巴西石油 (PBR) 2007 Q4 法說會逐字稿

Ladies and gentlemen, thank you for standing by and welcome to the Petrobras conference call to discuss the fourth quarter and fiscal year 2007 results. At this time, all lines are in a listen-only mode. Later there will be a question and answer session and instructions will be given at that time. (OPERATOR INSTRUCTIONS) As a reminder, this conference is being recorded.

Today with us we have Mr. Almir Guilherme Barbassa, CFO and IR Officer and his staff. At this time, I would like to turn the conference over to Mr. Alexander Fernandez, Investor Relations Manager of Petrobras, who has some additional comments. Please go ahead, Mr. Alexander Fernandez.

Good morning. This is Ted Helms. Welcome to our conference call to discuss fourth quarter and the fiscal year 2007 results. We have a simultaneous webcast on the Internet that could be accessed at the site, www.petrobras.com.br/ri/english. Additionally, on the webcast registration screen, you may download and print the presentation and download the financial market report. Also, you can send your questions to us by Internet, clicking on the icon "questions to host" any time during this event.

Before proceeding, let me mention that the forward-looking statements are being made under the Safe Harbor of the Securities Litigation Reform Act of 1996. Forward-looking statements are based on the beliefs and assumptions of Petrobras management and on information currently available to the Company.

They involve risks, uncertainties and assumptions because they relate to future events and therefore depend on the circumstances that may or may not occur in the future. Investors should understand that general economic conditions, industry conditions and other operating factors could also affect the future results of Petrobras and could cause results to differ materially from those expressed in such forward-looking statements.

Finally, let me mention that this conference call will discuss Petrobras results prepared in accordance with Brazilian GAAP. At this moment we are unable to discuss any issues relating to U.S. GAAP results.

This conference call will be conducted by our CFO and Investor Relations Officer, Mr. Almir Barbassa. He will comment on the Company's operating and financial highlights and the main events during this quarter. Afterwards, he will be available to answer any questions you may have.

Mr. Barbassa, you may begin.

Good morning, ladies and gentlemen. It's a pleasure to be here again with you discussing the results of the exceptional year of 2007 for Petrobras. When we are -- were able to give a total return to our shareholder greater than 130%. So the exploratory results that was the greater responsible for such a success of the Company was really a very good year in terms of exploration.

But let's begin by reviewing some of the major factors that drive our results year-over-year and quarter-over-quarter, starting with production. Next slide.

In this slide, you can see that production for oil during the full year was virtually flat. The contribution from the new production systems added 192,000 barrels to -- but this was offset by our natural decline rate, leaving production growth for the year at less than 1%.

As you know, the fourth quarter saw the introduction of four new systems but they had little impact on the year's averages, adding only 10,000 barrels per day. While not shown here, production of natural gas was equally flat.

In the next slide, you can see that these new units were not enough to offset the natural decline during the period. Production from P-52, P-54 and the FPCO -- FPSO-Cidade de Vitoria has only begun to ramp up this year.

The sum of current daily production from these units is currently around 150,000 barrels per day. As these units increase production, we expect to see health growth for 2008. As you know, we produced over 2m barrels per day on December 25, a very nice Christmas present.

Turning to the next slide, we published our reserve figures for the year ended December 31, 2007. As you can see, we have again comfortably replaced our Brazilian reserves, both on an SEC and SPE base. Interestingly, SEC reserves grew more than SPE because the ANP indicated we could extend our production in particular blocks as a condition to make additional investment in that block. This allowed us to book additional reserves. This is a very positive precedent.

Regulatory changes in Ecuador required us to take additional write-downs in these countries, thus reducing our international reserves. We still have a very health reserve to production life of 18.9 years on the SPE basis, and 14.5 using SEC criteria.

As an oil company, we are fortunate and somewhat unique in that our challenge is not replacing reserves. Rather, it is in developing improved reserves, appraising new discoveries with massive potential and exploring in promising frontiers that have not yet been drilled.

Turning to production costs in slide five, you can see that U.S. dollar lifting costs rose by $0.95 quarter-over-quarter. Including government participation, the increase was $3.03 per barrel. At the same time, the price of oil rose by almost $14. Almost half of the increase in lifting cost is attributable to the valuation of the Real. Lifting costs as a percentage of the price of a barrel of oil declined during the period. These costs now represent less than 10% of the price of a barrel of oil.

Lifting costs, when expressed in Reais were up BRL0.58 per barrel. The incremental costs of the new production units plus [Sociedad de Markaer] added BRL0.21 per unit to fourth quarter lifting costs. In other words, the new units were responsible for one-third of the increase in Reais lifting costs. As these units increase production, the unit costs will decline.

Refining costs, as you can see in the next slide, have been increasing the costs because of the re-evaluation of the Real and the additional complexity of our refineries, which require greater amount of catalysts and other material to process our heavy crude oil, while meeting stricter health, safety and environmental expenses.

In the fourth quarter, the rise was particularly dramatic because of program stoppages in the [Heduc Lubican Strait]. For 2008, it is expected that refining costs will be more in line with the average for 2007.

In slide seven, you can see the price of oil rose continually during the year and even accelerated during the fourth quarter. You will also see that the value of our relative heavy crude is now valued at around $12 discount to the price of Brent versus $10.5 in the prior period.

Turning to refining output in slide eight, you can see that throughput declined slightly during the quarter as a result of the programmed stoppages. Production of the domestic oil also declined as it was more economical to export larger volume of heavier domestic oil and import lighter oil. Higher acidity in some of our domestic production also reduced throughput of domestic crude.

Sales of product in domestic market continued to increase with diesel growing by 33,000 barrels per day and accounting for almost 70% of the product sales growth. This growth was satisfied by an increase in imports. It's important to note that our throughput of domestic oil is still up versus one year ago, following completion of the [hephapi].

In 2008, we expect to complete the upgrade of [Heduc] which will enable us to convert 36,000 barrels of -- per day of fuel oil into diesel and other light products. This will have a positive impact in our refining margins.

The next slide is -- illustrates the effects of maintaining gasoline, diesel and LPG stable in Real terms in the domestic markets during the fourth quarter. The strengthening of the Real and the bi-weekly adjustment in price of our industrial products caused the average realization price to increase $8.00 per barrel, which was less than international product price, which spiked by $11.

In slide 10, you can see the impact of stable oil production, relatively stable oil product price and higher costs on our results. Revenue increased by BRL948m. This was more than offset by higher import costs and higher lifting and refining costs.

Operating expenses also increased sequentially during the quarter by BRL579m, as a result of higher G&A, higher exploration costs, especially internationally, and impairment on our Ecuadorian assets. On a sequential basis, these additional costs were offset by provisioning of BRL705m, related to the pension plan in the third quarter.

It is worth mentioning that our net income for the full year in Reais under Brazilian GAAP declined by 17% relative to 2006. Net monetary and exchange variation was the principal cause for the decline. We have tried to improve the market understanding of this by breaking down the assets and liabilities that contributed to the evaluation during the period. This you can see in page 36 of the financial market report.

Essentially, higher net assets subject to monetary variation have increased as we fund our offshore subsidiary for capital investments that will be used both abroad and in Brazil. Combined with higher appreciation of the Real in 2007, net monetary exchange variation increased by BRL3m -- BRL3b. This effect is not in our U.S. dollar financial statement.

Net income under Brazilian GAAP declined by 20% during the first nine months of 2007, relative to the prior year, while during the same period, income in U.S. GAAP increased by 2%.

Turning to our principal segments, you will see in slide 11 that earnings in our E&P segment increased by 7% as a result of the higher price of oil, partially offset by the small decline in production and the increase in costs.

Slide 12 illustrates that our downstream segment was affected by stability of gasoline and diesel price in Brazil. Higher price for our other product was more than offset by the rising cost of crude and imported products, as well as higher refining costs.

Turning to the next slide, international results were adversely affected by the BRL495m of dry hole expense and another BRL401m from impairment of Ecuadorian assets. The positive effect from increased sales volume was more than offset by the increase of -- in costs from those sales, as downstream sales with a lower margin grew at a faster rate than upstream sales that typically enjoy higher margin.

In the slide 14, you will see the total capital expenditure and acquisition total, the BRL45b during the period, an increase of 34%. The acquisition of Ipiranga and Suzano contributed to this increase.

Slide 15, please. Turning to this slide, we see the finance -- how we financed our investment plan in 2007 as well as pay dividends of BRL7.5b. We used internal generated cash flow and reduced our cash balance by -- from the BRL27b at the end of 2006 to BRL13b at the end of 2007. Our net debt to the net book capitalization ended the year at a health 19%. Our target -- targeted net debt to the net book capitalization is 25% to 35%, so we are still below our target range.

Looking to the future, you will see in slide 16 that we have another three platform with a total of 460,000 barrels per day of capacity, and another 25m cubic meters of gas capacity coming on stream during 2008. In the case of P-51 and P-53, physical completion is more than 8% complete.

I would also like to draw your attention to the three new units that were contracted to be built since our last conference call. You may remember that the original bids for P-55 and P-57 were originally conserved because they were too expensive. After redesigning the units and rebuilding, we were able to reduce the cost quite substantially. In the case of P-56, for example, it is being designed as -- built as a clone of P-51. The cost saving on each of these platform as a result of this effort is approximately $600m per unit.

Next slide, please. And keeping a look on the future, you can see the pre-salt cluster where we have drilled in most of the blocks, but during 2008 we intend to keep the effort on the area to better evaluate and having the first oil being produced by beginning of 2011.

Next slide, please. Total shareholder return. This is very important. Finally, I would like to conclude with a review of the appreciation of our share price and the total return to the shareholder in 2007. The increase in value was the result of a combination of exploratory success, operational success, as well as positive development in Brazil in the oil markets. We think it also reflects the market's recognition of our enormously positive long-term prospects, as we continue to reinvest in our enormous opportunity set.

Thank you. We are now open for questions.

Thank you. (OPERATOR INSTRUCTIONS) Our first question comes from Paul Cheng of Lehman Brothers.

Hi. Good afternoon, gentlemen. Quick question. Wondering if you can talk about your drilling program for the next six months in the sub-salt area? Second, any comments related to Tupi, given one of your partner, BG, in their conference call talking about over 10b barrels, even higher than the range that you guys given. Any comment on that?

And lastly then, any comment on the well that you drill on the BMS-10? I think you already announced the 9 as a discovery. 10 has been drilled for awhile. Maybe I missed it, but I haven't heard what is the result on that. Thank you.

Okay, Paul. I will have my colleague from E&P to help us on these answers. Please, [Molinari].

Okay. Regarding Tupi, what we have in that plan, it is not for the next six months. We have an extended well test for 2009 and we have a pilot system of 100,000 barrels per day at the end of 2010 or beginning of 2011. And this is our plan for this area. Of course there will be other exploratory wells drilled in Tupi area.

What was the other question?

Hi. For Tupi, actually, your partner is discussing about --

Yes.

-- the potential, perhaps is higher than your initial range. Wondering if there any comment that you can have. And also, when talking about the drilling program and not really just focusing on Tupi, but also -- but more on the overall sub-salt program, and what is your drilling program or exploration program look over the next six months, whether you can share it with us that -- how many additional wells on the exploration front you're going to drill and where you are going to drill?

No, we are not -- we are planning new exploratory wells in the area and what we can say at the moment is what I have said, is that the extended well test and the pilot system. And there are other exploratory wells in the area.

And regarding the announcement of British Gas, which they use a different criteria. They [form it] oil in place, so their number was higher but it's not a recoverable volume. It is oil in place. So if you convert it into recoverable volume, it will be about the same as the Petrobras disclosed.

So you're still going to stick with, in the meantime, that the 5b to 8b barrel of the recoverable reserve that you have in place, you had previously disclosed.

Yes, it's 5b to 8b barrels of oil equivalent of recoverable volume. It's not reserves yet. Okay, we (multiple speakers).

I understand on that.

Yes.

I understand on that. And then my last question is, earlier that -- any comment on the Block DMS-10, the well that you have drilled over there?

Yes DMS-10 is [Parachil] was the first one to be -- that was drilled in the area. It's the well RJS-617. And like the others we have used to evaluate the area of Tupi because DMS-10, DMS-9 is closed of the Tupi area. And Tupi we drilled and tested two wells, RJS-628 and RJS-446. And we have also tested this DMS-10 and DMS-9 well. We drilled one well in each of these blocks and tested as well.

Any rough idea on what is the reserve potential in the Block 9 and 10?

No, we have to drill further. We have to drill other exploratory wells to evaluate these areas.

And when are we going to drill the additional wells?

Well we -- I cannot anticipate that.

Okay, thank you.

Thank you. Our next question is coming from Marcus Sequeira of Deutsche Bank.

Hello gentlemen. Good afternoon. I just have three questions. One, on production growth for this year. What sort of production growth are you expecting relative to 2007?

Second question, lifting costs. I'd just like to check with you if the -- your estimate for average lifting cost in 2008 is more close to $7.6 per barrel.

And last, on your discount -- on the discount of your oils -- international oil price. Should we assume a similar discount for the rest of the year, or do you have any new increase in light oil production that should bring this discount down? Thank you very much.

Molinari, can you help us, please?

Yes. With the lifting costs, our lifting cost, the average for 2007 was $7.70. And we have a plan now to reduce that to $6.10 per barrel in 2012. So we have a target. We are going to see the lifting costs going down from the end of this year on. And if should -- the Real is more and more appreciated than it is at the moment.

For 2008 what would you be targeting for average lifting costs?

We don't publish a yearly lifting cost, only what we have as a target for 2012, as I mentioned.

All right. Thank you. Then on production growth for this year, what sort of targets or plans are you guys working with?

Yes, for the production growth for this year we have the humpback of P-52, which now is producing 60,000 barrels per day with the three wells. We have P-54, both in the Roncador field. P-54 is producing 46,000 barrels per day with the three wells, same.

And we have three new oil systems going on-stream in the end of this year. P-51 is a semi-submersible platform. It's the first one that was entirely built in Brazil. It's going to come on-stream in November this year with 180,000 barrels per day. Then we have Marlim Leste P-53 in September. It's also 180,000 barrels per day. And then we have Cidade de Niteroi entering on-stream in December this year. These are the oil systems. But we have also Camarupim. It is (inaudible) Cidade Sao Mateus. It is starting production also in December this year.

And for the P-52, P-54, do you expect a peak production by when? By mid this year?

The peak production will be on the second quarter of this year.

And the last one, on the discount of your oil to international prices.

Sorry, it's not the second quarter, sir. Second half.

Half.

Second half, sorry.

That's okay. Thank you. On the discount of your oil, now the discount has increased this quarter. Should we expect this discount to remain the same or increase, or even decrease in the -- what should we expect in the -- for the rest of the year?

The discount of heavy crude compared with Brent, you mean.

Yes.

Let's have -- okay. As I mentioned in the presentation, we have increasing production of acid oil in Brazil. New production -- part of it comes with a higher acidity. And part of this production is being exported. What is giving us an increase in the discount, compared with the Brent last year was $10.5. This year was $12 -- about $12 discount. We expect to be in this area, $10, $12 in the future.

All right. Thank you very much.

Welcome.

Thank you. Our next question is coming from Mark McCarthy of Bear Stearns.

Hey guys. It's Mark McCarthy. Wanted to ask you just a few easy questions. First of all, Almir, I suppose you're the best for this. You've got a tremendous natural gas growth program over the next several years. You've got now the discovery of Jupiter. Needless to say, you have a lot of natural gas. Will you or will you not continue to sign the contract to import and renew the contract with Bolivia in 2017? And if so, why?

Mark, I believe it's too early to discuss this renewable -- renewal of contract. That is going to happen, not -- if it's going to happen, not in '17, but '19.

Right, sorry.

So we have another 11 years to go and see what will be happening around. So let's leave it for the future.

But is it fair to say that development of Jupiter and the signing of the contract are -- it's almost one or the other. Right? They're competing against the same market. They probably have similar scale, if not Jupiter being even larger.

We are -- at this moment, we are evaluating the difference -- different alternatives to produce the gas from the pre-salt cluster. As you know, it's far from the coast and there's still some problem to be better evaluated. And that depends on the solution. I believe, according to the solution, we are going to find the best way to use the excess if it happens to have, of gas we are going to produce in Brazil. As you know, there are other countries that are -- is in need of more gas. We can do some liquification of gas to export. It has a lot of alternatives there. At this point in time we don't have yet a final solution.

Okay. The other question was oriented to the downstream business. I figured there would be plenty of questions for Tupi and the upstream program, which has been the case. Assuming that -- you showed in your chart, I think. It was on page nine of your presentation, where it shows the average realization price in Brazil. You're very slowly getting squeezed. And thank goodness for the strength of the Brazilian currency, which has continued to make the purchases of the expensive oil actually not as negative. But to what extent -- this kind of comes in two questions.

First, have you hedged at all your very substantial fourth quarter inventory balance, given the fact that it's a distinct possibility that either you'll need to raise prices into the first quarter or you're going to be very close to breakeven?

And then the second question is, what is the level of spending in 2008 on the downstream upgrade program, because I believe you need to meet the fuel specification requirements by -- I don't know if it's in '08 or '09?

I don't know if we have the total investment for 2008 in the downstream, because what I have, Mark, is the total -- probably you know -- of CapEx for the -- improving the quality of oil. It's almost $9b. But this extends to (multiple speakers).

That's the 5-year program.

Yes, 2012.

But if I remember, it's very front-end loaded because the fuel specification targets occur in 2009, if I recall.

Yes, but we are going to deliver the oil -- specified oil for the domestic market, because as you know, to use the better quality and to have the better result, you have to change the engine of the tracks. It's not only a matter of having the right fuel or -- but you have to adjust the tracks as well.

Sure.

We are doing our share. And we believe that this is going to grew from 2009 as new engines come to be available in the market.

Okay. So do you know offhand what the planned CapEx is for downstream in 2008?

I don't have -- no. Anyone can help with this figure? No, I guess we are going to make it available, if possible, in our website.

Okay. And any plans to hedge the existing growing inventory position? I don't believe you've hedged them from a foreign exchange --

No.

-- perspective in the past.

Yes. This is not our policy. We don't work with hedge, except for very special transactions where we do sell or buy according to the transaction, itself, but not for the Company as a whole. We work with the market price.

Okay. And then, if I could -- just let me take one last question, and that is, you changed the accounting process for the transfer of natural gas to the gas and power segment a while back, a year ago or so, which has, in a sense, forced the gas and power business into losses. How much of the eliminations -- the negative that was produced, actually came from gas versus refining?

Alves, could you help us in this question?

(Inaudible) Mark.

I'm sorry. Can't hear you Alves.

Excuse, Mark. Could you repeat the question?

Yes, sorry. The eliminations loss during the period is made up sales of oil for the upstream to the downstream, and from gas from the upstream to the gas and power business, if you could just give me a basic percentage of how it was broken up. Was it largely in refining or was it at all within gas and power?

If I understood your question, we have some effects among the areas, depending on the level of supply of inventories and the tendency of price between the periods. Okay? In terms of elimination, just two variables can affect the number in each period. Okay?

Yes.

And the higher effect in this kind of transactions occurs between E&P and the supply area because the inventories of the supply area is so high, almost six days (multiple speakers).

Right. So is it basically 90% of that impact or is there any from gas and power?

Yes, mainly because in terms of the transactions involving natural gas, we don't have inventories of natural gas. There the most -- almost every effect is coming from the transactions between E&P and the supply area.

Okay. Thanks, Alves.

Okay.

Thank you. Our next question is coming from -- excuse me. (OPERATOR INSTRUCTIONS) Our next question is coming from Gustavo Gattass of UBS.

Hi Almir. I have a couple of questions here. Let me start with probably the easiest one. I was curious about that -- the comment you made about the SEC reserves and the SPE reserves and growth on the SEC reserves being related to contracts or indications that the contracts might be extended. I just wanted to know two things on that front. The first one, has everything that you could get in extensions already been incorporated into this new SEC number or was that a partial or a small event?

And number two, has the [ANP] done something that is binding and that they cannot back away from or was it just some kind of loose indication for now?

Let me have here, Molinari to say if we incorporated all the additional reserves or if there is still some blocks. Molinari, can you help us?

Well this incorporation was due to the extension of concession contracts, provided we make the investment required to do so. But that wasn't specific. I don't know the fields now that we have granted the extension. It's not for all the concessions.

Okay. So this is part of what you could have, both for this kind of a theme and the extension was already officially granted, then.

Yes, it's officially granted. Otherwise, we could not book a SEC [proven] in these (inaudible).

Okay. My second question -- I was actually looking back at your presentations, all the way back to 2004 or so. And this relates a little bit to the margin squeeze that Mark was mentioning on the refining front.

One interesting curiosity was that looking back at the price increases that you guys granted in 2004, 2005, what we usually saw was a situation where every time the average realization price in Brazil broke below Brent for one month or as much as three months, in one specific case, a price increase would come. I just really wanted to understand, has anything in the policy of the Company changed or are we just waiting and see like we did in the past?

We have no formula. So it does not fit to our -- to your conclusion. Our behavior does not fit to your formula conclusion. Really, we do not have these -- we are not guided by this kind of thinking or position as you mentioned. We follow long-term price. And at this moment, as I mentioned earlier, there is a higher possibility of having lower economic increase in the world -- worldwide, mainly in the United States. This may reflect in lower demand for oil.

Yes, it's true. We are leading at this moment with a higher price since November, December. But there is a very, very high -- very, very strong indication of recession. And the first consequence will be a lower demand and lower prices. So we don't -- we are not convinced that it is the moment to increase the price yet.

Okay. And my last question, just a very quick one. When you're looking at the gas and power business, what we see, at the very least, is a very, very poor performance from that unit that has continued. This quarter in particular, I was surprised to see that the revenues actually fell on that one.

I just wanted to have an idea from the management, now that you're putting so much money into pipelines and now that we're going ahead with Camarupim, Uruguay and all of those gas or non-associated gas fields, how do you see this playing out over the course of the next couple of years? Is this a unit that we should be considering as a negative EBITDA maker for a couple of years, or is it ever going to be improving?

We are, frankly, improving. As you know, we're in -- generally, we delivered 32m cubic meters a day from domestic production. And this is an increase of about 7m or more cubic meters per day in the southeast of Brazil. And as you mentioned also, Camarupim and other gas field or associated gas producers, is going to come on-stream.

We are finalizing a lot of newer pipelines, being able to deliver this gas to the right market. And we are seeing the future as better than the past in this area. We hope, in maybe one year or so, to start changing the situation we faced so far. You -- I have a colleague from gas and energy here. If you want to add something else, please do it.

About one part of our loss in the period was due to penalties that we had because we don't have -- we lack about some logistics that we're investing on, and some lack of supply of gas that it is inverting now. So another way to think about it also was the loss from the changing of the methodology of (inaudible) price from [ANP]. So if we consider that, in fact we reduced our loss in comparison with last year. And the forecasting about gas and energy is a better future. We are not reverting some kind of loss that we had in the past. And like Mr. Barbassa said, we think that we're going to, about one year, to here next avert this -- the loss in gas and power business (inaudible).

Okay. Perfect. Thank you.

Thank you. Our next question is coming from [Subhojet Darepo] of Morgan Stanley.

Barbassa, hi. Good morning. I have two quick questions here.

First one, I wanted to relate to the slide number two, in which you showed the mature field decline. And I see here the percentage in terms of '06 to '07 is north of 10%. Now in the past, Petrobras has guided us in terms of a decline of mature fields between 7% to 10%. And I was just wondering if you are sticking with that range of target or you think that something has changed in the last couple of -- two or three years that might consider you revising this range upwards.

And more of a qualitative answer on that issue is related to the production targets. That's something that's not new. It's something that happens with other companies worldwide. Companies are having difficulties in meeting their production targets. But from a qualitative perspective, would you be able to tell us whether that difficulty is really coming from the new production facilities which are a coming at -- a bit late from its original schedule, or it's something related to the difficulty in lifting the same or maintain the same productivity in the mature fields or, in other words, improving the recoverable oil?

And the second question is related to the Jubarte field. I understand, and correct me if I'm wrong, but the first pre-salt area on a commercial basis will come on-stream in, say, 30 or 45 days in the Jubarte area. It's going to be a small production. But I wanted to have, again, an analysis of whether that area -- to what extent could you consider it as a proxy for the Santos Basin, in terms of technological difficulties and, two, in terms of the economic feasibility of that area? Thanks.

Okay. I'll have Molinari to answer this question as well, please.

Okay. Regarding the decline rate, we still consider 10% the average decline rate of Petrobras for the coming years. With relation to the Jubarte, we are connecting a pre-salt well. It's (inaudible) [128] to the P-34 platform. In May is the soonest that we can do. And we want to test this well. And we are using the same FPSO that is producing the oil at the Jubarte wells. And we'll collect more data from the (inaudible) in the pre-salt of (inaudible). The pre-salt in this area (inaudible) is not as continuous as the Santos Basin. There are some factors, so it's a little bit different.

Molinari, do you think that the horizontal wells you're drilling in the Campos Basin at the Jubarte field could be considered as a proxy from an economic respect in terms of cost per unit of well in the Santos Basin? Is it totally different more in the fact that it's non-homogenous, it's less deep? Would you consider it's totally different or if you could draw some conclusions from there?

Well it's different. Probably the (inaudible) pre-salt wells in the Santos basin will be vertical wells rather than horizontal wells, like we have in the Jubarte field. So it will have an increase of the CapEx, but on the other hand, we have a lot -- a huge volume of oil. So in terms of unit cost, maybe in the same level.

Oh, that's interesting because I might be wrong, but I thought that, especially due to deep waters, you might improve your recovery factor by drilling horizontal wells, which might be different in this case because of the cost involved. But is there any particular reason why you'd go for a vertical well rather than a horizontal one?

Yes. Well we -- that's why we are going to make this extended well test. But the reason is that in this pre-salt of the Santos Basin, the (inaudible) is laden. We have carbonate and it is layered horizontally. So maybe the permeability in the vertical direction is not as high as in the horizontal direction. So a horizontal well may not help produce more. Did you understand?

Yes. We could take this -- more details offline, but so far, it's great. And just to -- going back to the first question, do you think that the difficulty the Company has been having in terms of meeting its production targets related to the mature fields -- the existing fields, or rather for the new production facilities, just on a qualitative basis?

Yes, it's -- the delay of our new systems last year, P-52 and P-54, certainly was, I think, the biggest cause. But of course we have a decline rate of 10%. So we have to put one big system on-stream every year, just to maintain the production, 180,000 barrels per day platform just to maintain flat, the production.

All right. That's great. Thank you very much.

Thank you. (OPERATOR INSTRUCTIONS) Our next question is a follow-up coming from Mark McCarthy of Bear Stearns.

Hey guys, another easy one. If you could just tell me, what was the breakdown of exploration versus development spending in 2007? And how many total wells do you expect to drill in 2008?

Molinari, can you -- do we have this informations?

Yes, I have. Let's see here. In 2007 we spent a total of $12b in the exploration and production, in total. Out of this exploration was $1.819b. Okay?

And could you give me a similar breakdown for 2008 and the number of wells that you anticipate drilling?

Yes. In 2007 we drilled 109 exploratory wells. And our success rate was 59%, including the pre-salt wells. On the pre-salt wells, we had a success rate of 100%. But the average of the 109 wells we drilled in 2007, the success was 59% -- the success rate.

This is in Brazil, right? This doesn't include international.

Yes, purely domestic.

Right.

In 2008, sorry I have in Reais here

That's fine.

But the exchange rate considered for this planning was $1.8 -- Reais per dollar. So it's total spending capital -- CapEx, BRL26.5b. And on exploration will be BRL4.3b, with an exchange rate of $1.8.

So if we were to hypothetically use a Real of one sixty-six -- I know that would be hard to imagine, but would you expect that the Real-based costs would stay fixed or the dollar-based costs, because you have -- a large chunk of this spending is really in dollars. Which number would move, the dollars or the Reais?

Following the investment, we have most of our expenses in U.S. dollars.

Okay. And if -- I know -- I don't know if it was included, but do you know what the actual proved developed number was in -- for Brazil for 2007?

The proven reserves?

No, the proved developed.

Yes, I have. Just a minute. I'm finding here. Yes. The proven development -- the development of proven reserves was 51% of the total reserves, that was 13.92b barrels of oil equivalent, 51% developed and 49% undeveloped.

Is that your -- those are your (multiple speakers) numbers.

SPE numbers totaling 13.92b barrels of oil equivalent.

Do you have a similar number for SEC?

No, I don't.

Okay. Thanks Molinari.

Okay.

Thank you. (OPERATOR INSTRUCTIONS)

Actually, Operator, I think we are concluding. And so, I don't think we seem to have any more questions. So I'd like to turn it over to Almir for any final comments.

Ladies and gentlemen, I thank you for being here with us. And I hope the next quarter we can have as good results as we had this time. See you then. Bye-bye.

Thank you.

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