TotalEnergies SE (TTE) 2005 Q4 法說會逐字稿

Good afternoon and thank you for coming for this presentation, which will be a short presentation on the results that you certainly already know very well, and I will concentrate my comments on the strategic update of the Company.

So first a few words to start with the financial performance of the Company for last year. Of course we have enjoyed a more favorable environment, both in terms of refining margin and it has led us to a new high in terms of net results at $15b adjusted, roughly 1% increase. The same increase, in fact, in dollars and in euros, and 27% return on capital employed. Well, the figure is [roughly that].

This creates a few comments on the public opinion but we have reacted relatively strongly in France to exploit that. Well, people should know what they want. If they want to have strong companies based in France, they must accept that they have to be at least as profitable as their large competitors. So we hope -- I know that we are not the only one to face this type of problem and there have been elsewhere in Europe other comments of the same type. But it is from time to time necessary to explain to people that you have to make your choice and assume the consequences of them. But for us, very clearly, we want to commit to be a company growing, and growing profitably.

In terms of capital expenditure, we were close to $14b last year, with $1.8b of acquisitions, mainly Deer Creek. $8.3b were returned to shareholders, both through dividend and share buyback.

And just one general comment, and I will come back more in detail on it. We have had a lot of important steps in preparing for the future, and all these steps lead to a potential of additional reserves of 3.2b barrels of oil equivalent, which is a very large figure by comparison with our production of 900m last year, and it’s roughly 50% through heavy oil acquisitions in Canada, 25% for LNG, 25% through exploration.

The main milestones for this year and next year, well, come back to a substantial growth in terms of production. Our production last year was flat on the underlying numbers after deducting the impact of the oil price and the underpayments to production. Things should accelerate with start-ups, a number of start-ups coming in 2006. But more in the second half of the year than in the first half, which means that most of the impact will be on 2007, and we should have a very substantial production growth in 2007.

For this year, we will have a few other important events outside of the development of the upstream with the start-up of new conversion units in our Normandy refinery in France, and the spin-off of Arkema in May, which will lead to a rebalance of chemicals.

I will not go through the figures of the results. You know them. Just a few comments on the benchmarking in terms of financial performance. You can see that together with Exxon we have been at the top of the majors in terms of increase of the earnings per share, about 5% in dollars. In terms of return on capital employed, we are also in a very good position, together with Exxon also in that case. And in terms of Total’s shareholder return, we have had the best performance last year.

Now I go directly to dividends. We have continued to grow substantially the dividend by 20%, which is what the Board is proposing to the shareholders’ assembly. And you can see that on a five years period we have had a dividend growth by 14% per year on average.

It shows that our payout is clearly lower than what we were expecting a few years ago, but well, the environment is also far higher than what we expected a few years ago. And what we prefer when we speak of pursuing a dynamic dividend policy is to have some regularity in the increase of dividends. It means also that we have, for the next few years, capacity of continuing to grow substantially the dividend.

So in terms of share buybacks, we were close to 3% last year, a figure a bit lower than in the two previous years, but it’s just linked to the fact that we have paid $1.3b for the acquisition of Deer Creek in Canada, which explains why the buybacks were a bit lower in the second half of the year than in the first half of the year. And you can see that on a community basis, between 2000 and 2005 we have had the best return to shareholders.

We -- on top of the distribution of the dividend which will take place on May 18, we will have the same day a split of the Total share - 4 to 1 in Europe, 2 to 1 in the U.S. - in order to come back to one ADR for one share and the spin-off of Arkema. So, at the end of the day, it means that for a shareholder who has today 10 Total shares, he will have on May 18 40 new Total shares, plus one Arkema share, plus the dividend paid that day. So we do everything the same day in order to avoid to have several changes coming at the short delay.

Going now to the different business segments and outlook, well, the increase in the results has been substantial. We are now concentrating our comments on the net operating income and not on the operating income. Due to the weight of income tax, I think it’s more attractive. And on top of that, we have more and more contribution from companies which are on an equivalent basis, which is not included in the operating income. So we really [prefer to] concentrate on the net operating income, and you can see that the contribution of the upstream to results has been $10b last year.

In terms of technical costs, well, we had some impact of inflation but you can see that we continue to be in a very competitive position with technical costs at $8.5 per boe last year.

In the exploration area we have continued to have a good level of activity, both in terms of getting access to new acreage and in terms of exploration successes, mainly in West Africa but also in Norway, in Argentina, in Yemen. And our average finding costs remain for the last few years’ average at $0.9 per boe.

We have decided to grow our exploration budget from $800m to $1b from 2005 to 2006. Roughly half of it is linked to the increase in the cost of services, mainly drilling rigs, and half of it is a real increase of activity.

Our reserve base, in terms of proved and probable reserves, is growing rapidly. We are now at 20 barrels of oil equivalent, which represents 22 years at the level of production of 2005. And you can see that we have a very good geographical diversification. We have on this map in red the countries which contribute for more than 1b boe, which is 5% of the aggregate figure. We have a newcomer in this category, which is Canada, which joins Venezuela, Nigeria, Angola, Norway, Kazakhstan and the UAE in the Middle East.

When you look to the distribution of these proved and probable reserves by type, you can see the growing weight of three categories which I think will be very important for the future - deep-offshore oil, heavy oil and LNG, which represent now more than one-third of this reserve base.

Concerning the proved reserves, well, according to the very restrictive rules of the SEC, we had last year a 99% replacement rate and 97% on a three years’ period. If we exclude the price effect, making the calculation on a stable oil price for all the period which has been taken at $40 per barrel, which is a variable figure which has a real industrial meaning, our reserve replacement rate last year was at 120% and on a three years’ period at 118%. So in spite of the fact that we are now putting proved reserves on near the point in time where we decide to launch the development, we have been able, during the last three years, to keep a very good reserve replacement rate.

Looking to production growth now, we have updated this chart with the expected start-up of the coming years. There are not a lot of changes by comparison with what we have shown six months ago. And we expect to have production growth in average close to 4% per year between 2005 and 2010, all this production being calculated at -- recalculated at the level of $40 per barrel both for 2005 and 2010. So it’s a real level of production growth, we are not playing with the numbers, starting from the calculation at a high price to benefit of the impact of price which would be lower in the future.

Concerning now CapEx, well, there for the upstream rate to $10b in 2006. Well, it’s an increase by comparison with the previous guidance by something like $1.4b, and we think that there will be roughly the same increase for the following years. Half of it is explained by higher costs on projects. Drilling rigs are becoming more and more expensive. But on top of that, the other half is explained by some changes in our investment policy.

In the U.S. we have swapped onshore gas fields which didn’t require a lot of investments with a deep-offshore development at Haiti, which is attractive but which will require substantial investment in the next two to three years. In addition, we are growing now our vision of investments in Canada with the new position that we have acquired. It will grow more rapidly than we expected a few months ago.

And a bit more generally, on the relatively old fields in the North Sea and in West Africa, we have decided both to improve -- to invest in modernizing some production facilities, connect some small satellites, in order to both improve the reliability and reduce the decline of these relatively old assets. And it has a good payback in a high price environment.

Now, concerning the outlook for the period of 2010, between 2010 and 2015, we have a lot of projects coming in the picture. First, thanks to the exploration successes, they have brought 5b barrels of oil equivalent of reserves in the last six years. And a lot of them, a lot of these additional reserves, the decision of development has not yet been taken and the new production will come after 2010, particularly in West Africa but we have also several steps of development off Kashagan.

And we have also the projects which will contribute very substantially to the production growth of 2010 in the Athabasca of course, with some LNG projects, particularly in Iran. The build-up should be after 2010. The Dolphin project in the Middle East; we should have further steps of developments at this horizon in time.

Well, I will pass over [two zooms] on Africa and North America, and just make a last comment on the upstream about LNG, which is developing very fast and we expect to have a growth of our LNG production by 12% per year between now and 2010.

A few words now about the downstream. The financial performance of the downstream has also improved a lot last year, with a net operating income growing from $2.9b to $3.6b. And you can see that we have remained constantly in the last five years at the top of the majors in terms of return on capital employed of the downstream.

For -- the downstream which is changing the most is the increase of the investment in refining. And here we have indicated what will be the main programs, like the hydrocracker in the Normandy refinery which will start by mid-year, some large desulphurization units in the Lindsey Refinery in the U.K., and in the Donges refinery in France, in Cepsa in our Spanish affiliate, a new hydrocracker associated with a new vacuum distillation unit is being considered. And in North America, we are considering the construction of a coker [inaudible] the Port Arthur refinery.

All these investments have a primary target of adapting the refinery to the new product mix required by the market, with particularly more diesel production, less gasoline production, these being specifically for Europe, and less heavy crude oil, both in Europe and in the U.S., and globally being able to accommodate more high-sulfur crude. And this is in line with what we expect for the crude mix worldwide in the coming years.

Concerning chemicals now, well, the chemicals have improved substantially their performance last year, with a net operating income growing by 25%. And in terms of return on capital employed, the figure has grown for the whole segment from 8.5 to 11.5%. And if you exclude Arkema, it has grown to a smaller extent, from a bit under [12% to 12%].

In petrochemicals, we are in Europe concentrating on maximizing synergies with refining. It’s a bit the same story in the U.S., but elsewhere it’s mainly developing in Asia and Middle East. In the Middle East, it’s in Qatar where we have several good projects underway. And in Asia for the present time it’s a large expansion of our petrochemical plant that we own together with Samsung in South Korea, with de-bottlenecking of the steamcracker of aromatics, a new polypropylene line, and de-bottlenecking two styrene units.

And at the end of the day, we will have acquired on the basis of roughly half the cost of construction of the new unit a very solid petrochemical asset base in Korea.

Concerning Arkema, a few details of the progress of the spin-off. We have ended the information and consultation process with labor representatives. And we expect the Board of Directors to approve the principle of the spin-off at its next meeting by mid-March and send the proposal to the shareholders’ assembly of May 12, with an implementation of the spin-off on May 18.

And as you have seen in the previous chart, Arkema has improved substantially performance last year with an operating income doubled to a figure of €230m. And the magnitude of the company is illustrated by the volume of sales, €5.6b, growing by 8% last year. And capital employed at the end of last year of €2b. And the company has good projects for development in Canada, in the U.S., in China, some additional restructuring in Europe. So the company will be launched with a very solid balance sheet, and I think has a lot to do to continue to improve its performance and obtain a good valuation on the market.

So finally, the policy for Total continues to be to pursue a profitable growth within an increase of the share of the upstream in the capital employed, which would reach, in a few years from now, a split of 60% for the upstream, around 25% for the downstream and 15% for chemicals. We have, I think, a clear visibility on our future growth and our [self-help] contribution.

Concerning the investment strategy, we maintain a priority to organic growth, which doesn’t mean that we will never make acquisitions. We have shown in last year that with the Deer Creek acquisition, which we think is a good acquisition at a cost of less than $1 per barrel of oil acquired, that we can make from time to time an exception. But it’s sure that we are able to grow through organic growth, create a lot of value through this policy, and use just a bit exceptionally acquisitions when we think that there is a particularly good fit with the strategy of the Company.

We want to keep a huge sense of capital discipline within the Company. For our development projects we remain with a very strict rule of selecting projects profitable at $25 per barrel. This being said, when we look to the different projects, we have also looked to the upside that these projects may have in the case of high price scenario. And it can be very different from one project to another, so I think you have to enter it in the picture.

And from time to time we will make a few exceptions when there are projects which can bring significant reserves at a relatively low cost per barrel. We can make some limited exception to the $25 per barrel rule.

For this year, our CapEx are expected at $13.5b, 75% allocated to upstream. In fact, the only large difference with the guidance that we gave in September has been to upstream, and I have already commented it. We expect that this level of CapEx to be relatively stable over the next few years.

Finally, the Company will very likely be left with a strong financial flexibility, which allows us both to capture growth opportunities and to deliver higher returns to shareholders. On top of the proceeds coming from our operations, and particularly our upstream production growth, we have a significant reserve of value in Sanofi-Aventis, which represents something like €13b. So we will be able to continue to have a dynamic dividend policy, while maintaining the gearing around 25/30%, and of course, being able to have substantial share buybacks with this sort of CapEx and dividends being available for these share buybacks.

So these were the main messages that I wanted to pass, and we are now, my colleagues, the Executive Committee and myself, we are ready to answer your questions.

Thank you. It’s Jon Wright from Citigroup. I just had two questions, please. The first is to do with downstream investments in Africa. You’ve highlighted that you’re looking at a number of opportunities. Can you confirm that they won’t be subsidized by the upstream in terms of the returns they have to pay on their own?

The second is just Mr. de Margerie made some comments about the service sector yesterday and he suggested that a way has to be sought to keep price increases under control within competition rules. And I wondered what options you see as possible for this to keep prices under control?

Well, the problem with the lack of competition - I answer first the second question as to the lack of competition in some service activities - is the fact that for a high-tech job, there is a very limited number of companies who can make offers reliable. So when you have two or three of these companies, it’s particularly the case in some activities, it’s relatively easy for them to push the prices up or even in some cases we have seen just one answer.

On legal grounds, it’s not that easy to demonstrate that there is a collusion between these companies. So we have to continue to monitor how they behave, but it will not be that simple.

Concerning investment in Africa, well, up to now, what we have done is acquiring some marketing assets which allow us to grow our market share in the African countries. Well, there is no link with the upstream business on this part. In a few cases there are governments who explain that it would be nice to commit to some refining, to bring some refining capacity, and that they will take into consideration the efforts made by the oil companies for selecting those who will be selected for some extreme projects.

It’s sure that we don’t want to mix the economics, so if at a point in time we feel that it is necessary to take some commitment in the refining, that the economics of this refining project is not -- are not fully satisfactory, you have to identify what represents a bonus to be taken by the upstream part, and see after that what we [inaudible] bonus for acquiring positions in the upstream, the profitability of the upstream is satisfactory. But we’ll not put a burden on our downstream business. The question is to know if the outlook for the upstream business justifies to pay a bonus, which will not be paid in cash, but in kind.

Colin Spence from Dresdner, two questions again. Can you just tell us what the status is on [Becancour]? That’s my first question.

And the second one is the technical press this morning have linked you as being Saudi Aramco’s partner in a new 400,000-odd barrel a day refinery at Dubai. Can you make any comment on that in the context of the point that was made in the presentation yesterday, and I think that John was getting at, about taking downstream positions to get upstream positions?

Well, on Becancour there is nothing new. We have exercised that option on an extension on the Becancour, field which is called the Becancour North. Well, you cannot say that [inaudible] is particularly cooperative. We will see in the future. They announced that they were launching the development of main Becancour when Becancour North will come in the picture. We will see.

I am not sure that I have caught your second question. No, because I understood the Dubai, so I [inaudible]. In the refinery project in Dubai. No. In Saudi Arabia, you know that Saudi Aramco has proposed to a number of companies to look to possibilities of investing jointly with them in some new refining assets, some of them being dedicated to heavy oil, so we have some contacts. We will see what are the merits of this contact.

It’s sure that it’s easier to decide conversion units, because we think that we have already good visibility in terms of conversion and margin, all this information, margin for a grass root refinery. But it depends also of what is the spread between heavy oil and light oil, so it’s just on a study at this stage.

Thanks. Neil McMahon, Sanford Bernstein. I’ve got two questions. The first is you mentioned that you’re going to spend incremental exploration money in some parts of the world. Maybe you could go into that. And one of the places you had up there was Sudan. Maybe you could give us an update on where you are there in terms of the data on the prospectivity of that area.

Just secondly, it seems that there are continuing claims on taxation in Venezuela. Maybe you could update us there on what the probability is that Syncor II is going to happen for 2010?

Well, concerning exploration, we are going -– our exploration is increasing the programs because we continue to have attractive targets, particularly in West Africa, but we are also starting exploration elsewhere in the world. You have seen that we have acquired new acreage in different parts of the world. So even if the biggest component of our exploration, if that will remain West Africa, we will continue to grow our involvement in a lot of further areas, including what is considered as relatively mature areas.

And for instance, in Norway we have been happy with the acreage we have been granted in the last few years. We have made some discoveries and we think that there are still a lot of efforts to be done.

Well, concerning Sudan, on technical grounds it’s an attractive area, very clearly. The other problems are a bit less simple. We have a difficulty which is most of the land of our block has been mined, so we need to have first opportunities to clear the mines before being able to work efficiently. We have had also some [junior] companies who have tried to interfere but we are very confident about our legal position on this block.

Venezuela is not a simple story too. We are in the middle of discussions with [inaudible]. When we discussed at the top level with President Chavez while things go relatively well, friendship and so on mentioned, and we have at the top level a lot of messages about the fact that they want to -- we continue to be involved in further steps of development of the oil industry in Venezuela. When after that our negotiation teams come back to Caracas, it’s a bit more complicated at the working level.

You have seen that we are [inaudible] on the start-ups before 2010, because we think that there is still a lot of things to be discussed before being able to launch the Syncor II project, and of course first to settle all the remaining points on the tax treatment for the existing production.

[Iris Mann] at Morgan Stanley. Some questions on the change in planning assumptions. Your planning has gone up from -- the trend is at $40. Can you confirm that that is the price you now use to screen your investments, [CapEx]?

Secondly, on return on capital, I know there are no explicit targets. But as your new $40 planning price, what -- particularly in light of cost inflation, what are you trying to achieve in terms of underlying return?

And thirdly, on the dynamic dividend policy, I wonder how we should interpret that. Is there an ideal payout ratio out of earnings at $40 like that?

Robert, concerning the first point and I will take the dividend.

Okay. You want to take the dividend? We think that’s the distinction between the price that we use to make our long-term plans. Long-term plans for us is plans for the next five years. And the price that we use for the economics, and you know that if you start at the level of the exploration it takes about four to five years to find something, after that another five years to define the development and to make the development. And after that, the production could last 10, 15 or 20 years, which means that it is very, very long term.

And so this is why, in fact, if we have taken $40 for the five-year plan for our economics, we take different assumptions for the oil price. One point is that for the new development that we are launching, we take $25 per barrel. For the long-term projects that are very important for the development of the Company, I think we may accept to take $30 per barrel with, in some cases, some flexibility.

But in any case, we look at what would be both the upside in case we could enjoy a higher oil price, and also the resistance to such a project with lower oil price.

And what type of return do we require? Return, that means this is in connection with the economics. It is clear that the type of return depends on the risk of the project, the country risk. It depends also of the nature of the project and the length of the project.

It is clear that it is more difficult to have a good return with a 20, 25-year project, compared to a project with a length of eight to 10 years. But it’s clear that in some difficult countries, for, I would say, medium-term projects, we could require 14, 15%.

I think that the question was also about the guidance for return on capital employed of upstream at $40 per barrel. Well, like all the other oil companies, we have stopped to give this type of guidance because there are too many things moving simultaneously, in terms, of course, in terms of tax.

So we are clearly in a transition period, and we must wait to see things settling a bit before being able to give a guidance with sufficient precision.

Concerning the dividend, well, you’ll remember that it’s a very different environment. We mentioned a payout target of 50%. In the meantime, we have increased regularly the dividend each year by something between 15 and 20%. And at this stage we will be with a 32% payout.

So before -- you cannot say that it has not been a dynamic dividend policy. But we are very, very far on the target that we mentioned previously in terms of payout. So it’s a bit the same story. We prefer at this stage to say we will continue to grow regularly the dividend, and wait a bit to see where the environment for the industry is stabilizing before being more specific about a payout target. But there is clearly room for continuing to grow substantially the dividend for the coming years.

Yes?

Hi. It’s David Cline from ABN Amro. Two questions, firstly on 2006 production. Assuming that the oil price stays roughly where it is today, do you think you’ll be able to grow production at all for 2006, or would that be too much of a challenge?

And secondly, on the change in CapEx attributable to cost inflation, are there any particular projects within your portfolio which have made a material contribution to that CapEx slippage?

Well, on the production, in 2006 I think you will have to be a bit patient in the first quarters because, in fact, the new production are coming more in the second half of the year than in the first half of the year. So you should see some production [figures] in the second half of the year.

On cost inflation, the -- I think the situation is quite different for our operated projects and for the non-operated projects. For the non-operated projects, we have a few projects which have had horrible changes in the cost of the project which we had longer. Now it’s behind us. We have Snohvit; I am not sure that it’s fully behind us. I hope, but I am not sure.

Well anyway, Norway, you have such a tax system. And it’s probably part of the problem that you don’t suffer really of cost overrun. You have your fixed [offering] with the CapEx. You have your planned tax burden, which means that the state is taking care of most of the cost overrun. So it’s a context which is a bit specific.

For our operated projects, our concern is, to force one, is on drilling rigs, and particularly for the heavy drilling rigs for deep offshore or for deep wells. And the cost of these rigs continued to grow substantially. So it hurts, particularly the deep offshore development.

And the second area of concern is the -- come to the first question -- come back to the first question, in some high-tech areas where you have very few competitors, typically all the equipment that you have on the bottom of the sea for the deep-sea development.

To some extent now, with a number of LNG projects, the engineering and construction companies which have the capabilities of building LNG plants are close to being fully loaded for the next few years. And there is not a lot of competition for new projects.

So this remains more concerned, at this stage. But these are areas where there is clear overheating in the industry.

Hi. It’s [Robert Templer] with [Simmons and Company]. Looking at your refinery upgrading projects, you’re certainly not the only company to announce such plans to be executed by early next decade. In fact, one could paint a picture where all the industry players are executing upgrading margins that might be quite a bit lower than they have been in recent history, however unlikely that scenario might be.

So, in light of that, I’m wondering what your test case is, what low return might you be willing to accept and what minimum margin might you see in order to get that threshold return?

Okay. Ian Howat?

Yes. I think we’re really pretty confident that the upgrading projects we put in are extremely robust. We’ve shown you in here the rates of -- the payback time in a 2005 scenario. Okay, 2005 was a very good year. But also in the average of, I think, the last five years, from memory, we put in here.

I think that if oil prices remain reasonably strong, let’s say something in the $40 range, rather than coming back down to the $20 range, I think you’re going to see fairly strong upgrading margins. And I think we’re going to get very, very good payouts from these projects.

I think we were more doubtful, where we have to be more careful, is in looking at the big grassroots-type projects where, we were talking about them earlier, there already have been quite a lot of announcements about new projects. And they’re going to build a lot of them certainly in the Middle East and Asia, rather than the Atlantic basin. Obviously not all of them are going to get built but if a substantial proportion get built, then you could probably see top-end margins weakening going forward.

But we think that as long as the oil price remains relatively strong, there’s going to be a big incentive to get more out of the bottom of the barrel and to make more clean products out of the existing crude supply.

[Let me just add] a point, which is the fact that the conversion margin will probably move in line with the oil price. When you look at the difference between [inaudible] fuels, on one hand, and the heavy fuel oil, the price of the heavy fuel oil is dragged down by the competition of coal when the oil price grows.

So, to some extent we could have, in fact, in the results of the downstream some link with the absolute level of the oil price, and perhaps even a bit more than with just the overall refining margin in the future.

Yes?

It’s John Rigby, UBS. Two questions, one is on Canada. Does the fact that your absent Northern American refining and conversion capacity in that area put you at a competitive disadvantage as people race to develop the oil sands in Alberta? All you have is Port Arthur in the south of the U.S.

And the second is just on Tahiti. Does that signal a move to try and build a rather more material presence in the deepwater Gulf of Mexico, or is it merely a tactical decision, based upon the availability of a single asset that you thought was an attractive move to make?

Right, Bruno maybe on the first one?

Well, in Canada, the acquisition of Deer Creek is really changing the situation for us because we are now the operator for a very significant acreage. And we have more presented this time on our own the best way to upgrade the production.

We are still studying the different options. Either a duplicated unit on the site of production, or to sell some intermediary stock to installations -- refining installations in the States. And so we study out the process and we will find the best solution for us.

It has also to be mentioned that the project of the coker in [Borasa] could give us some flexibility and choice. Maybe not directly, but thanks to swap agreements.

On the second point, well, we were up to now a relatively marginal player in the onshore exploration and production activities in the U.S. So we prefer to quit this business and concentrate our U.S. upstream activity.

On the deep offshore, this being said, I don’t think that it would mean a big increase in our allocation of capital to the U.S. upstream.

Yes?

A few questions. It’s [Edward Hay], Credit Suisse. The first one is assuming a flattish environment in ’06, ’07 versus ’05, [on top of] the U.K. tax rate changes, what do you think is the outlook, in general terms, for the corporate tax rate?

And then the second question is on cost overruns, it’s a Kashagan-specific question. Obviously that’s probably one of the areas where the costs have gone up. Do you think that you’ll still be able to recover those costs under the existing terms of the DSA, or are you seeing any pressure from the Kazak government?

Robert on the first one. I will answer on the second one.

I think that on average the tax rate for 2005 was, I think, 53%. Given the evolution of our production, the point that you mentioned concerning taxation, we should have an increase of our average tax rate of a few points in -- for the years to come.

Concerning Kashagan, well, the costs are enormous but the reserves are enormous too. So when you look to a cost per unit, I think there should be no major problem in recovering these costs. The only point that we have to check is that the government take is not postponed too far in the future, because of course in these developing countries they are very impatient to see some substantial revenues coming from production. It’s a bit normal.

But globally, I would say even with the increase of costs which has been announced, the cost per unit will remain relatively reasonable.

Another point which would be important is to keep sufficient level of control of the cost of transportation from Kazakhstan to overseas. And I think that in that concern, it’s very important to have several export routes being available. And we are working on a project to connect Kashagan with the [Bekudichan] line.

Yes?

[Inaudible]. How long would it take for European refiners generally to catch up with the move from light sweet crudes, like North Sea, towards heavier types of sources, like the [inaudible] Urals. In other words, how many years will it be before the advantages of refining, like [inaudible], which was built around Urals and nothing else, how long will it be before that disappears? Is it five years, 10 years or whatever?

Yes. I’m sorry [inaudible].

Well, there is currently a move towards heavier crudes and sour crudes. And refiners, because of the poor profits from the days of $11 a barrel, they won’t adjust it, they weren’t ready for it. Now you’ve done something, and others are doing something, [inaudible] others. How long would it take?

I’d just like to make it clear that our conversion units are more driven by the lightening of the product slate than by the heavying up of the crude slate. There might be a perception that globally the world crude slate is getting heavier and higher sulfur. If you leave aside, and I’m not sure you can leave them aside, but if you leave aside the Canadian tar sands, which is probably going to be developed in conjunction with its own refining system, that theory is not as obvious as all that.

What is obvious is that you’re getting a product slate that is -- it’s probably going to be more sulfurous, but not necessarily going to be heavier. But what is obvious, of course, is the product slate is just getting lighter and lighter. And that is going to be what is driving upgrading margins and the kind of investments that we are putting in.

[Inaudible question - microphone inaccessible].

Really? Well it had to happen one time. And in the last 50 years of this environment.

It’s a challenging statement.

Yes. As I said before, we think our investment in upgrading is extremely robust. Europe is chronically short of diesel oil. If you’re producing -- making a hydrocracking unit [inaudible] refinery, I don’t think you’re going to lose money on it, for sure.

I think we have another - yes? No other questions? Yes?

Maybe just a quick point of clarification on the 1P reserve additions for last year. Can you quantify what the net effect of purchases was, and any amount that was included on the 1P basis for Deer Creek? I know you mentioned 2P.

Well, in fact, in our 1P -- Deer Creek is important in the 2P additions. But it’s very limited because it’s just the first phase of SAGD which has been booked in 1P last year. So it’s a very small number in the overall booking of the 1P.

Well, if there are no more questions, we can now have lunch together and continue our discussion. And thank you for your attention.