巴西石油 (PBR.A) 2008 Q4 法說會逐字稿

Ladies and gentlemen, thank you for standing by. And welcome to the Petrobras conference call to discuss the fourth quarter and fiscal year 2008 results. At this time, all lines are in a listen-only mode. Later, there will be a question and answer session. And instructions will be given at that time.

(Operator Instructions) As a reminder, this conference is being recorded.

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

Good afternoon, ladies and gentlemen. Welcome to our conference call to discuss fourth quarter and fiscal year 2008 results. We have a simultaneous webcast on the internet that could be accessed at the site www.petrobras.com.br/ri/English.

Before proceeding, I'd like to draw your attention to the slide two. We may make forward-looking statements, which are identified by the use of the words will, expect, and similar, that are based in the beliefs and assumptions of Petrobras management and on information currently available to the Company.

Finally, let me mention that this conference call will discuss Petrobras's results prepared in accordance with the Brazilian GAAP. At this moment, we are unable to discuss any issues relating to US 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. And he will be available to answer any questions you may have. Mr. Barbassa, please begin.

Mr. Barbassa, is your phone line on mute, sir?

Sorry. Good afternoon, ladies and gentlemen. It's a pleasure to be here with you and have the opportunity to talk about the third quarter 2008 results. Looking at the conference slides and the past calls to discuss results, our cover sheet has had a picture of our most recent platform installed since our last call.

This time, we have the pleasure of touching three platforms on the cover page as all three have begun producing oil since our last call. Installing three platform facilities with total processing capacity of 460,000 barrels per day in the last 90 days highlights why we are confident that we can meet our goal of producing 1.3 million barrels per day in the presalt layer by the end of 2015.

Next slide, slide three, please. Let's talk about production. Since production drives our business plan and our cash flow, let us begin with an update. As you can see, for the fourth quarter, production declined by 1%.

Let's go to the fourth quarter. We had year over year an increase of 7%, even considering this 1% decrease from the third to the fourth quarter. And we reached the record of 2.012 million barrels per day at the beginning of this month. We are, as I explained, in the ramping up of three important platforms.

Let's go to the next slide. Yes, we are showing here the three platforms. And as you will see, the three units recently installed are all wells producing 127,000 barrels per day. You can also see that Cidade de Niteroi is producing almost 33,000 barrels per day with just one well. The production from these three new platforms has led to record production of 2 million, as I just said.

Next slide, please. Presalt, a brief update on the presalt -- this year, we expect to drill nine well in the Santos presalt blocks that we operate. Eight of these are exploration for appraisal. And one is the second well for the Tupi extended well test. This year, we'll have available seven additional drilling rigs capable of drilling in water depths greater than 2,000 meters. This will help our effort, not only in the Santos Basin, but in other exploration development and maintenance needs along the Brazilian coast.

The Tupi extended well test is scheduled to commence in the second quarter of this year. We are near completion of the first well, which was the regional exploration well in the block.

Next, please. Let's see prices for the E&P. The price of oil is the biggest challenge Petrobras is facing now. As you can see, the average price of brent fell from $114 to $54, a $60 per barrel decline from the third quarter to the fourth. Given the narrowing of light-heavy differential, our own crude fell less, by $53 per barrel. In either case, it's still a decline of more than 50%.

Next, please. Lifting cost -- the decline in the price of oil did have a positive effect, the reduction of lifting cost. Lifting cost expressed in US dollars and without government take declined by nearly 20%; although, as you can see, there was a small increase in reals lifing cost because of the devaluation of the real. Government take showed a much more substantial decline, as should be expected, given the linkage to the international prices. Expressed in US dollar, government take is down almost 50%. Lifting cost and government take on a combined base are down 45%.

Next, please. Despite the drop in the price of crude oil during the third quarter, Petrobras has maintained pricing of diesel gasoline and [LPGN changed]. This is consistent with our policy of pricing at international parity in the long term. As you can see from the graph, only November did we reach parity with the US price for the basket of Brazilian products. For the year as a whole, we averaged $11.91 below parity. A portion of the decline in US dollars occurred because of the weaker real during the fourth quarter. As you can see, when expressed in reals, our revenues were much more stable.

Next, please. Trade balance -- to discuss results, we need to put into perspective how our products and our costs adjust prices. Last year, we produced 1.855 million barrels per day of oil in Brazil. 1.416 million barrels per day of that amount went to our refineries in Brazil. And 439 bpd was exported. We imported light oil to blend with our heavy oil to optimize out throughput.

Additionally, since our refineries produced some products in excess of what the Brazilian market consumes, primarily fuel oil and gasoline, we export those products, while we import what the market is short, primarily [needle] distillates and LPG.

The trade balance between barrels of oil and oil products export and imported continues to improve with a surplus of 102,000 barrels per day in 2008. However, we exported low-value products and import higher-value products. The result is a negative trade balance of 928 million.

Because of our inability to fully process the mass crude in our refineries, Petrobras last year gave up margins equal to 100,000 barrels per day of oil and oil products. Capturing this margin will provide the economic returns for our refinery investment program.

Next, please. Difference in timing between revenues and costs -- over the long term with adequate investment, Petrobras can do much to improve its refining margin based on international pricing. In the short term, margins are affected by domestic pricing policy and accounting practices. These policies and practices have an important impact on the quarterly results, especially in an environment of rapid rising or falling prices.

This slide shows the composition of our products broken down into those products that only adjust over the long term and those that adjust more frequently. Because we adjust diesel gasoline and LPG price only to maintain parity over the long term, these prices did not move even as the price of the products in the international market declined by more than 50%. The remaining products sold domestically adjust with the exchange rate and the international price of products every two weeks. Revenue from export adjusts with each cargo. Therefore, revenue declined during the fourth quarter because of domestic sales that adjust biweekly plus export sales.

The decline in the cost of imports of crude oil and products over time should roughly offset the decline in revenues from exports of oil and products, adjusted by the relative margin between exports and imports for each period.

In comparison, between quarters, however, the difference in timing of the recognition between revenues and costs can create differences. Revenues on exports and prices that adjust biweekly quickly reflect international price. But Petrobras averages the cost of our products sold over the 60-day period. Therefore, the reduction in costs, particularly of imports and government take, is not coincidental with the reduction in price. In a flat price environment, this has no impact. But when the price of products rises or falls rapidly, this has an important effect.

Next, please. Operating costs -- this table demonstrates the impact that this timing differential has during the fourth quarter. The negative impact on our results were BRL2.719 billion, which include not only the benefit from lower price that was not recognized this period but also retained cost from the third quarter.

Low oil prices had several other impacts on results for the fourth quarter. The declining value of oil also affected fourth quarter results through inventory reduction and impairments. During the fourth quarter, inventory reduction to the lower of cost or market caused a reduction in income of BRL1.089 billion. Impairments of E&P assets in the amount of BRL925 million were deemed uneconomical at the year-ended oil price of 36 per barrel, adding to the impact of the fourth quarter.

The table in this slide shows all the extraordinary items that occurred during the fourth quarter and reconciles them to the third quarter operating cost. As you can see, inventory reductions accounted for BRL796 million, while impairment another BRL925 million. The effect of inventory averaging caused another BRL2.532 billion.

It is also worth noting the impact of hedging upon our results. Financial revenues from hedge operating reached BRL603 million in the fourth quarter against BRL156 million in the third.

As you can see, together, these extraordinary items bring fourth quarter operating income to a difference of only BRL1.378 billion between the two quarters. The difference can be attributed to the lower price on those domestic sales that adjusted biweekly.

Next, please. E&P segment -- turning now to a discussion by segment, exploration and production is the segment most affected by the decline in the international price of oil. The selling price of Brazilian crude oil was $47.95 per barrel versus $79.75 in the prior period -- prior quarter.

Average production decreased from 1.883 million to 1.865 million barrels per day as a result of natural decline of existing fields and programmed stoppages. As we saw earlier, lifting costs, including government take, were reduced with the decline in the price of oil. Included within the results of the segment during the quarter was an impairment of BRL603 million, which was based on conservative long-term approach for oil price [groove], as of in Petrobras business plan of '09-'13.

The same year-end oil price caused us to write-down 1.2 billion of barrels of our [proven] reserves. This relative minor adjustment to our productivity facilities and our proven reserves at such a low oil price are reflect of the strength of our E&P portfolio.

Also included in our recognition of BRL2.551 million for exploration expense, which were higher than last year because of higher drilling costs related to exploration and a larger number of wells drilled.

Next, please. Downstream -- the downstream segment benefited from lower costs but not nearly to the extent that would have been reflected had costs not been averaged. As mentioned earlier, cost averaging means the downstream segment did not benefit from the reduction in costs from lower price of oil and products.

Next, please. Gas and energy segment -- the international and gas and energy segments are relatively small segments within the large consolidated company. Some of the results, particularly of gas and energy, are reflected by the position within a larger consolidated whole. For example, gas and energy is dependent on supply from our E&P operation. International is exploring and developing new deep water frontiers that have synergy with our Brazilian operation. Consequently, its exploration expense relatively to earning is disproportional.

To better understand the contribution of these areas, it is better to look at the full-year results. Results from gas and energy segment demonstrate substantial improvement during the last 12 months as a combination of growing supply of gas, growing power generation, and higher gas commercialization margins.

The increase in higher gross margin is the increase in margin from the renegotiation of supply contracts with the gas distribution company as well as increase in sales of gas and generation of power. As mentioned earlier, gas sales increased by 26% during the year, while [that] generation from our own plants increased by 256%.

With the increase of domestic gas supply by E&P as well as ongoing completion of the gas pipeline network and the commissioning and testing of the [Piscine] at the [northest] of Brazil and Guatemala regasification facilities, Petrobras is now well positioned to supply foreseeable demands for (inaudible) power.

As a result, penalties paid in the past, largely as a result of our inability to meet our supply commitments, are not expected in the future. These penalties totaled BRL449 million in 2007 and BRL434 million in 2008. As we look to the future, results from this segment will be driven by the amount of [thermolet] generation required by the national system operator and the value placed on that generation.

It should always be remembered that having a complete gas distribution and thermolet generation capacity provides a profitable market for the rapidly growing production of associated and nonassociated offshore gas.

Next, please. International -- the international segment's operating income were a negative BRL881 million for the year. In the waterfall graph, we show the contribution of the international area as expressed by EBITDA and add back exploration expenditure as well as other nonrecurring provisioning.

Higher prices for our upstream production were offset by lower production volumes as declines in mature fields in Angola, Colombia, and Argentina were not offset by the start of the ramp up of the [Agibum] project in Nigeria. Reduced refining margins and unplanned stoppage from our Pasadena refinery also reduced the gross margin. As discussed previously, we have adjusted this year for the impact of the hedge accounting that more accurately reflects the true operating costs.

Impairments of assets substantially reduced operating income as we recognized impairment of our production in [Cottonwood Field] in Gulf of Mexico and the write-down of goodwill related to the Pasadena refinery acquisition. We also wrote down inventory related to our international activities to reflect the lower of cost or market in the amount of BRL699 million.

In 2009, we should see additional improvement and the continued ramp up of Agibum and the start up of [Akpo] just started last week. In 2010, we will begin producing oil from Cascade and [Schnook]. And we have participated in significant discoveries in [stones] in the Gulf of Mexico, US portion, and block 1506 in Angola waters.

Next, please. The net income as we can see from the waterfall slide shows that we had a reduction of about BRL3 billion. But when we add back the nonrecurrent expenses of about BRL1.7 billion eliminating these nonrecurring items, we come back to a near BRL9 billion of net income, what shows a reduction of about 20%, largely explained by the reduction in price during the period.

Next, please. Let's see the cash flow. Because of the changes in accounting law, we did not produce a quarterly cash flow for the fourth quarter of 2008. Given the concerns over cash flow in today's environment, we can show the cash flow from the first to nine months of 2008 and the full-year 2008. As you can see, even with investment of BRL52 billion, net contract debt increased by BRL11.8 billion during the period.

Next, please. The increase in debt for the full year is distorted by the exchange rate, since more than 60% of our financial debt is denominated in US dollars. Gross debt increased by BRL25 billion, 63% of the full year. Less the increase in cash of approximately BRL2.8 billion for the year also, net debt to book cap ended the year at 26%, which is at the low end of our net debt to net book cap targets for 25% to 35%. I should caution that the leverage rate does vary very slightly when calculated in US dollars in accordance with the US GAAP.

Next, please. Here, we have reconciliation between the two GAAPs we have in Brazil. The previous one is expressed by Law 6.404, is the one that prevailed up to last year. And then we adjusted according to the new Law 11.638 of '07 that showed us the net income for the period -- for the year -- as merely BRL33 billion. The change between the two GAAPs was about BRL900 million, what is not much when you take BRL33 billion as a base.

And the main change or the one that I believe causes better impact has improved the condition -- accounting rules in the Brazil -- is the transaction. Transaction has eliminated the change that was caused by exchange rate when you translate at the end of the period all the variables, like income and expenses, that were done outside Brazil in other currency into reals, taking the exchange rate of the end of the period. And the second items in the transaction is the translation of equity the Company holds in other currency. The translation -- the gain or loss due to this translation does not go to the results anymore. It goes to the equity -- stockholders' equity.

The other items do not give us much change. The leasing is the consequence of recognizing lease as a financial lease. It comes to the balance as a debt. So you apply all the accounting rules for debt or depreciation, the exchange rate impact on debt. You have, for example, the net financial expense of BRL1.6 billion is due to the rate due to the variation of the exchange rate.

Next, please. This is a very, very important item, very important slide that shows how the market perceived the business plan of Petrobras. If you look at the Ibovespa, for example, Petrobras was following closely Ibovespa. But just after releasing the business plan, it decoupled. Petrobras has had a much better performance. And this is showing in the New York Stock Exchange when you compare Petrobras with AmexOil as well, what shows that our business plan for the next five years was very well perceived by the market.

This is all. If you have any questions, we'll be [ready] together with my colleagues to answer you. Thank you very much.

Thank you. (Operator Instructions)

Yes, operator?

Yes, sir.

I would like to also remind the investors, the audience, that could they please limit themselves to two questions, including a follow up? Thank you.

(Operator Instructions) Our first question comes from Arjun Murti from Goldman Sachs. Please go ahead.

Thank you. I was wondering if you could provide any color on the well on BMS22 that finished drilling in the quarter, the [Izulo] well, whether the results were consistent with some of the other wells that you've been drilled in the play and how you're understanding the view of the reserves in the play or any other indication has been changed as a result of the well on BMS22. Thank you.

I'm sorry. But we are not the operator of this block. And as so, we cannot tell much on it. That's what I can tell you now.

Okay. No problem. Can you provide any comments then also in terms of any cost reduction initiatives? Obviously, with steel prices coming down, some of the oil service and drilling costs coming down, how should we think about that flowing through Petrobras? Are you able to bring down your costs with some of the service companies providing services to you all? Or is there some lag? Can you make any comments on cost reductions?

Yes, this is a very important point. We are really working very hard on the [stock], not only on the operational area, but on the CapEx as well. When we announced our business plan, we made it very clear that we were working on that business plan with prices that were enforced in the second half of last year. But we were doing our best to have better price -- I mean, lower price than that. And we are really very committed to that. And we are working also on the operational.

We have adopted internally in the Company at the last year -- at the end, by November last year -- many policies towards general and administrative costs. We are having some indication that they have been fruitful. They are providing some cost reduction. We are looking for opportunities to reduce costs in other areas. For example, the P61 and P62, we just cancelled the bidding process due to the -- 61 and 63, sorry -- we cancelled the bidding because of excess price. And we are working -- redesigned the [unities] and standardized as much as we can and going back to the market trying to get a better price. So these are only some examples. This is one -- maybe the most important items for the management of the Company right now.

Our next question comes from Marcus Sequeira from Deutsche Bank. Please go ahead.

Hello. Good afternoon, everyone. Two questions -- first, you showed on the quarter a net debt-to-EBITDA ratio of 0.85. I was wondering what your target is for the end of the year. And then on page four of the presentation, you've shown that you have had good productivity per well and industry platforms. My question is -- should we expect or are you confident that you will be able to reach peak production with less wells that you were previously forecasting in that we could see actually lower lifting costs? Thank you.

Regarding the EBITDA, we have no target for such index. So we tend to be strong on it. And we are really very strong having 0.85 in this ratio.

Regarding to the second question, Molinari can help us.

Yes, of course, we are always seeking to have wells more producible. One example is the one given by Mr. Almir in [Zabochin] Cidade de Niteroi. A single well is producing around 33,000 barrels per day. In the [brief outlook], the reason we expect to have a better productivity per well, so that will help to reduce the lifting cost.

Thank you.

Our next question comes from Paul Cheng from Barclays Capital. Please go ahead.

Hey, guys. Two quick ones -- on the dividend, wondering do you have a rough idea that when the payout is going to be made of the BRL9.9 billion. Also, when looking at that, your interest on capital is only BRL7 billion that you declined. So why don't we declare a much higher number that you get the full benefit from the tax? So that's the first question related to the dividend.

Second question, on your CapEx spending, can you give us a rough estimate what is the percentage of your CapEx maybe related to the new project for the current year, in other words, the percent of the spending that has not been tied up with the old or existing contracts and will be benefiting from the job in the current spot rate?

The payment of the dividend is going to be established by our shareholders' meeting that is going to happen at beginning of April 8th.

So what (inaudible) you have a proposal that when that you guys proposing to get payout?

No, we don't have --.

Second quarter or later?

We don't have a proposal yet to release to you. But by the end, we are going to have it before, of course. The second question --.

No, I mean that with that also that why we only declare out of the BRL9.9 billion that you proposed to payout, why we only declare about BRL7 billion in the interest of capital. Is it because of the law won't allow you to declare more to take the full benefit of the interest on capital?

No, we were limited to merely the amount we declared as interest on capital. We had a very, very small additional amount, matters of cents, $0.01 or $0.02, $0.02 or $0.03 per share we could increase. But really, we reached near the maximum.

I see. Is it 70% or that I thought it's 85% you can declare as interest on capital?

We have other limitations. (inaudible) We have a referential interest rate in Brazil, TJLP, that applies to net equity, shareholders' equity, to calculate the maximum we are allowed to declare as interest on own capital. And we went to near the limit we were allowed.

Okay. Thank you. And how about the second question?

Can you repeat it?

What's the percentage of your current year capital spending related to the brand new projects that do not have contracts already tied up? In other words, how much -- out of the $28 billion, $29 billion, how much is the spending that we should expect to benefit from the job in the raw material costs and the service cost?

We don't have this figure to tell you. What I can say is that most of what we are doing this year are [already] the contract. But how much, if you ask me, I would not be able to tell you. From the plan, this five-year plan, we have 35% that we're not yet under contract. We're flexible. But for the current year, higher amount is already with established price. But we have many, many services and equipment that are contract along the year. So there are opportunities here to adjust some of these costs. But how much, really, I cannot tell you now. I don't have this information.

Thank you.

Our next question comes from Emerson Leite from Credit Suisse. Please go ahead.

Okay. Good afternoon, everyone. Good afternoon, Barbassa. One question in relation to costs -- drilling cost is a big component of your future spending. And as recently as last week, we saw this new contract between Petrobras and Vantage Energy for the plutonium explorer at a fixed-year rate of $550,000 per day for an eight-year contract.

This is one of the highest rates on record for the industry. And given the status of things, I would like to understand why is this contract good right now. Why couldn't you wait a little more to try to get a better rate if you are really willing to see lower rates going forward? So why having this contract in place right now? And what is your feeling in relation to drilling costs going forward?

And the second question is in relation to the potential financing deal with the Chinese, if you could provide a little bit more color on what has been proposed in terms of the financing conditions, in terms of potential oil supply to the Chinese, a little bit more substantial the potential agreement so we can understand how good it will be for Petrobras. Thank you.

Emerson, regarding the cost of drilling, this drill ship was higher than was contracted by the international area. I have no representative here. I'll make some clarifications on our website to you and to the audience later on. Really, I don't know the reason. Probably, they have some commitment on the drilling. But I have to make it clear with the international area.

Regarding the negotiation with the CDB, the China Development Bank, where we are negotiating a large amount of financing to Petrobras in exchange to the possibility of a strategic supply of oil, it does not mean that we have to supply everyday. We have a commitment in the case of supply a certain amount of oil in case they require. And the details on these contracts are not yet available. We are still under negotiation. So we don't have neither terms neither conditions for such contracts. They are being built at this moment.

Okay, Barbassa. Thank you.

Welcome.

Our next question comes from Denis Parisien from Santander. Please go ahead.

Hi, gentlemen. Thanks for the call. Could you give us any color on the outlook, the possibility for lower prices in the domestic market for oil in diesel and those products that have been -- prices been kept stable this year? And can you give us any guidance on what you expect your EBITDA level to look like for the full-year 2009? Thanks.

At this moment, we have no decision on this subject -- I mean, no change in our current strategy. Prices -- if you look at the future prices, they are higher than the current ones. So according to our policy, we did not arrive to a moment to adjust costs. And if you look back during '08, our [PMR] were about near BRL19 per barrel below the international.

So to average longer run the international, we shall be on the level we are today. I don't know how much, how long it's going to take and how soon we are going to perceive that. Really, prices are going to stay where they are for longer period. So I cannot be of much help at this moment. What I can tell is that we are keeping the prices we are pricing today.

Okay. Are you going to provide any color on what you expect, some guidance for EBITDA for 2009?

No, we don't give guidance.

Okay. Thanks very much.

(Operator Instructions) Our next question comes from [Sevlo Durapia] from Morgan Stanley. Please go ahead.

Hey, Barbassa. How are you? Two questions, one on the debt side -- in order to maintain investment-grade status, what kind of credit ratios would you be looking at? Would it be net debt to capital, net debt to EBITDA? What kind of metrics should we monitor in order to make sure the Company would continue having the investment grade?

And the second question is related to page four of the presentation. I wanted to know if there's anything different from previous wells that were drilled and the pace of the ramp up, as this seems quite amazing with one well being drilled already 30,000 barrels being produced. I wanted to know if there's something unusual there, there's something new that is being implemented on these platforms that weren't before, or if not, why so. Thanks.

Okay. The metrics we are following is the net debt to net cap. As we have announced, we are aiming to keep this metric on the range of 25% to 35%. And I would like to make here -- to stress one point. Based on our business plan, if you look at our business plan, you are going to see that we work for financial purpose with oil price -- brent oil price -- of $37 per barrel. And at that price, according to our calculation, we'll be able to produce $10 billion of net cash flow after paying dividends and amortization and debt amortization.

And we thought also that every dollar in average for the above at $37 would give us an extra cash of $500 million. So far, the oil price has been higher than the $37 in average for the year. If it remains like that, we'll be generating more cash flow than we expected.

On the other side, we wok with very conservative costs. I meant the cost for CapEx and the operational costs that were taken, the cost of last year's second half. And there is a good chance that we are going to have a cost reduction for the year for most part of the year. And this is going to reflect as an extra cash generation for the Company. And all this together will help us to keep our ratios in the range we are aiming at.

Regarding the productivity of the last platform, Cidade de Niteroi in the [Djibouti] field, I'll ask for the help.

Okay. It's a platform with 100,000 barrels per day capacity. We are producing light oil. It's 28 degrees API. So the productivity is (inaudible). So we expect to have also high productivity in the presalt of the Santos and the Espirito Santos basins. So it's not a new technology. But it is (inaudible).

Great. Thank you very much.

Our next question comes from Gustavo Gattass from UBS. Please go ahead.

Hi, guys. I had one question per the request. But you mentioned in the Brazilian event that over the course of the first quarter we might have a better feel for how the cost-cutting effects might be playing out into the Company and also a short mention that we might even have a feel of how the CapEx might be looking at. What I wanted to understand is just when I look at the guidance that you have given out, the $28 billion for 2009, is that number subject to any kind of relevant downgrading if you can negotiate lower prices? Or is most of that already locked in?

Gustavo, we are looking for the opportunity to realize, to execute all the jobs, to execute all the plan we have for the next five years, but spending less than $174 billion. And this applies for this year, too. Probably, this year has less flexibility than the whole plan. But we expect to spend less than that by doing the same.

Okay. And if I may have a follow up, we've heard a lot of people mention on the whole idea about maintaining investment grade. I just wanted to have a feel from your end as CFO if it came to a serious strategic decision between doing something that would keep the investment grade rating and, say, slowing down the pace of investments in Brazil, which one of the two do you think the Company would pick?

This is a very good, very tough choice. I believer we are going to keep both. We are going to invest. And we are going to keep the investment grade. There are always some opportunities to do that.

Okay. Thank you.

(Operator Instructions) Our next question is a follow-up from Paul Cheng and Barclays Capital. Please go ahead.

Hi. Thank you. Two quick follow up, one on the page 11 of your presentation -- you leave out inventory losses in three item, the losses with devaluation of inventory. I presume this is mark to market on your existing inventory level. The inventory turnover in fact I presume is because of the [FH call], so in the ongoing that that has been lost. And the inventory loss trading operation, BRL964 million, can you explain to me why that we have this loss and what causing it?

Second question is related to some of the very promising drilling result in West Africa, Ghana. When looking at that, is there any lateral indication to the offshore northeast part of the country and wondering that have you guys looked at that and if there's any comment you can share. Thank you.

Regarding the inventory losses in trading operation, these losses, the reason is almost the same as the first line, where we have storage -- the inventory losses here in the trading are operations that we do offshore Brazil, outside Brazil. We buy from one source and sell to other destinations oil and oil products. What happened here that is not -- we had, for example, for the first quarter BRL964 million of losses. This is affecting our operational results. But most of these were got back through the hedging system. In the financial, we have BRL603 million of gains on the hedging of this oil.

Usually, when we buy this oil to be processed, for example, in the Pasadena refinery, we have sold already the oil products in the future. So we have a loss here. If we had a loss in the physical, we have a gain in the financial in the hedge. So this is affecting the operational income. But it's returning to the financial down below.

And the second question regarding Ghana, as I said, we have no representative of the international area. I can answer you through our --

No, I understand you don't have operations in Ghana. I'm talking about that since the belief in the geology is that 1 million years ago, Latin America and West Africa was in the same continent and drift apart. So what we see in Ghana (inaudible) and the lateral indication to the northeast part of the offshore (inaudible) that you guys are seeing. And is there any indication or anything that you can share from that aspect? I'm not talking about Ghana per se. I'm talking about what is the implication to you.

This is more a question for a geologist. I don't know if Molinari would like to add something to that. In fact, we don't know -- I believe no geologist knows where the presalt broke when they were -- the drifting apart of the two continents, how much remained in Brazil and how much were taken eastward to Africa, West Africa. This is -- today, I believe we don't have this answer. I don't know one geologist that would have. Of course, there is a lot of speculation at this moment. But it always is a guess.

Our next question comes from [Sal Effraine Chavez] from Arthur Capital. Please go ahead.

Yes. Thank you for taking the question. And I apologize if I'm asking for repetition. But I'm curious about the inventory adjustments that you took, given the higher -- I mean, the declining prices. So you had higher costs I guess feed into your refineries. I'm curious if that is what we should expect into the first quarter of 2009, if, let's say, we're now sitting around a level that maybe is hopefully stable. Should we see those as a sharp increase in the profitability of your downstream businesses?

As we have shown in the presentation, there are extraordinary items. And this is one of them. We expect that it will not repeat on the first quarter, at least at the extension we had seen in the fourth quarter. It all depends on price.

Right.

If price remains where it is now, we don't expect to have any of these happening again or in the period as long as price remains stable.

So I take it that you're looking into your inventory. And the average cost of your inventory right now is somewhat at a current level.

Yes, that's true.

Okay. Thank you.

Our next question is a follow up from Marcus Sequeira from Deutsche Bank. Please go ahead.

Thank you. Just one question -- regarding dividends, have you guys ever considered paying dividends in shares? I say that because the amount that you have to pay in dividends is close to the amount of new debt that you guys got during the quarter. So is there a way to relieve you debt [deeds]? Would you guys consider to pay in shares?

We considered. But there is always an option from the shareholder to receive it in shares or not. So we decided this time to pay cash.

Thank you.

(Operator Instructions) Our next question comes from Emerson Leite as a follow up from Credit Suisse. Please --.

My question is in relation to lifting costs going forward. We have seen lifting costs in the range of $8 to $10 in recent quarters. In this quarter, we had an improvement coming from the currency depreciation. And we have these new wells which have high productivity levels. I was wondering, when we think about the overall production in Brazil, you think just offshore, the average productivity per well is 20,000 barrels per day.

So what sort of improvement for the average lifting cost of the Company do we get from these new wells with such a high productivity? Should we expect a meaningful improvement in the lifting cost going forward? Or this range from $8 to $10, is it still reasonable given the start up of new systems and they have fixed costs that they bring together?

Emerson, we are working really very hard to reduce our operational costs and reducing these lifting costs as well as the cost of development of the oil field that at the end will impact the total cost of production. But it's very tough to say how much. And it's going to impact. We don't have this figure to release to you right now.

Okay. And I don't know if I could ask a second question. In case I can, I would ask what is the latest in terms of drilling results in [Zecichioinia] and in the [Baleias] drillings that were going on. Thank you.

Molinari, if you have any information, please.

At Zecichioinia, we drill at that well in BMJ3. And the results allowed us to continue there to ask an evaluation plan for the area. So we will continue to drill in that area. And [Baleia Dinia] is being drilled at there. We are a partner there in Baleia Dinia 3. (inaudible) is the operator.

Okay. Thank you.

Thank you, ladies and gentlemen. There are no further questions at this time. Mr. Barbassa, you may proceed with your closing remarks.

Thank you, all, for being here. I hope that next quarter we can have as good results as we had this time. See you then. Thank you. Bye, bye.

Ladies and gentlemen, your host is making today's conference available for replay starting one hour from now. You may access this replay at the IR website or by dialing 1-412-317-0088, code 427929, pound key, and then enter one to start the playback. This will be lasting through March 17th. This concludes Petrobras's conference call for today. Thank you very much for your participation. You may now disconnect.