm the target of reducing by 20% our refining capacity between 2007 and 2011.

Note that we also announced in the first quarter the merger of our refining and marketing activities in Italy with ERG, which will further improve our competitive position there.

Switching to chemicals segment, compared to the fourth quarter, adjusted net operating income more than doubled $2.2 billion in the first quarter.

We are in an environment that has shown positive movement in response to the economic recovery, particularly in the specialty chemicals, but we are still in a recovery mode.

For the base chemicals, in March we started up the new 1.3 million ton per year ethane cracker at Ras Laffan in Qatar, which we considered really positively to the petrochemical bottom line.

This is in line with our strategy to develop this activity in the Middle East, based on [shift] ethylene feedstock and in Asia.

In the specialty chemicals, earlier this month we announced that we closed the sale of the Mapa Spontex unit for about [$450] million.

This is part of our policy to monetize nonstrategic assets.

And finally, on the corporate side, cash flow from operations from the first quarter was $7.3 billion.

Investment, including acquisition, were $5.0 billion, acquisitions were $1.7 billion, coming mainly from the Barnett Shale and Laggan/Tormore.

Divestments were $1.4 billion in the first quarter.

This is essentially the ongoing sales of Sanofi shares.

Our participation in Sanofi is now 6.2% of this 10.9% at the end of the first-quarter '09.

Reducing our interest in Sanofi had a negative impact of slightly more than [$100] million on the income from equity affiliates between the two periods.

At the current market value, we have close to $6 billion left to sell, and we expect to complete the process by 2012.

The sale of the upstream asset and the Mapa Spontex unit for more than $1.5 billion will be recorded in the second quarter.

On June 1 we will pay the remainder of the 2009 dividend of EUR1.14 per share, which today represents a yield of about 5.5%.

If we annualized the dividend and the first-quarter results, this indicates that the payout ratio is very manageable at around 55%.

Our gearing was 21.5% at the end of the first quarter.

The dividend payment in June will increase the gearing by around 5 points, so we should be well within our announced 25% to 30% range.

The balance sheet is strong, and in the current environment, cash flow from operations can fund our investments and dividends.

To summarize, the first quarter was about delivering some production growth and being very active in strengthening our portfolio by launching new projects, selling non-core assets, restructuring downstream activities, and continuing to invest for the future.

Looking ahead to the second quarter, we remain very positive about production growth.

Oil price remains strong, and our gas price realization should benefit from the positive lag effect.

So we are confident that upstream will be in good shape.

Downstream and chemicals are more difficult to predict.

We expect refining margin and petrochemical margin to continue to be volatile.

For both the downstream and the chemicals segments, we must continue to concentrate on restructuring in major countries, expanding in growth areas and controlling costs.

For the Company as a whole, we are well positioned to maintain a strong balance sheet, and our main objective is to manage our cash flow to fund an investment program that will provide long-term profitable growth and a competitive return to our shareholders.

And now we can go to the Q&A.

(Operator Instructions).

Mr.

Jothilingam, Morgan Stanley.

It is Theepan here at Morgan Stanley.

Three quick questions actually.

Firstly, just on European gas realizations, I was wondering could you give us a little bit of color on how you see price realization in Europe evolving through Q2 and then into the rest of this year, particularly sort of from a contract perspective?

Second question, just on taxes, it appears that your tax rate was a little bit higher this quarter.

I was wondering if you could give guidance for the full year where you saw that if you left the oil price where it was.

And lastly, just on Jubail, I was just wondering if you could give us a quick update there.

I will start with the tax rate question, your second question first.

You mentioned this is true that our tax rate for first quarter of 2010 is about 60% higher than the 57% tax rate we had last quarter 2009.

This 57% tax rate in 2009 was low and was extremely low, below the average of the year.

So you should not take this as a real benchmark for us.

The rest of the year you could expect a small increase of upstream tax rate versus last year due to a higher oil price.

So I would say potentially in the range of 59% to 60% for the tax rate.

This is upstream, of course.

On Jubail works are going in line with our expectations.

Oil contracts have been passed for at that time, and I have no information of any delay whatsoever, and I think everything is going smoothly in Jubail as I said.

I will move on the European gas price question, the first question you had.

In Europe we benefited from an increase in gas price versus last quarter '09, mainly increasing the spot gas price by slightly increased gas price from long-term contracts, which are [invested] on oil prices.

I am expected this trend to continue in the forthcoming quarters.

I think that all I can say is you have to recognize that spot gas prices in Europe are about 50% higher than in the US currently.

Could you just remind us what your split between contract and spot is in Europe?

I think it -- let me think about it -- is something like 40% spot, 60% long-term.

Great.

That is very clear.

Thank you.

Lydia Rainforth, Barclays.

Two questions if I could.

Firstly, you just talked out technical costs being flat in 2009.

I was wondering how you see those moving in 2010.

And then secondly, just on the Halfaya project in Iraq, I think Mr.

De Margerie was making comments that Total does not want a minority stake in that and feels like they would like it to be bigger.

I was just wondering what had changed since the initial bidding round.

On technical costs we are obviously expecting those technical costs for the forthcoming year to go up because of higher DD&A basically.

On OpEx we will see it will depend mainly on Forex.

On Iraq more broadly, I would say that Iraq is an important country for us.

And it is a real opportunity for us to increase our exposure to new projects in Iraq, which makes sense.

I mean which we can actually make reasonable money while developing resources in this country, we will try and do it.

On concerning Halfaya, a contract has just been signed with CNPC, CNPC being the operator, and we are happy with that I think.

I have no indication that this will change.

Jon Rigby, UBS.

Two questions.

One is, are you able to give some indication of where the increment in terms of the LNG sales that you have made, either 1Q over 4Q or 1Q over 1Q went, i.e.

the markets that those volumes went to just to get some idea about I guess the potentiality of increased revenue over time as they get diverted back to higher value markets.

And the second is my impression has always been that Total has been reluctant historically to sell upstream assets.

I guess that is partly a view of the upside potential in oil prices.

But you typically have not churned your portfolio anywhere near as much as anyone else.

I just wondered whether the disposal that you talked about doing reflects a change of philosophy in the way you manage your upstream portfolio now.

Okay.

Thank you for those questions.

I will answer first the LNG question.

I will give you because we were prepared for this question actually.

On Yemen LNG first quarter this year, we have taken four cargoes -- Total have take four cargoes, two went to the US or Mexico and two went to Asia, one in Korea, one in China.

On Qatargas 2 we have taken seven cargoes.

Three went to the US-Mexico direction, four cargoes goes to South Hook, and one cargo went to Europe.

Right.

That is basically in France.

I would say that globally for our LNG offtake, 60% went to Asia, 30% went to Europe, and 9% went to North America.

That was for the LNG.

Your second question, is there any move in our figures or fear about selling assets?

First of all, I will mention to you that they are offers that are difficult to refuse.

So the offer we had on [that] was so attractive to us that we, with no hesitation, take it.

In addition to that, I would say that we already are not saying that we will do it.

It will depend on prices, but we are ready to be more flexible in our asset management, and we are ready to sell what we believe are non-core assets for us, including in the upstream.

And that is a bit of a change, isn't it, from the way you used to manage that business?

Am I right?

You are right because we have done nothing in the past.

Mark Gilman, Benchmark Company.

Just a couple questions.

I wanted to follow-up on the technical cost issue.

It appeared to me at least upon initial analysis that the technical costs in the first quarter were really quite high by comparison to prior periods.

Do you agree that that is the case, and is there anything in particular we could attribute that to?

Our technical cost in the first quarter this year was about $14.7 per barrel excluding exploration.

And it was $14.9 last quarter '09.

So it was not as high as in last quarter '09.

So I do not share exactly your view.

Okay.

We can talk about that perhaps later.

I also noticed that it appears from the indication of price sensitivity per production sharing contracts that it seems to have increased fairly significantly in the first quarter.

Is there something specific that has caused that?

And also, did you encounter any threshold effects in production sharing contracts that impacted first quarter and future volumes going forward?

If I will remember, the sensitivity on oil price, and I compare first-quarter '09 to first quarter this year, was about 2300 barrels per day, per dollar, per barrel.

And this is not far from the sensitivity we had.

In terms of threshold, I think we figured some threshold in Angola, but I'm sorry I don't know them by heart.

But we will deliver it to you.

And we'll ask (inaudible) to come back to you in that respect to give you the exact timing when we match both thresholds.

Irene Himona, Exane BNP Paribas.

I had three questions, please.

First, you had a positive working capital in the quarter despite the higher pricing, and this drove quite a bit of the, as I said, the percent increase in cash.

Can you talk a little bit about the drivers behind the working capital?

Will it reverse in the rest of the year?

My second question was on product sales.

Obviously they fell quite steeply in the US and Europe.

I presume part of that was due to the refining situation.

But can you talk a little bit about oil demand trends that you are seeing so far this year?

And my final question is on CLOV.

The trade press is indicating a potential delay because apparently Sonangol may have rejected your recommended contractors.

I wonder if there is any comment you can make.

For your first question about working capital, you may have noted that every first quarter we have a reduction of our working capital.

This is due to a tax effect we always have last quarter of the year and first quarter of the following year.

In the last quarter of any calendar year, we paid taxes in advance in Germany, for instance, in Italy, for instance.

And we have this credit the following quarter.

This is why we always have a reduction of our working capital first quarter of any calendar year.

Some comment about oil demand trends.

In Europe we see the drop in volumes compared to first-quarter '09 and last quarter '09 mainly due to business-to-business activity and mainly also due to the drop in fuel oil sales.

You have to remember also that in France there were rumors for special tax, which was aiming to increase the fuel oil prices late last quarter '09.

And these taxes did not happen actually.

But as people were afraid of these taxes, they were bringing a lot of fuel oil higher end of the year.

This is why we also maybe were facing this drop in volume first quarter this year.

In Africa I would say [and we believe] we see an increasing volume in comparison to first-quarter '09.

More globally speaking talking to the traders, we see demand going slightly up on the worldwide basis, mostly driven by Asia and Middle East.

On CLOV you know that we have internally sanctioned this project.

It is in the process of being approved by our other partners.

It is true also that Sonangol and the state of Angola is willing to have more local content, and this is part of the game.

And this is normally a discussion in that process.

It might be that some contractors are not active with that, but for us this is normal business.

(Operator Instructions).

Mrs.

[Cullen] from Morgan Stanley.

(Operator Instructions).

Mr.

Neill Morton from MF Global

I actually have two questions.

The first actually is perhaps a revamp of Mark Gilman's question earlier because I noticed exactly the same issue with the upstream versus Q4.

Looking at EBIT, excluding the higher tax charge, you effectively had slightly higher oil prices versus Q4.

You had an increase in volume of about 50,000 barrels a day flat gas price, flat exploration charge, but yet your Q1 EBIT was flat in dollar terms versus Q4.

So I'm just wondering if there are startup cost issues here.

I guess the underlying issue is whether the incremental volumes, the new volumes are actually adding incremental margin as you have previously highlighted in presentations.

And then just the second question has been asked in the past.

I noticed, Patrick, that every number you quoted in your prepared remarks were in dollars.

You have commented about being the biggest company in the Eurozone, etc.

But are you still considering reporting your results solely in US dollars?

To answer your second question, by French law I cannot issue my books in any other currency except euro.

I am sorry for that, but under French law -- and this is the same under Italian law -- we are not permitted to use another currency.

Of course, we will use the dollar to give the market appropriate data but the formal books have to be maintained in euro.

Your question about cost and EBIT.

You need to understand that volumes were up in comparison to Q4, but volume -- I mean production [right] -- but there were two days less in the calendar quarter, first-quarter 2010 in comparison to last quarter 2009.

And, of course, and also you did not know that, we made less uplift in this last quarter, first-quarter 2010 in comparison to last quarter '09.

So basically [we feel the sales] are quite stable.

So I just missed that.

You made less in Q1 versus Q4?

I mean you have less calendar [days].

So, in addition to that, we made less uplift.

So, in aggregate, the sales, despite the growth in production, the sales were stable.

Lucas Herrmann, Deutsche Bank.

Actually I'm just on to extend you beyond the half-hour.

But seriously it was the same question really that Neill and Mark asked, but I guess part of me is just wondering as well in terms of the relatively strange profit performance on better volumes and better price, how much of that is actually the fact that for the LNG businesses in Qatar and Yemen, you actually are just consolidating income on the equity line.

So, in effect, we are seeing barrels come through the -- we are seeing barrels coming through the upstream line but clearly with no operating income.

Is that an appropriate observation?

Yes, both equity consolidated are below the line.

But you also have to understand that the tax rate has an effect also in our bottom line, and as it was mentioned at the beginning, the tax rate we had this quarter, was higher than the last quarter '09 in the range of 60%.

Just, again, going back to Europe and gas prices, I mean your comment with gas pricing in Europe was broadly flat, which I am slightly surprised by given that if I look back four to six months, there has been a very marked improvement in oil price.

You would have expected some stronger improvement on the contract side of your business this quarter.

Not in comparison to last quarter '09.

Okay.

It might be a slight lag effect, but I think if you -- I can give you some figures.

The average gas price for North Europe was last quarter '09 $6.01 per Mmbtu where it was $6.28 this quarter.

There is so much -- not so much difference between the two quarters.

We have no further questions.

(Operator Instructions).

Mark Gilman, Benchmark Company.

I have noticed that the natural gas volumes from the Middle East were quite a bit higher than I would have thought in this period and were higher by a much greater amount than the increase in reported equity production.

Can you comment on what was driving that particularly given that the second train at Yemen did not, as you had indicated, start up until March?

I think on LNG the growth was about plus 40%, which is in line of the target.

In addition to the LNG volume, you have the Tabiyeh contract in Syria, which increased the volume and I think that is it.

And how much was that, Patrick?

About 30,000 barrel of oil equivalent.

Sergio Molisani, UniCredit.

Quick question on the Laggan/Tormore final investment decision.

In your strategy presentation in February, you showed the CapEx reduction obtained in the Surmont Phase 2 and the CLOV.

Can you give us some flavor also on the CapEx reduction achieved for the Laggan/Tormore and some more indication on the tax benefit you are planning for this project from the UK government?

I don't have in mind the exact figure for the cost reduction obtained in Laggan/Tormore.

This was part of the decision process we had, and this is thanks to both the cost reduction and the tax rebate we obtain.

And then we decided to launch the Laggan/Tormore, which at that particular date was matching our investment criteria.

But I'm sorry I don't have the (inaudible).

I think for the tax itself, it is two times $150 million I think about.

So something like $300 million, $320 million tax rebate, and this was necessary to launch the project.

We have no further questions for the moment.

(Operator Instructions).

There are no further questions for the moment.

So I will say thank you to everyone.

Have a good weekend.

I remind you that this was the first good evidence of our rebound of our production, and I hope you will notice that for sure.

And have a nice weekend, everyone.

Ladies and gentlemen, thank you all for attending.

You may now disconnect.