Petróleo Brasileiro S.A. - Petrobras (PBR) Q3 2007 Earnings Report, Transcript and Summary

Ladies and gentlemen, thank you for standing by and welcome to the Petrobras Conference Call to discuss 2007 Third Quarter 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 Barbassa, CFO and IR Officer and his staff. At this time I would like to turn the conference over to Mr. Ted Helms, Investor Relation 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 simultaneously 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 Question to Host' any time 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 we'll discuss Petrobras's results prepared in accordance with the Brazilian GAAP. At this moment we are unable to discuss any issues relating to U.S. GAAP result. A 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 first since the first discovery of the Giant Fields of the Campos basin almost 20 years ago. On Thursday we announced that Tupi area in the block BMS-11 is escalated 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 areas and passed 8 of these wells. Based on the performance of these past wells, all the oil produced from them, we feel confident in our hypothesis that the pre-salt extend 800 kilometers from north to south, and it is some 200 kilometers wide. It is located in waters' depth of between 1500 and 1300 meters. We do not believe these are any... there are any particularly troublesome technological issues. We expect to produce from the Tupi area. The technological challenges we'll instead be focused on how to reduce the cost of development and operation. We still would not had a reliable cost estimate or development. Although we do think it's, 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 18 to 20. One of our principal challenges will be how to utilize the gas. Either through re-injection gas pipeline connecting to the other gas facilities or even such novel ideas as generating electricity and then transporting electricity to the mainland. With respect to future production on these areas we currently expect to have 100,000 barrels per day pilot program by 2011. Production from Tupi and all the recent findings are not covered in our production goal nor are the costs associated with developing these two. As we learn more and review our long-term business plan, we will inform the market accordingly. These we moderately adjusted to [ph] Tupi and other potential discoveries in the pre-salt. In CMP our national quality on energy policy and in coordination with A&P, has withdrawn pre-salt blocks from the upcoming ninth bid round. They had 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 bordering the pre-salt concessions already awarded will not open [ph]. Petrobras estimates that approximately 25% of pre-salt areas have already being awarded of which Petrobras offset an interest of 75%. We have not made an announcement of just recoverable releases in other blocks such as BMS-9 and BMS-10 although we have stated that we do not expect future reserves announcements for these blocks to be in the same magnitude of BMS-11. Turning now to third quarter results, slide 4. As you can see production was up less than 1% from the prior quarter. We are all going behind that of new system introduced earlier in the year was essentially offset by natural decline and a series of un-programmed 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 on stream and unexpected platform stoppage had caused average production to fall below our previously announced target. You can see how our year-over-year production has increased whereas the implementation of new system 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 108,000 barrels per day platform, our work interest is only 9%. Repsol-YPF owns the other [indiscernible]. FPSO - Capixaba has added 38,000 bpd to the average of 2007 as compared with 2006. Unfortunately the reserve oil performance of this area has been below expectation and consequently the platforms production capacity of 100,000 bpd has not been reached nor moved. We expect to do so in the trajectory future. We are analyzing the possibility of timing order wells from neighboring fields to clearly 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 the year we expect to tie wells at 103 into P-34. This well taps a pre-salt field in the Jubarte area. This tying 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 total range of about 6000 bpd to 100,000 bpd by the first semester of 2008. The addition of capacity of these platforms which added 203,000 bpd of new production compared to its nine months 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 3 million units during the first quarter of this year. This should lead to a sustained period of production growth in 2008. Golfinho Module 2 is currently moved and we expect first oil in next week. Up to the end of 2007 two wells will be producing and we expect this production to occur in the first half of 2008. P-52 is currently moved and it is... and in the process of connecting a first well with first oil expected later this month. Up to the end of 2007 two wells will be producing and we expect peak production of these units 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 target for annual oil production in 2008 is 2 million barrels per day. As you will see this targets are below our previously announced guidance of 1,840,000 bpd in 2007 and 2,060,000 in 2008. And we prudently expect first volume from P-51 in June of 2008 and P-52 and FPSO-Cidade do Rio de Janeiro by December 2008. Most of the production for strong units will be felt in 2009 and this all provides strong follow-in support for the production growth we are expecting from P-52 and P-54 for next year. We must carefully monitor our oil production growth but it is also was mentioning the growth in gas production next year as we have seen complete results from our investment in oil and gas. As you can see in slide 8, phase two of Peroá Fase 2 will add 5 million cubic meters during 2008 with first gas from this development to accrue in November 2007 this month. Additionally we expect first gas from Camarupim in December of 2008 to get at least fuel production units... will have a nominal capacity of approximately 50 million cubic meters of that to date or equivalent to 98,000 bpd of oil equivalent. The contribution from this gas forms 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 blend 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 company 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's more closely represent the cost of alternative source of energy. Our REDUC extension facilities continue to move forward and we continue to expect to have the regasification capacity of approximately 20 million cubic meters per day available by the end of next year. We will move now toward discussion of our domestic refining sectors. On the slide 9 as you can see refining performance as measured by capacity utilization to boost domestic oil 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 product increased by 0.6%. The increased demand were achieved through output required an increasing product input primarily diesel. The improvement in throughput since last year as a result of the completion of the upgrade of REVAP [ph] refinery which has increased reliability and the capacity. We continue to invest in improving refining margins in Brazil primarily by building delayed cokers that will process more of our domestic head crude oil; I assume, will permanently 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... we have announced benefit of... through the supporting our hedge domestic oil for rising cost of the oil. We finally have commenced, we will also be substantially improved by the increment of output of 47 barrel 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 we plan our performance. As you can see in slide 11, during the third quarter of 2007 the average price of our crude oil increased by... increased to $64.4 per barrel from $57 in the second quarter. Part of this difference is attributable to the decline in light/heavy differential in crude oil market which has the differential between the crude and that of Brent to fall to $10.50 versus $11.70 in the previous quarter. Finally we look at international refining margin expressed by US... United States Gulf Coast crack spread. We see that they declined dramatically during the period from $14.9 a barrel in the second quarter of 2007 to 8.8 during the third quarter of same year. As you see in later slides, lower international refining margin and a smaller light/heavy differential led to higher earnings in our BNP segment and lower earnings in our refining segment. In the slide 12 you will see the margin between brands and other to realization of price of our basket of products in Brazil decreased from $9.5 in the second quarter to $6.2 in the third quarter of 2007. These are fueled by margins as a results of the decline of international refining margin. From the second to the third quarter of 2007 the margin between average realization of price in Brazil less that of U.S Gulf Coast was recently unchanged at $4.5 per barrel. During the month of August the temporary devaluation of Riyal as a result of the effect of the sub-prime prices caused by the differential to widen. The increase in international product price in September caused the differential to widen further. It should be noted that the comparison between price in the U.S. Gulf Coast and Brazil is not an exact comparison and is more useful as an unused illustration of our long-term commitment in international price leverage. For example, quality differential between products in the Gulf Coast and Brazil affect prices. Additionally, gasoline in Brazil faced competitive cost pressure with Ethanol and compressed natural gas. Therefore an increase in gasoline price in Brazil will diversely affect demand. So with US Gulf Coast prices are an important indicator of pricing levels. But other factors might... must also be considered. We will continue our policy of not processing 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... this international price. Moving to slide 13, we show a comparison of second quarter versus third quarter results. Net revenue increased primarily as a result of increased demand for deliverables in Brazil. This additional demand to offset price by an increase in imports which increased the cost of goods sold. Offsetting the increase was... cost of goods sold improved... increase was caused by higher cost of imports. EBITDA was affected by one-time expense of 6... currently is 97 million reais related to an amendment to greater re-benefit... 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 50 million reais also reduced EBITDA. In the other adopting measures to control these costs, although some of them are unavoidable as we invest in personal and fixed amount in preparation from our future growth. Primarily as the results of these items EBITDA declined proportionally from the strong 14.2 billion reais in the second quarter to 13.1 billion reais in the third quarter of 2007, a decline of 1.12 billion reais. This led to inflow decline in our operating income which also fell by 1.26 billion reais as compared to the prior period. And net income which also declined by 1.27 billion reais. Please refer to our marked report issued on November 9th for further reconciliation between second and third quarter of 2007 as well as a comparison of the first nine months of 2007 as well as 2006. In this slide 14 we have already discussed this change associated with cost of goods sold, general and administrative and the pension and health plan. Slide 15. In the slide 15 you will see that lifting cost... both were the unexpressed in dollars and reais have stabilized particularly in the past 12 months. The lifting cost in US dollars excluding government fee, including from $7.33 to $7.65 between the second quarter and third quarter of 2007. During the last 12 months from this first quarter of 2006 to the third quarter of 2007 lifting cost increased by 5.6% or $0.41 a barrel. A limited increase in lifting cost of fuel despite the delay in ramp-ups and new projects... of new projects which caused pressure and that the unit leasing cost as full operating costs would not be allocated against the full capacity. It is also worth noting that during the same period of time, crude volume increased by more than $25 per barrel. During the recent history we think that most of the cost inflation in the industry is behind us. Also if the price of crude oil remains in the $90 per barrel range, additional cost pressure have to be expected. When calculated in reais recent costs excluding government fee increased from 14.45 reais to 14.65 reais between the second and third quarter of 2007. From the first quarter of 2006 to the third quarter of 2007, we had declined from 15.46 reais to 14.66 reais per barrel. The decline of leasing cost line expressed in reais, that most rates the importance of the extend rate up on our lifting cost. Turning now to slide 15 through 17, I would like to review the results of two principal segments, domestic exploration and production and the refining and transportation operation in Brazil as well as our overall growth results. In the slide 16, you will see the first two results from E&P segment. The higher value of fuel in general and a smaller light/heavy differential led to higher price for this segment revenue. The small increase in production also contributed to additional revenues. We imported oil products increase reflected in the cost of goods sold. Slide 17 reconciles the change in income of the downstream segment in Brazil where higher carriers volume because of an increasing demand of 3% and much less to higher revenue. These additional revenues were more than offset by the higher cost of product sold primarily important to high light crude oil and product need to meet the increase demands... domestic demand. Declining refining costs from $2.69 per barrel in the second quarter versus $2.55 in the third quarter of 2007 due to fewer programs and refineries shutdown partially offset the previous increase mentioned. Slide 18. Turning to slide 18, we can summarize some of the results from the previous slides to reconcile the net income. You can see that increasing the cost of goods sold exceeded increasing revenues. Operating expenditures were primarily affected by the charge of 695 million reais 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 from that refinery investment and international expansion has all contributed to an increase of 35% in the investment 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 range of 25% to 35%. Also the special investment program was partially responsible for the change in the ratio. Also worth noting, during the quarter Petrobras purchased 2.9 billion reais of long-term Brazilian Government loans to hedge the existing liability of the Petros fund. This reduced our cash and cash equivalent by an equal amount accounting for the minor increase in our net debt to net capitalization. I would like to conclude this presentation by reviewing the total shareholder returns of Petrobras during the last five years and comparing them against the return of the... a 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 opportunity. 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'll now be happy to address any question you may have. For help with a specific questions I have my staff with me. Thank you. Question And Answer

[Operator Instructions]. Our first question comes from Paula Kovarsky of Corretora. Paula Kovarsky - Itaú Corretora de Valores S.A.: Hi everyone. I have actually three questions. First question relates to increase in imports of light oil. I understood from your presentation that this has a lot to do with diesel requirements and the domestic demand. But I would like... in the release we mentioned couple of problems with high activity levels in domestic oil production. So I would like to understand how much of this tax increase in imports and whether this is recurrent or not. And the other question relates to leasing cost that we see going up at the end and your 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 it was mention today in Brazilian press about the potential change in the petroleum law. So would you be able to comment how will that affect Petrobras royalties and government take payments going forward?

I'm not clear. I feel that farmers prepare their land for new crops. So, there are more demand of green fields. But since we consume in Brazil all the diesel that we produced here, in this case it's important to calculate the maximum and to produce the maximum diesel we can do from our refinery. And sometime, running the financials, running 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... we'll have something else from our downstream. Paula Kovarsky - Itaú Corretora de Valores S.A.: It's better to import light oil than the diesel?

Just diesel. This is the reason why we have imported more light crude and more diesel in the quarter. Regarding lifting cost we would like to say... because I found that in the previous quarter, we would have had almost no increase in the lifting cost. What has increased is the government take and the government take related to the oil price... international oil price. Anything else. Are you looking to the lifting cost in dollars or just comparing the direct market with this quarter in reais? Paula Kovarsky - Itaú Corretora de Valores S.A.: No, I am talking about the U.S. dollar number which is the number where you base your guidance actually on a -- any five-year plan you are progressing a downward curve on lifting costs. So I would like to know by when shall we expect the downward trend to show up?

I don't think there is such trend and probably this is an exchange rate impact on these numbers. We are working harder to reduce the lifting costs. We have some program and I think that we are succeeding on it bit. And also 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 to take the blocks out of the ninth round to better evaluate. And let's wait for what they are going to say if they are 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.

And our next question is from...

Please go ahead please.

Our next is 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 be 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 this 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 this negotiation for Petrobras because at the same time that we have stabilized the old plan, we were able to offer to 20,000 new employees that pension plan as well. And the cost was once for all.

Our next question comes from Marcus Sequeira of Deutsche Bank.

Hello, good morning everyone. Just two questions. One, I know this is pretty early to tell, but can you... 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 negotiation you guys are having with the distributors in order to satisfy their demand and at the same time be able to dispatch from your thermal plants? Thank you.

Okay. Regarding Tupi light oil, we do no have yet tests on our refinery oil. We expect that being light will improve the conditions for our refineries but it was not that specific. We cannot tell much about that at this point. Regarding natural gas and distribution company negotiation, which 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 and have the flexibility to deliver all the product to be used instead of gas when the gas is needed for other reasons.

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

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

Thank you very much.

Our next question comes from Mark McCarthy of Bear.

Hey guys, good afternoon. I have a number of questions, some are pretty straightforward. I mean first of all I wanted to thank you for this sort of project update. I think it was good addition to your prepared remarks. There was a couple that you... 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 buyback any shares and what is the deadline; I can't recall the deadline of the announced buyback program for the preferred stock. There are 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 cost. 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?

Let's... first question. Let's start from the beginning, Gasene. Gasene, we have already signed all the contract, we've split the total pipeline into five units, then 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, we expect for this time [ph].

So construction hasn't 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.

So we are assuming 18 months from the start date, is that fair?

We expect to have it operating by 2009. And I am going to check there 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 take into consideration what happened recently in the company.

What's the deadline on that Almir?

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

November?

December, another month. We have another... and the costs of... or the impact of the cost of 52 and 54... maybe Ildo can tell us something. We suppose by this quarter... the third quarter, we have most of the costs already running because we were working on the platform to be ready to start. But Ildo please? Ildo Luis Sauer - Director of Gas & Energy: Thank you very much. Ildo Sauer from E&P, and well we are going to take about 9 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 or the 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's quite difficult to forecast what will be the impact on the next quarter because most of the... the most important share of this costs has already incurred, now it is just time to wait until we reach the peak of this production of this unit. Okay.

But Ildo, you have not started expensing the costs from P-52, P-54 until you have first oil, right? I don't mean the cost of construction; I mean the cost of lifting? Ildo Luis Sauer - Director of Gas & Energy: Yes, but we are already incurring in the costs of people on board and all the clearance costs to keep the platform on location and working and connecting the wells and they are all there, and these costs are being accounted. Okay.

So would you say there shouldn't 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? Ildo Luis Sauer - Director of Gas & Energy: I think it is good to evaluate and to make this forecast.

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

And next question comes from Gustavo Gattass of UBS.

Actually we will hold on a minute, I think they are still answering the prior question.

Mark, you have right, the cost of... 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? Ildo Luis Sauer - Director of Gas & Energy: We still have a number of years in order to declare commerciality of Tupi, and we will use this time that can reach maybe up to five years and we will use these in order to fully evaluate the fuel and so 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 cost of drilling for each well and the time of drilling and we are quite confident about the feasibility and we are studying just the economic and the alternatives and we will need more wells in order to reach this conclusion, okay.

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

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

Mark, I am having Ildo to helping you but I doubt he has this breakdown. Ildo Luis Sauer - Director of Gas & Energy: Maybe I can send you later. And... but I don't have here these numbers... this breakdown on...

Okay. I'll come back to you offline.

All right.

Thanks guys.

Our next question comes from Gustavo Gattass of UBS.

Good afternoon guys. I have a couple of questions here, just the first one. When you were talking about the pre-salt development and talking about Trubask [ph] here potentially running one well from a pre-salt find in the Campos basin. I was wondering if you could, I would say, first give us an idea of how large you guys think that time might be and second if you could 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 must say that we do not have the information about the volume of the field. We are going to start final production in the Trubask. But I will transfer you to Ildo, he can tell more about the potentiality. Ildo Luis Sauer - Director of Gas & Energy: 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 that... to drill, and for sure, we believe that while we are drilling these wells next year... in the next two, three years, this is a campaign in order to fully evaluate the acreage we have over the pre-salt section. And... but we don't have the numbers. And it's difficult to make a forecast about its volume. We are quite confident, we are drilling the wells as there is a number of wells just in... up to December 2008, we are going to drill 32 wells just on the pre-salt section. That's a pretty big picture, isn't it?

Okay. No, that's fair. I had two other questions. The first one, you mentioned to Mark 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, evaluations for the cost of the module in Tupi today? Ildo Luis Sauer - Director of Gas & Energy: 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 find 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.

Okay. And my last question just referring to the production units... you have a number 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. Ildo Luis Sauer - Director of Gas & Energy: Okay, for the Brazilian earnings, we have all the license both for P-52, P-54 to stop the drills and I know also for the field, and there will be no delays related to environmental license. We are just looking for the environmental license for... in order to move the Seillean to start producing in Jubarte which is our next field [ph], but we believe that it will... we will receive the licensing in the next couple of months, then will be possible to start positioning that to move to last... to other location, and then in this short-term, there is no problem 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 on-stream during the next year by... one by mid of the year, and the second on the second half.

Okay, thank you.

Our next question comes from Paul Cheng of Lehman Brothers.

Hi, and good afternoon gentlemen. I have several short questions. Almir, I just want to clarify that in the third quarter you did not receive any tax benefit associated with interest on capital rate?

Benefit on interest? We did declare interest on our own capital in the same amount we did in the second quarter.

So there's a 219... Tupi and 196 or 94 [ph]?

Yes, yes. Each quarter what gave us a rebate on the tax.

Why the effective tax rates, if that's the case, to be so high? That the benefit of the interest on capital that you declare, should we have seen a much lower effective tax?

No, we think that income tax in the fourth quarter, because we have the lower net revenue, but because also we declared interest on capital. But today's no difference between third and... second and third quarter, regarding interest on...

No I understand that, but if I do a simple math the effective tax rate in the third quarter is about what 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 figure it offline on that one. On the second question on Tupi, I presume since you only have drilled two wells, this is not a P-90 estimate on the find being build. Can you tell us is it a P-50, is it 50% probability or what kind of probability that we should look at that estimate?

Okay. Let's have Ildo to answer your... this question. Ildo Luis Sauer - Director of Gas & Energy: We're in the process of evaluating the size of this discovery. It's quite... it's not possible to say if it is a P-50 or P-90. We are trying to find what are your contracts, if we did not it then we are saying that from the depth that we build these two wells, we believe in this 5 billion as a minimal 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. Then we have to drill more wells in order to evaluate and to get a better picture of it.

When are you going to drill the next appraisal well? Ildo Luis Sauer - Director of Gas & Energy: Well it will depend upon the schedule for all the drilling rigs, then we drill the wells in the same place. We have a schedule and immediately after a well has been finished, then we decide to what location is better to the drilling rig to go. Considering the schedule, we do not disclose the schedule and because it's... 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 year.

Is it going to be first half of next year or second half? Ildo Luis Sauer - Director of Gas & Energy: Maybe the second half.

Second half? Ildo Luis Sauer - Director of Gas & Energy: Yes.

And Almir, I just want to clarify the government does special participation. Are those being... is calculated based on your actual oil realization, is not based on the brand price, the benchmark price, right?

No, it is based on the international oil price.

The fact it is based on the international oil prices, not on your actual realization?

Yes, yes, it's based on international and not on our realized... average realization price.

Okay. Because that seems to get a conflicting signal previously. A final one on Venezuela, your recent exit on 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 one-off project-by-project or that that's something a little bit... a more bigger scale in terms of your approach to Venezuela?

No. Well in fact negotiating 12, 14 projects to work together with PDVSA. And as we reach a conclusion on these studies, please be sure that conditions for us is not economical, then we dropped and this is one of the cases. We still have an oil project going on, on Venezuela area as well as the refinery in the north east of Brazil that they have to be our partner. But in the case of Mariscal Sucre, is just came to the conclusion that the economics were not attractive for us.

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

2007 now budget is 54 billion reais.

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

Probably, we will be below the target. We still will not reach this much. Till September we spent 30.6 billion reais, so spent to 20 billion reais... almost 24 billion reais in three months, probably it will be under 50 billion reais in realization.

And how about 2008?

I don't have this year... the budget for 2008.

Maybe 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.

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

Okay.

Thank you.

Welcome.

Our next question comes from Christian Audi of Santander.

Almir, question was related to the refinery margin and pricing. Really we saw a squeeze on the margins this quarter given the behavior of oil prices and refined product pricing. So far in October, November that pressures is likely to continue into the fourth quarter further eroding your refining margin. 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 really do something about domestic gasoline and diesel price?

It is your question that follows the answer is follows our price policy. We don't see it. Of course if you see at this moment $100 almost like 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've had oil below $50 this year and we do not adjust for a short price. Let's see how the market will perform in the future and then if necessary we will readjust the domestic price.

Okay. So from a commercial point of view, you are not... because we are getting to quite low levels, you are not seeing... you are sticking to that policy, in another words commercially... I am sure your commercial people are not happy and definitely putting pressure on something to happen, but you don't see that toward 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 is on integrated company is the consolidated figure. And as a consolidated figure, we are doing as the other oil companies. If you will take our peers and see how they perform in this same period, you are going to see that. But we are not far from them. We are 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 year.

Okay. And the second question is 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 it was 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's shape-wise may not be at a very top level, thus requiring lot of investment. But is that the typical format of the refinery capacity that you're searching for currently internationally?

The main reason how then we bought the Okinawa refinery is for trading. That refinery has 9.6 million barrels of storage capacity and these can help us to better market the products we are selling in the region. And Okinawa is very well placed between Japan, Korea, China, and so we are already established in Singapore. We are having there the huge storage capacity, we have in these refineries three... we replaced three boxes, where ships can unload, one of them, one monopoly [ph] for the FCCs. So 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 for the refinery itself that costs a very, very low price.

And the last question is for Ildo. Ildo, with respect to the... a couple of quick ones, how many appraisal wells were you talking about for developing? And 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 are 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 are going to need to develop to keep obviously Petrobras being so large the advantages that you have access to all the platforms that you are currently using elsewhere in your system. But given the nature of Tupi, the depth, the pre-salt, is equipment likely needed for Tupi or something that you can just reallocate out of other fields you are currently working on or will it really need to be especially designed platform for the high-def needs of Tupi? In other words can you just... 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 process of building and ordering platforms from scratch? Ildo Luis Sauer - Director of Gas & Energy: Yes, well, the first question is where we are going to drill was much as necessary, just as a simple matter for your question. But we have a few years, we have moved up to five years to... we plan commerciality of Tupi, then we are 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 the behavior of the tools in the reservoir before decide what kind of development is the best one. Then there is no way to discuss if we can use the same solutions we are using in the Campos Basin or use FPSO to move an FPSO platform or semi-serbai [ph] FPSO to peak, 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 the end, we will be able to figure out what is the best development scheme. Okay?

Okay. Thanks.

Our next question comes from Cabu Carmar of Lucite Research [ph].

I have a couple of questions. Can you give us near-term guidance for natural gas production for '08? You are doing it for crude oil in the presentation. What would be for the natural gas, I think at the moment is about 270,000 barrels a day. So can you give us... comment for on 2008, what will be the guidance for natural gas? Ildo Luis Sauer - Director of Gas & Energy: As we have a plan to add during 2008 and 24, 25 million cubic meters per day. This is our trend now [ph]. It represent 24,000 cubic meters which means 150 barrels of oil equivalent the next year, I don't know if it helped. Okay.

And in terms of utilization levels, is it like within the domestic efforts [ph]? Is it... 91% is the maximum capacity you can achieve or is there still room you have to increase the utilization rate? Ildo Luis Sauer - Director of Gas & Energy: In the refining capacity wins.

Yes. Right now we have achieved like 91% as the maximum utilization in the domestic refinery, is there any more room for increasing the rate to closer to 95% or mid 90?

We are working hard to increase as largely as we can, but if you compare with international standard, we are not far off to the record levels that capacity can be utilized in refineries. And don't forget that we are giving you the average of 11 refineries if not one or two. So the average 91% is very high leverage when compared with the industry. But of course we're investing in quality and control and insurance base to increase the reliability in the refinery to even... improve even more the utilization capacity.

In terms of the usage of domestic crude, it seems to be still at 78%. Is it because still the mismatch and you need to import light oil or what is the plan. Is it eventually going to go... you'll be 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 are going to inaugurate one delayed coke unit per year and these will help us to process more and more of the domestic oil. This is a program and that we have established some time ago, and we are implementing. To build out one coke unit takes time. And 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 5,000 to 6,000 miles away. But we have adjusted our refineries, and this is what we are doing.

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

The new oilfield you may see will come on stream really experience an increase in production in the international area. But most of our investment in the expansion of international activities is still in the exploration. Well, actually, we're growing and the... all this we have established for growing internationally in E&P is organic growth. So we are investing explorations instead of making acquisitions. So this will take some time and expenditure at this first moment.

That's it, thank you very much.

Welcome.

Our next question comes from Rebecca Gutierrez of ODS-Petrodata.

Hi, good afternoon everybody. 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 field you were specifically looking at?

I guess we have not decided yet, but let me have Ildo help me here. Ildo Luis Sauer - Director of Gas & Energy: Well we have not decided yet and we are looking for the best opportunities in order to field the unit.

Okay. All right, that was it. Thank you.

Our next question comes from Neil Mortin of MS Global [ph].

Good afternoon gentlemen. I had a question on the pre-salt blocks that were withdrawn from the upcoming licensing round. What's 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? Ildo Luis Sauer - Director of Gas & Energy: We are already working with other companies. We are looking... we are in 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. And in order to evaluate the Pre-Salt section, it's much more a time available in the quarter... in the cross section quarter in balance [ph]... our need because it will take a good time to evaluate the... because of the size of this section. Then we will use the time available which is close to five years in order to drill more wells and make some long-term tests and to see if at the end we can have a development program... a development a development project and declare the commerciality. Okay.

I was referring actually to the blocks that hadn't been awarded, that was withdrawn from the licensing round. Ildo Luis Sauer - Director of Gas & Energy: Yes, probably in the future, if they been leased by A&P, probably we will work with other companies the way we are doing today. Okay.

Okay. Could I also just follow-up on a couple of questions on Tupi. And I have seen lots of aerial maps in the field and I think you probably alluded to this earlier but the comments about the affiliates that drill the oil-water contact but I haven't seen any comments yet about reservoir thickness and do you have any indicative numbers about gross pay, net pay, that sort of thing? Ildo Luis Sauer - Director of Gas & Energy: Okay, the first well we... in the... we disclosed this information and the results of the first drill and this will be on the first one as a fixed rate well. The first well found a reservoir close to 80 meters of thickness and the second one which is Tupi around three reservoir. The first one immediately below the south and other two sections below this reservoir with almost the same thickness close to 100 meter and we didn't find the water contact. Then the reservoir is quite clear and we couldn't see any fault and that's why we evaluated size of the Tupi field. Okay?

Okay, fine. The depths you gave are net pay rather than gross? Ildo Luis Sauer - Director of Gas & Energy: Well I don't have these numbers here but, now it's difficult to say.

Okay that's fine, I leave it there. Thank you very much. Ildo Luis Sauer - Director of Gas & Energy: Okay, thanks.

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

Okay, thank you for your participation in this call while we discuss the third quarter results and we showed that have a very high potential and we expect to keep the good results in the... 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 to replay at IR website or by dialing 973-341-3080, also followed by the code 9425916 lasting through November 20th. The number again is 973-341-3080. At the voice prompt enter the access code 9425916. This concludes the Petrobras conference call for today. Thank you very much and have a nice day.