巴西石油 (PBR.A) 2007 Q3 法說會逐字稿

Ladies and gentlemen, thank you for standing by and welcome to the Petrobras conference call to discuss 2007 third-quarter results. (OPERATOR INSTRUCTIONS). As a reminder, this conference is being recorded.

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

Good morning, ladies and gentlemen. Welcome to our conference call to discuss 2007 third-quarter results. We have a simultaneous webcast on the Internet that can 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 Question to Host anytime during this event.

Before proceeding, let me mention that 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 current information currently available to the Company. They involve risks, uncertainties and assumptions because they relate to future events and therefore depend on 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. The conference call will be conducted by our CFO and Investor Relations Officer Mr. Almir Guilherme 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 afternoon, ladies and gentlemen. Let's start with slide 3. I would like to begin today's conference call with a short discussion of the announcement of the most significant discovery in Brazil waters since the first discovery of the giant fields of the Santos Basin almost 20 years ago.

On Thursday, we announced that Tupi in the block BM-S-11 is estimated to contain 5 to 8 billion barrels of oil recoverable. We also disclosed that we have now drilled a total of 15 wells in the Pre-Salt area and tested eight of these wells. Based on the performance of these test wells on the oil produced from them, we feel confident in our hypothesis that the Pre-Salt extends 800 kilometers from north to south and is some 200 kilometers wide. It is located in waters' depth of between 1500 and 3000 meters.

We do not believe there are any particularly troublesome technological issues with respect to producing from the Tupi area. The technological challenges will instead be focused on how to reduce the cost of development and operations. We still do not have a reliable cost estimate for development, although we think at least initially it will be more costly than our more traditional developments in Campos Basin.

Early indications from our test wells indicate that the oil-to-gas production split from the field will be approximately 80 to 20. One of our principal challenges will be how to utilize the gas, either through reinjection, gas pipeline connecting to the other gas facilities, or even such novel ideas as generating electricity and then transportating electricity to the mainland.

With respect to future production from this area, we currently expect to have 100,000 barrels per day pilot program by 2011. Production from Tupi and other Pre-Salt finds are not covered in our production costs, nor are the costs associated with developing this fuel. As we learn more and review our long-term business plan, we will inform the market accordingly.

[Given the money] of Tupi and other potential discoveries in the Pre-Salt, the CNP or National Committee on Energy Policy, in coordination with A&P, has withdrawn Pre-Salt blocks from the upcoming ninth bid round. They have done so to have more time to evaluate the consequences of this potentially massive new area along the Brazilian coast. They simultaneously made clear that the concession terms governing the Pre-Salt concessions already awarded will not (technical difficulty).

Petrobras estimates that approximately 25% of Pre-Salt areas have already been awarded, of which Petrobras possesses an interest of 75%. We have not made any announcement of the recoverable reserves in other blocks such as BM-S-9 and BM-S-10, although we have stated that we do not expect future reserves announcements for these blocks to be in the same magnitude of BM-S-11.

Turning now to the third-quarter results, slide 4, as you can see, production was up less than 1% from the prior quarter. The ongoing impact of new systems introduced earlier in the year was essentially offset by natural decline and a series of [owned -- own] program stoppage.

Turning to slide 5, during the first nine months of the year as compared with the first nine months of 2006, production increased by 2%. Delays in bringing new production system onstream and unexpected platform stoppage have caused average production to fall below our previously announced figures.

You can see how our year-over-year production has increased with the implementation of new systems, offset by natural decline from existing production. P-50 added on average 148,000 bpd to our production during the first nine months of 2007 as compared with 2006. Keep in mind that while this is a 108,000 barrels per day platform, our work interest is only 9%. Repsol-YPF owns the other 10%.

FPSO-Capixaba have added 38,000 bpd to the average of 2007 as compared to 2006. Unfortunately, the reserve oil performance of this area has been below expectation, and consequently, the platform's production capacity of 100,000 bpd has not been reached, nor do we expect to do so in the immediate future. We are analyzing the possibility of tying in other wells from neighboring fields to fully utilize the platform's production capacity.

P-34, after a series of [capacity] delays related to the pumping system, is now producing 57,000 bpd versus capacity of 60,000 bpd. It was mentioned that next year we expect to tie (technical difficulty) add [103] into P-34. This well taps a Pre-Salt field in the Jubarte area. This tie-in will allow us to begin testing this formation. This is a good example of how we can use our existing asset base to accelerate knowledge and production from the Pre-Salt.

FPSO-Cidade do Rio de Janeiro in the Espadarte field experienced delays in completing their five first wells, as well as some gas leak issues. These issues are now resolved, and we expect production from the platform to increase from the current production of 6000 bpd to 100,000 bpd by the first semester of 2008. The additional capacity of these platforms, which added 203,000 bpd of new production compared with the nine-month period a year ago, was largely offset by the natural decline rate from existing systems of 170,000 bpd.

As you will see in slide 6, we will begin production from three new units during the fourth quarter of this year. This should lead to a sustained period of production growth in 2008. Golfinho Module 2 is currently moored, and we expect first oil next week. After the end of 2007, two wells will be producing, and we expect big production to occur in the first half of 2008.

P-52 is currently moored and in the process of connecting their first well, with first oil expected later this month. After the end of 2007, two wells will be producing, and we expect peak production with new rigs by the second half of 2008.

P-54 has been towed to their production site and is currently being moored, with first oil expected in December with one well. Peak production from this unit will be reached by the second half of 2008, representing a very positive growth in our production profile next year.

This is illustrated in slide 7, where we can see that our projected targets for oil well production in 2008 is 2 million barrels per day. As you will see, these targets are below our previously announced guidance of 1,840,000 bpd in 2007 and 2,050,000 in 2008. We currently expect first oil from P-51 in June of 2008 and P-52 and FPSO Cidade de Niteroi by December of 2008. Most of the production from these units will be felt in 2009, and therefore provides strong follow-on support to the production growth we are expecting from P-52 and P-54 for next year.

The market carefully monitors our oil production growth, but it is also worth mentioning the growth in gas production next year as we start seeing concrete results from our investments in oil and gas. As you can see in slide 8, Phase II of Peroa Fase 2 will add 5 million cubic meters during 2008, with first gas from this development to occur in November 2007, this month. Additionally, we expect first gas from Camarupim in December 2008. Together, these two production units will have a nominal capacity of approximately 15 million cubic meters of gas per day, or equivalent to 98,000 bpd of oil equivalent. The contribution from these platforms will be part of the increase during 2008 of 16.7 million cubic meters to be supplied from Espirito Santo Basin.

Given the growing demand in Brazil for gas and the lead time to bring new source of supply to the market, Petrobras has engaged in a policy of increased gas price. Since 2006, Petrobras has increased price to local distribution companies by 22%. We have recently announced that we expect to raise price for natural gas an additional 15% to 25% on average during next year to bring our gas price into levels that more closely represent the cost of alternative sources of energy.

Our [recalcification] facilities continue to move forward, and we continue to expect to have recalcification capacity of approximately 20 million cubic meters per day available by the end of next year.

We will now turn to a discussion of our domestic refining sectors on slide 9. As you can see, refining performance as measured by capacity utilization throughput and domestic oil as a percentage of total throughput has been relatively constant. From the second quarter to the third quarter of 2007, demand for product volumes increased by 3.3%, while our output from refined products increased by 0.6%.

The increased demand relative to output required an increase in product imports, primarily diesel. The improvement in throughput since last year have primarily been a result of the completion of the upgrade of (inaudible) refinery, which has increased reliability and capacity.

We continue to invest in improving refining margins in Brazil, primarily by building delayed cokers that will process more of our domestic hedged crude oil while simultaneously increasing diesel production and reducing fuel oil output. As you will see in slide 10, we have three projects currently underway in our refinery that will increase throughput of domestically produced oil by 31,000 barrels per day. This has the economic benefit of substituting our hedged domestic oil for light imported oil. Refinery economics will also be substantially improved by the incremental output of 47 barrels per day of diesel and by the decrease of 61,000 bpd of fuel oil.

Before turning to the quarterly results, I would like to review key market conditions in the oil market that have influenced our performance. As you can see in slide 11, during the third quarter of 2007, the average price of our crude oil increased to $64.40 per barrel from $57 in the second quarter. Part of this difference is attributable to the decline in light/heavy differential in world oil markets, which let the differential between crude and that of Brent to fall to $10.50 versus $11.70 in the previous quarter.

When we look at the international refining margin expressed by United States Gulf Coast crack spread, we see that they declined dramatically during the period, from $14.90 per barrel in the second quarter of 2007 to $8.80 during the third quarter of the same year. As you'll see in later slides, lower international refining margin and a smaller light/heavy differential led to higher earnings in our E&P segment and lower earnings in our refining segment.

In slide 12, you will see the margin between Brent and average realization price of our basket of products in Brazil decreased from $9.50 in the second quarter to $6.20 in the third quarter of 2007. This attributes primarily as a result of the decline in international refining margin. From the second to the third quarter of 2007, the margin between average realization price in Brazil versus that of U.S. Gulf Coast was virtually unchanged at $4.50 per barrel. During the month of August, the temporary devaluation of the real as a result of the effect of the subprime crisis caused the differential to widen. The increased international product price in September caused the differential to widen further.

It should be noted that the comparison between price in the U.S. Golf Coast and Brazil is not an exact comparison and is more useful as an illustration of our long-term commitment to international price levels. For example, quality differential between products in the Gulf Coast and Brazil affect prices. Additionally, gasoline in Brazil faces competitive cost pressure with ethanol and compressed natural gas. Therefore, an increasing in gasoline price in Brazil will adversely affect demand. So U.S. Gulf Coast prices are an important indicator of pricing levels, but other pressures must also be considered.

We will continue our policy of not passing through to the Brazilian retail market the short-term fluctuation in the international product price, up or down. We closely monitor international conditions and current and future price levels to determine whether price adjustments in Brazil are needed to align our price in the long term with international prices.

In slide 13, we show the comparison of second-quarter versus third-quarter results. Net revenue increased primarily as a result of increased demand for [delivered ships] in Brazil. This additional demand was [ascribed] by an increase in imports, which increased the cost of goods sold, offsetting the increased revenues.

Cost of goods sold increase was caused by higher cost of imports. EBITDA was affected by onetime expense of R$697 million related to an amendment to retiree benefits designed to create a long-term equilibrium in our pension plan. Higher sales costs related to higher sales volume, and higher general and administrative costs of R$50 million also reduced EBITDA. We are adopting measures to control these costs, although some of them are unavoidable as we invest in personnel and systems in preparation for our future growth.

Primarily as a result of these items, EBITDA declined sequentially from R$14.2 billion in the second quarter to R$13.1 billion in the third quarter of 2007, a decline of R$1.12 billion. This led to an equal decline in our operating income, which also fell by R$1.26 billion as compared to the prior period, and net income, which also declined by R$1.27 billion. Please refer to our market report issued on November 9 for further reconciliation between second and third quarter of 2007, as well as a comparison of the first nine months of 2007 versus 2006.

In slide 14, we have already discussed the change associated with cost of goods sold, general and administrative, and the pension and health plan.

In slide 15, you will see that lifting costs, both when expressed in dollars and reais have stabilized during the past 12 months. Lifting costs in U.S. dollars, excluding government take, increased from $7.33 per barrel to $7.65 between the second quarter and third quarter of 2007. During the last 12 months, from the fourth quarter of 2006 to the third quarter of 2007, lifting costs increased by 5.6% or $0.41 a barrel. This limited increase in lifting costs occurred despite the delay in ramp-ups of new projects, which caused pressure on the per-unit lifting costs as full operating costs could not be allocated against full capacity.

It is also worth noting that during this same period of time, crude oil increased by more than $25 per barrel. Given this recent history, we think that most of the cost inflation in the industry is behind us, although if the price of crude oil remains in the $90 per barrel range, additional cost pressure has to be expected.

When calculated in reais, lifting costs excluding government take increased from R$14.45 to R$14.65 between the second and third quarter of 2007. From the fourth quarter of 2006 to the third quarter of 2007, they have declined from R$15.46 to R$14.66 per barrel. The decline of lifting costs when expressed in reais demonstrates the importance of the exchange rate upon our lifting costs.

Turning now to slide 15 through 17, I would like to review the results of our two principal segments, domestic exploration and production, and the refining and transportation operations in Brazil, as well as our overall corporate results.

In the slide 16, you will see the positive results from E&P segment. The higher value of crude in general and the smaller light/heavy differential led to higher prices for the segment's revenue. The small increase in production also contributed to additional revenues. The imported oil products' price increase is reflected in the cost of goods sold.

Slide 17 reconciles the change in income of the downstream segment in Brazil, where higher sales volume because of an increase in demand of 3% in the domestic market led to higher revenues. These additional revenues were more than offset by the higher cost of products sold, primarily imported [high at light] crude oil and products made to meet the increased domestic demand. A declining refining cost from $2.69 per barrel in the second quarter versus $2.55 in the third quarter of 2007 due to fewer programs and refineries shut down partially offset the previous increase mentioned.

Turning to slide 18, we can summarize some of the results from the previous slides to reconcile the net income. You can see that the increase in cost of goods sold exceeded the increase in revenues. Operating expenditures were primarily affected by the charge of R$695 million related to the negotiation with the pension plan.

Turning to slide 19, Petrobras is currently in the midst of some of its heaviest capital investments. The new production system comes online in the fourth quarter of this year, and in 2008, planned refinery investments and international expansion has all contributed to an increase of 35% in investments during the first nine months of 2007 as compared to 2006.

In slide 20, you will see that our net debt to capitalization ratio did increase from 17% to 18%, still well below our target ratio of 25% to 35%. Our substantial investment program was partially responsible for the change in the ratio.

Also worth noting, during the quarter, Petrobras purchased R$2.9 billion of long-term Brazilian government bonds to hedge the existing liability of the Petros fund. This reduced our cash and cash equivalents by an equal amount, accounting for the minor increase in our net debt to net capital ratio.

I would like to conclude this presentation by revealing the total shareholder returns of Petrobras during the last five years and comparing them against the return of the broader oil industry, as measured by the Amex Oil. We think this data reaffirms that the best use of our capital is to reinvest in the oil and gas business, fully exploiting our resource base, our know-how and our market opportunities. We are proud of the returns we have generated for our shareholders, and I assure you we remain fully committed to capital discipline, despite the dramatic increase in price we have seen these last five years.

This concludes my remarks on our results of the third quarter. We will now be happy to address any questions you may have. To help with specific questions, I have my staff with me. Thank you.

(OPERATOR INSTRUCTIONS). Paula Kovarsky, Corretora.

I have actually three questions. First question relates to increasing imports of light oil. I understood from your presentation that this has a lot to do with [detailed] requirements and the domestic demand. So I would like -- in the release you mentioned a couple of problems with the higher [CDC] levels in domestic oil production. So I would like to understand how much of this exactly includes an import and whether this is recurrent or not.

And the other question relates to lifting costs that would be going up again in U.S. dollars quarter over quarter. So I would like to hear from you when or by when shall we expect those costs to go down.

And then the third question is there was a mention today in the Brazilian press about the potential change in the petroleum [wasso]. Would you be able to comment, how would that affect Petrobras royalties and government take payments going forward?

(technical difficulty) farmers prepare the land for new crops, so there are more demand of diesel. But since we consume in Brazil all the diesel we produce here, in this case it's important to calculate the maximum and to produce the maximum diesel we can do from our refineries. And sometimes, learning the financials, learning the economics of the refinery, we found that it is better to import more light crude than use more of the domestic oil produced in Brazil. Besides that, you want to have something else from our downstream.

It is better to import the light oil than the diesel.

I just said it. So this is the reason why we have imported more light crude and more diesel in the quarter. Regarding lifting costs, [Ugu] would like to say, because from the previous quarter, we would have had almost no increase in the lifting costs. What has increased is the government take, and the government take is related to the oil price, the international oil price. Anything else?

Are you looking to lifting costs in dollars, or just comparing the direct market with this quarter in reais?

No, I'm talking about the U.S. dollar number, which is the number where you base your guidance, actually, in the five-year plan. You're forecasting a downward curve on lifting costs. So I would like to know by when should we expect the downward trend to show up?

I don't think there is an event, and probably this is an exchange rate impact on these numbers. We are working harder to reduce the lifting costs. We have some programs, and I think that we are succeeding on it.

Regarding the petroleum law, we cannot say -- we can't say much about this because we don't have it yet, and if there is any change. What I understood the government did was take the blocks out of the ninth round to better evaluate. And let's wait for what they're going to say, if they're going to change the conditions or not. But what's important here is that contract awarded is going to be respected. So conditions prevailing for the awarded contract will not change.

Our next question is from the Web. It's from Craig Shaw of Harding Loevner. The question is, how much of the 695 million expense booked in third quarter for amendments to the Petrobras plan are recurring? Also, what sort of change expense should we expect in the next fourth quarter?

This is once for all time and is not recurring. It is a part of the negotiation we had with the employees about the change we did in the pension plan, and our conditions to offer the new pension plan for the new employees that we have hired since 2002 that today is counting as much as 20,000 employees. So it was very important, these negotiations for Petrobras, because at the same time that we have stabilized the old plan, we were able to offer to 20,000 new employees a pension plan as well. And the cost was once for all.

Marcus Sequeira, Deutsche Bank.

Just two questions. One, I know this is pretty early to tell, but what do you envision regarding Tupi Field and could it change your strategy for refining going forward, since you are going to be having access to a big amount of light oil?

And then on the natural gas situation, what sort of negotiations you guys are having with the distributors in order to satisfy their demand and at the same time be able to dispatch from your terminal plants? Thank you.

Regarding Tupi, light oil, we do not have yet tests on refinery oil. We expect that being light will improve the conditions for our refineries, but it was not tested, so we cannot tell much about that at this point.

Regarding natural gas and the distribution company negotiation, it is underway. We have concluded with a few of them, but we have more than 20 distribution companies in Brazil. Each state has at least one, and these will take some time yet. Our main goal in these negotiations is to create a flexible situation to deliver gas whenever we have the flexibility to deliver all the products to be used instead of the gas, when the gas is needed for other reasons.

Are you guys planning to increase the investments in Bolivia with this gas situation?

We are evaluating this alternative. We do not have yet a final position, but we are looking for opportunities to increase our investment in Bolivia, having in mind that now we have already at this time the new situation.

Marc McCarthy, Bear.

I have a number of questions. Some are pretty straightforward. Almir, first of all, I wanted to thank you for the project update. I think it was a good addition to your prepared remarks.

There was a couple or one that you didn't touch upon, Gasene. If you could -- I'll just lay the questions out, if you can touch upon them all. If you could update us on the Gasene bidding and the construction update in terms of when do you expect the full connection between Catu and Cacimbas to be done.

The second thing is did you buy back any shares, and what is the deadline? I can't recall the deadline of the announced buyback program for the preferred stock.

There were some questions on lifting costs -- when you will bring on P-52 and P-54 in the fourth quarter, you will start expensing them. And typically when that happens, we see a spike in lifting costs until the volumes come on to dilute those costs. How do you expect that to occur into the fourth quarter? Can you provide us a breakdown of the 14 billion of CapEx between what has been spent on drilling versus platforms?

And then the last thing is related to Tupi. Has Tupi been deemed commercial from an internal project planning standpoint? And what is the deadline for appraisal and filing with the A&P?

Lots of questions. Let's start from the beginning Gasene. Gasene, we have already signed all the contracts. We split the [tow pack] line into five units, and we awarded to five different companies, and it's already signed. The startup date, the building of this pipeline is depending on the environmental license that is [not set for] anytime soon.

So construction has not started?

No, not yet. From Catu to Cacimbas did not start yet. We have the south portion already in construction, almost done, part of it, but the longest section is to be started anytime.

And we assume 18 months from the start date, is that fair?

We expect to have it operating by 2009, and I'm going to check here the exact period of time of 2009. In the meantime, let me tell you about the buyback. The share buyback we are reevaluating, and soon we will be saying what we are going to do, taking into consideration what happened recently to the Company.

What is the deadline on that?

The end of this, what we have been authorized by the Board, was December.

November?

December, another month. We have another month. And the costs of or the impact of the costs of P-52 and P-54, maybe [Ugu] can tell us some things. But I suppose by this quarter, the third quarter, we have most of the costs already run, because we were working the platform to be ready to start. But Ugu, please.

[Ugu Heltu] from E&P. It's going to take about nine months to reach the peak of production and to stabilize the lifting costs. Probably in the first half of 2008, we will -- yes, at the end of the first, beginning of the second half of the next year, we will reach the peak of this, so be on it. Then from now on, most of the costs are already incurred, but until we reach the peak, it is quite difficult to forecast what will be the impact on the next quarter, because the most important share of this cost has already occurred. Now it is just time to wait until we reach the peak of this production of this unit. Okay?

So you have not started expensing the costs from P-52 or P-54 until you have first oil, right? I don't mean the cost of construction, I mean the cost of lifting.

Yes, but we are already incurring the costs of people on board and then all the clearance costs to keep the platform on location and working and connecting the wells, and they're all there, and these costs are being accounted, okay?

So would you say there should not be much of an impact in the fourth quarter, or we should see a $0.50 per barrel impact, like we have seen in the past times when this has occurred?

I think it is good to evaluate and to make this forecast.

Marc, let me check with the accounting people here. If we are expensing the costs, we're incurring with the team that is working or not during the period previously to the first oil. Just a moment, please.

Gustavo Gattass, UBS.

Actually, will you hold on a minute? I think they're still answering the prior question.

Marc, you're right. The preoperational costs are expensed only after the first oil. So we may have an extra cost on these two platforms as the first oil starts.

And the last question about Tupi being commercial, and how long does it take?

Marc, we still have a number of years in order to declare the commerciality of Tupi, and we will use this time that can reach maybe up to five years. And we will use this in order to fully evaluate the fuel and to reach this conclusion. But I can assure you that it is feasible to develop. We have all the technology and we have drilled the wells. We are reducing the costs of drilling for each well in the time of drilling. And we're quite confident about the feasibility, and we are studying just the economics and the alternatives, and we will need more wells in order to reach this conclusion, okay?

Marc, the question regarding Gasene, when it will be operating, is the second half of 2009.

If you can just touch upon the breakdown of the CapEx. So far this year in E&P, you've spent nine months, 14 billion. You seem on track to do about 20 billion. What portion of that is development? In the past, the Company has a lower proportion of developed proven reserves than other companies. I'm curious if in fact that number has been taken up. We can come back to that, guys.

Marc, I'm having Ugu to help in this, but I doubt he has this breakdown.

Maybe I can send you later. But I don't have it here, this number, this breakdown.

Okay, I'll come back to you offline.

Gustavo Gattass, UBS.

I have a couple of questions here. Just the first one, Almir, when you were talking about the Pre-Salt development and talking about [Trubache] potentially running one well from a Pre-Salt find in the Campos Basin, I was wondering if you could, I would say, first just give us an idea of how large you think that find might be? Second, if you could, I would say, just give us an idea of whether you think there might be more of such finds under this Campos Basin, which is where you already have infrastructure?

Gustavo, I am afraid we do not have the information about the volume of the field we are going to start final production in the Trubache. But I will transfer you to Ugu. He can tell you more about the potential of the field.

The principal section is present there, both in the Espirito Santo Basin and the Campos Basin, and also in Santos Basin. We have a number of wells to drill, and we, for sure we believe that while we are drilling these wells next year and the next two, three years, this is a campaign in order to fully evaluate the acreage we have over the Pre-Salt section. But I don't have the numbers. And it's difficult to make a forecast about these volumes. We're quite confident. We are drilling the wells. There is a number of wells just in -- up to December 2008, we're going to drill 32 wells just on the Pre-Salt section. That's a pretty big picture, isn't it?

That's fair. I had two other questions. The first one, you mentioned to Marc right now that you have already taken a look at the Tupi story and you think it is commercially viable and feasible. Your policy has usually been to develop these things on a module-by-module basis. Do you guys have any idea of best and worst case, I would say, valuations for the cost of the module in Tupi today?

It's quite difficult because it's too early to say. We have a number of alternatives. We need to understand a little bit better the reasons why in order to understand what will be the production drive if there is water there. We didn't have the water yet, the oil/water content. Then we still have a lot of jobs in order to figure out what kind of development is the best one on the Tupi. I think it is too early to say, okay?

My last question, just referring to the production units, you have a number of units coming up this month and next month. I was wondering if you could just give us an idea of how the environmental licenses are going for that, and whether or not you could give us an update on the FPSOs on the African side of story on the international side?

For the Brazilian units, we have all the licenses both for P-52, P-54 to start to drill, and then also for the field, and there will be no delays related to environmental license. We are just looking for the environmental license in order to move the Seillean to start producing in Jubarte, which is a [Mali]-based field. But we believe that we will receive the license in the next couple of months. Then it will be possible to start producing there, to move Seillean to other locations. And then in the short term, there is no problems with environmental license, okay?

And regarding Nigeria, we expect also a platform that has been built by the two oilfields we are developing offshore Nigeria is to be onstream during the next year, one by the middle of the year and the second on the second half.

Paul Cheng, Lehman Brothers.

I have several hopefully short questions. Almir, just want to clarify that in the third quarter, you did not receive any tax benefit associated with the interest on capital, right?

Benefit on interest capital -- (multiple speakers), we did declare interest on our own capital in the same amount we did in the second quarter.

So [219 Tupi and 196 or 94]?

Yes, each quarter. What gave us a rebate on the tax in the quarter --

Why the effective tax rate, if that is the case, to be so high? If you have got the benefit of the interest on capital that you declare, should we have seen a much lower effective tax rate?

No, we think that income tax in the fourth quarter, because we had lower net revenue, but because also we declared interest on capital. But there is no difference between second and third quarter regarding interest on --

No, I understand that. But if I do simple math, your effective tax rate in the third quarter is about 31%. If you have declared the same interest on capital, one would think that your effective tax rate probably would drop to below 30%, maybe somewhere in the 27%, 26%. But anyway, we can take it offline on that one.

On the second question on Tupi, I presume since you only have drilled two wells, this is not a P90 estimate on the find being built. Can you tell us, is it a P50? Is it 50% of a 3P, or what kind of probability that we should look at that estimate?

Ugu, I will hand it over to answer you this question.

We're in the process of evaluating the size of this discovery. It's not possible to say if it is a P50 or a P90. We are trying to find the water/oil content. We didn't find it. Then we are saying that from the depth that we feel these two wells, we believe, in the 5 billion as a minimum value for the size of this discovery. But how big it can be, it is based on the seismic finals and not on the results of wells. Then it can be even bigger than this. We don't know yet. We have to drill more wells in order to evaluate and to get a better picture, okay?

When are you going to drill the next appraisal well?

Well, it will depend upon the schedule for all the drilling rigs. Then we drill the wells in a sequence. We have a schedule. And immediately after a well has been finished, then we decide for what location it's better for the drilling rig to go. Considering the schedule, we do not disclose the schedule, because it is a little speculative, and we need to decide for each well. It will be next year, but I cannot say in what month. But probably next --

Is it going to be the first half of next year or second half?

Maybe in the second half.

Second half?

Yes.

Almir, I just want to clarify. The government special participation -- are those being -- is calculated based on your actual oil realization. It is not based on the Brent price, the benchmark price, right?

It's based on the international oil price.

So it's actually based on the international oil prices, not on your actual realization.

Yes, it's based on the international, not on our average realization price.

Okay, yes, because that seems to get a conflicting signal previously. A final one on Venezuela -- your recent exit from the LNG project, does that signal there's a change in your view in that country or your future participation? How should we read that? Is it a one-off project by project, or that's something a little bit -- a more bigger scale in terms of your approach to Venezuela?

No. We start negotiating 12, 14 projects to work together with PDVSA. As we reach conclusion on this status, if they show that conditions for us is not economical, then we drop. This is one of the cases. We still have an oil project going on on the [Mesell] area, as well as the refinery in the northeast of Brazil that they have to be our partner. But in the case of Mariscal Sucre, just came to the conclusion that the economics were not attractive for us.

Almir, a final one -- on '07 and '08, can just give me quickly what is the latest number that you guys are looking for capital spending, 2007 and 2008?

2007, our budget is R$54 billion.

Is that going to meet the budget or is going to be over?

Probably will be below the target. We probably will not reach this much. Up to September, we spent R$30.6 billion, so spent almost R$24 billion in three months. Probably it will be under R$50 billion in realization.

How about 2008?

I don't have with me -- anyone here has the budget for 2008? (multiple speakers)

Maybe, then, if Ted can give me a call and let me know, that would be great. Thanks a lot.

I don't have. I can provide you later.

If Ted after the call can give me a call and let me know the number, that would be great.

Christian Audi, Santander.

Almir, the question was related to refining margins and pricing. Clearly, we saw a squeeze on the margins this quarter, given the behavior of oil prices and refined product pricing so far in October and November. That pressure is likely to continue into the fourth quarter, further eroding your refining margins. So my question related to pricing -- how far, how low do these refining margins have to go in order for you from a commercial point of view to really do something about domestic gasoline and diesel prices?

Christian, this is a question that follows our price policy. We don't see -- of course, if you see at this moment $100, almost that figure, it can impress you. But if you look at the average price of the year, the average price is $67 in 2007. We had oil below $50 this year, and we do not adjust for short price. Let's see how the market will perform in the future, and then if necessary, we will readjust the domestic prices.

Okay. So from a commercial point of view, you are not -- because we're getting to quite low levels -- you're not seeing -- you're sticking to that policy? In other words, commercially, I'm sure your commercial people are not happy and definitely putting pressure on something to happen, but you don't see that -- it's too early for that commercial pressure to really cause anything to happen?

Yes, but see that the E&P made much more money in this third quarter. What counts on integrated company is the consolidated figure. And on the consolidated figure, we are doing as the other oil companies. If you take our peers and see how they perform in the same period, you're going to see that we are not far from them. We're following the trend. What we do not have is the same pricing policy as they have, but the results for the investor is the exact trend of the peers.

The second question related to the acquisition of the refinery in Japan. Your strategy remains one of pursuing downstream capacity elsewhere. As you identify these targets, for example, such as in the case of Japan, there was a very low price, but we don't know yet how much investment will go into it, but is that a typical profile of these refineries that you're searching for, something that shape-wise may not be at the very top level, thus requiring a lot of investment, but is that the typical format of the refinery capacity that you're searching for currently internationally?

The main reason why we bought the Okinawa refinery is for trading. That refinery has 9.6 million barrels of storage capacity, and this can help us to better market the products we are selling in the region. And Okinawa is very well placed between Japan, Korea, China. So we are already established in Singapore. So having this huge storage capacity, we have in this refinery three, four -- placed three blocks where ships can unload, one of them or one [monoboy] for the FCCs. So a very convenient site for us, and a site that we can evaluate -- the refinery is working and producing oil products for the island, and we can evaluate what to do, what will be the best alternative for the refinery itself that costs a very, very low price.

And the last question is for Ugu. Ugu, with respect to Tupi, a couple of quick ones. How many appraisal wells were you talking about for developing? Then secondly, when you talk about developing it in stages, I know it's early to tell because you haven't finalized the development plan. You're far from that. But generally, these stages, how many stages were you considering?

And the last question is, when you look at eventually all the hardware, all the platforms you're going to need to develop Tupi, obviously Petrobras being so large, the advantage is that you have access to other platforms you're currently using elsewhere in your system. But given the nature of Tupi, the depth, the Pre-Salt, is equipment likely needed for Tupi something that you can just reallocate out of other fields you're currently working on, or will it really need to be specially designed platforms for the high-def needs of Tupi? In other words, do you have the flexibility once Tupi gets going to just reallocate existing platforms within your system or, no, you really have to go into a process of building and ordering platforms from scratch?

Okay, the first question is we're going to drill as much as necessary, just as a simple matter for your question. But we have a few years, up to five years to declare commerciality of Tupi. Then we're going to use this, not only to drill wells, but also to make some long-term tests in order to understand the reservoir. We need to understand, get behavior of the [flues] in the reservoir before we decide what kind of development is the best one.

Then there is no way to discuss if we can use the same solutions we're using in Campos Basin or use an FPSO, to move an FPSO or a platform or a (inaudible) FPSO to Tupi because we need to understand before what will be the behavior of this group to find the aquifer, to understand if the water will help us to produce this oil, and then just after then, we will be able to figure out what is the best development scheme, okay?

[Peribu Carmar], Lucite Research.

I have a couple of questions. Can you give us near-term guidance for natural gas production for '08? You have given it for crude oil in the presentation. What would it be for natural gas? I think at the moment there's about 270,000 barrels a day. So can you give us a comment on 2008, what will be the guidance for natural gas?

We have a plan to add during 2008 24, 25 million cubic meters per day. This is our (inaudible). It represents 24,000 cubic meters, which means 150 barrels of oil equivalent in the next year. I don't know if it helps you, okay?

In terms of utilization levels, is it like, within the domestic (technical difficulty), is it 91% is the maximum capacity you can achieve, or is there still room you have to increase the utilization rate?

In the refining capacity, you mean?

Yes. Right now, you have achieved 91% as the maximum utilization in the domestic refineries. Is there any more room for increasing the rate to closer to 95% or mid-90%s?

We're working hard to increase our [capacity] as we can. But if you compare with the international standard, we're not far to the record levels that capacity can be utilized in refineries. And don't forget that we are giving you the average of [leving] refineries. It is not one or two. So the average, 91%, is very high leverage when compared with the industry. But of course, we are investing in quality and control and insurance (inaudible) to increase the reliability in the refineries to improve even more the utilization capacity.

In terms of the usage of domestic crude, it seems to be still at 78%. Is that because still the mismatch and you need to import light oil, or what is the plan? Is it eventually going to go -- you will using close to 95% or 100% of domestic crude, or is it going to remain at 80%?

We are investing, as I showed in the presentation, we are, in the next three years, we're going to inaugurate one delayed coke unit per year, and this will help us to process more and more of the domestic oil. These are programs that we have established some time ago and we are implementing. To build out one coke unit takes time. We are aiming to process as much as we can of the domestic production in Brazil because the best place to sell is Brazil. We are producing 100, 150 miles out of the main consumer centers. Processing this area close to the area and selling is much better than to import from the international market that is 5000 to 6000 miles away. But we have adjusted our refineries, and this is what we are doing.

In terms of international volumes, can we expect a flat line for next year or do you see any increases in volumes for international division?

As the new oilfields in Nigeria will come onstream, we may experience an increase in production in the international area. But most of our investments in the expansion of international activities is still in the exploration. Well, actually, we're growing, and all this we have established for growing internationally in E&P is organic growth. So we are investing in exploration instead of making acquisitions. So this will take some time and expenditure at this first moment.

Rebecca Gutierrez, ODS-Petrodata.

My question was concerning slide 5. I believe you mentioned that you were analyzing possibly tying in wells from nearby fields to increase the output of FPSO-Capixaba on the Golfinho Field. Can you disclose which nearby fields you were specifically looking at?

We did not decide yet, but let me have Ugu help me --

We have not decided yet and we're looking for the best opportunities in order to field the units.

[Neil Morton, MS Global].

I had a question on the Pre-Salt blocks that were withdrawn from the upcoming licensing round. What is your best estimate of how long it will take to evaluate them, and would you envisage forming a consortium with international partners to explore and develop them in the future?

We are already working with other companies. We are in a joint venture with BG and PetroGulf. And all the acreage that we have in the Pre-Salt section, most of it in joint venture with other companies. In order to evaluate the Pre-Salt section, it's much more time available in the quarter, in the [cross-section contrum] than our needs, because it will take a good time to evaluate this because of the size of this section. Then we will use the time available, which is close to five years, in order to drill our wells and make some long-term tests and to see if at the end we can have a development program, a development project and declare the commerciality, okay?

I was referring, actually, to the blocks that haven't been awarded, that were withdrawn from the licensing round.

Probably in the future, if they have been leased by A&P, probably we will work with other companies the way we are doing today, okay?

And could I also just follow up on a couple of questions on Tupi? I have seen lots of aerial maps in the fields, and I think you probably alluded to this earlier about the comments about the failure to drill the oil/water contact. But I haven't seen any comments yet about reservoir thickness. Do you have any indicative numbers about gross pay, net pay, that sort of thing?

The first well, we disclosed this information in the results of the first, on the Tupi, and the first one, which is the 628 well. The first well found a reservoir close to 80 meters of thickness. And the second one, which is Tupi, found three reservoirs, the first one indigenously below in south and the other two sections below this reservoir, with almost the same thickness, close to 100 meters. And we didn't find the water contact. Then the reservoir is quite clear, and we couldn't see any folds. And that's why we evaluate the size of the Tupi Field, okay?

Okay, fine, but the depths you gave are net pay rather than gross?

I don't have this number here, but it's difficult to say. I don't have it here, okay?

That's fine, I will leave it there. Thank you very much.

Thank you. That is all the time we have for questions. Mr. Barbassa, please proceed with closing remarks.

Okay, I thank you for your participation with the call where we discussed the third-quarter results, and we showed that we have a very high potential, and we expect to give the good results of the Company for the quarters to come and years to come. And thank you very much for your patience.

Ladies and gentlemen, your host is making today's conference available for replay starting one hour from now. You may access the replay at IR website or by dialing 973-341-3080, also followed by the code 9425916, lasting through November 20. (OPERATOR INSTRUCTIONS).

This concludes Petrobras' conference call for today. Thank you very much, and have a nice day.