巴西石油 (PBR.A) 2015 Q4 法說會逐字稿

Good morning, ladies and gentlemen. Welcome to Petrobras Conference Call with analysts and investors for the presentation concerning 2015 results and the fourth quarter of 2015. We would like to inform you that participants will only be listening to the conference call during the Company's presentation, which will be conducted in Portuguese with simultaneous translation into English. Following the presentation, a Q&A session will begin in Portuguese and English, and instructions will be provided at that time. (Operator Instructions)

Present with us today are Mr. Ivan de Souza Monteiro, Petrobras Chief Financial and Investor Relations Officer; Ms. Solange Da Silva Guedes, Chief Exploration and Production Officer; Mr. Jorge Celestino Ramos, Chief Downstream Officer; Mr. Hugo Repsold Jr., Chief Gas and Power Officer; Mr. Roberto Moro, Chief Engineering, Technology and Procurement Officer and other Company executives.

I would like to remind you that this meeting is being recorded and please be mindful of slide number 2, which contains a notice to shareholders and investors. The words believe, expect and similar ones related to projections and targets are mere forecasts based on the expectations of executives regarding the future of Petrobras.

To begin, we will hear the Executive Manager of Investor Relations, Mr. Lucas Tavares de Mello. We will then proceed with the presentation concerning the results for the fourth quarter of 2015 and the year 2015. Right after the presentation, we will proceed with the Q&A session.

Good morning, everyone. I would like you to be mindful of slide number 2, which has a notice to shareholders.

Now, moving to the slide number 3, we will talk about the exchange rate. And we noticed that at the end of 2015 the exchange rate was BRL3.90. There was a depreciation of 47% of the real in relation to the year of 2014. Now, when we look at the fourth quarter of 2015, when compared to the third quarter of that same year, we've seen an appreciation of 2%.

On slide number 4, now we talk about the price of Brent. We noticed a drop on average Brent, which was almost $100 in 2014, to $52.46 in 2015. I would like to remind you again that once we compare the fourth quarter of 2015 vis-a-vis the third quarter, we also saw a 13% drop in the Brent price.

Slide number 5, here we have some highlights on our results. The free cash flow amounting to BRL15.6 billion, something that hasn't been posted since 2007. Adjusted EBITDA was BRL73.9 billion, 25% higher when compared to 2014. Total production of 2,787 millions of barrels of oil equivalent a day, which is up by 4% over 2014 with a daily production record in the pre-salt of [1,173,000] of BoE at the end of 2015.

Lower expenses related to oil and oil products and production taxes; impairment of assets was BRL47.7 billion and investments of BRL2.1 billion, still on the negative side. Higher net financial expenses due to foreign exchange depreciation and higher interest expenses.

Now referring to the fourth quarter of 2015, we had the impairment of assets of BRL46.4 billion and investments of BRL1.9 billion. On the positive side, the free cash flow was BRL7.3 billion and a reduction of 57% in our net financial expenses.

Now moving on to slide 6, still speaking about our results highlights, our EBITDA was up by 25% in 2015, when compared to 2014. The EBITDA margin went from 18% in 2014 to 23% in 2015. Investments were down by 12%, reaching BRL76.3 billion in 2015 vis-a-vis BRL87.1 billion in 2014. Free cash flow was BRL15.6 billion in 2015, when compared to a negative BRL19.6 billion in 2014.

Slide number 7, still speaking about our highlights, our net debt in dollar terms was down 5% when compared to 2014. The average debt maturity was up, reaching 7.1 years when compared to 6.1 years in 2014. Net borrowings denominated in dollars went from $25.2 billion to $12 billion in 2015. So, down by 52%. And the cost of debt went from 5.6% a year to 6.3% a year, comparing 2014 to 2015.

Now slide number 8, consolidated net results, a negative result of BRL34.8 billion. The net operating income was down when compared to 2014, mostly explained by lower demand for oil products in the domestic market, even though we had higher oil export volumes. So, cost of sales was also down due to lower expenses, with imports and the production taxes and a lower share of imported volumes in the sales mix. Therefore, gross profit was up by 26%, reaching [BRL98.6 billion] vis-a-vis BRL80.4 billion in 2014. Operating income was up by 9%, mostly due to impairment of BRL47.7 billion. Tax expenses were BRL9.2 billion. Legal contingencies and losses BRL5.6 billion. And BRL1.9 billion was the impairment of trade receivables from the electricity sector. Therefore, our operating income was BRL2.9 billion, higher than 2014, but negative by [BRL12.4 billion].

And in terms of our financial result line, there is a major difference when comparing 2014 to 2015, minus BRL3.9 billion in 2014, mostly due to foreign exchange losses, due to the depreciation of the real and increase in our interest expenses and higher debt and interest on tax expenses, lower interest capitalization. Thus, our overall result was negative BRL34.8 billion vis-a-vis a negative BRL21.4 billion in 2014. This dollar denominated result in 2014 represents $8.5 billion when compared to $7.5 billion negative in 2014. The adjusted EBITDA, we already talked about, it is BRL73.9 billion, meaning 25% higher than 2014, and investments was down by 12% when compared to 2014.

Now moving on to slide number 9, here we analyze the impairment provision from 2015 and 2014. On the left side of the slide, we have the 2015 impairment figures reaching BRL49.7 billion. We also notice that it was mostly concentrated in the E&P activities, unlike what happened in 2014, which appears on the right side of the chart. The impairment in 2014 was BRL45.4 billion, but it was mostly concentrated in the downstream operations. Now when we look at investments in 2015, the impairment was BRL2.1 billion and BRL0.8 billion in 2014.

Going on to slide number 10, still speaking about impairment, it was BRL47.7 billion as mentioned. The main reasons for this impairment were in the production E&P fields we had the reductions in oil prices and the geological review of Papa-Terra reservoir. At Comperj, we had the postponement of the startup of the project and also E&P equipment, we have expectation of future idleness of drilling rigs. And the discount rate, discount rate affects all of our projects due to a higher risk premium, reflecting Brazil's loss of investment grade.

Slide number 11, here we have a breakdown of the main E&P projects which have been affected by the impairment. Papa-Terra BRL8.7 billion, so it is the most relevant one. And as seen before, this was due to a geological review of the Papa-Terra reservoir. All of the other projects are mainly linked to the lower oil prices, in conjunction with the higher discount rate utilized in the parity tests.

Slide number 12, we will now look at EBITDA -- adjusted EBITDA without special items. In 2014, EBITDA was BRL59.1 billion; in 2015 was BRL73.9 billion. And without all of these special items it would have been BRL85.5 billion in 2015 when compared to BRL63.3 billion in 2014, which means an increase of 35%.

Now looking at the EBITDA margin without the special items, again it would have been 19% in 2014 and 27% in 2015, when compared to 23% when we consider special items.

Slide number 13, here we have a simulation of 2015 consolidated net income without the special items. Here, when we look at the chart, we see that the result reached was [BRL34.8 billion] negative in 2015, but if we go with the impairment of BRL49.7 billion and then REFIS, legal contingencies, receivables from the electricity sector and others is BRL14.3 billion. Also if we discount income tax of minus BRL15.5 billion, our net income estimated would have been [BRL13.6 billion], which is without the special items. This is the simulated number.

Now going to slide 14, we talk about the consolidated net results for the fourth quarter; that was BRL36.9 billion negative. Operating revenue in the fourth quarter was higher when compared to the third quarter, because of higher prices of oil and oil products, and gasoline adjustments in September of 2015 and lower oil product sales in the domestic market. Cost was stable. There were lower expenses with imports and production taxes and lower share of imported volumes in the sales mix. Thus, gross profit was up by 13%, reaching BRL26.8 billion.

Operating expenses, that was mostly impacted by the impairment of assets that took place in the fourth quarter of 2015, and the financial result is better. It's better than in the third quarter of 2015, because in the fourth quarter of 2015, there was an appreciation of the real. When we look at the result, was BRL36.9 billion, that is the net income and loss with a negative figure of BRL3.8 billion in the third quarter. The net income was BRL9.4 billion negative in the fourth quarter and BRL1.1 billion negative in the third quarter. The adjusted EBITDA in the fourth quarter was BRL17.1 billion when compared to BRL15.5 billion in the third quarter. Investments were BRL20.8 billion vis-a-vis BRL19.3 billion in the third quarter and that was due to seasonal increases.

Slide number 15, now we will talk about exploration and production. We see that we are still growing our production, production grew 5% between 2013 and 2014, and 4% between 2014 and 2015. And in 2015 we reached a goal in terms of oil production in Brazil.

Moving to slide 16, now we refer to pre-salt. In December, we had a production record in this region of 874,000 barrels per day, and also a daily production record, which was reached in December 14, 2015 of [1,173,000] boed and 942 kbpd.

On slide number 17, the objective was to connect 72 offshore production wells and we reached the target when we connected 73 wells during 2015, whereas the target was 72.

Slide number 18, now we refer to downstream. The oil products output in Brazil was down in 2015 when compared to numbers from 2014. Even though the yield of diesel, as we see in the chart -- I mean the production of diesel since 2013 has been capped stable, around 850 barrels a day. Therefore, this number is still high.

Slide 19, now we will talk about the sales of oil products. Production was down by 9% in 2015 vis-a-vis 2014, mostly due to lower demand of some oil products, particularly naphtha from Braskem, and also gasoline. There was an increase of ethanol content in Gasoline C from 27% to 25%, a lower market share. Diesel, we had a lower consumption. There was a lower consumption in infrastructure projects, lower market share and a higher content of biodiesel in the diesel/biodiesel mix.

Slide number 20, here we see the operating income evolution comparing 2014 to 2015. In 2014, we had a negative operating result of BRL21.3 billion. The Downstream unit posted an improvement because of better trading margins of oil products. Exploration and production had the opposite performance, lower margins because the Brent prices were lower and also this year we had impairment in the E&P sector.

In terms of gas and power, there was an improvement in the results because of better trading margins of natural gas, and in terms of distribution we see a worsening in the results due to lower market share and lower sales volume. These are the main line that accounted for the worsening of our results. So, at the end of 2015 our operating income was minus BRL12.4 billion.

Slide number 21, here we have a general and administrative expenses, there was a 2% decrease in SG&A comparing 2015 to 2014. In the lower part of the slide, we have the holding personnel there was a 3% increase. Therefore, despite the salary restructuring, that was a decrease in headcount, and in the upper part of the chart we see a decrease in other lines of 5% and this stands from expenses in consulting services, data processing and other services.

And in terms of gross profit and the percentage of the as SG&A vis-a-vis gross profit, gross profit was 8%. I mean SG&A was 8% of gross profit, and this is a downtrend when compared to the years before to the previous years.

Slide number 22, we have the indebtedness of the Company. The indebtedness denominated in reals was affected by the foreign exchange appreciation, when we look at the figures denominated in US dollars there was a decline between the fourth quarter of 2015 and the fourth quarter of 2014 and going to $100 billion rather than $101 billion.

Net debt over EBITDA on the fourth quarter 2014 was 34.8%, and there was five times net debt over EBITDA ratio, and it reached 60%. On the right side of the chart, we had the net profile 50% of the debt is fixed and the remaining is floating. The cost of debt in 2015 was [6.3%] a year. The average tenure was 7.14 years. And net borrowings between 2014 and 2015, in 2014 was one $25.2 billion and in 2015 net borrowings were $12 billion.

On slide 23, we have our cash flow for 2016. Early this year, we start with our initial cash position of $26 billion. We had $22 billion of operating cash flow. Judicial guarantees were [negative $5 billion]. Dividends, interest and amortization was [negative $19 billion]. I mean the dividend line is zero. Investments [negative $19 billion], divestments $14 billion, rollovers and borrowings $1 billion and $1 billion. So by the end of 2016, we will have $21 billion in our final cash position.

With that, I conclude the presentation and we move to our Q&A session.

(Operator Instructions) Luiz Carvalho, HSBC.

A couple of questions. Let me start on slide number 23, the last one that Lucas commented about. I can see some numbers that draw my attention, particularly investments around $11 billion and actually the final balance $21 billion. I would like to better understand the zero dividends. Could we use this as a guidance for next year or you are absolutely not considering in this cash flow, just because you don't want to give any guidance? Just to have a better understanding of how you see the dividend policy for this year and the Company's understanding. If there is any loss, we will keep on not paying. What is the impact in terms of control, corporate tax versus oil?

And the second question, maybe Solange could help me out. Yesterday during the press conference, Solange mentioned that the breakeven point for pre-salt is around $30 or $35 per barrel. And I think she also mentioned the first wave, so to speak, of cost reduction was a decrease of approximately 13%. The second wave, the second wave might bring additional cost reduction. So we are speaking of a reduction of 25% of the breakeven for pre-salt vis-a-vis the last guidance. So could you give us a breakdown of all the items and the current breakeven points?

And just a last follow-up question. What about Petros stake, is there any kind of discussion ongoing in the sense of the Company having to use a phase funding structure and how can employees contribute to make it happen, maybe with an increase of contribution? Thank you.

Thank you, Luiz, Ivan speaking. First, asking about dividends, the Company had a negative result in losses. So we don't have any expected dividend payout this year.

Solange is going to answer your question about the breakeven point.

Answering your question about the Brent and the breakeven points, what I wanted to tell the press yesterday is that, that's something we are working on. I made reference to the first wave, because our most recent planning already include those benefits that were checked for the negotiations in the agreement. However, there are other benefits, which were also included and I did not mention them yesterday. And possibly in the breakfast we had at a different occasion, I had made reference to it. I am referring to yield, productivity, in terms of construction of ports, which were not included at that time, with a significant reduction in the time to build wells.

Particularly in pre-salt project, I think I told you before, this is the most significant share for the well building costs. This is the most significant share. So, any benefits in this regard is extremely welcome.

A second point that I also mentioned yesterday, and by the way, I discussed with you in the past in a more thorough manner. It is the fact that in those most recent analysis and planning, there is a continuity, a continuation of well production going down. That's a better behavior than we expected. And by having this included in our planning, we managed to postpone many of the well completions, from the moment they won't be necessary as we planned before, but maybe only later on. And by the way, you analysts came to us asking us why in our planning we had a reduction, a significant reduction in expenses, without an equivalent in the production goals, even though they were reduced but not in the same dimension. So it is the same as we mentioned before.

In terms of the inclusion of some benefits, they were already considered from the operational and also contract standpoints. But all I want to do is to draw your attention to the fact that this is an ongoing process for the portfolio optimization. And this amount will reflect many conditions to future analyze our projects and everything that we've been working very strongly, be it through events like the one that I mentioned or also through internal individual optimization on a project base.

Luiz, answering your question about Petros, when you have the third consecutive year showing a deficit, you should work an adjustment program and this program requires contribution from the stakeholders and the sponsor. This is already reflected in Petrobras statements.

Ivan, maybe if you could go back to the dividend question. I know you mentioned the Company had a negative result in 2015 and consequently did not pay it. What about going forward? For any reason, the Company has another negative result in 2016, will this remain the understanding that there won't be dividend payouts or is there any kind of divergence in terms of the corporate tax, showing that these companies [or] ordinary shares [and/or] common stock and preferred stock.

If the Company has dividends, they will be paid out. If there are no dividends, they won't be paid out.

Regis Cardoso, Credit Suisse.

I have two questions. The first question is about what to expect in the business plan CapEx. Solange already answered the previous question about CapEx optimization, but what about impairment that we can see this year for E&P this quarter? Should we expect a postponement of E&P projects in the future? And my second question is, I would like to know more about RNEST impairment. In Comperj, we can see a significant reduction, but what about RNEST? We already had a reduction, a write-off, maybe already affected by the discount rates and possibly a benefit due to foreign exchange, in order to reverse the picture. So what about the influence of these factors and why is it that we don't have any impairment or another reversal of impairment at RNEST?

The first part of your question will be answered by Solange, and then by Jorge Celestino.

Solange speaking; good morning Regis. If I understood your question, you mentioned -- you wanted to know if you're going to have any project postponement in our next project. We talked to you recently about adjustments made to our business plan, and right now, or in June 2015, when we worked on the first big adjustment of the plan considering the new market scenario, we mentioned a couple of risks of potential postponements, and today we understand that we are increasingly having these risks under control compared to the past.

Now I turn it over to Officer Moro. He has some analysis about such risks and very important facts to be shared with you all.

Like Solange said, last year we said there were some risks involving project delivery. So now I'll try to give you a snapshot of our status last year. Last year we had 16 big projects for pre-salt, 16 FPSOs and platforms connected to projects, and six chartered and 10 own units. The 10 that were chartered or leased we intended to deliver two last year and we did, and one of them we anticipated terms of approximately five months in advance.

And our problem in the previous year had to do with contracts for our 10 own units, six for pre-salt blocks for the concession block and four for the transfer of rights. These 10 own platforms that we had to deliver are realized through 11 major contracts. So last year, of the 11 contracts, we had seven contracts with structural problems and they were nearly terminated. And one of them was effectively terminated early last year. So, four contracts we had no problem and seven with problems, and the one that was terminated affected six units, six of our own units.

So we had to make a decision last year whether to continue with these contracts or to start from scratch. And based on the impacts of non-continuity, we decided to continue and try to renegotiate and come to another balance of these contracts and that's what we did.

We bet on that at that time, but that accounted for quite a big risk, because we were not assertive of the results of negotiations. And now the status in 2016, early 2016, all contracts have been renegotiated. Of the seven, one was terminated, was contracted again, with a strategy to recover construction in nine months. It was taken abroad. And for these contracts we will be delivering the compression modes of two platforms that will be delivered and shipping in March, one in Thailand, the other in China, allowing us to complete and giving you a real view of completion of P66, for instance, which is there idle in the shipyard, just waiting for the modules to come.

So, now we have a real possibility, a lot of assertiveness by year-end. So, we can fully meet our business plan. As for the additional six contracts, they were all aligned again related to changes to the execution plan or rebalanced to the local contract or, because we are in charge of our accounts with a lot of assertiveness, all of them up and running, renegotiated and now creating a better outlook. There are inherent risks, naturally, inherent to the process, to the building process, but with far more comfortable condition in terms of delivery terms and deadlines. So that was just adding to the previous comment. So, now we are increasing the reliability behind our deliveries.

And in terms of postponements to the contracts, Jorge Celestino is going to talk about RNEST now.

As to impairment tests for Comperj and RNEST. Comperj, just as a reminder, it was not -- well, the hibernation activities were not considered in the business plan up to 2019 -- 2015-2019. It was not on the horizon. And what we are pursuing and keep on pursuing right now is the completion through a partner stake. When we rolled Comperj impairment for year 2015, there were three factors that led to impairment. Number one, postponement of Comperj to 2022 in the horizon of the business plan, the discount rates and additionally the diesel market, which is lower now, and also diesel margins. If you look at the horizon, these margins are also lower. At the end of the day, we generate cash flow that has an impact on PP&E. So this happens in Comperj, but not in RNEST. In RNEST, the second train is expected for 2015-2019, but we will continue with the work in progress. And impairment tests run with the same diesel market, same discount rate, they did not lead to an impairment of RNEST train number 2.

Can I just ask a follow-up question please? So there is an impairment factor, which is foreign exchange rate. I think it does help somehow to offset the higher discount rate effect. So if possible, could you make more comments on it? And then coming back to what you said about diesel margins, I would like to understand if there are any different margin projections in Comperj and RNEST?

In terms of diesel margins, there are no different margins in RNEST or Comperj. Diesel margins are the Company's margins, and the strategy area runs under different scenarios. So we don't have different margins. As to CapEx, naturally the CapEx that you have for Comperj terminal was slightly higher compared to CapEx for RNEST terminal, and effectively does have an impact.

Gustavo Allevato, Santander.

I have two questions. First question is about the electrical system provisions. We can see they are recurring in Petrobras' earnings. What about the status and negotiation to try to lower problems? And I want to know if the agreements made with creditors are in line or as expected?

My second question is to Solange. What happened to Papa-Terra, what about the target of production for 2016, does it already take into account a lower production in Papa-Terra? And what about the target for 2020 in the revision in Papa-Terra? Thank you.

With regards to the electrical system, this is routine work. Whenever the Company finds lack of guarantee, actual guarantee, it has to work on provisions. You may be making reference to this first big -- that we worked on and this is fully in line, but the whole Company exposure that does not have an actual guarantee. The exposure is taken to provision as we did late in the year. This is routine and it always happens, not only for the electric system, but for any other exposure of the Company.

Now Solange is going to tell you more about Papa-Terra.

All our identifications and findings over 2015 vis-a-vis changes to the project compared to our original plans were fully included in our projections. So, we don't expect to see any change vis-a-vis our projections, due to the facts that you mentioned. We are strongly engaged, there is real expectation. By the way, expectation that we can have a more bullish scenario to what we originally planned. We did another planning for our projections for these assets in a very realistic scenario and we work in with targets, or oriented to this bullish scenario.

Just another follow-up question to the first question. Ivan, is there any study at Petrobras in terms of diesel supply to thermal power plants with advance payment, in order to not to have additional provision risk, and just an update about the last slide, what about the BRL5 billion of judicial guarantee. Thank you.

The company adopts several procedures, both commercial procedures and collection procedures. This is part of our normal operation in the several business areas of the Company. In case of non-payment of the Company through the contracts that we have with those companies, puts in place all of the routine collection procedure to enforce the contract.

Now in terms of judicial guarantees, there are still some pending legal disputes and every time you migrate from an administrative process to a debate in the judiciary, you have to make guarantee deposits, while you continue to litigate. And so, the amount that Petrobras will be obliged or not, to deposit in an escrow account to -- I mean if that is the case, to continue discussing all of these issues at a legal level.

[Philippe Santos], JP Morgan.

I have three questions. The first is about the diesel policy. In general, diesel production was already above domestic consumption and your competitors began to import diesel and placing this imported fuel in the domestic market, taking advantage of international prices. In case the scenario remains the same, do you want to export your surplus or sell it domestically? This is my first question. The second question relates to borrowings from the Chinese bank. In the last slide you showed that [$10 billion] amount does not appear and that was the amount of borrowings with the Chinese bank that doesn't appear in your cash flow. And my last question refers to CARF proceedings. I think there is one amounting to [BRL7 billion] or something else and whether these provisions are not being considered by you?

I like to give the floor to Celestino to answer the diesel question.

In fact, our planning model, it's a linear planning model and we run this template, offering imports and exports of oil and oil products. And this model runs, so as to generate the best economic outcome for the Company. We have offered some diesel exports. We had the first one for diesel [10] and that took place in February, was our first export activity. And this is how we intend to work. We constantly seek for the best economic result for the Company. Importing companies are deemed necessary to supply the market and we will also operate refineries to reach its utmost, the best economic level.

In terms of borrowings, which you just mentioned, we just had the agreement with the Chinese Bank. Just after the outlay that we will post something, there is this $1 billion that was just the first part of the (inaudible) that we did with [Sileze] and there has been an outlay. This is a very conservative position. We don't want to be surprised. So, once the cooperation agreement is signed and then we go to the contracts and as the outlay hasn't already been posted, it hasn't been reflected in our figures.

CARF valuated the entire litigation proceedings at all different legal levels and the amount that we posted is what we think is necessary to face all of the cases, both at the judicial level and in other levels. This amount of [BRL7.5 billion] involves a contribution to Petro in 2010 and the litigation came to a very close tie. And then in the judicial level, they were right in terms of deducting all of the taxes that were paid by Petros.

Could you give me more details? I know that you cannot talk about the terms that you have with the Chinese Bank, but can you give me just a few details concerning the basic assumptions? The contract is exactly the same as the contract we signed last year amounting to $5 million, the same format?

In the contract, there is a 10-year term and this is aligned with what Petrobras is now, but we do not give out any more details, but it follows the same terms. In 2009, we had our first agreement and the second one was signed last year, and the third agreement will take place this year.

Bruno Montanari, Morgan Stanley.

First, I would like to revisit Papa-Terra. I know that you said that you are working according to plan, but can you give me an idea of what could be expected in terms of production level, capacity utilization of the platforms? And the second thing refers to China Development Bank. I think five -- you have [BRL5 billion to BRL10 billion]. Is this with a trigger or once you decide to withdraw you have to withdraw the entire amount of [BRL10 billion] at once? And the third question is about the US class action, what will be the next steps and whether you have any timing idea for the parties to begin getting into an agreement or settling this issue? Thank you.

I will start by answering your two last questions and then Solange will refer to Papa-Terra. We were not obliged to withdraw the [BRL10 million] all at once, and this is not what we want, but this is not like a revolver or a trigger. There is a contractual payment term that we have to follow. In terms of the class-action, there is nothing -- nothing has been decided about that yet. We're still in the discovery phase, people are giving their depositions and we are still discussing this and getting ready for the trial and I think the judge has set a date, which is in early September of this year.

Now, I'll give the floor to Solange who will answer your question about Papa-Terra.

The consortium is leaning over a total redefinition of the project and this includes the way we operate that special unit that drills wells and the performance of this drilling is poor. And we are also focusing on the entire draining grid and I am referring to the wells, so the location has to be redefined and the trajectory has to be revisited. All of this review work on the operating side and project definition will take place at the end of 2016. Therefore, it's too early for me to tell you now about any rampup decision. In the absence of this new project, we have our -- now over view how -- what is the status of the project, what is the performance of the wells, the performance of the rigs. Therefore, using all the existing knowledge in our existing models, we ran optimistic simulations; in our worst case scenario, current scenarios and we aren't getting ready to adopt a more realistic position, but the entire project will be redesigned, and I'll be able to give you a better answer -- to answer your question, by late October when the entire project will be redesigned by the consortium members.

Diego Mendes, Itau BBA.

I also have two questions. One about impairment. When we look at the figures, you used a Brent of $72, long one. And what was the basis for that? And whether we could see any reduction in this amount and this would probably lead you to further impairment? And also your cost of capital increased about 100 basis points versus 2014, whereas at the end the landscape was much worse and this -- both the equity used and the cost of debt changed. How did you calculate those figures and what should be expected in the long run? And the second question relates to your hedge account policy. If we compare the end of 2015 to the end of 2014, you significantly increased your exports coming, from $50 billion to $61 billion in a time when the price of oil is down, in the US, they even extended the tenure. How should we consider all of these positions in the future and whether you still have room to increase that $61 million further?

Diego, thank you. First about Brent prices and cost of capital. This is extensively debated by all business areas of the Company and this is the best view that we had and this is what we use to -- carried out the parity test. This is the Company's view, this is a significantly lower number in the case of Brent and a higher figure when it comes to cost of capital. This is our logic.

In terms of the hedge account, we increased the denomination, but this is compatible. If you compare two variables, the drop in the domestic demand for oil products and higher production of the Company, which lead us to more availability to exports. The Company is trying and will continue to be more predictable in terms of our results. All of the rules are well described in the guidelines of the Company and it does reflect our best judgment, because it also considers our own debate and also consultations from the outside market.

So in terms of Brent, so $72 should also be included in your business plan?

Yes, this is correct.

Frank McGann, Bank of America.

Two questions if I might, one in terms of the write-off, the impairment. I was wondering what percentage of the write-off was attributable to the change in discount rate and what amount is related to that and what amount is related to other factors? And then just perhaps an update on the current status of your [pre-salt] assets.

We do not have this amount in terms of Brent and discount rate, but the IR area will send that to you. We don't have it right now, but we do have it available, and we will send it to you. And regarding pre-salt, I'll give the floor to Solange to answer that part of the question.

Our pre-salt projects are very much aligned to the outlook described by Moro. We just started up a unit in the first quarter of 2016. There are two other units leased. They are up to speed and in the case of one of them, we may see an anticipation, so we may start up a unit earlier than what has been anticipated, and this has been the case with some two other units when there was an anticipation, even the four months prior to plan. And in the following years, after 2017 onwards, we will then follow the rule described before, where some of the delay risks have already been solved.

Now in terms of construction of wells and the connection of wells, our plan is up to date. For years, we've been working in our well-connection plan and we've been sharing the status of that with you and we are in compliance with our plan also in terms of the pre-salt in 2015. We added four additional wells, in addition to what has been planned.

And the productivity of the wells and the exploration of Libra, as I said yesterday to the press, it is also up to date. Yesterday, I also talked about the results. The Libra exploratory area had a magnificent performance. And again yesterday I talked about over 300 meters in depth. This is very relevant, because very soon, in early 2017, we will install a pilot unit in Libra, it is a pilot unit, it will be our largest pilot ever in Brazil of 50,000 barrels. And once the connection is made, they could have that capacity, we will test it. And as time goes by, pre-salt predictability remains untouched. We did not encounter any other factors that will lead us to believe that we will have delays to that target that we mentioned before.

John Herrlin, Societe Generale.

Regarding the impairment discount rate, I may have missed it, did you specify what the discount rate was?

The discount rate is linked to risk and also linked to the activity itself for each business unit. So for each company, we have a different discount rate. We do not have a single discount rate for all the businesses, because we have to reflect a specific risk of each business unit. All discount rates are applied -- that are applied for 2015 and 2014. In 2015, there was an increase, even because now Brazil had a downgrading in its investment grade and you will find it is common, it's an increase in the discount rate, but there is no such thing as a single discount rate, because each discount rate reflects the different business unit risks.

(Operator Instructions) Anish Kapadia, TPH.

A few questions please. Firstly, we've a seen a recent rise in international oil prices. I just wanted to see what is the view in terms of increases in gasoline and diesel prices at the pump in 2016 in your cash flow forecast? The second question, as well as on Papa-Terra, you have also had -- it seems disappointing production from some of your other new units in the Campos Basin, on Roncador and Parque das Baleias. Can you update on your production expectations from these fields and when you would expect them to reach plateau? And what are you seeing in terms of the underlying decline rates in the Campos Basin, it impacts all I think? And just a final one. I was wondering if you can give an update on the progress on Buzios -- on the FPSOs for Buzios and the expected ramp-up you'd expect from them? Thank you.

I'll give the floor to Solange who will talk about Buzios and Campos.

We don't have problems in Roncador, structural problems, neither in Roncador or Parque das Baleias. Now let me draw your attention more specifically to Parque das Baleias. We had a unit with operational problems in the first months, but these problems were solved. And now, it is at full speed with very good results.

As to the decline rate, prior to that I would like to talk about Campos Basin. Yesterday, I talked to the press, where we were mentioning the importance of the Basin that we have two kinds of important -- two important works there in terms of more economical assets. We've been strongly invested to revamp platforms over 2015. We've invested BRL2.7 billion in the platforms and now we are designing projects, complex projects of full fields. And yesterday we also announced, and by the way, this is also related to the question about the decline.

Marlim was our first field of deep waters. Marlim, it started running in the 1980s and for the third consecutive year we have growing production in Marlim field. So our mature reservoir policy and also improved operating efficiency, in these very same units, Marlim, for instance, and also in those related to Roncador and also that was related to Parque das Baleias, these are programs or problems that were solved and now they're bringing quite positive results. So, this was one of the main contributions that allow us to meet our goal of production over 2015.

Just as we are working with a lot of diligence to implement the pre-salt projects, we are also extremely careful with Campos Basin, which accounts for 70% of our output. And our cash flow basically lies on the efficiency of Campos Basin. Of the top 10, eight are in Campos Basin. And we have good news to share about the extension of concessions. These big fields, huge deepwater fields whose reserve is not depleted in 2025, so we are already searching for projects and try to have investments for big concessions in the area.

Once, right now, we have already defined the model of the extension, the concession model. And for another 27 years, we will have a big revamp process, revitalization, so we don't have a drop in production and therefore decline is under control.

As to Buzios, I am sorry, I still have to talk about this question about Buzios. In Buzios, we also have a campaign for the limits of the field, it is the main area of the transfer of rights area. We have extended well tests being carried out in this area, tests with mid-sized vessels and they allow us to mitigate risks once we have big projects taking place.

We have already defined four big projects in the portfolio for this area. These projects are also being detailed by Officer Roberto Moro when he talked about our units.

And we talked a lot about Libra, but Buzios also has amazing results in terms of reservoir and productivity. We're very happy with the exploration results achieved in Buzios.

Now I give the floor to Jorge Celestino to answer the first part of your question about the forecast of diesel prices.

With regards to diesel prices expected and according to our planning, we have the Brent price curve that the management bets on. In addition, we also hedge the diesel, the spread or the diesel margins and also our competitive edge. So in our margin, we have a competitive positioning at the Petrobras system, which is also added to the picture and that's how we work on prices and price forecast.

If I may, I would just like to make or give more accurate information. When I talked about Comperj for 2022, actually it is January 2023, this is what we see in our plan. This is more accurate information.

Caio Carvalhal, Brasil Plural.

Most of my questions have already been answered. If I may, I would just like to have a better understanding of two things about impairment. First thing is, is there any strategy here, because we've seen before some variations, maybe not big variations of oil prices and maybe not so strong about Brazil cost, but we had never seen such a strong impairment. My idea is will that happen annually, if the performance of oil prices really speeds up and will change over $72 on the longer term, should we expect to see some gain? I want to know if there is going to be an annual strategy about these fields.

Another question is what about the assets of the transfer of rights in the light of the new assumptions for impairment? Does the Company also intend to apply this for transfer of rights, because the book value is still at BRL74.8 billion by the end of 2014, 2015. I assume we're speaking of something slightly different in the negotiation contract. But should we expect to see something downwards in the valuation of transfer of rights asset, which might be positive for the Company?

And last but not least, also about the revision. Wasn't there any value gain, was the value small or not considered yet? And lastly, along the same lines, the impairment test revisited the value downwards, maybe due to Papa-Terra or the discount rate and oil value and not related to production profile. And in the revision of the reserves, there was a big drop, [0.7 or 0.8 barrels]. Or the drop of reserve from 2014 to 2015, there was a revision or a drop of 3 billion barrels, if I'm not mistaken, [1.7 barrels, 1.8 barrels] due to technical and economic reasons as you have posted in the report. Is there really no impact on production? Are these reserves that have not been developed yet or that will be developed in the future? Or should we expect to see another impact due to this reserve? I think I have more than two questions, but they are around the same topic. Thank you.

Caio, thank you. Ivan, speaking. This is an annual review. It was the regular periodicity and it included all the assets, including the transfer of rights you mention. And you also mentioned in your third topic about extension. Extension was afterwards, it did not include the balance sheet in 2015. If I'm not mistaken, it was discussed 10 days ago. So, there was no impact on the balance sheet, on March 3 more specifically. And as to the impact on reserves, Solange is going to answer your question.

More effectively, and maybe I'll be redundant, because Dr. Ivan already mentioned this, the provisioning test or recovery of impairment test, this recovery test happens every year and this is an atypical year, due to the magnitude of the impact of prices. So basically that's what happened. The price impacts, the price in which all the Company's assets had been tested last year, they were tested again. So not only the forecast and the drop of price in the year, but also the long-term forecast. That's the basic thing. Tests were run, based on a long-term forecast, 30, 40 years for E&P, much longer, and this year, we reduced our projection. Our future projection is based on the analysis in the market. So the assets were put to the test with very different amounts, no exception. Transfer of rights, although it's a separate contract, it is subject to rules, subject to rules of appropriation of reserves and parity tests, like all the assets in this topic.

And you also mentioned at the end to the announcement we made, 20% reduction in our proven reserves that's what we published. Once again, under the same impact, something unique in our trajectory, and also unprecedented specific sudden drop, as we had with Brent oil prices. Now this revision does not have an impact or a significant impact, because that's a long-term revision, it's long-term, and Petrobras is also very strong in this regard, trying to increase the recovery factor. So, we are working hard to increase the recovery factor, even though sometimes we have a lower impact on those amounts.

And you also make reference to some technical facts. One of the technical facts that we mentioned at that time is specifically Papa-Terra. Papa-Terra is a mid-sized asset, it is post-salt from Campos Basin. And it also suffered a significant impact due to cost reasons and also associated to a different impact. So this was due to Brent price in the long term, but also additionally, results were affected by the performance of some wells and reservoirs for the completion well rig, and we also had a higher impact on Papa-Terra compared to other assets, but there is no impact on production.

By the way, I answered that before in the first question. When we had our breakfast meeting, we also discussed the business plan. So, that business plan already included our most realistic scenario for projections and deliveries of these assets. What we are annualizing right now are the accounting aspects related to the parity test. (technical difficulty)

Lilyanna Yang, UBS.

I have a question about your divestment plan. Do you believe that you will still sell $14 billion until the end of the year as your target anticipates and what kind of assets you will be putting for sale? Do you still have your onshore fields that should be put for sale? This is BRL1.2 billion was due to what? And from previous answers I noticed that in addition to that, there was nothing related to pre-salt. My third question relates to local content. What is the level of fines due to the non-compliance that were issued to you and how many waiver requests have been already accepted in your particular case, of course?

Well, you have lots of questions. So I'll give the floor to Solange. But speaking in more general terms about of divestment plan, yes, the target is $14.4 billion for this year. The Company is working in different areas. Some of them have already been disclosed, but I'd like to ask Solange to answer your question, and something related to selling our internal assets.

Well, again, I would just change the order of my answers, starting with the fact that -- I mean you asked me to speak about the type of assets that are part of our divestment portfolio, and again, I think I recall our last conversation when we said that there is no limit in terms of the maximum amount of returns for the Company and what assets will be part of that in terms of Upstream and Downstream.

Assets, that are put for sale involve 98 production concessions and six other assets that are very much integrated. 10 production sites scattered in different areas from Serra to the Cerro Espiritu Santo. We did some very detailed work, listing all the benefits to Petrobras, which involve divestments and also in terms of being more attractive to other players, small and mid-sized players that may be interested. And in terms risks and opportunities, these are things that are all part of a package that can be very attractive to takers.

Now in terms of Lapa, it's more related to seismic repositioning. It's a more technical thing and that's what led us to that result, but that was not necessarily linked to pricing.

Now answering your question on local content, I think you can notice an attempt on the part of the regulating agency about how we comply with local content requirements. The regulating agency has clearly demonstrated its intent to promote further development, not only from foreign companies, but also Brazilian companies with an eye on developing the industry. As they know the difficulties encountered by some vendors and suppliers in Brazil, this new measure has been very positive. We are keeping a very good dialog with the regulating body and therefore, we do believe that soon enough we will see some positive results.

Now you also had a question about the waiver and that local contents debate, but I will ask the IR people to get in touch with you later.

Now still talking about Lapa, the impairment was more related to their production platform?

Maybe I didn't make myself clear. The reservoir of the area was submitted to a seismic analysis. So it's not related to the platform, neither pricing.

Pedro Medeiros, Citigroup.

I also have a few questions. First, Ivan, could you please tell me a bit more about the performance of programs related to manageable costs? Can we just list all of the gains that you were able to achieve related to renewal contracts or overhead or new positions and how can this compare to your initial expectation?

The second question is a follow-up on the transfer of rights issue. I understand that the impairment test did not affect the asset base related to the transfer of rights, but could you please give me an update on the contract renegotiation? In fact, the renegotiation or the amount of the contract and what is your expectation concerning gains or losses?

And my third question is merely a follow-up question. I look at your financial results and you have a provision for abandonment of BRL14.1 billion in 2015. And this should have been recognized in the fourth quarter. Was this included in the results? This is something that is not very clear to me now.

The reduction of these manageable expenses, I mean, are you happy with what you have so far? The answer is, yes. There are a lot of initiatives in many different parts of the Company, you just mentioned a few. I didn't want to give you any precise information right now, but we can contact you further and give you all of the breakdown information you need. But it doesn't mean that the Company will not pursue further improvements. Solange already talked about the second wave, she talked about that yesterday. We will work hard in the second wave and our intent is to achieve further reductions. We do believe that the future price of Brent is now in a different level, a lower level in the long run and this certainly had a significant impact. And to that end, the Company will have to reinvent itself. It will have to adapt its costs to the new reality. This will therefore be a continuous process and we will identify any possible opportunity to promote further reductions.

In terms of the transfer of rights, I will again give the floor to Solange.

We also shared with you that there are two certifying companies that were hired. One on the part of the government and one of the part of Petrobras. They are both working diligently to come up with the first results in the second quarter of 2016. We've been meeting to discuss assumptions, but I don't have a schedule clearly defined, because everything will depend on when the certificates will be delivered. Therefore, right now, I cannot tell you anything about gains or receivables coming from the transfer of rights.

Thank you very much. We now conclude the Q&A session of this webcast and audio conference. I will now turn the floor to the Company's Director, Ivan de Souza Monteiro.

We would like to thank you very much. And if you need any additional information, please talk to our IR people. Thank you all very much. The audio of this conference call for replay and slides presentation will be available at the Petrobras IR website at www.petrobras.com.br/ir.

This concludes today's conference call. Thank you very much for participating, and please disconnect your lines. Have a good day. Thank you.

Statements in English on this transcript were spoken by an interpreter present on the live call. The interpreter was provided by the Company sponsoring this Event.