Theodore Helms – Executive Manager, IR Almir Guilherme Barbassa – CFO and IR Officer Jose Miranda Formigli – Exploration and Production Officer Jose Carlos Cosenza – Supply Officer Jose Alcides Santoro – Gas and Energy Officer Maria das Graças – CEO

Bruno Montanari – Morgan Stanley Marcus Sequeira – Deutsche Bank Kyle Cabral – JPMorgan Frank McGann – Bank of America/Merrill Lynch Paul Cheng – Barclays Gustavo Gattass – BTG Pactual Luiz Carvalho – HSBC Lilyanna Yang – UBS Christian Audi – Santander Pedro Medeiros – Citigroup Auro Rozenbaum – Bradesco Paula Kovarsky – Itau BBA

Good morning ladies and gentlemen, welcome to Petrobras conference call with analysts and investors for the presentation of Third Quarter 2013 Results. We would like to inform you that participants will be in a listen-only mode during the company’s presentation in Portuguese with simultaneous translation into English. After the presentation, a Q&A session will begin at which time further instructions will be provided. (Operator Instructions) This broadcast is being recorded. Present with us today, Mr. Almir Guilherme Barbassa, Financial and Investor Relations Officer; and Mr. Jose Miranda Formigli, Exploration and Production Director; Mr. Jose Carlos Cosenza, Downstream Director; Mr. Jose Alcides Santoro, Gas and Power Director, as well as other company executives. We will now listen to Mr. Theodore Helms, Executive Manager of Investor Relations. Please Mr. Helms, you may proceed.

Good morning, everyone. We are about to begin another Petrobras conference call with analysts and investors for the presentation of third quarter 2013 results. This conference call is being broadcast live via the internet in Portuguese at our website, www.petrobras.com.br/ri. In addition, a telephone broadcast is available by dialing 55 (112)101-1490 and 55 (113) 193-8000. To listen to the call in English, you can go to www.petrobras.com.br/ri/en, or you may call from the United States, 1 (866) 890-2584. And for calling from other countries, please dial 1 (646) 843-6054. Before we continue, I would like to remind you this meeting is being recorded. Please be mindful of Slide #2, which contains the notice to shareholders and investors, the words belief, expect and other similar words related to projections and targets are mere forecasts based on the expectations of executives regarding the future of Petrobras. Lastly, I would like to inform you that results have already been disclosed in Reals as well as in U.S. Dollars, in accordance with International Financial Reporting Standards, IFRS. Today’s conference will be limited to figures expressed in Reals. At this time, I call in CFO, Almir Barbassa, who will together with other Petrobras directors present our results and the main events that occurred in the third quarter of 2013. Afterwards, we will be answering questions from participants. Please, Mr. Barbassa

Good morning everyone. Thank you for joining us for another Petrobras results presentation. Now at this time, we will be presenting the results of the third quarter 2013. We have our directors present here with us who will provide presentations in each area. Now let us begin. I would like to invite director Formigli to speak about Downstream.

Now first slide. You can see our production in the third quarter 2013. As anticipated, the production is in line with that of the second quarter ‘13. Unfortunately in the third quarter, we did not have an increase in production, because we faced a delay in the implementation of a few projects. This will be detailed next. These problems have been overcome, and today, we expect growing trend in production already in the fourth quarter. And then in 2014, we will have a significant production growth as compared to 2013 with all the units starting production. The average in the third quarter was 1,924,000 barrels which is in line with the second half of 2013, where we’ve had 1,931,000 barrels. It shows a production growth, especially as we look at September production where we’ve had a significant growth compared to July and August. September production 1,975,000 barrels compared to a production of 1.9 million in the previous months of July and August. Why did we have this? Well, although we’ve had our scheduled stoppage in Campos Basin, they were less intense than expected and we had a larger number of wells interconnected to our platforms, either platforms installed in 2013 and also platforms that are already in production which were installed previously. These are the complementary projects as we call them to offset the production decline. Further on, I will talk about the good results we’ve been able to harvest in terms of a slower decline rate. Lifting cost went up 9.7% as compared to the lifting cost in the second quarter 2013. There are two main reasons for the lifting cost increase; foreign exchange variation which impacts our cost, especially offshore inputs where we have the leasing rates of our vessels. Also the CBA, the Collective Bargaining Agreement this September, and the startup of two FPSOs, Rio das Ostras which is working on Espadarte, the long-turn test and more time for Cidade de Paraty, which went on all this quarter, the first oil was in May last year. Now from E&P, the net income. The E&P net income is higher than that of the second quarter, R$11.6 billion compared to R$8.9 billion in the second quarter ‘13. Production at the same level, but this was a result of higher oil prices. In the next slide, we have excellent news, which is the positive evolution as we had the production starting in the Decoupled Buoyancy Systems. We will have P-63. We are concluding conditioning and interconnection of the first well. Production expected for October 31. We had a delay from October 23 to October 30. This was because of sea conditions in Campos Basin, where we had to delay our pooling in the installation of our flexible equipment and this project had a delay. This was an impact we had in the third quarter, but as we had planned for production to start in July, but this is because we identified coral reefs later on in the process. In the beginning of the process, we had determined that as mass movement. When we analyzed the data later on, this was confirmed as coral reefs. Now the confirmation was only in the beginning of 2013 and this is the reason why we had to change the sea layout that is the platform had to undergo changes. We had to use a new layout, so as not to interfere with the coral reefs. We’ve been able to do that and we already have the operating license from the Brazilian Environmental Agency. So we now we have the licenses. It depends on our own performance as well as on sea conditions. In cases of Cidade de São Paulo and Sapinhoá, these are two systems that have already been installed in the first half of the year, but unfortunately we faced problems as we installed the Decoupled Buoyancy Riser Systems. We are now installing the first monobuoy, but all four monobuoys, they were built in China then they arrived in Brazil. We’re currently installing the first monobuoy. And we have seen a great vulnerability of the installation vessel as regards to sea conditions. So as this vessel is highly vulnerable to sea conditions, this is the reason why we’ve had a delay. We will have more funds in – sorry, we will have another vessel. So that with more vessels we will be able to have a production ramp-up to try and minimize the delays we’ve had during the installation. The first monobuoy, as I said is being installed as we speak, and up until the end of November the installation shall be concluded. In December, we will continue to install the risers and the flexible jumpers, so that first oil is expected for late January. This is our estimate today in terms of the first oil and production in the system after the delays we’ve had to face in the installation of the monobuoys. It is important to remember why we had to use the monobuoy. We went together with our partners, we decided to install this system, the flexible lines were not qualified for this project, not with the content of CO2 we had. So, only decoupled systems using steel in the risers were correct for this system. This is the reason why together with our partners we decided to use the Decoupled Buoyancy Supported Riser System with monobuoys, because it is less vulnerable to sea conditions. Another problem we had this quarter regarding the production curve is connected to the availability of PLSVs. Because in 2010 and 2011, we were not able to contract these vessels, the new PLSVs because we had a delay in the discussion about how these vessels should be contracted, because we had the local content requirement. This produced a delay. Now we are improving the efficiency of PSLVs and we are contracting other PSLVs which will arrive during 2014, so that we will be able to minimize the impact in the future production curve. But today, we are working hard to solve this problem. Now in terms of our units, we would like to say that new oil is about to come. P-58, I’ve spoken about P-63, so going back to the fourth quarter, P-58 will be ready in the first week of November. It’s leaving the Rio Grande shipyard and it will navigate to its site. First oil is expected in the first fortnight of December, in the first half of December ‘13. We’re only waiting for this unit to arrive on site. P-55 has already arrived. It is being anchored right now and we have the process ready for first oil using a flexible line connected to the well. P-61, Papa-Terra is in Angra dos Reis and it will navigate to its site in the first week of November to install the wells. DB-50 to install is there already, that is, they will provide the connections to TLWP, the Tension Leg Wellhead Platform which is P-61. TAD will come to its site from China. It will be dry, so that it will be in Brazil in the beginning of December. And finally, P-62, a platform that was planned for next year, will be coming out of shipyard Atlântico Sul in the beginning of November, so that we will have the first oil in the first quarter next year. So this shows how much new oil we will have during 2014 and the connection of wells to platforms. Now the other item I’d like to highlight is in the lower parts of your slide. It is the performance of our reservoirs. The natural decline observed in the last 12 months was below the projected range of 10% to 11%. So more specifically it was only 9%, which shows the right management of this reservoir. Correct gas and water injection and production using wells that perhaps will have to be added, so that we will have additional development. It shows that our management is occurring as expected. Now news on the pre-salt front, show excellent performance. We did not have a breakthrough of water, so we’ve had an excellent performance. In the next slide, you can see the successful efforts to increase operating efficiency in Campos Basin. Last year, approximately at this time last year, the older assets of Campos Basin had an efficiency below 70%. Now if we look at the first bar chart to the left hand side, you will see, we’ve had a growth in production as compared to what we would have without PROEF. PROEF is the program for operating efficiency improvement, that is, we’ve had eight percentage points better operating efficiency from 66.9% to 74.9%. And this was the result of topside action with scheduled maintenance, keeping our maintenance units to optimize the time of scheduled maintenance, so everything is prepared beforehand, so that we’ve had gains of 33,000 barrels per day only in Campos Basin operating unit, which brings to us an NPV or net present value of US$662 million compared to expenses of US$1.3 billion up until August ‘13. Now as we look at RIO operating unit, operational efficiency gains are even more significant because of the potential of these fields managed by RIO operating units, and compared to Campos Basin. In this case, our target was to keep the operational efficiency, because the units in RIO are newer than those in Campos. Without PROEF, we would have an efficiency of 91.2%, but we’ve had an increase of 1.2 percentage points, which account for, or which represent 32,000 barrels a day. We were able to gain efficiency by improving management, by improving scheduled maintenance so we no longer have unscheduled stoppage, and also the allocation of critical assets for this maintenance. The fact is that we’ve had a lower total expenditure, a lot of management efforts, but with low expenditure, only US$3.2 million. And if you look at the Net Present Value, it is extremely attractive. US$804 million is our estimate with gains of 32,000 barrels per day in the quarter. If we adopt these gains, we’ll have 65,000 barrels per day additional, and our global operating efficiency adding up all operating units increased from the third quarter 2012, where the average efficiency was 85% to an average efficiency today, third quarter 2013 of 89%. So gradually all of our units are being able to sustain and improve their operational efficiency, which shows that not only are we adding new oil, but we are also taking good care of the old oil. And the new oil will be produced at a higher efficiency than that we had last year. On the next slide, we are just mentioning our results that we consider to be extremely successful, achieved in the recent Libra oil fiend auction. And Petrobras was involved in a consortium with 40% stake. In addition to its mandatory 30% stake, we had additional 10%. And with us, we managed to join companies that add a lot and very well to the technical expertise and Petrobras financial robustness to lead such a magnitude project as Libra. Shell and Total, each one with 20% stake, and companies with large experience in the implementation of mega projects in power and energy, particularly deepwater worldwide. And last but not least, two Chinese companies, CNPC and CNOOC. And they also bring knowledge, but particularly financial robustness to a project of this magnitude such as Libra. We were successful presenting the minimum bid of 41.65% with a mandatory bonus of R$15 billion. And we are confident about the extreme financial attractiveness of this project in Petrobras portfolio being added to the current business and management plan, but not mentioning replacing projects, but rather we keep on managing our portfolio. But by no means with the entry of Libra imply any delay of any other project that is economic attractive in our portfolio as we expect today in our business management plan for ‘13, ‘17. Further details on how we intent to have the project implemented – by the way, some of them have already been disclosed. We expect the first oil for commercial purposes to happen up to 2020. And for external well test, today in the minimal exploratory program, up to 2016. We would certainly meet our goals and also the local contact expected by the project, like I said with very high financial attractiveness when it comes to internal rate of return. On the next slide, I would like now to give the floor to my colleague, Cosenza from Downstream.

Thank you, Formigli. Good morning, everyone. On this first slide, we are presenting the domestic oil product production, pertaining or comparing the second quarter of ‘13 with the third quarter of 2013. In this comparison, we can see a slight increase or reduction in oil products this quarter with stability purposes. But something important to say is that when we compare this third quarter of 2012, there was a 5% increase, but when we compare the second quarter of 2013 with the third quarter of 2013, there is good improvement in the profile of our refineries due to the higher noble oil product production basically diesel and jet fuel and gasoline, which is very relevant showing our surge for more economic performance in our refineries due to the production of higher value-added products. As to oil processing, here we show the used factory. In the third quarter of ‘13 of 93% slightly lower compared to 99% in the second quarter of 2013, basically due to the fact that we had two important stoppages in Duque de Caxias in REGAP refineries, and for 10 days, we stopped REVAP. And this led to a use rate of 96% and a reduction of approximately 30% of daily oil processing. Another highlight this quarter for average processing July which was our record processing of 2.139 million barrels per day, which is extremely important to our facilities, and we also had a peak of 2.200 million barrels per day. I’d like to remind you that in the fourth quarter, our trend – well, we don’t have any stoppages that will effect oil processing. We expect to see something very close to what we had in the second quarter of 2013. As to costs, when we compare the second quarter of 2013 with the third quarter, there is an increase in refining cost of 17% and largely due to the provision of the Collective Bargaining Agreement in September 2013, and a reduction of the processing we had due to stoppages in the units. On the next slide, when it comes to the sale of oil products, the market this quarter was really very different from the previous one, particularly, due to the diesel markets. We had a record processing of diesel of 1.030 million average, which is a very significant number and a record figure of sales in the country, and obviously it took a lot of effort to supply these products. When we compare the increase with the second quarter of 2013, it was 5% above, like I said before, basically due to the summer grain and crop and industrial activity and the global growth of oil products, particularly comparing the second and third quarter around 2%. Gasoline, virtually flat. And the highlight was diesel, with a very significant increase of 5%. Next slide. Now we show the result of our NGAS [ph] or LNG products. When we compare the second quarter and the second quarter of ‘13, there is an increase in exports of about 12%, that was due to increase in oil exports stemming from our lower throughput in our refineries and the stoppages of REDUC and REVAP and partially REGAP. As to imports, the market was stronger this quarter leading to an increase in imports of diesel basically with 238,000 barrels per day, and imports of gasoline remains flat, compared to the previous quarter, 13,000 barrels to 28,000 barrels which brings stability considering the volume we are processing at our refineries. And the leap in the net import balance, when we compare the second quarter of 2013 with the third quarter, there is an increase of 349,000 barrels per day of imports for 425,000 basically related to the higher need of diesel in our country. And now we compare prices; domestic and international prices. As you’ve seen in the third quarter, there is a very remarkable effect by exchange rate comparing the second to the third quarter around 11%. And Brent oil, which was from the second to the third quarter, an 8%. So this mismatch became stronger and that’s the result in supply which had a negative net income of R$5.5 billion. And now I give the floor to Alcides Santoro.

Thank you, Cosenza. Good morning, everyone. This chart shows supply and demand of natural gas. The quality of demand or the demand unit, there is a significant reduction of 6% in the total volume delivered to the market. This reduction stems basically from a drop in the thermal electric demand that dropped 16% compared to the second quarter of 2013, owing to more rainfall in hydroelectric reservoirs. As to the non-thermal market. For the second quarter in a row, there is a slight increase of 1% at the non-thermal market, showing a recovery of our economy. As to supply, we show lower gas supply and particularly a significant reduction in the imports of LNG, approximately 30% related to the second quarter of 2013. There was a low reduction of 1% in the national domestic gas supply mainly due to the scheduled maintenance in Santos Basin. Net income for gas and power units, was minus R$192 million vis-à-vis R$576 million in the previous period, mainly due to the lower volume generated and also the lower price of energy. And now I give the floor to Maria das Graças. Maria das Graças: Good morning. On this slide, we show the results of PROCOP. It is the operating cost optimization program from January to September 2013. I would like to remind you that in the horizontal axis we have a breakdown of the main activities, operating activities performed by the company. And the on the vertical axis, we show the percentage of our achievements of total savings for 2013. That’s our forecast. Up to now, our savings are R$4.8 billion, already exceeding the annual goal of R$3.9 billion. Considering this total while R$3.9 billion, the inclusion of subsidiaries, BR Distribuidora, Petrobras Bio and Liquigás starting in July. By and large, the bulk of the gains above our expectation that we have achieved are related to our productivity, considering that several initiatives show our trajectory of improvement of such throughputs that is happening faster than we expected. In other words, productivity levels that we expected to have in 2014 have already been achieved by 2013, leading to savings above the average. I would also like to thank by the way all the company’s employees and the workforce that is strongly engaged, so we can keep on delivery PROCOP’s results. And now I give the floor to officer, Barbassa.

Thank you, Maria das Graças. Let us now analyze the results related to the third quarter. If we focus now on the main variables, we can see that our operating income this quarter was lower when compared to last year, and particularly, when compared to the second quarter of the current year. Why did that happened? Over this third quarter, we had a strong demand. We had additional growth in diesel, which exceeded one million barrels per day. So although we produced more – more of this oil product at our refineries, thanks to the improved efficiency on a daily basis, we still had to import to add to our demand. And this import took place at a time in which Real was fully depreciated and we had a peak of Real depreciation this quarter exceeding sometimes even 2.4 Real per Dollar. As a result, well, we also had a higher import of oil products. And international prices were also higher. And all these factors together led to a significant impact on our operating results. And we add to that higher expenses with subcommercial and dry wells, and although they were aligned with our forecast, we did expect to see higher expenses this quarter compared to the previous quarter. We also have to consider the negotiation that happens every year in September. It is the Collective Bargaining Agreement. And from this Collective Bargaining Agreement, we have a provision of costs. And there is a share of these costs that only happen right now, which is a bonus given to our employees which is just once a year. And on a monthly basis, we have to factor in those recurring increase. Well, that’s a lump sum bonus and that’s why we have a more significant impact on results this quarter. On top of that, in the second quarter of the year, we also had a higher volume of divestment, and that brought additional results to the second quarter unlike what happened in the third quarter. Consequently, well, considering these higher cost of production in refining this quarter, we had a significant decrease in our operating income this quarter. Now what about our EBITDA? This whole effect has an impact on EBITDA which was therefore lower than we expected if it weren’t for all these drivers and elements that I mentioned before. And net income also is affected by our operating income, even though the net income was held by the financial result of the third quarter, when there was an exchange rate depreciation lower than the second quarter. And this whole part of the debt that is not hedged, the non-hedged net debt is exposed to the dollar. And it also had an impact on our results, but still very much lower compared to what we had in the second quarter. On the next slide, we show a comparative analysis of our operating income between the second quarter and the third quarter of this year. We can see that sales have a higher volume. Sales have grown in Brazil. And if we add to that a higher level of exports, which also increased by 27%, we had gained in our revenues. However, our COGS was affected by 11% when compared to the second quarter for the reasons we previously mentioned; higher diesel imports, exchange rate depreciation which also happened reaching the peak this quarter. And on top of that, we also had higher prices of Brent oil abroad, an increase of 8% prices and imported products as well. The Collective Bargaining Agreement also increased costs and other expenses compared to the second quarter and added to dry wells or dry holes or the non-disposal of assets, we also had a significant impact on the results and earnings of the period. Therefore, we went down from 11.1% to 5.5% in our operating income this quarter. Net income, we also had a stronger impact from operating income and also the financial results which brought a difference. Although, we also had losses on the third quarter, it was lower compared to the second quarter. So there has been some recovery in the company’s net income, stemming from financial effects, over our indebtedness which is exposed to exchange rate variation. In this quarter, we also had lower results and less or fewer taxes to pay. So this quarter, in the third quarter, we had R$3.4 billion in our net income, net results. Next slide, you can see our investments and its behavior. We’ve invested additional R$10 billion as compared to the same period last year, that is, from January to September ‘13. We invested R$69.3 billion compared to R$59.8 last year. It means 16% growth in Brazilian currency. If we measure that in U.S. Dollars, the growth would be 5%. So we had an impact of the Brazilian currency depreciation. Most of this investment was in energy, and was in exploration and production that is we continued to increase our production, and 32% in downstream, which was also significant. Of the 165 most important projects we currently have at Petrobras, the implementation is 98%, in line with the plan, looking at both, physical progress as well as financial progress. It means that we are very much in line with our plan. The next slide, you can see our capital structure. We’ve had an increase in net debt. We’re now above 35%, which was the desirable cap for the company in terms of net debt over net capitalization. And our net debt over EBITDA increased and is now above three times, 3.0. This is because we had a lower operational income which has already been explained, and it was also explained by higher investment. In addition, we paid out dividends and we also had to pay for interest. It means we had a significant cash expenditure, which increased our net debt as measured in Brazilian Reals from 176 billion to R$193 billion, Brazilian currency. Now in U.S. Dollars, the net debt increased less, so from US$79.62 to US$86.5. This is the evolution of our net debt in U.S. Dollar. As a consequence our executive board approved a new methodology for price adjustment. Now this new methodology is providing more predictability in the company’s cash generation. Also we believe that with this new methodology, we will be able to reduce our leverage income down to the desired level. As I’ve shown you, we’ve recently exceeded the levels that we had determined for the company. And so we want to reduce our leverage to be able to more easily implement our plans. Now this methodology was approved by the executive board. It was taken to the Board of Directors. After their considerations, they requested that we conducted further analysis. It is actually something quite relevant for the company. And a decision was made by the Board of Directors. We now have a deadline, November 22. They requested us to present the results of this further analysis. So they will consider these results to make a decision. With that, I conclude my presentation and we will now be available to answer questions if any. Thank you very much.

We will now begin the question-and-answer session. Each participant will be limited to two questions at most. Please speak slowly and clearly so that the executives will be able to answer them afterwards. We inform that questions asked in English will be translated into Portuguese for Petrobras executives, who will answer in Portuguese. There will be simultaneous translation into English. (Operator Instructions) Mr. Bruno Montanari from Morgan Stanley has a question. Bruno Montanari – Morgan Stanley: Good morning everyone. I have a question to Barbassa. I’d like to understand a bit more of this new methodology in terms of timing for the implementation that is if it is approved, and I’d like to hear your views in terms of international prices and limits for price adjustments domestically, if you could share that with us? And again what if this methodology is not approved, then are we going to see a review in your CapEx plan in the short-term? Thank you.

As I made clear in my presentation, this methodology, further analysis will required, including simulations and actually it has quite a few important parameters in it. So at this time, we cannot make considerations or try to make statements about this new methodology, because it is currently under analysis. Now what is important is that the principle behind it is very relevant. That is whatever the parameters included and whatever the implementation method shows in, this new policy will bring with it, a better predictability for the company’s cash generation. And as I said before, our plan is to go back to the levels established in our business plan – our business and management plan. So right now making statements about whether it will be approved or not and what parameters will be included – actually at this time, this exercise would not be adequate. So I am sorry, I cannot conduct this exercise with you right now.

Mr. Marcus Sequeira from Deutsche Bank has a question. Marcus Sequeira – Deutsche Bank: Good morning. A question about refinery. First of all refineries, we thought about the participation of Asian partners. And the question about E&P is about Libra. We know this is a big project to you, but we also feel the need for additional platforms. We know the company already has concession contracts with some projects of pre-salt, and also considering timely – how to have these projects in a timely manner. Could you elaborate on that please? What is your expectation for the project or could you give any additional information please?

The project of the Asian partners is still being studied. They are assessing the project and also the refining schedule. For example with one of our studies that is trying to simplifying the projects, but the difference compared to the first quarter is very significant. They are studying our project to check the right scheme or refining or processing. Now answering your question about Libra, at this time we are not disclosing our expected production curve for Libra. There is no doubt this project has a very high capital limit from R$8 billion to R$12 billion as announced by the agency. And the partners including Petrobras had their own evaluations that were obviously used at a time in which we decided to go for the minimum bid. The production curve will have a significant impact to all the partners in Brazil. And we cannot disclose right now. As to the need for platforms, this has been certainly factored into the analysis. The Brazilian markets ability to implement these projects at the speed we consider to be the most adequate, which means the first oil will certainly in 2020. So our demand today for this timeframe shows the capacity to work on the contracts, certainly not right now but in the coming future, because the demand – the strong demand of the transfer of rights and the units that are already under construction particularly for Lula, BMS-9 and BMS-11 will be delivered and implemented at under production which is even better with revenues generated to Petrobras. So this coincidence has been analyzed, and we believe the need to build these units just adds to our install capacity in Brazil. So the minimum local count of 55% which is mandatory for all the units by 2022 and 59% after 2022 does not bring any threat to us considering the installed naval industry we have in Brazil. Thank you. Marcus Sequeira – Deutsche Bank: Thank you.

Mr. Kyle Cabral from JPMorgan has a question. Kyle Cabral – JPMorgan: Good morning. I think this would be a priority for us and also going back to Bruno’s question, we’d like to know a bit more about prices and this project, this new methodology that is currently been analyzed. So if you look at production, we’ve seen some interesting news. We had not seen production growing for two months in a row since last year and we’ve seen this now. I believe that in the next quarter, we will again see a decline in production in October/November then perhaps it will pick up again in December. Is this what we can understand from the timing of new equipment starting operations? So now perhaps October would be a month where we would not have new equipment coming in, so we would see again a decline and it would pick up in December or not? Perhaps I am wrong. And do you expect to see production growing in the fourth quarter? I mean I’d like to have your short-term view. Now again about 2014, can you give us an idea about production growth? Are we talking about production going from 5% or are we going to have a 10% growth in production in 2014?

Okay. Well I will answer. You know that Petrobras is very conservative in terms of not disclosing projections. At any rate, I will try to tell you what we can tell you about these two subjects because I can understand the relevance of the production curve. This is a key item for us, because it is very important to determine the results. So it’s important for investors, for minority shareholders or controllers too. So fourth quarter 2013, the production will – production tends to pick up significantly in this quarter, that we see a growing trend up to December. So first, we will continue to have the same level as September, because we still have scheduled maintenance for October and November, but there are new wells starting operation. So let me give you an example. This weekend on Saturday, we began Lula Centro anticipated production or early production. It’s a dynamic producer, again operating in Santos Basin with ANP full licensing and the Brazilian Environmental Agency licensing which is a very relevant fact for us, because this system production adds 17,600 barrels per day, in addition to 11,000, 12,000 barrels a day, in addition to beginning the production in this reservoir so that we can calibrate the Lula Centro unit. Let me say that this production is still restricted. This is not the whole potential of this well. As you know, we’re limited to 500,000 cubic meters of gas a day in terms of flaring. So that is why we have a restricted production, but other wells are now being interconnected. P-63 will start operations in November. We will already have the production of P-63. And there are other new wells being interconnected to older systems, which will again increase our production. With P-55 and P-58 coming in, plus a growing production from P-63 in December, well then our production will be stronger. For next year, 2014, we will continue in this growing trend. At this time, we cannot tell you whether it will be 5% or 10% which was your question, but I can tell you, we will have a significant number. Not only will we be able to offset the natural decline which as I said is now 9%, that is it’s below 10%, which is extremely relevant for us that is if you consider the impact on production in our large fields. Now we will be able to offset this natural decline and we will have an important growth during next year with the production ramp-up of these new units. In the first and second half of the year, we will certainly have a solution for the buoyancy riser system, because we will have advanced in our learning curve. We will have the summer, so that we will have better sea conditions than we now have, because now we are in the winter. And then we will have a higher production. I cannot tell you the number, but it will be significantly higher than what we’ve seen this year. Kyle Cabral – JPMorgan: Thank you.

We have questions in English from Merrill Lynch now. Frank McGann – Bank of America/Merrill Lynch: Yes, good day. Two questions, one just in terms of following up on that question, the level of maintenance that you are expecting in 2014 versus 2013 as you commented on how whether that should be materially less – maintenance being done next year versus this year. And then secondly, many of the service companies have suggested that the amount of drilling activity has declined. And I was wondering if that was really true or if it’s just – the units or the type of work being done has changed so that the perhaps number of wells being drilled is somewhat lower?

Okay, Frank. I’ll give you this information. When it comes to the maintenance level, in terms of average – for average jobs scheduled maintenance, we expect to see a level that will be equivalent or slight lower than this year. The benefit is that we have a rising production which will offset. We have to bear in mind that scheduled maintenance will always happen. When we stop with the scheduled maintenance, it means that one or two years later the unscheduled losses will inevitably happen, will certainly happen. So the number of frequency of stoppage will be equivalent or lower than this year. However, the advantage is that the level of unscheduled maintenance certainly will be lower. And our goal obviously is to go or come to zero, because we’re investing in scheduled maintenance this year, so that next year we won’t have a high number of unscheduled maintenance. So that’s our permanent rationale when it comes to our efficiency which is very much well shown by improved efficiency. When we show efficiency figures, it’s important for analysts to know that they include scheduled maintenance. So if we have good performance when it comes to our total efficiency with scheduled maintenance so that’s a sign that we are increasingly getting closer to the potential that reservoirs can deliver us. So this is the rationale of showing why we invest scheduled maintenance to improve efficiency. So I want to make that clear, because sometimes some companies exclude from the improvement numbers, the correspondence scheduled maintenance but that’s not Petrobras’ case. We include all stoppages, scheduled or unscheduled. So that’s for the first item. The second item Frank, about drilling. What happened was that the number of drill rigs remains basically the same, 69 rigs. Some of them are docked. There are three docks which is also part of the normal flow. With 69, you – every five years you’ll have to stop. So this is all within our expectations and schedule. However at this time, what we have is that a huge effort to develop our production in order to add to the wells precisely to allow well interconnection in the units that are coming in. We manage to drill the wells beforehand and now we’re focusing in completion. In addition to work-overs at Campos Basin, just some brief stats. Right now, we have 10 drill rigs, floating rigs for the work-over in Santos Basin. All within the efforts that we saw on the slide in order to improve PROCOP’s [ph] efficiency, which has been delivered with a positive net present value and also growing as we showed you before. So drilling today and exploration, we have a total of 19 drill rigs for drilling and test purposes, which also happens. Sometimes, you have a concentration of some drills and tests. Recently, we announced the result of the test in Sergipe. So this is the model of [indiscernible] this is the distribution of rigs that allow us to decrease our drilling works, but the number of rigs remains the same. And I can assure you that right now, these rigs are dedicated to the completion of the wells, so we can have higher ramp-up speed rode by our interconnection ability. Thank you. Frank McGann – Bank of America/Merrill Lynch: Okay, thank you.

Mr. Paul Cheng from Barclays has a question. Paul Cheng – Barclays: Hi, good morning everyone. A few questions. One is for Barbassa, and one for Formigli. Formigli that in Libra, can you tell us that in terms of the decision process, that who set what veto rights and how that investment decision that is – you [indiscernible] decision from all the partners for affecting or that certain partner and the government has certain veto rights. And what are those? And the second question is that Barbassa, for the – what you currently have proposed on the pricing mechanism, can you at least tell us that what you have currently proposed? Is it a mechanical process like the Chinese have 22 days is the average price is raised from the international price by 4%, do you automatically adjust. How that process currently being proposed? And I think yet the agreement for the Petrobras are not accepted by the government. At what point you will look at your capital spending program? Thank you.

Well, I’ll try to answer the first question. Please confirm if this is exactly what Paul Cheng asked from Barclays. In the case of Libra, what about the governance and the consortium as regards minimum percentages or minimum votes for certain decisions, then whether any member of the consortium has the power of veto. Is this the question please? Paul Cheng – Barclays: Yes, I do want to know that if all the decision on any particular decision will get what...

Very well then. Okay, let me answer the question. During the exploratory phase, the consortium PPSA, which is the specific company set up by the government to represent the government, and B, the government’s representatives in the consortium. Now this company cannot influence the consortium decisions. We have a minimum exploratory program which will be shared with PPSA, because the team there knows a lot about this topic. However PPSA does not have the power to decide what the consortium will do. Now for certain decisions after the phase of – that is during the development phase, PPSA will have the power of veto. This is during the development phase. Now when we look at the team in PPSA, they have high technical level, they have a lot of knowledge about the industry, both domestically and internationally. There are people who are deep scholars, people who know a lot about this industry. So we do not expect any problems in the relationship with them. Now, in the consortium we have some percentages that have been established in the contracts. So for some decisions you may need 91% of approval including the participation of PPSA. Let me give you an example, something that would be completely absurd, but let us imagine that in the commercial statement, we have a decision that is against the implementation. I mean I believe this would be absurd, because we do not anticipate these problems. Now if we want to return the block license, then we would need unanimous, that is we would need the agreement by all partners. For other decisions, you don’t need unanimity. You may have a lower percentage, but it depends on the decisions. If we look back at our previous experience when we participated in other consortia in the same concession system, we know that when we can prove that we have the best internal rate of return and the best net present value, then usually the members in the consortium are aligned. We believe that as we look at this team, the team we have in this consortium and the team we have in PPSA, we will obtain the same level of alignment. All the members, not only Petrobras, feel very optimistic about the evolution. We believe that we will have a very good alignment in the development of our production plan following the governance guidelines we have for Libra.

Paul, about pricing and the new policy that was approved by the executive board, I want to highlight that it has been approved by the executive board and its essence – it has in its essence, it has two factors which the executive board considered important. One, it will improve the predictability of cash generation for the company, and not only will it improve this predictability, but it will also provide for cash generation that will allow for us to lower our leverage coming down to the comfortable levels we have established for the company. Now the current study which was requested by the Board of Directors are the parameters for us to implement this new policy. Now among these parameters, I could perhaps mention price adjustment percentages, interval of price adjustments. Basically these two parameters are currently under analysis. Now, I believe that at this time, it is not for us to discuss what about the future, if this policy is not approved, if we will have to review the CapEx plan. Well, I believe it is not the time for us to engage in this discussion. It is important to understand that the new pricing policy has been approved by the executive board, and it will provide for us the right conditions to decrease our leverage and to increase the predictability of cash generation. Now we’ve offered quite a few options for the implementation of this new policy. We can actually made changes to some of the parameters and still attain the same desired result. So now we will continue to work on the new policy so that it is ready for implementation in this deadline we’ve announced, which is November 22. Thank you.

Gustavo Gattass from BTG Pactual has a question. Gustavo Gattass – BTG Pactual: Good morning. I have a series of questions. So I’ll try just to be very brief. Barbassa, I would like to consider two brief points. The first point, well I think I never heard you making any comments just as you did in the last presentation or this presentation saying that the leverage exceeded the limits and all the rest. I always had a feeling that the legal governance of the process was that the management would be free to use adjustment. So I would like to understand about the new mechanism are two points. First, why not use something since challenges are stronger compared to previous quarters? Second, is there anything behind this mechanism that significantly changes how Petrobras is doing business, truly requiring the Board’s approval when actually the management would be in charge? That’s what I understood before. So this is my question to you. And if I may, I don’t know if I address this to Cosenza or to all of you, but when we consider your realization price this quarter, there is a rise in Reals of 1.3% when the Brent oil – well if you consider Brent oil in Reals, the increase is 17%. I mean always start – there was another component non-diesel, gasoline or jet fuel that would be passed on or transferred consistently to consumers, but doing the math, I have the feeling that the volume of the transfer was only 7% of the sales. Did anything different happened this quarter to justify such a low price vis-à-vis the second quarter? Thank you.

Gattass, answering your question about the pricing policy. Our policy is widely known. And it worked out fine for quite a long time and it can still apply. However, as you mentioned so well, we have exceeded the limits that we decided in the past. So considering the whole program – our whole investment program, we thought it would be appropriate to be more adaptive to the current reality. And this adjustment brings more predictability, and also a return or a lower leverage. So why don’t we start this implementation right now. There are some items involved. Once we highlight that these conditions of predictability and leverage to be present, be it now or in a month, this is not so significant. So we might carry out studies that apply better to our reality. But always ensuring that the new policy will factor in and bring as approved our forecast, and also allow us to implement our business and management plan as is. Thank you.

Mr. Luiz Carvalho from HSBC has a question. Luiz Carvalho – HSBC: Hello, good morning. I will continue. Question to Formigli. I have two questions about production, because the probable scenario as Barbassa mentioned is that we’ll have more predictability in terms of cash generation and pricing. Production therefore takes on an even more important role, I mean given the growth you expect for the next year. The installed capacity in 2014 will be significantly bigger than in previous years, but in our analysis and something you mentioned in your slide, it draws my attention because the decline we calculate comparing quarter-to-quarter, year-on-year, the natural decline is significantly higher than the 9% you mentioned. So do you think that – I mean perhaps you have the effect of scheduled or unscheduled maintenance, but when we make the adjustment, the level is always above 12%, 3% higher than the 9% you’ve announced. So can you give us some more details, because this difference between 9% to 12% or even a difference from 9% to 14% or 15% can be very significant when we think about growth in the future? Second question is also about production. When you look at the data from August by ANP, for the first time after 2005, when we’ve had these data, the production of water has exceeded the production of oil. Of course we understand the natural decline, maintenance that was not adequate in the last few years, but I’d like to understand how we can view this into the future? Do you view a higher production of water from now on, or do you believe we will have oil production picking up and remaining above the production of water?

I will answer, but we still have to hear from Cosenza about refining. So let us let us – let Cosenza answer this about refining and then we go back to your question from HSBC.

Yes, Gattass, about your question, why we’ve had the NPV growing so little, because gasoline and diesel are the largest volume, that’s why they have such a big weight. And the other products, we did not pass onto prices the market volatility. Only naphtha and the other products – well, they depend on a decision coming from the market or from other entities but we do not pass this on to prices. So if you look at the average realization price, you see that impact, but we do not pass it onto the final price. Was this the question?

Well then, now I will answer the question coming from HSBC from the production decline. Well I know that you – now you trick the results well-by-well. However, you have to understand that when we analyze the natural decline, this analysis considers not only well-by-well, we also look at reservoirs and drainage per well. We also have to consider the complimentary wells development. This is how you calculate natural decline anywhere in the world, that is, it’s not as if you had a portrait and you – a frozen portrait of the field so that you will not have an increase in the number of recoverable barrels. So when we say that the natural decline was 9% for the whole Petrobras and the natural decline of our largest fields were between 10% and 11%. Yes, of course there are fields which you probably track that may have a higher natural decline. For example, if you look at reservoirs such as fractural carbonates as you have in East Marlin and [indiscernible], they naturally have a higher natural decline, because it is a characteristic of that kind of well. When you have other types of sediment, when you have sandstone or other types of sandstone, you have a lower natural decline. If you consider the average of whole basin, it’s below 10% or 11%. So when conduct your analysis well-by-well, be careful because you do not have the complete data and Petrobras cannot disclose more data than what you in the ANP website. This is a decision made by the agency by ANP, otherwise we will begin to have analysis by reservoir and this is not how we work. Regarding, the production of water, Campos Basin, if you produce water, it means that you are producing oil, if you increase the recovery factor. So you have to inject water and then you need water treatment and disposal. One of the items on which we’ve been working to improve efficiency is to de-bottleneck some platforms, so they can live with more water, because that is how we will attain the potential of the reservoir that is increase the oil production, oil plus water. When you see a higher production of water that is higher than oil, this is not something permanent, because we are currently installing new platforms. When they come into operation, P-63, P-61, P-58, P-55, and P-62, the amount of oil will grow, so again the oil/water ratio will change, will be more favorable to oil. But in the mid and long-term the water production has to grow, because this is part of the development logics. You can only attain recovery factors above 50% as you have in Marlin, when you have also a high injection of water. Now PROCOP’s responsibility is to work to reduce the consumption of chemicals. Actually this is one of our levers. This is one of the drivers of savings. This is where we obtained some of the most significant cost savings in the offshore production, because when you produce a lot of water, you need chemicals to separate oil from water. So there, we are optimizing the consumption of chemicals that have to be injected to separate water from oil, always according to our environmental licenses. Will we continue to produce water? Yes, but it will be less as we install new platforms. As the new modules start operations in Roncador, we will have more equipment. And also in the case of P-58, we will have new oil. So then, we will have more oil that is we will have more oil compared to water, but we have planned for having water production and when we cannot do that on board, we will do that in a subsea. That is why we have been investing in the technology of water, oil separator. So we will not need more topside work. We will be able to inject water and transport only oil to the platform. Luiz Carvalho – HSBC: Thank you very much. Just as a follow-up, Formigli. As you do these calculations, you’re looking at the number of oils. So it’s a different number of oils as you compare year-on-year. So you may have a stable production in a field, but you may have a different number of wells. Is this correct?

Yes, when you talk about natural decline, you’re talking about the reservoir, not the well. So you cannot do your calculations well-by-well, because if you do that, some wells will have a higher decline, other wells will have a lower decline. For you to calculate natural decline, you have to look at the whole reservoir, because the whole reservoir adds or subtracts pressure as you drain each well. So that is why you cannot calculate natural decline well-by-well, as if you were doing a regression to calculate the total natural decline. We have a simulator where we consider other factors to calculate natural decline adequately. Luiz Carvalho – HSBC: Okay, thank you.

Lilyanna Yang from UBS has a question. Lilyanna Yang – UBS: Thank you for taking my question. My question is still related to pricing. I am sorry about my skepticism, but apparently there hasn’t been so many changes. I believe that company always adapted or considered the policy considering the international policy, but now we have a more quantitative one by the management. And I believe you explained with more detail later on, but why does the board has to approve this pricing policy? And another question, I would like to know the provision considering the Collective Bargaining Agreement for 2013 this quarter?

Hi, Lilyanna, this is Almir speaking. Actually what we are addressing here is a new methodology to align prices to international prices. We have clearly stated in our business and management plan, that the company follows in a mid to long-term basis all international prices. Now what changes after the new approval by the company’s management is actually the methodology to do the same alignment. And now once we have the final definition of the parameters of this new methodology, then our percentage periodicity will be offset. Therefore ensuring there is predictability so to speak of our cash flow. And on top of that, also give signs or shows that we are moving towards a lower leverage at the company level. Thank you. Lilyanna Yang – UBS: So just to clarify, so your idea – the company’s idea is to disclose so investors could also count on this predictability? Thank you.

Lilyanna, well this might be part of the methodology. However, the tension is to have a clear formula regardless of the method, but it should allow to show predictability to all interest parties. Okay? Lilyanna Yang – UBS: Thank you.

We have a question in English. Mr. Brendon [ph] has a question.

Hi, thank you. The CapEx spend rate this year appears to running below the full-year guidance. Can we expect a big increase in the run rate for 4Q consistent with prior years? And also a question on the Libra bonus payments. What core will that be – will that payment be made?

Now to clarify your second question – have you finished the question? I mean, it was not clear for us here. Can you please repeat the question? Now we wait. I will answer – I will answer the first question about CapEx. As we said, we’ve attained approximately 98% in physical progression as compared to the plan, as well as in the financial progress compared to our budget, or compared to our plan. Considering this volume, we may tell you that we have been able to fully deliver our plan. However, in the fourth quarter of the year, we will have higher numbers as compared to previous quarters, because we’ll have a natural growth and also the effect of year-end. So we expect a possible growth of CapEx in the fourth quarter. Although, we consider that we are very close to 100%, but we expect to remain at this level. At least this is what we expect until year-end. We’re now waiting for you to repeat your second question please? Okay, next question please.

Mr. Christian Audi from Santander has a question. Christian Audi – Santander: Thank you. I have three questions. Barbassa, the first question is addressed to you. When it comes to timing, I would like just to have a better understanding of the final decision, will it be delivered on this 22nd or could it happen beforehand, or could even be postponed. Maybe on the 22nd, the Board will ask further information? So will it certainly happen on the 22nd or not necessarily? Is there any flexibility in the process? Second question Formigli, just quick follow-up related to production or output in the fourth quarter. What about the output in October, would it be more in line with September, but will it grow in November and December? And as to Libra, would you be paying bonus signature cash for Libra and how much or up to when? And then last question, regards to scheduled maintenance at refineries in the fourth quarter, what are the expectations and what about the capacity used from 99% to 96%. Would you go back to 99%? And can you sustain at such a high level in 2014? Thank you.

Christian, I’ll answer your first question. Your question about the use of the new methodology of price adjustment, and to what extent it could happen before November 22. November 22, according to our schedule or the meetings of the Board of Directors, November 22, will be the new or the next Board meeting, general meeting. So in virtue of this schedule, that’s how we came to this deadline. If by any chance, the parameters evaluated or the parameters that we are working on, if by any chance everything is concluded beforehand, it might happen but November 22 is the date that has been set. Thank you. Christian Audi – Santander: Just a brief follow-up. But is it a final decision or could on the 22nd, you ask for more information, further information be asked?

It is the management’s decision. It is a decision approved by management. However, those implementation – let us see first how complex it is. We have already started to carry out studies on several alternatives available in terms of parameters. Additional evaluation will take some time though, but nothing prevents us from having them completed within the deadline. So now I give the floor to Formigli.

Hi, Christian, let us talk about the output. The problem of working on projections is exactly this. When you say that in the quarter we will have a higher output compared to the previous quarter, which is the last quarter, considering the new oil and the stoppages, everybody wants to know production or output on a monthly basis, but we don’t get to this level of detail. What I can tell you however is that our current projection is growing, no doubt about it, considering the rhythm of scheduled maintenance plus the new oil that is coming in. So please don’t ask me details month-on-month, because that’s not Petrobras’ practice to work on these kind of projection. Christian Audi – Santander: I am sorry to interrupt you, Formigli. So are you saying that you’ll be at minus 2% vis-à-vis the level in 2011?

Good question. We’re doing everything in our power to be in the lower range of the limit that was set early this year. And this is due to the delays we had in some of our new systems that I highlighted before. However, now we have all these solutions properly set with the exit of shipyards, so that now we can have an interconnection process. We have the wells drilled. We are in the completion phase. We have some platforms exiting shipyards, are about to be anchored and now we are in the world of well interconnection, which is expected to happen in coming months and also next year. Now you asked about Libra payments. Now that’s a topic that – well, our forecast is by the end of November, there is a meeting scheduled. I am not going to tell you any dates in order not to have the media at ANP, but there is a meeting schedule at ANP just all that details pertaining to the payments, the payment of – the percentage of bonus for each one of the consortium members. And afterwards, we’ll get to know exactly what the payment date or method will be. If it will be directly from the consortium member to ANP, or in which the operator or in this case Petrobras, we have a cash call, quote, unquote since the consortium is still been worked on and we transfer payment to the government. So there will be a meeting this week at ANP involving all the consortium members to work on that topic. Christian Audi – Santander: Formigli, but will be Petrobras with cash and not be in financed for the bonus percentage? You want to know if there will be any carry-over, of Barbassa, for instance if you take the R$4 billion or R$5 billion. Would you pay in cash or any other kind of payment?

What I can tell you right now, Christian, is that there is no carry-over forecast of any partner vis-à-vis Petrobras.

Christian, regarding refining and downstream, I would like to say that for the fourth quarter, we don’t have any stoppage scheduled. We had REVAP which started in the second two weeks of September and took 10 to 15 days into October. It already returned with three days of gain after the stoppage. So we want to have it repeated in the second quarter of 2013, at least equivalent to what we had in the second quarter of 2.100 million. Christian Audi – Santander: So considering scheduled maintenance, what do you expect for next year? Do you think it’s feasible to maintain this high level of capacity use next year?

I wouldn’t say it will be too high. It will be just high. For the first quarter of next year, we have a significant stoppage, not so big due to REVAP, but it shouldn’t affect our output so dramatically. REVAP is 40,000 and this one would be about 28,000 or 29,000 in the first quarter of next year. We expect to repeat the number in 2013, but improving it because the reliability process that we’ve been implementing for quite a while now at the new refining units make us confident, that we are on the right track maintaining refineries up and running within the standards, particularly trying to continuously improve our assets, once we improve or increase our complexity in our refineries and facilities. Thank you.

Mr. Pedro Medeiros from Citigroup has a question. Pedro Medeiros – Citigroup: Thank you everyone. I have three questions. Some will be just to follow-up. Formigli, the first question looking at the results of PROEF, I know you’ve talked about that, but as you look at the numbers you’ve reported, I’ve calculated in the first nine months of last year, PROEF reached 460,000 barrels per day, this year 399,000 already including PROEF on both years. So we’ve had a drop of about 14% comparing year-on-year. Now as you look at these results and at the potential of this reservoir, can you tell us how much of this number was impacted by scheduled or unscheduled maintenance, so that we can truly understand the performance? My second question, I know that ANP has also changed the price of assets for the transfer of assets. And they have already worked on the contracts. So I’d like to know about – I would like to know more about this process and what is the timing for press review? Finally, a question to Cosenza. The media is doing this discussion about the eminent contract of equipment for refineries BM-1 and 2. Now should investors already taken to account the inclusion of these two refineries in the next investment plan of the company? Thank you.

All right. First question about PROEF or BC. Well the data that I have here with my team, they show that production from BC at the last year was about 430,000 barrels of oil per day. You mentioned 460,000 or 465,000. No, I think that perhaps if you want, you can send us a specific question and we can provide more details to you. So this decrease you mentioned from 465,000 down to 399,000, in fact our number is from 430,000 down to 399,000. But I think we could clarify that having a specific conversation with our investor relations team. Now about the review of prices for the transfer of assets. We will rigorously deliver before the deadline. So in 2014, we want to review the valuation of our areas. Why? Because as we look at our results so far in drilling, these areas, we confirm the possibility of producing the five million barrels in Franco or adding the other areas that we want to keep. So there is no indication of difficulties there. Now if you ask me when do we plan to begin discussions with the government? Well, very soon. Our plan is to begin discussions about this topic very soon with the government agents and stakeholders involved. Now in 2014, we will be on time, we will be within the deadline. We’ve had a very good result. Now just to give you an idea of the dynamics we have in this process of assets, we have nine rigs working in this area. So it shows that we have a very interesting result. I believe this was the question that was addressed to me. So about this, we are currently improving the performance of these refineries because we want to have a better net present value better than what we had in the first phase. And now as of April next year, we will launch the specific packages. Of course, this is pegged to issues of funding that is so that we can materialize that, but this is our plan. Thank you.

Auro Rozenbaum from Bradesco has a question. Auro Rozenbaum – Bradesco: Good morning. I have two questions. One question was just touched upon previously. Over the weekend there was an announcement by Petrobras including 100% Abreu eLima and they made – they came to a conclusion with Venezuela. I would like to have that confirmed. And the second question is, what is the idea to work with Abreu eLima? The second train. Would it still be used in Venezuela oil? Will there be any change to process Brazilian oil, tell about that?

Auro, Cosenza speaking. Abreu eLima Refinery. The change that we announced officially on Friday does not change anything at all when it comes to the project. We still consider the unit as being a heavy oil processing unit and we’ll go wherever necessary to process oil within our projections or designs, but I can tell you that the suitability of domestic oil is under study and we might have additional supply in these refineries or in on this specific refinery considering the characteristics when we compare heavy oil to light oil. But that’s what we are working on right now. To summarize, we are trying to use existing facilities in the project and also trying to process our own light oil whenever necessary or possible, but considering the constraints of processing. Our expectation is to increase processing with our domestic oil according to our project. Auro Rozenbaum – Bradesco: Am I right to assume that that’s a closed subject with Venezuela, so it will be a 100% Petrobras refinery?

Today it is 100% Petrobras. Until February 28 of this year, Petrobras develop several facts in order to make feasible an operation that was set in previous years. But under those conditions, negotiation did not progress. So we decided to have Petrobras included. But considering what we said early in the process four or five years ago, this still applies if they managed to do so. Auro Rozenbaum – Bradesco: Perfect. Second question. It has to do with outputs, production. Formigli, considering the discussions of the natural decline and also showing a drop of 10% or 11%, if I may just make a comment before I ask my question. Actually the well-to-well evaluation and the decline interpretation is not a decline statement, but rather a conclusion that refers to the return we see in the assets or Petrobras assets or the local production. I’ve been trying to make comparisons with other countries and it’s very hard to find abundant data or information such as we see here. So what these data show us that should be something common is that the return of investment or the return of wells and basins overtime tends to be lower, which is not the same with the drill cost. The whole cost follows the rent of drill rigs. So when we check well-on-well, we have to consider the return on CapEx and not always or only the decline rate of reservoirs which is more complex and also requires information, therefore many reasons are not made available. So my question is the following. The natural decline lower than 10% or 11% as you mentioned, does it result from the excellent performance of pre-salt? In other words, do you have this broken down? What is the natural decline in Santos Basin? Do you have those numbers? Campos Basin I mean.

Auro, this question about calculating the return on capital employed only well-on-well, apparently this is not right. Forgive me but that would lead to a long discussion. We also have to consider – we would have to consider injector wells if we were to properly manage the well. When we decide to have a well to train a specific area of the reservoir, it does have an impact on all the other wells, that’s why you need a simulator to check the delta, production delta or the additional volume that you lived through that well vis-à-vis all the rest of the reservoir. So the well-on-well math and you mentioned that very well data available. I think there is nowhere else in the world where we disclosed as we do. And unfortunately from the one hand, it allows us to have a thought or follow-up of our performance. It might also lead to conclusions that I personally don’t consider to be the best or aligned with the global view of reservoir simulation. You shouldn’t consider just the reservoir behavior alone. It takes knowledge of the pressure level in the reservoir. It makes a brutal difference. And it also takes an idea of the volume of the porous rock, and consequently how much – or how much volume is left which you don’t have otherwise. So please when I warn you all that this follow-up is not perfect, I might lead to – it might be misleading. This is the reason, but obviously it does allow us to have a general follow-up. When you ask me about the specific decline of big fields of Campos Basin, excluding pre-salt, this decline is within that range I mentioned before, 10% to 11%. Once we include pre-salt, it drops downwards. We don’t see a decline yet because today we still have a large volume. What I mean by no decline, I am referring to no decline in production, but obviously from the moment, I take the first barrel out, there is a decrease in volume, pressure and general volume. So we do have a decline, but it will only happen in the future once we have to work on artificial lifting and then gradually there will be a decline on a well-to-well basis. So my straight forward answer on Campos Basin, excluding pre-salt, once again within 10% or 11%. Once we include pre-salt, it goes below 10%. Okay? Auro Rozenbaum – Bradesco: Perfect. Thank you for your answers. And obviously we count on your support. So we can join forces, join efforts and eliminate any [indiscernible] analysis and improve our lessons and interpretations of the figures – production figures. Thank you.

Ms. Paula Kovarsky from Itau BBA has a question. Paula Kovarsky – Itau BBA: Hello good morning everyone. I have few follow-up questions. First, about this formula. I think it is the first time we heard you were saying that the only products that follow international parity are jet fuel and naphtha. Now so do you want to include projects such as fuel oil, LGP in this formula so that we would have more predictability? This is my first question. My second question is about Libra. It’s a question to Formigli. I understand that company does not want to share with us at this time, the new calculations looking at production curve, but let me just check one thing, my understanding. You mentioned that first oil is expected for 2020. You expect to have an acceleration in Libra production. I’d like to understand in your view, is it possible to add Libra to the current curve, or Libra will be just using the usual methodology that is looking at the return of each project and then decide which projects will be given priority? And again if you have the risk of projects such as Iara which are apparently facing challenges, if they would perhaps be delayed for Libra to come first, or perhaps have a different schedule. I mean although you may not give us precise answer, so I’d like to understand your view, your general methodology. And finally, about the renegotiation of Barra’s capitalization. Would you expect or can we expect that the economics from these areas, I mean we could expect them to be higher than what you’ve calculated at the time of capitalization, because the flow rates are better than expected. So I’d like to know your frame of mind for this negotiation. Is it possible for Petrobras to return certain areas with Petrobras making adjustment in the economics of these projects to keep all of these barrels, I mean what is your vision, what is your reasoning as you want to start these discussions with the government sooner than later?

Now Paula, let us begin talking about the new methodology. We want to highlight the relative weight of each oil product. Diesel and gasoline have always been the focus of this discussion, because they represent – well, in this quarter, we’ve had one million barrels per day, a bit more of diesel oil and about 500,000 barrels per day of gasoline. Now, so we’re about 50% are only these two products. I mean as you look at our revenue. And of course we consider that. However, when you talk about predictability and the reduction of our leverage, well we have to consider all of the factors. So we will not only consider key factors or essential factors, but we also have to look at the market of each oil product to understand what kind of adjustments would be adequate. So all of these variables can go through an adéquation as we conduct these studies. Now what is important is the overall result. Paula Kovarsky – Itau BBA: Now just to confirm my understanding, Barbassa, because I am trying to understand from what you’re saying, what you are telling is, is that you’ve always had a conceptual methodology in terms of having long-term price parity. So the same concept still applies. Now what you were discussing are the parameters included in the formula. Is my understanding correct?

Yes, you are right. Now the – and the essence of this information – I mean we want to have predictability. So with the new methodology we expect to increase our capacity to predict our leverage and how we will be able to attain parity with international prices. Paula Kovarsky – Itau BBA: The reason for my question is that in your assumption as you talked about your strategy previous years is that you would have a parity. So this assumption was already included in your plans, right?

Yes, like I said. Yes, we’ve had this assumption, what will now have in addition is how to get there. So this is the new predictability we will have.

Now Paula, good afternoon. About the role of Libra in our business and management plan, we will not disclose what Libra will represent in terms of production curve. We will do that as soon as possible. We understand the market wants this information, but this has to be done in common agreement with the partners and also after conducting some studies. You’ve asked whether Libra will be additional or instead of, that is in replacement for. Now, all of our calculations as we participated the consortium, Libra would be additional. We are not sacrificing other projects in our pipeline for Libra to come in. Portfolio management is something we do and we will continue to do, not dependent on Libra, that is if we have a new discovery tomorrow in our portfolio in the exploratory efforts, and if this is better than other opportunities we have already mapped for coming into production – I mean when a unit is not yet ordered or when you can still make adaptations then that’s what we will do. I want to make it very clear that all of our analysis on Libra, were considering Libra as additional. And that’s how it had to be, because our projects except for transfer of assets, we always have partners. So we cannot give into our participations in a consortium, because we have other opportunities. So we are managing our portfolio together with our partners, but not because we have now the rights to work on Libra. Now you also spoke about the value of Barra’s in transfer of assets versus negotiation strategy. I apologize but we shall not disclose information about this topic. We will not talk about our strategy to valuate or current valuation in our discussion with the government, because this is a confidential matter. It will be discussed with the government. As soon as we have relevant fact, we will disclose them to the market. Thank you. Paula Kovarsky – Itau BBA: Thank you.

Thank you. At this time, the Q&A session of the Petrobras conference call is over. CFO, Almir Barbassa will now make his final remarks. Please, Mr. Barbassa.

Again, I thank you all for participating in this meeting and we wish you a very good day. Thank you very much.

Ladies and gentlemen, the ID of this conference for replay and slides presentation will be available at the Petrobras IR website at www.petrobras.com.br./ri. This concludes today’s conference call. Thank you very much for your participation. Please hang up your telephones and have a great day.