TotalEnergies SE (TTE) 2004 Q4 法說會逐字稿

Good morning, ladies and gentlemen, and welcome to this meeting to present the annual results of Total, and at the same time, to present the latest strategic outlook. I don't think it's going to be news to you, but the news is good, with net adjusted income of €9b, and including exceptional items and before adjustments, €9.6b, a ROACE throughout the Company of 24%.

Now, of course it's true that we've had a favorable environment in 2004, both in terms of crude oil prices, which are now up to $38.3 per barrel, and the refining margins, which have increased by 57% in Europe and are now at about $32 per ton. And even so, even though it's only been true for the second half of the year, roughly, there has been a rebound in petrochemical margins.

Against that, of course, we've had the negative impact from a weaker dollar, 9% down on average in 2004 compared to the average of 2003, but the positive elements far outweigh the negative element.

Now, all that of course should not conceal the fact that we've had a very good solid operating performance. We have a successful exploration program. Hydrocarbon production is very much in line with what we indicated to be the trend. It's up by 3.7% last year, excluding the end of year price effect and the impact of the end of year prices on the buyback and PSC contracts.

The refinery utilization rate improved and is now running at 93%, and in petrochemicals we had good Olefin production, up by 12%. So a good combination of a good environment and solid operation from the Company.

Now, looking at the environment and dwelling on that very briefly, I don't need to dwell on it very much because you're as familiar with the environment as I am, but of course, we've seen brisk increase in demand in 2004, which you can see on this slide, explained basically by strong demand in Asia. And that has led to a decrease in spare capacity, as we say, and there is a modest level of spare capacity at the moment and since the middle of last year. And it's been about 2% of world output capacity, which is fairly low when one considers the uncertainties prevailing in some producing areas.

Another point I think that needs to be mentioned, even if it's slightly more recent, is that within OPEC - where traditionally we've seen opposition between some countries in favor of higher prices and others in favor of more moderate prices - there has been a move towards moderate prices. And I think OPEC is now tending to say that around $35 to $40 a barrel doesn't do anyone any harm, and it's pretty good for OPEC members. And it's something I think that this is what the organization considers when it adopts its strategy.

Now, our approach is a little more prudent, for obvious reasons, but also because there have been so many forecasting errors in oil prices, both on the downside and on the upside. And we therefore prefer to be a little more cautious, and therefore we talk about a reference environment of $25 per barrel.

That's the price per barrel we use in providing our ROACE guidelines for you, and as far as investment decisions are concerned, in major projects, we want to make sure that at $21 per barrel, the economy of the project is okay. So don't consider that the improvement in the market at the moment will last forever, nor what OPEC would seem to prefer.

The final slide in this introduction about the environment, in refining and in petrochemicals we've also had favorable market trends. In refining, there have been several factors supporting refining margins. First of all, the fact that the oil mix is tending to become heavier worldwide. And whereas lighter products are coming out of refineries, we have fairly low potential capacity in terms of distillation and none at all in terms of conversion. So that means that the conversion ratios are high and so we anticipated this movement, and we've therefore decided to go in for some fairly substantial investments in refining.

And then there are a number of high operating constraints on sulfur, aromatics, CO2 emissions, and this has led to a slight fall in the actual availability of refineries.

In terms of petrochemicals, what you see here is a change -- changes in the capacity utilization rate of petrochemical plants throughout the world. They had fallen to fairly low levels in 2001/2002. This started to rise last year, but it didn't really -- wasn't really visible in the figures, and in the last half of last year, we had a rebound above the mid-cycle.

And that's the issue of the environment, and I'd now like to give the floor to Robert Castaigne for him to present the results to you, and he will go to the rostrum to do that.

Good morning. I will focus my comments on the full year results for 2004. First of all, operating income was €17.1b, up €4.1b over 2003. Now, of this €4.1b additional, €3.1b was due to environmental effects of the increase in crude oil prices, a very sharp increase in refining margins, but also the pick-up of the petrochemical cycle in Q4. Conversely, there was also the adverse effect of the dollar on our results in euros. As for adjusted net income, €9.04b, up 23% on the previous period.

Let me say a few words about this so-called adjusted net income. Now, we're talking about a bottom line of €9.6b. Now this figure, €9.6b, includes some positive non-recurring items for a total net of approximately €700m, which is the difference between the capital gain on the dilutive effect of Sanofi-Synthelabo, net of the provision for deferred taxes and restated for accounting adjustments at Sanofi, totaling €1.7b.

On the other hand we booked provisions, particularly in chemicals, for approximately €1b in taxation - +€1.7b on the 1 hand, -€1b on the other hand, leaving us a balance, a positive balance of €700m, giving us an adjusted net income of €8.9b.

Now, this is where things get a little more complicated. Sanofi accounted for the acquisition of Aventis at acquisition cost or historical cost, but had to restate the assets under amortization. So in Q4 2004, our share of that amortization was approximately €150m, which had an impact on our accounting results and adjusted accounting results. So if we reversed this €150m, this gives us what we call an adjusted net income of €9.04b, which is exactly the underlying profit of the Group.

So that was a little complex, and I apologize. Adjusted earnings per share in euros were €14.7 per share, up 27% on 2003. Now, that increase is slightly sharper than the increase in adjusted net income, largely due to the buyback of shares in 2005, approximately 3.6 of the Company's capital.

Now, adjusted net income in dollars was $11.2b. That's a sharper increase than in euros, up 35% on 2003 in dollars. Adjusted earnings per share in dollars rose by 40%, again due to the buyback of shares.

This brings me to the breakdown of performance by sector. A strong performance, indeed, in each of our segments. In fact, all our segments were up sharply on the previous year. Upstream was up 35%, downstream up 80% and chemicals up 114%.

And in the upstream, first of all, there was the impact of higher oil prices, the impact of higher production. Maybe I should point out that the net increase in operating income was sharper than the operating increase, due to the higher rate of taxation. This was due in particular to the discontinuation of maintenance in the second half of the year on turnarounds that were in Venezuela and Latin America. Conversely, our production in Nigeria, in Amenam, which was highly taxed.

Downstream benefited from the strong increase in refining margins but also from the implementation of the new self-help programs, approximately €200m benefit.

In Chemicals, a strong rebound of petrochemicals in Q4. The Chemicals segment was also boosted by self-help programs as well, announced in previous years.

Moving on to profitability now, here we see the consequences of the strong performance and better results. In the upstream, our return on average capital employed was up from 29% to 35% in 2004. And downstream -- in the downstream, we are higher than any -- we performed better than any of our competitors, and in chemicals, our ROACE was up to 8.5% in 2004.

In 2004 we invested €8.7b, or $10.7b if you prefer, bearing in mind that we had targeted $10b in CapEx. This figure of $10.7b included $400m for the closeout of [a cluster of] shareholdings with Gaz de France, GDF. We also have an investment in euros, and of course, when the dollar weakens, our investments in euros, when expressed in dollars, are obviously impacted. So over and beyond the GDF impact, which had an impact of €300m, our investments were very, very -- or our CapEx was very, very close to what we forecast in dollars for 2004.

Now, the capital employed decreased, particularly in the upstream, largely due to the impact of the dollar, which weakened by some 7% over the full year. And of course, one-shot amortization in chemicals for instance, for some €850m. In particular this included the complete impairment of the chlorochemicals assets, where we've announced a restructuring program. We also had to carry out one-shot impairments in the polyethylene segment.

Now, let's see how we fared with the other majors. Our performance was extremely good. You see this in terms of the return on average capital employed, which was approximately 24% in 2004. Now, this is also true. We've outperformed the other majors in earnings per share, expressed in dollars, with the possible exception of Exxon, but we are on a par with BP and Shell in dollars.

Cash flow allocation, you will see that each of our segments has generated positive cash flow, in fact, substantial cash flow. Broadly speaking, the cash flow generated was €8.5b. This cash flow has been used, of course, to pay out the dividend but also to buy back shares.

In 2004, as you know, we paid a dividend at the half, because we've actually begun paying an interim dividend, or half yearly dividend. As a result, in November of 2004 we paid an interim dividend in respect of fiscal 2004, which will of course be paid in November 2005 as well, in respect of fiscal 2004. So Total paid out 8.2% of its market cap valuation as of January 1 in the form of a dividend payout.

Now, the Board of Directors will be proposing that the General Meeting of Shareholders sets the dividend at €5.40 in respect of fiscal 2004, which is up 15% on the previous year. This is an increase of 22% in dollars.

Now, you will see how our dividend compares with those of our main competitors, be they in euros or dollars, but very clearly we have increased our dividend much more sharply than our competitors. This gives us a total payout ratio of 37% and on the right-hand chart you'll see how this payout compares with those of the other oil majors. As you can see, we are above average. Some of our competitors who had much higher payout ratios than ours now find themselves lagging slightly behind us.

That's it, thank you.

Thank you, Robert Castaigne. Let's now move on to the upstream, Christophe de Margerie for Exploration and Production.

I don't know how Robert was able to read that. He must have better eyes than I have. As our Chairman and CEO said earlier on, the Group and upstream has benefited from the favorable environment, an increase in crude oil prices of 33% over the year. We shall see what the situation was with gas. It's +14%, which is certainly fairly high, and we have some gas projects which are not at market prices. But this is also due to the increased output and our reserves.

As far as production is concerned, production is up, in line with our forecasts and our commitments, about 4% in average per year. Last year it was 3.7%. This year it's at 3.7%, which doesn't take account of the price, of course, to be very precise. If we do take account of the price effect, which is about 270m barrels in reserves, a 3.7% increase without the price effect, a price effect which is about 1.9% minus. So reported growth is up by 1.8%, up to 2.539b barrels per day. And the production would have been a lot higher, of course, if one had calculated differently.

Another factor which of course is favorable for the Group, you heard about the substantial differential in terms of Brent in 2004. We compare ourselves with our competitors, but have not suffered quite as much as others. We have Total production with a discount of $1.50, $1.60 compared to Brent, whereas our competitors have a discount of about $3.00, if not more. So we have an extra price effect of $1.50, and that's due to our production mix.

We have more light crudes than our competitors have, and gas, as Robert said very briefly a few moments ago, +14% in 2004. And we're making up the backlog, of course, which has not yet been taken into account, but here we are benefiting very clearly from the increase in prices, both on the U.S. market and on the U.K market.

And finally, of course, because this also contributes to the valuation of our production, the technical costs that we tried to keep down as much as possible. And the environment here is a lot more inflationary, of course, not only with commodity prices but service prices tending upwards.

Our technical costs are up from $7.33 to just below $8, $8 per barrel. In fact, it's $7.97 if you like precise figures. They're up $0.4, due solely to the environment, the exchange rate, in other words, and the rest is 30 cents. So the costs have really increased by 30 cents per barrel, from 1 year to the next. That can be explained fairly quickly - 10 cents on Exploration, 10 cents on OpEx and 10 cents on amortization.

We have development costs which are increasing. So you can see on this slide that we haven't managed to benchmark with our competitors in 2004, but if you look back at our level of 2004 compared to what our competitors were doing last year, unless they've reduced their costs, which I doubt, we're still doing pretty well, comparatively. And this means that we have a ROACE of 35% and we intend to remain at very strong profitability at a reference price of $25 per barrel, and at $25 per barrel the profitability would be 21%.

Now, to succeed in this business you have to have good exploration successes. That's basically where it's all at. That's where we produce the best margins, and that's where we contribute most to increasing our local presence and technological expertise, and here we've had a good year in terms of exploration. We include in that appraisal and pure discoveries, pure finds, and we're continuing to increase our production potential.

This is of course is not easy at the moment, with high crude oil prices, but we've continued to obtain permits in areas that we're familiar with - Venezuela, Indonesia, the U.K. offshore - but we've also tried to extend beyond that, and we're now back in Australia. It's only exploration for the time being. We haven't found anything yet, but there's no reason why we shouldn't. Even if we've been out of an area for many years, there's no reason why we shouldn't go back there, because the prices are higher and there are interesting prospects in this area of the world which have not yet been found.

You're familiar with the discoveries. I'm not going to dwell on them here, basically in areas that we're familiar with - Bolivia, a new gas find in Kazakhstan, Kashagan Satellite, in Nigeria. On top of that though we have new, fairly high reserves in Block 246 in Congo. We're getting back in there, Libya and so on and so forth.

But I think what is important here is that most of the appraisals will involve the development of fields over the next 2 years. Let me take something from this list - Usan, which is a new polar development on Block 222 in Nigeria; Egina, a new finding which over and above Akpo should lead to further developments; Acacia, Block 17 - that's Pole 3 which is now confirmed, the Moho Bilondo. We should be taking a decision to launch that in the first 2 months of this year, and Irharen in Algeria, Timimoun, with a few more wells. We should be able to launch a gas project fairly soon. So we confirm a large potential and plenty of new ideas in terms of exploration.

Exploration of course, is fine but we have to maintain and renew our reserves. We at the moment have a range of 940m barrels produced every year and we shall be moving towards 1b barrels of oil produced every year fairly quickly. And we have to keep that rate up, of course, simply to keep those figures going.

Now, last year with the exploration done, we are doing more or less what we need to do to renew existing reserves. But if we want to do more to continue growing, then we have to add barrels of oil to our reserves, over and above maintaining that figure, and that's what we're in the process of doing.

We have a number of major projects ongoing. In 2004, we were very close to getting there. We haven't quite got there yet. We will see what happens in 2005. But we've had an average year in terms of replenishment of reserves because the figure that you're familiar with, 11.5b barrels of reserves, to a figure of 11.15b. 11.15b, of course, is not at the same end of year price. It's at a price of about $40 per barrel.

If we take the dollar equivalent of $25 per barrel, which is the price we used last year to calculate our reserves, we are at the level of last year, slightly more. We have 20m more barrels. And you always have to look at these figures on a 3-year rolling basis, but on a 3-year rolling basis, taking into account the price at the end of the year, we have a replenishment rate of 120% over 3 years, and with the price at $25, it's 131%.

We hoped it would be 135%, 140% at the end of last year, so we're only slightly below that, and we're hopeful that that will be exceeded this year. With finding costs which are low, which have been maintained at $8 per barrel, so that means that we're continuing to have potential for high margins here.

The reserves, and I think this is what Total is all about, they are diversified. And they remain, of course, within the areas that we're familiar with, but they are substantial areas for us. It's of course -- it's interesting to put here the proven and probable reserves, and we have close to 20 years, based on current production rates. That's 19b barrels, and that means that we can be fairly confident about the future.

And we also have a number of countries with more than 1b barrels of reserves, there are 6 of them. I'm not going to go through them in detail. You have them in dark red on this slide. We know what they are. We have 4 which are between 500m and 1b, Congo for instance, which was not the case earlier on. And in yellow we have countries with reserves of less than 500m barrels of oil equivalent, and we also have new business which is being finalized in gas, as we shall see in a few moments’ time.

The target rate for production growth of 4% on average until 2008 - we confirm that here today and we extend it now to 2010. Because with the projects that you have on this slide, and particularly those in green and in red, green means oil, red means gas. So these are significant projects which will come on line in the next few months.

Looking at gas, for instance, Novatek, in which we are to take a holding of 25%, 4b barrels of equivalent oil today. That's 1b for us. They're not yet booked, of course. And in the Middle East, 3 major gas projects, the Yemen and I don't think we've mentioned this to you for many years now but Yemen is now very close to coming on line. Pars LNG is in the major [Bushehr] field, just across the Gulf from Qatar in Iran, and Qatargas II, which we're developing with Exxon.

Let's not forget the oil, Usan in Nigeria, we talked about it earlier on. Block 17 and Pole III in Angola, and Tyrihans in the North Sea. The U.K. North Sea is declining, but it's declining overall, of course that doesn't mean that we're not finding new reserves. And to bring online wells which are perhaps a little more marginal than those we've had so far, but with higher energy prices and the possibility of producing these marginal fields, that will contribute, of course, to an increase in our production and future reserves.

In the pie chart on the right-hand side, I think what's interesting here is that you have the percentages. They are significant. Conventional gas, that's the dark red, 41%. Heavy oils, 5%, deep offshore, 14%. LNG, that's increasing quite considerably, 15%, and conventional, 25% -- conventional gas 25%, conventional oil 41%. So that's in the two-thirds, one-third of it, it's about 60/40. That's an increase in gas - 60 oil, 40 gas. So basically growth, profitable growth, with ROACE of over 20%, with the price at $25 per barrel.

2011 and 2015, that's basically tomorrow morning as far as we are concerned in 2005, and we're looking at these projects both in delineation and technical areas. These obviously are projects which are not yet launched, but they are based on existing strategies and existing development poles.

In Gas and LNG, we're doing a lot on LNG, a third train in Iran, two extra trains in Bonny LNG in Algeria, LNG in Angola, which we're going to get going, and then non-LNG gas, extension of Dolphin. We're working seriously on an extension to 3b. The Dolphin Project is 2b today and doing pretty well. Southern Cone, we want to valorize the gas reserves we have in the south of Argentina, south of Bolivia as well, and Novatek, as I said a few moments ago. Novatek is what we have at the moment, but there is also considerable development for Novatek, looking forward to 2010 and the years beyond.

Caspian Sea, which of course is very important for us, this is Kashagan, the full field. There are several phases here in 2011 and 2015. We believe that we're looking at 1.2m barrels per day of production and why not more, with the new discoveries that we've made around Kashagan?

In offshore, we're continuing what I think is a success story; Block 17, smaller findings, but which could be developed marginally, Block 32, which is today not too far from reaching commercial size, and Block 2046, Akpo, where there are other findings which we can develop, Pegase in Congo. And in heavy oil, which is our fourth major development area, we're looking here at negotiations which are starting on Sincor II. Sincor II, which will be a modernized equivalent of Sincor I, which is producing 200,000 barrels per day and where we're looking at steam injection and recovery and Surmont full field and [Tabasca] in Canada with ConocoPhillips.

Let's just zoom in quickly on a number of projects, just to show that these aren't just figures on a piece of paper. It looks great, doesn't it? And these are the major projects in the Gulf of Guinea, and they are great. 3 of them have already been launched, the first 3 here, Moho Bilondo, we'll be taking a decision in the next 2 days. Akpo we hope too, Usan at a few months, and B17 Pole III should be decided by the end of the year. 4 coming online in between 2006 and 2010 and which will therefore contribute directly to the 4% average growth of production every year that I referred to earlier on.

And this means that we will continue to maintain our position of the leading producer in Africa, which is not always said. Let's not insist too much on it, but it does account for output of more than 1m barrels per day in the Gulf of Guinea.

A second zoom on Russia - Russia is of major strategic importance, particularly for gas. We're quite happy to include some oil in it as well, but it's easier to develop in terms of gas in the long term. And that's why we're taking this holding that I very much hope we shall soon finalize in Novatek, and this will enable us to have $900m roughly, 1b barrels of oil equivalent in reserves, and production which is starting as of now, more or less, and which will increase right up to 2010.

We're talking about 800m -- 800,000 barrels of oil equivalent per day. That's 200,000 for us as the 25%, and it's a way of getting into this extraordinary area of Western Siberia.

The final zoom, the Middle East, this of course is and remains the area where we have the major reserves in the world, which is now opening up more to gas than to oil. We're focusing strongly on gas in this area, and here, you have most of our projects on this slide that I touched on earlier on, and Dolphin is doing well. Dolphin will be launched online at the end of 2006. We're anticipating an increase in capacity of 1 Bcf per day. It hasn't yet been negotiated.

Yemen LNG, you, I'm sure, saw the press release yesterday about the sale of gas from Yemen in the beginning of 2009. Yves-Louis will say a few words about that later on. It's not a pleasant surprise, far from it, because we've been working on this for the past 15 years. But it does show that with patience, with determination, we can move these projects forward successfully, especially, of course, when you have the luck of having high oil prices at the moment.

Iran, it's now time to launch an LNG project opposite Qatar. This of course is in agreement with our partner. Qatargas II, we are in the process of finalizing long negotiations that we've been having with Exxon and BP, with the second train of Qatargas II. This represents a very high reserve level and coming online pretty quickly. So the Middle East of course will therefore involve an increase of 50% of our output in the Middle East by 2010 with a very strong input from gas, 40%. Which of course is in line with the 60/40 figure I showed you earlier on.

So I just wanted to show you that the 4% increase in production figure per year and increasing our reserves beyond 2005 is not just words. They are projects, projects which have already been launched, and projects which are coming online and being finalized.

Thank you very much indeed, Christophe. Yves Darricarrere to say a few words about LNG.

In view of the downturn of domestic production in the U.S. and the North Sea, we expect LNG growth to be 2.5 times higher than overall gas consumption. This will give us a growth rate for this sector of 8.5% annual average between now and 2010.

Now, our objective against this backdrop is to confirm ourselves among the major players in the LNG market. We plan to increase our LNG production by 10% per annum between now and 2010, increasing from the 7.5m tons in 2004 to 14.5m tons in 2010.

Now, in 2004, by comparison with 2003 the sale of our LNG production grew 7%. This was due to our increased supplies from our Indonesian plant, the increase of our Bonny plant in Nigeria, and the de-bottlenecking of Qatargas.

Between now and 2010, our growth will stem from a portfolio of -- a well-balanced portfolio of projects. Partly the expansions to existing plants, the fourth, fifth and sixth trains of the Bonny plant in Nigeria, for instance, the third train of the Oman LNG plant, and of course, the building of a new project, a new plant in Snohvit and a number of grass roots projects about to be launched. Christophe de Margerie just mentioned Yemen with its 2 trains, our recent acquisition of a stake in the Qatargas and of course the Pars project in Iran.

Now, by 2010, nearly 40% of Total's gas production will be in the form of LNG. The current proportion is 25 to 30%. Christophe de Margerie referred to the proportion of LNG production in our total energy production. After 2010 -- for the period after 2010, we have several projects in the pipeline, the second and third train in Iran, the second and third trains in Bonny and the Angola LNG project, in respect of which the engineering is ready to begin.

Moving on to the gas midstream, in 2004, the midstream -- our position in the midstream improved considerably, both in terms of re-gasification capacity, but also in terms of our sales to customers, to end customers.

Now, on re-gasification, after acquiring a stake in the Mexican terminal called Altamira, in March we subsequently bought a 26% stake in the Indian terminal at Hazira. Then in November we reserved long-term, in fact very long-term capacity from the Sabine Pass in Louisiana, 10bcm a year. And then we took part in the development of the Fos Cavaou terminal in France, in the form of signing final agreements with Gaz de France, or GDF.

Now, this brings me to the second aspect of our involvement in the midstream gas. These are final agreements with the GDF by way of the withdrawal from our cross-shareholdings in GSM -- GDF. It means that we now have direct control of a portfolio of 7.4bcm.

If we now look at the industrial and commercial portfolio, we have in the U.K. some 6.4bcm and of course our involvement in the Spanish and Benelux markets. If we put all of this together we have approximately 13bcm a year of confirmed outlets in Europe, or confirmed European customer base.

Now, our trading and marketing to - be it local generators or major industrials - rose by 50% in 2004, increasing from 10bcm in 2003 to 15bcm in 2004. So this reinforced access to the market means that we have growth levers in the field of GNL production. Thank you.

Thank you, Yves-Louis. Jean-Paul Vettier on Refining and Marketing, if you would, please.

Good morning, ladies and gentlemen. The downstream results in 2004 have increased very sharply because the operating income was up from €2b in 2003 to [€3.2b] and up from €1.5b to €2.3b. The environment was good for refining and marketing, particularly in refining, with a contribution to the result of more than €1b.

Now, this improvement has not been reflected in our internal benchmark, TRCV, which was designed about 12 years ago, and as we've seen in 2004, no longer sufficiently reflects the reality of the value of our products. Nor does it reflect sufficiently the discrepancies in prices between high-sulfur crudes and light crudes. So you see here the extra contribution compared to TRCV.

And I might add that we are looking at how we are going to adjust the TRCV figure by the middle of 2006 so that it reflects the markets more precisely between 2005 and 2010. The dollar of course has been weak, and we have -- the marketing environment has only deteriorated the result by €200m because throughout the year, the product quotes were changing all the time. And in a very keen competitive environment, it's difficult to pass on the final increase to the final customer. So there has been a slight visible effect in 2004, accounted for by €200m.

But we do of course have our self-help programs that we launched during 2003, the ambition program, which contributed to an improvement in our result by about €150m. All this led to a high profitability level of the downstream business of 25%. And with the same approach as was referred to earlier on, with a reference environment with refining margins of $15 per ton and an exchange rate that we had on average in 2004, we would still have a profitability of 13% which is pretty good, of course. Now, in the next few years, is there a downside risk with a movement to $15 per ton of refining margin? I don't think that's very probable.

2004 has also seen changes in our refining capacity to markets and to new specifications. The Auto Oil Program, adjustment to specifications, has been launched over the past 3 years and will be completed in the next 2 years with an impact in terms of CapEx which will be lower than in the last 3 years. You'll see this on the dark red bar here. We're at the end of the investment program here.

We still, of course, feel that it's necessary to improve safety investments and over and above normal maintenance we need to make sure that maintenance is carried out in terms of increasing safety, especially where these installations have now been up and running for the past 30 years, as far as most of them are concerned.

Energy efficiency is an area which will require slightly higher investment over the next 2 years, given the probable trend in energy prices. And therefore we shall reduce our profitability requirements in that area slightly because, of course, we have to reduce our emissions, particularly CO2 emissions, and they will be a partial justification for that investment.

The performance valorization area, of course, has increased quite considerably over the past year. This is because of a need to adjust our refining capacity to adapt to new market trends for distillates in general and for diesel fuel, by investments that we've already referred to in Normandy, in a steam-cracking area, but also in a new installation which is more adapted to the current trends of the market.

The investment here is in high pressure lubes, and de-sulfurization, or hydro-processing facilities, because there has been an increase in the price discrepancy between sulfur, high-sulfur crudes and light crudes whereas the demand for white products is increasing. And we therefore must adapt our refining capacity to these new market demands in the new few years, and that's why, over the next 3 years, we shall be increasing investments of €3 per ton installed down to about $5 per installed capacity per year from 2005 to 2008.

Refining petrochemical integration is moving forward year after year and it's a factor increasing our profitability. This looks a bit complicated but it's fairly simple when you're familiar with the increasing demand for propylene. Some of that propylene comes from refining and that in refining, you can produce more or less propylene, including changes in the catalysts.

We are now, in fact, producing more propylene from our refineries and changes in catalysts will make it possible to do even more in the next 2 years. Hydrogen, of course, is absolutely essential to make our products less polluting, to get more sulfur out of them. Hydrogen is necessary. Steam-cracking produces hydrogen and therefore that's another area that we need to develop very strongly.

Gasolines will contain less and less sulfur in the future. A large part of that sulfur comes from FCC gasoline, so either you can purify that or when there is a link between refining and petrochemicals, you can send those sulfurs into steam-cracking, and that is another way of integrating refining and petrochemicals. It's also possible to increase links in aromatics with the aromatics content of benzene, which has fallen quite considerably over the past 2 years, as you will yourself realize. Whereas in petrochemicals, as we saw in 2004, the market was fairly tight in benzene. And the technical positions are favorable here, and we therefore, as I said, intensified integration between refining and petrochemicals.

A lot has already been done. A lot will continue to be done, in the pipelines, for instance, that we're building between the Provence refinery and the petrochemical Naphtha plant which will come online in 2006 in that area. And we have a number of other operational platforms in which we're investing, in Feyzin, Antwerp, Normandy, Port Arthur, as an example.

In marketing, the sale of refined products, I said that volatility was fairly low in 2004. Yes, in a very competitive environment, with increasing price increases, we've had stable results, basically. And I think this is due to a good balance in our marketing effort. Geographic balance, first of all, between Europe and overseas - Africa, Caribbean and French overseas territories; specialties, which are now more and more important in marketing - LPGs, lubes, specialties and other products.

I think another thing here is the specialization of our service networks. The reduction in fixed costs per cubic meter sold, the increasing efficiency of our self service station stores, the efficiency and effectiveness of our loyalty programs, and better contacts with our customers.

In terms of profitability, I think, again, a good balance, a balance which we are constantly having under review between development investment and a discipline in the use of capital employed, particularly in areas like Europe. But also, I think, fairly aggressive investments to boost our outlets in the Caribbean for instance, where we've made inroads into Jamaica, Puerto Rica. Those, of course, are incremental increases for a company like Total, but it does round out our marketing effort.

The same is true in Asia, where we have worthwhile developments in Pakistan today. And tomorrow we hope to have the approval to do that from the Chinese authorities in China in partnership with a Chinese distributor - 250, 300 service stations in and around Beijing.

Capital employed has remained fairly stable, as you can see, in spite of the CapEx but thanks to a fall in working capital requirement. And that fall in working capital requirement, of course, is not easy to achieve. We've done it in a very determined way and the contribution to that is the reduction of days outstanding from 27 to 23 days over the past 3 years.

This means that we've managed to maintain profitability on the downstream, among the best of the majors in 2003. We had a good level of profitability on the downstream business and I think the 25% of 2003 -- 2004 rather, confirmed that that is still the case. It's also due to, as I said, the balance between development CapEx and clear control of capital employed and the balance between Europe and the areas in which we're making strong inroads like Africa, the balance in products, particularly specialties, and a number of focused developments that I referred to earlier on.

We believe that the action plans, and there are many action plans that we've launched in the downstream area over the past few years, and they too are bearing fruit and make us confident that we will continue to remain very profitable. And coming back to the reference environment of $15 per ton, perhaps we will return to that in the next 2 years, perhaps we won't. But even with that, by increasing our profitability programs, we consider that we can improve profitability by a further 2%. So that even if we do have $15 a ton, we can have profitability of around 15%.

Thank you, Jean-Paul. Francois Cornelis will now address his presentation of the Chemicals sector.

Well, as you already heard, the environment was much more favorable for Chemicals in 2004 than in 2003. In petrochemicals the year was marked by a sharp increase in the margins on aromatics, particularly very high benzene prices. There was also a sharp increase in margins in Asia.

The second half year was marked by an upturn in European margins. As a result, the operating income shows the effect of the strong contribution of Samsung, our joint venture in South Korea, and our results improved sharply in the fourth year when the U.S. and European clients accepted the price increase we passed on.

In Intermediates we had margins on very good costs that were low but volumes actually increased in the course of the year, thanks to which our results improved. In the Specialties there was no slowdown in the second half year, which proved to be just as good as the first half year. In fact, the operating income for all our specialties was up for all our specialties, I should say, over 2003.

In 2004 the petrochemicals cycle turned up. It would appear that the global production capacity exceeded 90%. As a result, our gross margins increased month-on-month. In 2004, we also reaped the benefits of our reliability programs but factoring out Samsung, we had production records in ethylene in particular, up over 10% on the previous year, and secondly, polypropylene sales, which were up 3% on the previous period.

Now the 2005 petrochemicals budget will still be devoted to improving our platforms and to improving our reliability program. However, for the period 2006 to 2009, our budgets should focus more on the Middle East and Asia, with large de-bottlenecking projects for the Samsung joint venture platform in Korea. And we also plan to work on catofin -- the catofin plant in Qatar, which will be a combination of polyethylene and de-bottlenecking.

We had a very good year in 2004 with a strong growth, 5% with [Bostik], 5% for Hutchinson, 9% for [Atotek]. Operating income was up from 430m to 490m. Now, as we really focused on ROACE and didn't make any major acquisitions in 2004, the period generated strong cash flow, particularly in Specialties. We expect to be able to uphold growth of over 5% in years to come, largely due to a substantial R&D budget of 5% of revenues and over 6% at Atotek.

Now, in February last we announced the creation of Arkema. So 2004 was largely devoted to reorganizing our Chemicals sector, and more specifically, to the spin-off of the Chemicals sector into 2 separate entities - an entity called Arkema and a petrochemicals entity called Total Petrochemicals.

This project was announced in February and planned Arkema to be created in October, which we did. Negotiations with the trade unions finished in September. The staff were appointed on October 1 and organized into 3 divisions, organized as follows - in the chlorochemicals, the objective is to reduce the breakeven point and to be able to post profits even at the bottom of the cycle. That has enabled us to conduct meetings with the staff representatives for the reorganization of 3 production plants - [Sanfin], [Jari] and Lyon.

As for industrial chemicals, and particularly fluorinated, oxygenated and acrylic products, all products were very well positioned. We are eager to develop worldwide. As a result, we have devoted our budget to improving our presence in chemicals in the U.S. We also plan to improve our portfolio, which is still operating at low margins and with varying degrees of quality.

Now, the Arkema spin-off announced for 2006 has therefore been confirmed. Now, that means that by 2007 to 2009, the capital invested in the Chemicals sector should be devoted 57% to petrochemicals, slightly, or 40% to specialties. Now, the ROACE in the mid-cycle improved in 2004 due to 2 effects. First of all, the full year effect of the Samsung joint venture, which was much higher than our petrochemicals average profitability. But secondly, the benefits of our self-help programs - 2 positive effects.

Now, we plan to continue these self-help programs and by 2007, in mid-cycle, we expect to achieve an ROACE of 12%. Again, due to the self-help programs that improve profitability by an annual average of 1%, but also due to the change of portfolio and notably due to the spin-off of Arkema.

Thank you, Francois. Let me now just say a few words to conclude. As to our investment program first of all, for 2005 we've earmarked a large CapEx budget, $12b - $11b basically organic growth and $1b for the acquisition of the 25% in Novatek.

The major characteristics of this CapEx program is, first of all, to continue to invest in growth of the upstream, that's 70% of our CapEx, with the major projects that you heard about this morning. Downstream, an increase in CapEx to a certain extent, adding to the usual CapEx that you've seen over the past few years, meeting new market specifications. But we're also trying to increase our margins by having more conversion facilities, and a fairly prudent CapEx in terms of chemicals, 10% of our CapEx in 2005.

As guidance for the following years, what we're basically looking at, our CapEx budgets are between $10b to $11b per year. That's not very different to what we said last year at this time. $11b isn't very different to the $10b that we talked about last year. Because of course, we have to take into account the fact that the dollar has weakened and it was $1.25, whereas last year it was $1.10. So when you consider that a third of our CapEx is in the euro area, so you have to convert that into dollars, and then of course with the IFRS standards, we capitalize the turnaround in refineries and petrochemicals.

So basically, we're talking about the same order of magnitude. That being said, if we are able to get involved in larger projects and other projects than the ones we're talking about at the moment, and which are clearly value-creating projects under our price environment, we may very well invest a little bit more.

What about our cash flow allocation policy? Let me say a few words about that. On the left hand side of this slide, you have a number of scenarios. The most prudent is $20 per barrel and $15 per ton for the TRCV margin. The most optimistic strategy is $30 per barrel and $30 per ton for refining margins. You may find that that is perhaps a little prudent but we are prudent in our forecasts. We could perhaps have extrapolated a bit more but we didn't.

What basically does all that mean? I think what it means is that we shall be generating cash of between $15 to $20b a year and in order to spend that, we have CapEx assumptions of about $10b a year in the next 2 years, and dividends which will be about $5b per year. So if we're in these favorable scenarios, we'll still have available cash flow, even with the large CapEx program that we already have and that we are continuing. And we therefore will continue to be able to buy back shares.

Buy back shares is the adjustment parameter. If we have more cash we'll be able to buy back more shares than we have in the past 2 years. But we will continue to be very careful about our investments, in order for us to agree to increase our investments. The return on those investments will have to be very attractive.

2 or 3 other messages - we shall stick to our guidance in terms of a debt to equity ratio, 25 to 30%. At the end of 2004, it was 26.7% but that's about 31% under IFRS, so we shall reduce that slightly. But we're basically talking about fine-tuning here.

As far as our stake in Sanofi-Aventis is concerned, we do not intend to divest ourselves of that holding in the near term. It's a good investment. There is a good pipeline of products in Sanofi-Aventis and we believe that, therefore, the value of our holding will increase. There is, of course, a tax issue here and there are likely to be changes in the tax on capital gains. So there's no point in rushing to cash in on those capital gains at this stage.

As far as the distribution for the payout ratio is concerned, you may smile if I say that our target payout ratio in the medium term is 50%. It has fallen, and fell to 40% in 2003, 37% in 2004. But we do intend to say 50% payout ratio in the medium term, even though the environment may not be as favorable as it has been in 2004. So there is still potential for an increase in dividends.

A final point about growth strategy; our growth strategy has paid off so far. Over the past 10 years, for instance, we've -- if you take Total's results 10 years ago, we've multiplied them by 20 over the past 10 years. Of course, we're not the same company as we were 10 years ago. With the 2 mergers, we've more or less tripled the size of the Group, but we've multiplied the size of the Group by 3 but we've multiplied the results by 20.

And I think what that means very clearly is that there has been a strong increase in production, 4 to 5% a year. Now, that of course has considerable combined effect. There's been a fall in the breakeven point, a strict discipline on technical costs, which has paid off. The environment, of course, is more favorable. That of course is only one of the factors among many. And I think basically what this amounts to is that our strategy has been a winning strategy and we see no reason to make major changes to it, compared to what we've been doing over the past few years.

What this means basically in terms of upstream is that we shall continue to combine growth with profitability, with the coming online of all the projects you've heard about this morning. The general characteristics of all these start-ups is that they basically focused on large fields which enabled us to extract good profitability whatever the environment is. And we shall continue to do that, even if people say "well, of course it's more and more difficult to find new reserves". Well, I think if we explore the number of fields that we are exploring, then we can be confident that the results will come. And with Novatek we hope to finalize that fairly quickly.

Downstream, you've heard this morning what we're doing. I think perhaps there was a slight change in the strategy, inasmuch as we intend to make more investment in refining capacity because of all the changes that we need to make to our refining capacity. And we hope that our margins will remain not necessarily as high as they were in 2004 but very comparable to what they have been in previous years, with development of our sales and marketing in Asia, in Africa and in the Caribbean.

And in Chemicals, we have of course taken some time to decide on our strategic options, but now we have done that and we are implementing those options with a growth in petrochemical output, focused specifically on Asia, with the development of specialties, which are doing well, and with the spin-off of Arkema in 2006.

So I think, overall, therefore, this company is in a sound financial position. It has a great strategy. We have management teams which are very solid. We also have a lot of younger managers coming to the fore, and I think you can therefore trust in our capacity to continue to grow and be one of the most competitive players in the oil industry.

Those are the messages I'd like to leave you with this morning, ladies and gentlemen. And having put those messages across to you, I am, with the members of my management team up here on the rostrum, prepared to answer any questions you'd like to put to us.

Okay, do we have a first question? We do, from the second row.

I've got a couple of questions on the upstream. Firstly, on your new production [targets] of 4% per annum to 2010, if I understand you right, in 2010 you're including Novatek, but in the base year you're excluding Novatek. If that's right, can you say, broadly speaking, what the growth rate might look like, excluding Novatek.

Secondly, on unit technical costs in the upstream, you're at $7.97 you say in 2004, which is close to the maximum level you targeted of $8 per boe previously. Are you still confident that you can maintain unit technical costs below $8 a barrel or may they go up from here?

I'll answer your first question, and then Christophe de Margerie will answer your second question. You're quite right to say that in the way we have calculated production growth, the starting point is indeed 2004 which excludes Novatek. Now, the arrival line that in 2010, theoretically includes all the new major projects we commented. This is why we have greater visibility through 2008, 2009 and 2010. We have 3 large LNG projects. We have the Novatek project, and, of course, there are a certain number of developments in the discoveries and oil fields.

So if everything goes to plan, our growth, our production growth will be slightly above 4%. If 1 of these projects fails to materialize our growth could be in the region of 4% or fractionally below 4%, not to mention the fact that a lot will happen between now and 2010. There could be a number of other players involved in the landscape, needless to say, but we are confident about the production growth trend of 4%.

I think the message we really wanted to get across is that we have a number of major projects that are nearing maturity, if I can call it that. I can't guarantee that all 5 or all 6 will materialize by 2010, but broadly speaking, everything is going well, and the ballpark figure would be production growth of 4% over the long-term.

Well, we'll see. When you look at what we have in the pipeline for 2010 to 2015, I know that's further afield, but one could well expect us to continue on that growth trend between 2010 and 2015. Christophe, will you take the question on technical costs?

Well, I would have preferred to answer the first question, but maybe if I could add, concerning Novatek, Novatek isn't a company we're acquiring like TMKBB. It's really a joint venture, and we'll be a subsidiary and when we started negotiations with Novatek, what we were seeking to do was to acquire a stake in the form of a joint venture. We weren't considering integrating Novatek in the whole oil sector. It's really a project but I'm saying this before the Chairman and the Executive Committee.

If Novatek would fail to materialize, we would be looking for something comparable, projects of the third type, as we call them. That will enable us to achieve our growth target independently of exploration and production. Nonetheless, I will answer your question on technical costs.

As I said earlier on, the 0.7% increase to almost $8 a barrel was largely due to the environment. If the current exchange rate continues to prevail, we will not achieve that, but if the euro were to weaken slightly, our technical costs will be much closer to expectations. What I would like to say is the 3 x 10 sense in exploration services and [BD&A].

Now, in exploration, the 10 centimes are 0.72 which becomes 0.82. I hope, and I'm saying this in front of my Exploration Director, if we can find more barrels, even at 0.90 or 1, we'd be very happy to find those barrels. So on oil prices, even at $25, that's still very acceptable. I think that's really what I was driving at. You're telling us that we felt that $8 was the maximum and that we're nearly there, but now we've got a time when the barrels are at $17 a barrel.

The current price is $44. I'm not saying we're going to let technical costs go, but there is a direct relation between the 2, so our operating expenses, leaving aside currency effects, are such that while contractors are losing out on conventional areas but in deep offshore our heavy oil sectors, which are high-tech areas, there aren't many contractors and there is a lot of demand. So there is upward pressure on prices, clearly in evidence in services, so we'd be maintaining these costs.

Now, though it may be conservative to continue to work on the hypothesis of $25 a barrel, this is another way of telling our people that just because the oil prices are much higher doesn't mean that we're going to let our technical costs run loose, but if oil prices stay at $44 a barrel, I can assure you that we will not be keeping our technical costs at $8 but we will be earning a lot more money than we do today.

Another question?

My name's Bouvechy (ph) from Agil. Is it meaningful talking about oil at $25 a barrel when the current price is almost $44 and in view of the approach you expect from Asia, China?

I think the general awareness of the fact that the demand for energy is going to be high. We can expect prices to remain durable, at least in the region of $25. Well, it's meaningful in 2 ways. First of all, in-house, we're not going to let prices soar. Now, that's important. That's an important message to get across to our staff in all 4 corners of the world, so we will continue to tighten the belt on costs. Just because oil prices are high doesn't mean that costs are not worth working on, on the contrary.

And the second area in which it's meaningful, one may or may not agree, but that's really a matter of personal opinion. People who have been observing the oil sector over the last 30 years or so are aware of the fact that the fluctuations in oil prices have been so sharp and the forecasts have been so misleading that even though the general feeling today is that oil prices will remain durably high, we can never be entirely sure that they will, so always say for future, be cautious.

Now, when we carry out our economic analysis, we have always based our hypothesis on an inflated scenario, so this is based on 2% inflation a year. When you look back over time, you see that during the first half of the '80s oil price were in the region of the equivalent of $80 to $90 a barrel on today's prices.

Yes, if I could just add on to the question about prices, it's very difficult to forecast prices, but you talked about a very high rate of utilization of your production. Is there any connection between that and prices? Could it be that you're not meeting demand? Could that be decreasing prices, in fact, just to give me a better understanding of price levels?

Yes, there is undeniably a relation between the 2. When we analyze our monthly results our Trading Director shows us the curve that is the correlation between oil prices and the level of oil stocks and products. Now the curve has always worked well, but has ceased to work well for almost a year now.

This is mainly due to the fact that there is very little spare capacity at present. Indeed, there is ongoing concern about the fact that if anything goes amiss in an oil producing country, and unfortunately, this is something that happens quite frequently, well, oil prices are hiked up another few dollars, and this is how oil prices have risen so sharply over 2004.

I feel if we don't increase our spare capacity quite significantly, I expect that oil prices will remain relatively high, partly due to the concern about any stoppage in production in oil producing countries, and of course, it's not very difficult for OPEC to regulate oil prices at a very high level. Looking at it another way we could increase the spare capacity in several ways, increased CapEx for new production facilities, and if there's ever any slowdown in growth. Let's not overlook the fact that growth has slowed down. In fact, demand actually has been decreasing in Asia for a year now.

I think that's about what I could add. Could we have the next question please?

Savile Le Francois (ph) from Network [indiscernible]. First of all, Christophe de Margerie when discussing Novatek, explained the possibility of the project not materializing. What about the white paper that consists in limiting the holding of foreign companies? Could this be a hindrance to your project? Secondly, could you give us updated information on oil prices at €45? What would the effect be before and after tax?

What are the effects as oil prices increase, and the final question on exploration, in view of the fact that the replacement rate was below 100%, at least by SEC standards in 2004, are you inclined to earmark more funds for exploration in 2005?

Let me answer that last question, and I'll give the floor to Christophe de Margerie. For several years now, we've been saying that our replacement rate for exploration and appraisal can be in the region of 100%. Now, this is what happened in 2004 because the replacement rate, according to SEC standards, if you take a barrel at $25 at the start of the year and then a barrel of over $40 at the end of the year, you haven't really got a good reflection of industrial performance in the course of the year.

So the important thing is the real significance of replacing reserves, the significance this has taken on. So the replacement ratio, we have calculated very accurately at 102% for 2004. Now, we did that because we haven't generated any agreements of the type of agreements with the oil producing countries whereby we have regularly had access to additional reserves. Now these are areas and there are years where we have a lot of agreements of this type, others where we have much fewer.

This is why, with its great wisdom, the industry has tended to reason over a 3-year period. Now, as you know, there's been a lot more tension on the reserves in recent times. We take a close look at annual reserves and 3 year reserves, so I think it's important to get back to industry standards and over a 3 year period we always a third type of agreement, third type business that occurs. We have 1 or 2 occurring right now.

So by comparison to what we have been presenting over the last few years, I think we're still on the same trend, and we're still capable of increasing our reserves in order to boost production growth. Christophe, would you like to take the question on Novatek?

Concerning Novatek, I don't want to be interrupted as being in any way pessimistic. There's no reason why it shouldn't happen, but one might have expected Novatek to be in our reserves at the end of the year. They are not. This is just to show you how projects of this magnitude can completely alter statistics. We have 1 to 2 a year. We hope that the Yemen project will go through in a few months time, but this time last year, I don't think I even mentioned Yemen, which just goes to show that 1 major project can be replaced by another.

Now, concerning Novatek more specifically, we're still awaiting the decision of the anti-trust authorities that have raised a number of additional questions subsequent to the reorganization of Novatek and in particular, the acquisition of new minefields. Now, the authorities were familiar with that. We expect that they will complete their analysis very rapidly, and that the outcome will be positive.

As for the 51-49, yes, we'll be asking for 49%, because that is the new rule. But quite clearly, what the Russian government wants now is that in the case of new businesses, and I'm not talking about acquisitions. In the case of new businesses, foreign investors systematically work with a Russian shareholder owning 51%. Now, if the partner's good, the project is sound, this is what we do in most of the OPEC countries. We work with the national oil company.

Let's not overlook the fact that Russia does produce oil. One does tend to overlook Russia, but Russia is yet another oil production country, and it is perfectly normal that the Russian government is eager to associate its oil companies with the development of the oil industry in Russia.

As for the sensitivity to our oil prices, crude oil prices, yes, with the euro at $1.25 and at the variation about $25 a barrel, every fluctuation of $1 would be $450m and on net income, the effect would be €200m. Now, this sensitivity doesn't really change up to $35 a barrel and then declines, but only very slightly.

Have we another question?

Dominique Patry from Cheuvreux, a question on your dividend policy. Your dividend has been increased by 15% for the 3 years, so could this mean that your policy, a somewhat aggressive buy-back policy, is going to change in any way?

I was expecting that question the other way around, to be honest. No, when you look at the payout, you get the impression that we're not fully in keeping with our medium-term objective. No, it's 15% increased per annum on average over the last 4 years, in fact. So this year's increase is very similar to previous increases. We had a very sharp increase just before the merger. That was in 2000 in respect of '99, but bearing in mind that the dividend in '99 was not that good because '98 was a poor year.

Now, I'm not guaranteeing that we will continue to increase the dividend by 15% a year for the next 2 decades, but theoretically, we do have some leeway to continue to post a positive dividend growth, and we expect to be able to earmark substantial funds for our share buy-back program.

Well, the share buy-back is the variable in the equation, depending of course on the impact of the environment on our results, and depending also on investment opportunities that may or may not arise. Just because we have been top of the chart in remunerating our shareholders in 2004 doesn't mean we should continue to do so. If we have satisfactory projects, we've nothing against increasing our investment in acquisitions.

Next question?

[Jean-George Else]. I'm a portfolio manager. On your slide on Page 12 concerning maintaining reserves at a satisfactory level, you have discovery costs at 0.7 for you and 2.5 or even 3 in the case of your competitors. This is on Page 12. Could you explain that rather large variance?

Christophe de Margerie, I know you're very modest. Could I call on you to answer that?

Unfortunately in 2003, 1 of our competitors actually outperformed us, so we weren't best in class. You need a magnifying glass to see that particular competitor, so it was up to $0.8, up 10 cents in 2004. As I frequently say, if I had more barrels at my disposal, we would be prepared to accept this price changing slightly.

Now, insofar as we have not got the capacity to find more, it's in our interests to keep this figure as low as possible. The lower it is, the more margin we have, admittedly to share with the oil producing countries, but the more we'll keep our technical costs down. Now, that's the way I'd like you to think of it. It's important to keep the figure down, but if instead of 900m barrels I have 1.2b, I would be quite happy, and even the Chairman has confirmed that we'd be quite happy to accept an increase from 80 cents to 90 cents.

I'd like you to take it that way, because 1 of our competitors reproaches the fact that our figure was good because we hadn't discovered very much. I think our results have shown you exactly the contrary, but of course you can interpret figures in all sorts of ways, as you know. We are happy with the 80 cents. We are happy with the 900m barrels production. I think our explorers are fundamentally very good exploration people. I'm saying this in front of the Exploration Director. We'll just ask them to continue to be very good exploration people. That's all.

Have we another question?

[Achim Stockogen]. I have a question on the balance between growth and profitability. It appears to me that you have focused less on profitability with no major guidance for the future. Could it be that this is because growth is more difficult now that costs are rising? Could you give us your profitability targets for the future?

When you talk about growth, profitability and that we are less focused on profitability at a time when we have a return on average capital employed of 24% for the Group, 35% in upstream, 80% in downstream, I don't think you can say that we've let up or eased up on profitability. I think if you were to reason on the basis of the same reference environment, okay, we'd have to look at the consequences that a more favorable environment would have in terms of costs. You can't just look on the 1 aspect and not look on the other side.

In our new reference environment, in fact we commented on this in various parts of our presentation, on our hypothesis of $20 a barrel or $15 a ton refining margin and a euro at $1.25, there's 3 conservative hypotheses. On this basis, our profitability objective for the various sectors between now and 2007 and 9 is to be in excess of 20% for the upstream, 15% for the downstream and 12% for chemicals. That's in the mid-cycle.

Now, the figures will not be changing for the downstream and chemicals but upstream has simply benefited from the fact that there's been a - or it's been affected by the fact that there's been a slight increase in technical costs, to a lesser extent than those of our competitors.

Next question in the front row?

I have a question on the adjustment of buy-backs on the 1 hand, and your dividend. Now, your dividend is not increasing as sharply as your income. Does that mean that you're allocating the difference to the buy-back program, or if not, could you tell us how you balanced the 2?

Well, in 2005, the situation will be straightforward. In view of the overall dividend of €5.40 for 2004 and the interim dividend of €2.40 paid in November, that means that next May, we will be paying a final dividend of €3 per share. That is the basis issued in respect of 2004. Now, last year for the first time, we decided that we would pay an interim dividend in November equivalent to approximately half of the previous dividend so you know now virtually what you can expect the dividend to be in November 2005, and of course it's really all regulated by gearing, with the gearing kept at between 25 and 30.

We will continually adapt all year long on the basis of expenditure if we have [invests] in, say, our Russian project, you will see that for a certain period of time we'll be buying back a few shares. We also take into account trading conditions. We do not want to influence balances in the stock market, but you know the figure at the end of the year. That's how we regulate the balance on an ongoing basis. On average, over the last few years, I think we have bought back a maximum of 3.5% to 4% a year.

Maybe 1 last question then, from the gentleman here in the third row. I don't think this gentleman has an opportunity to ask a question yet.

Thank you, [Jean-Jeff Lemarge]. Would a regular increase of $2 a barrel on top of today's prices, between now and 2010, would that have a significant impact on the growth of your hydrocarbon production if the crude oil price were to increase to $60? What about the impact on your production sharing costs? How will the effect be on your production growth target of 4%?

The second question, of lesser importance, maybe, could you tell us about what would appear to be a slight stand-off maybe, with Angola? And thirdly, I'd like to underscore the, let's say, the hierarchy of ROACEs. I think your excellent ROACE puts you at the top of the league table, but this is probably because of the small denominator rather than the large numerator. Would you like to comment on that?

Well, let's answer those questions in the opposite order and concerning the ROACE, it's true that when you look at the sector such as the downstream sector you have to admit that we have kept a very strict control on capital employed. And that has enabled us to contain our ROACE particularly well, keep it at the top of the league table. This is something we did very intentionally.

Maybe it's because in all 3 former entities of the Group, we all experienced a series of periods during which the downstream went through difficult times, so we wanted to keep a very tight rein on capital employed. I think we were quite right to do so, and we have reaped the benefits. Now, that doesn't prevent us focusing on acquisitions even though they may have a short-term negative effect on ROACE.

I don't think your comment applies in any way to the upstream because the capital employed in upstream has been increased rapidly and the results in income have increased even more rapidly. So I think that would really have to be analyzed sector by sector. Christophe, would you like to say a few words about the situation with Angola?

Well, the Angola situation is mainly a political situation. Insofar as possible, we endeavor to avoid commenting on the situation. It's not entirely in our hands. It's really an issue between the French and Angolan governments.

Now, we don't see how this could hinder our development in Angola. There was the Block 3 episode, which I'm sure you will recall. This was for the renewal of a concession that Angola was entitled not to renew. Now, we were very disappointed, to say the least, but otherwise we received approval to develop Rosa which was the important aspect from our point of view. As for the remainder, I think you really need to speak to the French Ministry of Foreign Affairs.

And this brings me to the more delicate issue of oil prices. I'll give you my answer and you can analyze it whatever way you want, but we can only reason so far. You suggested a price, a 2010 price at $60. Well, in 2004 we lost $48,000 a year, which was the difference between the 2.825, or 5.83 and the 2.653m, so we lost 48,000 barrels at $9.5 a barrel, which is approximately 5,000 barrels a day. Now, can that continue indefinitely? Well, we'll have to, I think, take a close look at all our contracts, 1 by 1 but $5,000 a day for a barrel is probably not too far from the truth, but I think we'll have earned a certain amount of revenue in the meantime.

Now, at $2 a barrel a year, that would mean a slowdown of 0.4% of production growth. Now, that's all quite artificial. It's all really just mathematics. You will see that this will have a 6% or 7% positive impact on income. Well, at $60 a barrel, I think if we're able to produce more barrels, I think the replacement rate will increase. Technology will improve as well, so it isn't bad news that can be isolated and mean that we will reduce our production. You can't isolate it like that.

As for our profitability targets, we reduced our objectives, our ROACE targets to over 20% from the current, but our costs are not $25 a barrel. Now, we're not going to recalculate. I mean, it's impossible to know what our costs are at $25 a barrel, but remember that current prices are $44 or thereabouts. I'm not going to say that's not serious but we are not in a $25 a barrel environment.

Okay, it's already 1.00 pm, so I propose that we bring the Q&A session to an end, and why not continue our discussion over a cocktail in the next room? If we can continue to answer your questions, we'll be very pleased to do so. To all of you, thank you for attending.