Welcome to Brava Energia's Training Conference Call For The First Quarter Of 2025. The presentation and comments on the results will be made by the company's Chief Executive Officer, Décio Oddone, and the other officers of the company. We would like to point out that simultaneous interpreting is available on the platform. To access it, simply click on the interpretation button at the bottom of the screen and choose your preferred language. This conference call is being recorded and will be available on the company's investor relations website, ri.bravaenergia.com, as will the presentation that we show here. We would like to inform you that all participants will be in listen-only mode during the presentation, after which we will begin the question-and-answer session when further instructions will be provided. Before proceeding, we take this opportunity to advise that forward-looking statements are based on the beliefs and assumptions of Brava Energia's management and current information available to the company. Forward-looking statements may involve risks and uncertainties as they relate to future events and therefore depend on circumstances that may or may not occur. Invest analysts should take into account that events related to the macroeconomic environment, market segment, and other factors could cause results to differ materially from those expressed in such forward-looking statements. I will now give the floor to Mr. Décio Oddone. Mr. Oddone, please go ahead. [Foreign language] Boa tarde a todos. Good afternoon to all. Welcome to our video conference call to discuss Brava Energia's first quarter 2025 earnings results. Before I start showing the presentation slides, I would like to put the company situation into context to help you understand our results. Primeiro trimestre de 2025 was a period of transition in the operations of our main fields, Atlanta and Papa-Terra. Transition after the startup of Atlanta and the restart of Papa-Terra. Q2 2025, which we will report in August, is the quarter of consolidation of operations of these fields, which should only be fully reflected in the financial statements from Q3 2025, which begins in July. We started 2025 with production records. In April, we reached 82,000 barrels of oil equivalent daily, a volume we expect to surpass in May. Actually, in May, it was 90,000 barrels, and in the last few days, 94,000 barrels. This transition was reflected in oil sales. As we had to balance FPSO of Atlanta, we did not sell oil in January when the price was still higher, and we had to sell an offload of off-spec oil that had been stored at Papa-Terra since the time of the previous operator. The trading numbers for this quarter were impacted by these events, and Pedro will go into more detail momentarily. The increase in production has a positive impact on the cost of Atlanta and Papa-Terra. This quarter, we had full operating costs of the operation as the platform went back to operating, while production was still low but ramping up. For this reason, the reported lifting cost does not yet reflect the values we are already achieving. At Atlanta, for example, we reported $20 per barrel with FPSO chartering and $11 without the chartering. At current production levels, we have reached $6 per barrel without considering FPSO chartering and about $10 per barrel, including the platform. At Papa-Terra, after stabilizing production at the levels recently reached, around 18,000-20,000 barrels, we will focus on improving efficiency and reducing operating costs. With the connection of the last two wells, we will be completing phase one of the full development of the Atlanta system and entering a phase of harvesting the fruits of the CapEx realized. In 2022, we invested more than $2 billion at Atlanta, and now it is about time we reap the fruits of this investment. Travassos will provide more details on these topics. Onshore, we continue to reduce costs and leave behind again that state of investments in the integrity of the facilities and installations. This was very intense after the asset was acquired by 3R Offshore. We achieved an EBITDA of $35 per barrel, which is still among the best in the region. In the last few months, we made progress with steam injection and started a nitrogen pilot at Fazenda Belen. We will address these points as well. We apologize, but we lost the sound of Mr. Oddone. Mr. Oddone, your microphone is muted. You may proceed now. Now we can hear you. Oh, I do not know how this was put on mute. I was talking about onshore, and I said that Boeri will give us more detail on the progress made to reduce costs related to steam injection and the nitrogen pilot test. The most important thing for an oil-producing company like Brava, which is improving operations, this is happening already, and this will have consequences, which, as the wise men once said, come later. With this, we will be able to accelerate cash generation and deleverage the company, our main short-term objective. Comparisons with Q1 2024 are imperfect, as Brava Energia only began operating in an integrated manner in August last year. The reported leverage is a snapshot of the past, as it captures the reality of the last 12 months, which is different from the current reality. If we look ahead to the next 12 months, we get a different picture with much lower leverage, and that's what we are working towards. Even with production that still does not reflect the full potential of the assets, we achieved an EBITDA of $182 million in Q1 2025 and maintained a solid cash generation. Manati is coming back online, and with the startup of the new wells at Atlanta, we expect to have better results in the coming quarters. After achieving production and cost records in Bahia, we decided to end negotiations regarding the possible sale of onshore and shallow water assets. According to material fact communicated to the market, we made this decision in order to maintain a diversified portfolio, which allows us to mitigate risks. Our onshore assets, like I've said before, give us greater flexibility to adjust CapEx according to the price of oil, while the offshore projects give us scale and greater potential for increasing production. This flexibility of the combined portfolio has allowed us to reduce the investments originally planned for the year by 15%, now at around $450 million, without having a substantial impact on expected production. At the same time, we are reducing structural costs by more than 10%. As a result, we have achieved a breakeven EBITDA of around $30 per barrel. Considering financial expenses and CapEx, we generate cash with oil at around $50 per barrel. Even if there is a more depressed Brent scenario, we will lower our cash. With this same objective, we are developing initiatives to partially or fully replace our position as creditor of Enauta Energia of $412 million, and we are making progress in liability management of debts due this year. Pizarro will give us more detail on this. In April, we replaced Mastrangelo, our former Chief Operating Officer. Now Travassos is taking over, and this is his first call. Welcome, Travassos, and I wish you great success. We also recently started using EY as our auditor. We published our reserves report, which shows our ability to maintain production for a long period of time. We also released our sustainability report, which includes a list of the initiatives related to governance, the environment, and people. We continue to build a culture that seeks to generate value for our shareholders, and the results we have achieved are the result of our team's efforts. That is why I'm wanting to thank everyone, all of our employees, for their work. I'll finish the introduction, and I'll move to the slides. This slide summarizes a good part of what I've said already. It brings us production in Q1, which has increased since then, EBITDA generation, and a strong cash position. A strong cash position that the company is posting. Next slide. Here we have a map of our production and the evolution of production by the company in the last few years and quarters. Like I said, in the last few weeks, we achieved more than 94,000 barrels. Down below, we have our reserves certification. 15 years of production of 1P reserves, considering April production, which ensures the sustainability of our operations for quite a long time. Next. Now let's talk about our operating data. The important thing to mention here is that with this level of production, we are also going to have now Manati going back online and the operators taking initiatives to resume production. We have two new wells being connected at Atlanta. They should be completed by the end of this quarter. We have a high percentage of oil production, which improves our earnings. Now moving to offshore. I will turn the floor to Travassos because he's going to have his debut now as COO. Good afternoon, everyone. I will bring you some highlights of the offshore segment. We're at a moment of strong production increase. In this quarter, we achieved an average of 41,000 barrels of oil equivalent in the last 20 days at Atlanta by connecting wells 4H and 5H. We expect to connect another two wells by the end of June this year, and this will bring us another production increase at Atlanta. As for Papa-Terra, we resumed our production capacity at Papa-Terra. We are now producing around 20,000 barrels daily. We achieved efficiency at Papa-Terra of 93%. I believe that this is the historical record for Papa-Terra. If we look at the bottom graph, we see the trend last year, and we can see a clear recovery in Q1 of 2025. Manati, as Décio Oddone mentioned, while production at Manati is being resumed with two wells, we have a pressurized gas pipeline. Now it is just a matter of time for the operator to resume production. This will bring us an improved result to our operation. We have also had good results in BC-10. We are in an upswing trend. When we look at this chart, I think that this becomes clear. In the first quarter, we have a production of 37,000 barrels, and in April, 48,000. We are in an upward trend. At Atlanta, we have operating efficiency, and at Papa-Terra, likewise, we have been trying to pay the attention that this asset deserves. We are working strongly to focus on the main efficiency points, and that is what we addressed in Q1 2025, and we are starting to reap the fruits of that initiative. Basically, this is what I have for the offshore business, and I turn the floor to Boeri to speak about our onshore business. Thank you. Good afternoon. Okay, so let's continue the topics that we addressed in the previous call. We continue advancing in our plan to have steam injection generators that we installed at the Estreito field. We started in June 2024 to install the new steam generators at Estreito. In September 2024, we had production at Estreito that was not so high, and since then, we've been improving production. We had an 18% improvement compared to the production at September 2024. The activities of steam generation at Estreito are giving us positive results as expected. We intend to install another two steam generators at Estreito, and three of those will be installed in Alto do Rodrigues field. Now speaking about the EOR, which is Enhanced Oil Recovery. EOR, we have two important projects. One is a nitrogen project in heavy oil fields and a polymer project in intermediate oil fields. The nitrogen project consists of injecting nitrogen in 30 wells in Fazenda Belen and others. We have eight wells in Fazenda Belen, and we have the production results of the first three. The results have been very encouraging, very positive, and according to what was expected, a reduction in water production and a good increment in oil production. By year-end, we expect to have the evaluation of the nitrogen project so that we can plan the full development of this technology. With the polymer EOR project, we are advancing the licensing project of the first injectors. We will do a total of 10 injection wells. We are moving forward with the licensing and trading issues. Speaking about drilling, in the previous call, I said that we were going to use a casing drilling technology to improve our drilling time even further. That is what we did. We achieved an important improvement of 22% compared to what we were doing before. We were able to drill wells in Alto do Rodrigues in an average time of 1.4 days. I guess 22% better than what we have been doing so far. Almost 100% of what was being done by Pedro Braz when they were taking three to four days. All of this will be included in our budget for 2026. With a lower cost, we will be able to make possible projects that were impossible or not feasible before. Speaking about CapEx and given the drop in the Brent oil price, and as Décio Oddone mentioned in the beginning, we need to be efficient in the use of our CapEx. We reduced our drilling activities ending the 2025 campaign. We are ending the drilling of the last well. Some drilling rigs were demobilized. The last one will be demobilized now in the end of May. In the coming month, we'll do the same with two workover rigs. We are going to have just eight rigs for the whole onshore. One workover in Bahia, five workover rigs in Rio Grande do Norte, Sierra, and two pulling rigs in Rio Grande do Norte and Sierra. This reduction is not due because the projects are not feasible for the current prices, but our breakeven point is lower. It's lower than this brand. It's not that. It's just that we're doing this to protect our cash creation, our cash generation, and reduce leverage. Speaking about the OPEX, we continue to improve the efficiency of our operations. In the first quarter, we achieved $17.7 per barrel. In the month of April, this dropped to $16 per barrel. We continue to work to improve our operating efficiency even further. We are reestablishing some plans to make some methodology changes in the way in which we operate by integrating new technologies, real-time data collection, monitoring of the operations also in real-time, which will allow us to reduce costs even more, given a better use of our resources and problem detection and solving in real-time. Now I'll turn the floor to Pedro to talk about the commercial. Thank you, Boeri. Can you please change to the next slide, please? Here, the highlight is trading. Here, I will talk about four main topics, starting with Atlanta. This quarter, we had the startup of the first offloads of FPSO Atlanta. This is a record in terms of loading, 1 million barrels in load in the platform, which was initiated in early March after the initial formation of the platform. Right after that, we conducted the first operation of co-loading between Atlanta and Parque das Conchas, both for exports to Southeast Asia. Both operations were very close to Brent quotes within the pricing window during an environment of high volatility, both in terms of oil, also in terms of all of the margins associated to fuel oil with low sulfur content for in Parque das Conchas. If you look at the year, the quarter was initiated with Brent prices close to $80, and it ended with prices close to $64. In March alone, the margins of low sulfur fuel oil presented high volatility, and there was a significant reduction in terms of the normalized track record. This has been already recovered throughout the second quarter, and even though the profitability of the operations were very close to Brent quotes. The second highlight, in Papa-Terra, they resumed operation, and efficiency hit record numbers. We have five offloads conducted in the quarter. However, with a low revitalization program of the platform, where we decided to do the offloading of an exceptional cargo, about 400,000 barrels. They were in the platform since the days of the previous operator, and there were still issues related to quality, and that's why that load was exceptionally well priced. Since then, we had more than five offloads, all in compliance with the sales contracts, and a progressive improvement in the quality of the operation. Right now, we are working in the negotiation of new conditions to trade Papa-Terra's barrels, and this will reflect all of the investments that we did to improve the logistics of the platform. This will also reflect in the contribution of the heavy oil from Papa-Terra, especially when this is mixed with the pre-salt production. We hope that these new conditions come into force in the second half of the year, given the improvements in current conditions. The third item has to do with operations of our refineries. I would like to highlight the signature of a new oil supply contract with this new partner, which reinforces the long-term commitment between both companies. It is a two-year agreement involving investment commitments to increase the robustness of the operation and trading that would mean a difference of 20-30% vis-à-vis the previous agreement. In the refinery still, as of April, we started independent operations to sell fuel oil, discontinuing the partnership with Rising. Since then, we already serve more than five clients with different destinations. These results will become more apparent as of the second half of the year. Finally, speaking about gas, we also had a quarter of high volatility. This was a higher exposure to spot prices because they were a bit more under pressure. There was a very positive combination because there was a high performance of gas production in Bahia. However, there was a high oscillation of demand due to some operating issues from one of our clients that supplies gas. All of these issues are already normalized. Now I'll turn the floor to Pizarro, who will go on and speak about the financial highlights. Thank you, Pedro, and good afternoon, everyone. We will now talk about the financial highlights of the first quarter of 2025. Slide 14 shows net income of the company, net revenue of the company, with a significant evolution between the fourth quarter of 2024 and the first quarter of 2025, reaching 491 million BRL in the period. That is a 47% increase, mainly attributed to higher production coming from offshore assets. Next slide. Here we show that 52% of upstream revenues are related to offshore assets. Out of that total, slightly over 90% are revenues stemming from oil sales. Now moving to slide 16. Here we show our EBITDA evolution, which reached $183 million in the first quarter of 2025. Offshore assets, they not yet reflect the potential of the portfolio. With the recent ramp-up in Atlanta, we had a relevant EBITDA increase when compared to the previous quarter. Offshore, I would like to highlight the EBITDA per barrel of onshore operations, reading $35 a produced barrel, with a breakeven for EBITDA generation close to $28 per barrel. Next slide. Here we show lifting cost. The highlight goes to the second consecutive cost reduction per barrel in onshore. In offshore, we see lifting costs slightly higher momentarily, and this will be reduced by fixed costs both in Atlanta and Papa-Terra as well, with an increase of that ratio of offshore over total production. Consolidated lifting had a slight increase momentarily until we update the offshore costs. Next slide. We show CapEx in the quarter, which also contemplates investments to connect both wells in Atlanta and all of the subsea equipment, adding up to 43 million barrels. The remaining, approximately $108 million, contemplates $36 million in onshore drilling. On that note, I would like to highlight that the company decided to postpone the onshore drilling campaigns due to Brent prices, which reduced the number of rigs. This is going on throughout the second quarter, as mentioned by Boeri. Until the beginning of the third quarter, the company will have only eight workover rigs and no drilling rigs, meaning that the trend to reduce CapEx in the coming quarters is a certainty, both for offshore and onshore. In the next two slides, I'll talk about the company's capital structure. Slide 19, we show that the net debt of the company is around 2.1 billion BRL, not considering receivables from the charter from FPSO Atlanta and a cash position of $831 million. Very robust. I would like to highlight that this temporary leverage tends to be reduced with increase of production already experienced in April and May. This does not consider production in Manati and the last two wells in Atlanta. In addition, the company is getting operating cost reductions, reducing admin expenses, and also CapEx in relation to what was projected for the year. We are also creating alternatives for the chartering at FPSO Atlanta. I would also like to mention that increase in offshore production will dilute fixed costs, which can more than compensate more challenging Brent scenarios. This was seen in April when production increment more than offset Brent reductions once compared to the average in the first quarter. In the next slide, we show that the cash position is much higher than all of the obligations for 2025 and 2026. We would also like to highlight that the next phase of liability management will be earmarked to fund in part or in full the exchange rate debentures maturing in 2027. Next slide. We show the cash flow for the period and the hedge position. We had $1 billion in operating cash flow, and we amortized approximately $650 million, considering the balance between earn-out payments to Petrobras, which is part of the calculation of our gross debt, the prepayment of lower debts, which were more expensive, and also the issuance of $64 million, which was very competitive with interest rates below 7% in dollar terms. In terms of our hedge position, our position was reinforced, and we have 24,000 barrels hedged in the second quarter at an average of $72 per barrel, and also 13,000 barrels in the collet form with an average of $61 per barrel. At the end of the first quarter of 2025, we had about 2,000 barrels a day at $74 and slightly below 10,000 barrels with a floor price of $61. This position has been reinforced now at the beginning of the second quarter. Now I'll turn the floor back to D´ecio for his final remarks. When I finished my initial remarks, I was told that I had some connection issues. This shows that operating problems occur everywhere. I will shut down my video to improve my connection. A priority for the next coming months is cost reduction and deleveraging. We are changing the focus of the company. At the moment that we are deploying projects and acquiring assets, we have a lot of CapEx. This is a period where we are now trying to reap the benefits of our CapEx, especially in Atlanta and Papa-Terra and also Manati that is ramping up, as we said before. We reached 94 barrels a day as an average production in the past week. This efficiency search is now being reflected in our lifting cost. We had $20 per barrel with the chartering at Atlanta. If we look at the production levels, it is below $6 per barrel without considering the FPSO in that platform. In onshore, when we combine our production and upstream assets, the price per barrel is $35, very productive. This has to do with our efforts to reduce CapEx for the year. At the current oil prices, our CapEx is around $450 million a year, and this does not impact production in any way relevant. This higher efficiency will also support our deleveraging. Therefore, we believe that despite a Brent challenging scenario, we will have EBITDA below $30 per barrel. This is a great breakeven point. If we consider financial expenses with CapEx, our free cash flow generation occurs with oil prices at around $50 per barrel. That means that we are moving forward to deleverage further, and this will allow us to think about the new phase of the company. I would like to thank you all for your attention. Now I will open the floor for questions. Thank you. We will now initiate the Q&A session. In case you have a question, please click in the Q&A icon in the lower part of your screen and please type in your question. To ask live questions, just click in the same icon and type your name and company or use the raise hand button. For questions, you can use the Q&A feature or raise hand feature. Please wait while we collect your questions. Our first question is from Vicente Falanga from Verdisco BBI. Vicente, your microphone is already enabled. Good afternoon, D´ecio, Pizarro, and all of the Brava team. I have two questions. My first question is about the cash generation outlook for the second quarter. My second question is whether you could elaborate a bit more about the divestment of your assets in Bahia. What is the plan for the asset in terms of drilling, the field, and what does it take for you to unleash the gas production and whether you could also have strategic partnerships in your Bahia assets? Thank you. Thank you, Vicente. I would like to start by saying, as I was commenting earlier on, that we have cash generation. We branded around $50 per barrel considering financial expenses and CapEx. I think that once production increases in the next few weeks, we will be well positioned to improve our cash generation, not only for the next coming quarter, but also for the entire year. Now, in regard to the Bahia assets, we analyzed the results that we had in Bahia more recently, and we continue to improve our cost and efficiency in Bahia. Things are moving quite well. We also managed to increase production. Now we are working to sell our gas production that we have in Bahia. With that, we will have a double effect. We will increase revenue, and by the same time, we will dilute costs. We are also putting a lot of efforts to integrate the activities of the assets in Bahia. We have Manati. We have compression in Bahia with great possibilities, which is now running idle. I mean, at only 45%. We are discussing with the operator the way to use that facility. This will certainly increase our efficiency in terms of gas production in that territory in Bahia. We are also thinking about the future of Manati. Manati can be used to store gas in Bahia. We have the potential to leverage our asset in Bahia. We are also trying to work to reduce costs of our production in Bahia. In Bahia, more particularly, we continue to work to reduce costs even further. As I mentioned before, at the end of last year, we exchanged the OEM operator, and this has reflected in an improvement both in terms of costs and our operations. We also reduced headcount. We reduced the use of surface facilities, and we will continue to work to promote further reductions while, at the same time, we will enhance our gas production because we could add more sales once we enable that gas that is not being used or is idle. All of that will certainly allow us to make improvements in the free cash generation in Bahia. Thank you. Next question from Leonardo Marcondes, Bank of America. Go ahead, sir. Hi, good afternoon. Décio, Pedro, Pizarro, Boeri, and Travassos. Thank you for taking my questions. I have two questions. The first is regarding CapEx. During the presentation, you spoke a little about this, but I'd like to understand some points a little better. First, what was non-recurring in this quarter and should not be repeated in the coming quarters? Secondly, I'd like to understand this reduction of onshore rigs and how this can impact the expectation of CapEx and production vis-à-vis the certification. Thirdly, I'd like to understand what you're thinking about CapEx for 2025 as a closed year. I have another question for Travassos. I would like to hear from you, please. What are the main challenges and opportunities that you identified in Brava's assets? You've been with the company for just a little time, and I'd like to understand the priorities and plans for the offshore fields. That's what I have. Thank you very much. Thank you, Leonardo. I've been told that my internet, that my sound is dropping. I apologize. So I'll keep my camera off. As regards CapEx, we are completing a very CapEx-intensive phase at Atlanta. The completion of phase one of the full development, $1.3 billion. Now we only have to connect the last two wells in the next 45 days. With that, we no longer will need to make this major investment for the company. The company is also leaving behind a phase of major investments to improve the integrity of the Papa-Terra platform. This will change the level of offshore CapEx. We just need to drill four wells, two at Papa-Terra, two at Atlanta. This is also part of the FPSO, but we are addressing integrity. There is always a lot of work to be done in that regard, but much less. This reduction in the number of rigs will happen with very little impact on production. I'll ask Boeri to explain what his plans are in more detail for the onshore operation with this reduction in the number of rigs. Before that, I have to tell you that we are working with an expectation of $450 million of CapEx for the year. Boeri and then Travassos to address the question about offshore challenges and opportunities. Hi, Leonardo. To add to what Décio said about CapEx, about 50% in the first quarter was linked to the onshore operation. What we will not continue? We will reduce the number of rigs, as mentioned. A strong reduction in CapEx in this last part of 2025. Also in this steam generation project, we have executed about 75% of the CapEx for this project. What's remaining is 25% of the total CapEx for the project. Speaking about onshore production and how we will reduce the impact of having fewer rigs, like I mentioned, we have a possibility of monetizing gas in Bahia. This is an opportunity that we have in our hands. We are working also on a project to increase gas production in Rio Grande do Norte. We have a plan to increase gas production, and this is evolving quite well. There are some opportunities at Macau. From the top of my head, I remember we doubled the production of gas in Canto do Amaro and Alto do Rodrigues, and all of that continues to evolve. Also, our compressors at the wellhead reduce pressure and have an increased production of gas in the Rio Grande do Norte fields. This month, at the end of May, we will be finalizing the revamping of the Canto do Amaro compression plant. Over there, we have a compressor plant that will allow us to increase gas and oil production because these fields are being explored with gas lift. These compressors are not yet working with the expected efficiency, but like I said, we will be finalizing this by the end of the month. All of these actions put together, plus some improvement activities in Canto do Amaro, will allow us to offset the reduction of production due to fewer drilling rigs from now to year end. We expect to maintain onshore production at the current levels. Let me add, before I give the floor to Travassos, Leonardo, if we look at the first quarter, we had $150 million of CapEx. Of these $150 million, more than $40 million are earmarked to Atlanta. In a way, this will no longer be recurring when we complete the connection of the last two wells. We have about $35 million for onshore drilling. As of Q3 of this year, we should no longer be drilling onshore in 2025. These two effects are the main effects that will allow us to normalize the CapEx profile at a much lower level than Q1. This does not happen fully in Q2, but we do observe a very relevant reduction in Q3 and Q4 of 2025. Travassos. Thank you, It is quite interesting the point that you mentioned because, you see, we continue to connect wells now getting to the second half of the year. Leonardo, thank you very much for your question because it gives me an opportunity to speak about the challenges I am seeing at Brava. Of course, the main challenge is having a capital structure that is streamlined, lean, working with efficiency, reducing the lifting cost. Overall, these are the challenges. Now, speaking about each one of the assets at different stages, when we look at Atlanta, we have efficiency, connection of the wells. We plan to top up the unit very soon. We have a current production of 43,000-44,000 barrels with a plant capacity of 50,000 barrels. We imagine that we can top up that unit. In parallel, we have a campaign to increase efficiency at Papa-Terra. For Papa-Terra, we had an important challenge. We had about 12,000 or 13,000 barrels daily. Now we are at around 20,000-21,000 barrels. For Papa-Terra, I understand your question. You want to know about the upsides and where we are going to focus our management. We have to pay the attention that this asset deserves. We achieved an efficiency of 93%. There were some operational threats to our efficiency, but we are addressing each and every one of them. We have these two assets at different stages and different challenges. We have Manati. We see opportunity at Manati. We are not the operators, but we believe that Brava has a lot to collaborate with that asset. We have the Peru asset with an excellent operating efficiency. We operate Peru at low cost and high efficiency. I think we can apply that to Manati as well and bring our experience to that asset, favoring Brava and our partners. Overall, these are the points and opportunities that I would like to highlight. Thank you very much for the question. Excellent. I thank you. Have a good day. Thank you, Leonardo. Next question from Gabriel Barra with Citi. Go ahead, Gabriel. Hi there. Thank you. Décio, Pizarro, and the whole Brava team. For a quick follow-up, I think that Atlanta, the start of Atlanta, has been very successful. I think that the next concerns we have, I'd like to hear from Travassos in his little time heading the offshore operation. I'd like to hear from him about the decline of production. It might be too early to speak about that, but perhaps he could share with us his first impressions about the behavior of the reservoir looking forward so we can understand a better production profile. That would be interesting. Second point about capital structure. Perhaps we'll have a different moment of oil price, a little more bearish than what we had in recent years. Pizarro mentioned investments and being more rational about investments. I'd like to hear from you about production peak. Something around 100,000 barrels daily produced in two years. Are you maintaining this? Because I want to understand the recurring maintenance CapEx of the production if we have that level of production or if you could change your mindset depending on the oil price. So my question is, how sensitive are you to oil price to get to this level of production and investment? These are my two questions. Thank you. Thank you, Gabriel. Travassos will answer the first one. Thank you, Décio. Thank you, Gabriel, for the question. It's an excellent question. Actually, when we speak about decline, we talk about expectation. We're talking about estimates or estimates. We have to speak about a typical decline for a heavy oil reservoir. What do we expect in Atlanta? We're going to have a peak of production. Then we're going to have a more marked decline. Initially, this marked decline will be offset by the phase two of Atlanta, which is expected for the end of 2026. We are going to see another marked decline in the beginning, but with a very long tail of production. This is the expected behavior for the reservoir. In this start of production, we have seen results that are slightly better than what we estimated. We expected the decline curve will be like this. In the next three to four months, we might see a production decline, but that will pick up again as we deploy the projects. We will see a much more even behavior. That is the typical behavior of a heavy oil reservoir as what we have in Atlanta. For capital structure, that will be answered by Pizarro. It is Décio speaking. For capital structure, we are getting close to 100,000 barrels daily in the CapEx level. We have to maintain this level of production in the coming years. It is lower than what we have executed recently. We do not have any major project like Atlanta to implement. This is what we are working with. Pizarro, could you give us more color regarding that? Thank you, Décio. Gabriel, in our business plan, we have the drilling of four wells, two at Atlanta, two at Papa-Terra. The breakeven rent for this project is very low, very low, below $25,000-$27,000 because this whole production will be incremented practically without added costs and diluting fixed operational costs for FPSO Atlanta and after two units at Papa-Terra. The probability of maintaining these four wells in our business plan for 2025-2026 is very, very high. With these four wells alone, we will more than offset the expected production decline in the whole onshore and offshore segments until these wells come online at the end of 2026. We continue to maintain a production level above 100,000-105,000 barrels average production for 2027 with these four wells alone. The part which is much more flexible is the onshore part. That is why we demobilize a good deal of the rigs and postpone some of the investments, as Boeri mentioned. These are also profitable projects, even with the current Brent oil price of $60. However, with the aim of maximizing free cash generation, we are postponing the campaign. On the other hand, we can resume these campaigns if the Brent oil prices improve in the coming quarters. What is fundamental in my answer is that the business plan is maintained with these four wells. Obviously, if we have even more challenging Brent scenarios, we can be led to reassess these four wells, not because of profitability, but to maximize cash flow. For now, the project is maintained. Thank you very much. We would need a very radical scenario, right? Because the breakeven price is low and we do not need to invest in the platforms. Thank you. Thank you for the questions. Our next question is from Bruno Montanari from Morgan Stanley Sir, your microphone is unmuted. Good afternoon, and thank you for taking my questions. I have two questions. Revisiting the portfolio recycling issue at the moment, if we see a recovery in oil prices and eventually demand for onshore assets, and if they go up in terms of pricing, do you think that the company would revisit your partial or full exit of offshore? Maybe Brava would allocate more in onshore where returns seem to be more attractive? My second question is whether you could give us an update on the synergies of your businesses, where we stand, what still has to be captured. On a third question, what do you see in terms of EPS and receivables? What will be the timeline of that money in terms of being converted into cash? Thank you, Bruno. In regards to the recycling of our portfolio, what we think about doing is to focus on assets with higher production. We already sold a series of small assets in Rio Grande do Norte, in the northeast of Brazil. We are also reevaluating other small assets of our portfolio. Other sales or other divestments of higher assets are not on our radar. We are just approving the thesis where we want to reduce CapEx in onshore once prices are lower. Maybe we will restart drilling when prices go up. Onshore divestment is not on our radar. In regards to synergies, I would like Pizarro to answer that part of your question. Thank you, Décio. Thank you, Bruno, for your questions. Even now, connecting with the portfolio recycling, both parts of the synergies are related to this combined operation of onshore and offshore, both in tax terms, also in terms of the reduction in corporate costs and more competitive costs for debt issuance. All of that is part of that operating synergy, that synergy between portfolios, onshore and offshore. This allows us to have about 35,000 barrels in onshore and approximately 50,000-60,000 potential barrels coming from offshore. In total, then we would have 95,000 barrels as production potential that the company can use combined. We already took the necessary measures so that we would have $800 million to farm the synergies, very much related to debt and cash between different subsidiaries. Now, the increase coming from the incorporation of Enauta Energia into the old 3R group generated BRL 2 billion of assets. That can also be used to reduce taxes throughout the coming years. We also had operating synergies, and Travassos is working diligently with the procurement area to reduce the base, helicopters, support vessels, both for emergency plans as well as the operation itself. All of that is part of that $800 million that I mentioned in terms of activities already mapped out, things that we have already deployed just to farm all of the synergies or to get them in place. In terms of EPSEN, we are working to find alternatives. We already received some proposals from some players that are interested both in full or in part. They would like to maybe we could replace the company's position because it's a creditor. The IP company is not usually in that position, but we want to give away that position and give it to a third party. In our view, we are making some intelligent moves to share risks and returns of our current position, meaning that the part that would mean a higher risk to a partner, we do not intend to sell. The partial that for third parties represents lower risk, this is the part that we will probably give away. This is the structure that we have in mind for the coming months. This should still occur in 2025 and probably in the third quarter, towards the end of the third quarter. That is why we are working hard to get that monetized as soon as possible. Thank you, Bruno. Our next question is from Luiz Carvalho with BTG Pactual. Your microphone is already unmuted. Can you hear me? Yes, we can. Good afternoon, and thank you for the opportunity to ask a question. I would like to revisit your last topic, and I think the main issue is how fast can the company deploy this deleveraging process? We understand that it is dependent on oil prices, but somehow you are putting together a hedge structure. You already mentioned a few points like SG&A, the review of the CapEx plan, EPSEN. What else is in the radar that could be in the company's hands that could help you expedite things and generate more equity value throughout the process? I mean, BGN and synergies, you talked about the merger of the companies. I do not know, maybe divestments of part of your assets, maybe it would make sense to reduce your stake in Atlanta or maybe at some point in the future. I just want to get some more substance to the items so that I could have better visibility about this deleveraging process. My second question, probably addressed to Travassos, you already talked a little bit about your view for production going forward. In the short run, you talked about stabilization of Atlanta, maybe at a lower level due to normal decline. What is your stabilized production for the year? I know you already have a hedge structure, but what would be that cash generation? This is in line with my first question, considering a more challenging oil scenario. Luiz, we are not thinking about selling any assets. I'll ask Pizarro to answer your question about hedge and the other initiatives we have in place to deleverage. I'll turn to Travassos. Thank you, Décio. Luiz, if we look at the orders placed at AGD for the first quarter of 2025, the request was to have a maximum limit to four times in the second quarter, 3.75, third quarter, three and a half times, and fourth quarter, it will be normalized. Why do I say that? Precisely because the fourth quarter of 2024, where we had no production coming from Atlanta and Papa-Terra, lingers until the third quarter. Since we usually look, I mean, if we were looking at next 12 months, even with current Brent prices, our leverage level will be much lower. This indeed happens, especially deleveraging. It occurs from the third to the fourth quarter. I would like to remind you that even in the second quarter, even though we put in place CapEx reduction, M&A, and OPEX, we will still be connecting the two wells in Atlanta while at the same time we are demobilizing the onshore rigs. In fact, deleveraging starts to become clearer as of the third quarter. In the second quarter, we do not expect reduction unless we can implement partial monetization, probably, as I said before, of EPSEN receivables in the second quarter. This reduction after these receivables come through, I mean, it is not immediately implemented. There is no EBITDA loss linked to that. This is an important aspect. Whenever we talk about sales of assets or divestment, to Décio's point, we have to bear in mind that we are proportionally taking off some of the EBITDA from that asset. It does not mean that we will add value in terms of deleveraging. Atlanta is a very good example. We are in a production profile that is quite high. We have the expectation of a relevant EBITDA going forward linked to Atlanta and a partial sale but probably not add value with the purpose of deleveraging. Therefore, we are mapping out everything we can do. We are implementing some measures. One of these measures is hedging. We already hedged 35,000 barrels, as I said, and it will be even more in the second quarter. In the third quarter, where leverage is already slightly down, but it's still over two and a half times. We also hedged that, particularly because we want to remove the variable from the scenario. Looking at Brent prices, this will have an impact on the second and third quarter of the company. Now, going to the fourth quarter, once we clean up the fourth quarter of 2024, the leverage of the company will, of course, it will depend on Brent prices, but it should be very close, ranging between 1.7-2.3, meaning a very healthy leverage for a company that just concluded a project in Atlanta involving billions of dollars. We should bear in mind that the company has been investing a lot, and now we are prepared with a much higher production profile. Looking at the last 12 months, I mean, it is jeopardized by the reasons mentioned before. Next 12 months, probably our deleveraging will be more advanced when compared to other companies in Brazil. Travassos. Thank you, Décio. Now, still talking about the future or the coming months, being careful enough with the type of information and what this could mean, it's easy to conclude because when we look at Atlanta, we see excellent efficiency for a unit that just started up. Today, production is between 42,000-44,000 barrels, and there is the expectation of connecting two other wells by the end of June. These wells were wells that used to produce before during Petrobras' management, I mean, around 6,000 barrels. Now we see good efficiency with PC10. Peruá is also posting constant production. There was just a natural expected decline, no surprises there. We also have the return of Manati. At a given point, we will possibly reach 100,000 barrels with a good level of efficiency, the efficiency level we have today. This gives you an idea of our production level. As I was saying in the previous question, we expect some decline at a given moment, especially coming from Atlanta. We will recover that going forward with the drilling of the next, the two other wells. This is what we see in terms of production curve. It is very clear. Thank you very much. Just adding another comment, as Travassos was saying, we should go beyond 45,000 barrels. If we reach the maximum production level of the platform, the decline will start occurring once the two new wells are connected. This will happen maybe in the midst of 2026 and early 2027. We should resume our top production level. In this way, we ensure that the next four to five production years in Atlanta will have a production profile which is very high, allowing for a very competitive lifting cost, something ranging around maybe less than $10 or $11, as Décio mentioned at the beginning, but at 30,000 barrels. Even then, we will be at around $13-$14, including chartering. Everything is fully addressed to maintain the main asset of the company that accounts for 40%-50%-55% of the whole. Our efficiency profile will remain very high. This favors EBITDA per barrel. This reduces breakeven to generate EBITDA, and it makes us very comfortable going forward, precisely due to all of the investments that we had in Atlanta in the past. Thank you. Very clear. Next question from Vasco Selos with the EBS. Go ahead, sir. Hello, Décio and all of the officers. I'd like to go back to CapEx and breakeven. First question, perhaps to Pizarro. It is clear the movement of the company of trying to reduce CapEx throughout this year, working with $450 million compared to those $560 million you had mentioned before. Could you comment on how the 2025 CapEx relates to the 2026 CapEx? Will there be an increase in 2026? To offset that, I understand that the four wells offshore offset the onshore. What about the onshore assets, their decline or even integrity, if you want to resume investing in that production in the future? The second question to Décio, you talked about a breakeven of $50 per barrel. We were trying to come to terms with these $50, looking at a normalized production scenario of 90,000 barrels. And we have gotten to a value closer to 60 for 2025. So lifting costs in Q1 was 20, but with the high production, it should drop to around 15 if we add another fiber royalties plus SG&A, interest rates, leasing, and so on and so forth. It would be close to 60. Maybe a question to Pizarro. Could you help us understand this calculation in more detail? That would be very helpful. Thank you. Pizarro, over to you. All right. Let's start. Like I said, we had $150 million CapEx in Q1. We expect to have $450 million for the full 2025. However, in Q2, with the CapEx still a little heavy given the connection of the last wells at Atlanta. Q2 will probably show reduction vis-à-vis Q1. Q3, Q4, lower than what we had in Q2 and Q1. With that, we will total about $450 million. Now, if we look at the full year, we probably will have had about $80 million still linked to the connection of wells at Atlanta. When we look at 2026, we will start 2026 with a normalized onshore CapEx, a lower level of CapEx. As we have been saying, we should have those investments related to the four new wells, two at Atlanta, two at Papa-Terra. The total CapEx for 2026, we are still working on this, but it should be around that order of magnitude or perhaps a little higher. It all depends on the Brent oil price. As we always say, we have a lot of flexibility to dose the pace and our ability to expedite or step on the brakes of projects, particularly regarding new wells. As for the decline, Boeri has mentioned this, and he can add his comments. The expectation is that these steam generators, when they become operational, coupled with eight workover rigs, will allow us to maintain production with a certain level of stability. There might be some decline, some production increment over the next few months, but the expectation, and that is Boeri's attempt to not allow a decline, offsetting this decline with these two activities in addition to pilot projects that do not have a scale effect in the short term, but that can have a greater effect when these projects are implemented at a greater scale. That would be more towards the end of 2026- 2027. As for the breakeven, when we look at the past, Taso asked the question, right? Taso, when we look at the past, we end up being contaminated by non-recurring events such as a lifting cost. As you mentioned, the expectation is that the lifting cost will drop. Our lifting cost, when we say that it should be $16-$17, that includes chartering. When we look at the discount vis-à-vis the Brent, as Pedro mentioned, there were moments when we lifted through different situations. We had more discounts in Papa-Terra and Atlanta more than the company expected. When we look at the fixed cost dilution, G&A, for example, if we consider 95,000 barrels, our expectation is that the breakeven to generate EBITDA will be at around $30-$32. G&A per barrel is between $3 and $4. Royalties is proportional to the Brent. If we're simulating a Brent oil price at $30 to calculate a breakeven to generate EBITDA, we're talking about $3 of royalties, and so on and so forth. The discount vis-à-vis the Brent, considering that practically 90% of our production is oil with a high production from Atlanta that momentarily had a higher discount vis-à-vis the Brent, but this tends to be reduced, we'll get to this level of $30-$32 to generate EBITDA. To pay interest on the debt minus financial expenses linked to investment of the cash and receivables from Enauta, we get to a level close to $37-$38, depending on the quarter. When we add to that CapEx to be executed in 2025, that can add between $12 and $15, depending on the quarter. That would be the level between $50-$53 per barrel to start generating free cash after CapEx and after the financial results. This is kind of the order of magnitude of the numbers that we envision looking forward and not looking back, given the non-recurring events that I mentioned. I'd like to add something regarding onshore. It is important to remember the change in strategy that we are adopting. We are not adopting a strategy which is very much intensive in well drilling because that entails a high cost in water treatment. We are betting now on steam injection to increase production. Also in the pilot projects of nitrogen injection that we started and polymer injection that can give us good results with a much lower CapEx level. The wells have been drilled already. That is the strategy we will be testing in the coming months, which will have a big impact on the company's total CapEx for onshore. As for integrity, we have almost two years operating in the main cluster. We took over Porteguara Cluster, and we did a lot of work over the last two years. The level of integrity we had when we took over the assets is totally different now, both in Rio Grande do Norte and in Bahia. Also, as Pedro mentioned regarding Papa-Terra, it is super clear. Thank you very much. Next question from Conrado Wegener with Bangusa. Mr. Wegener, go ahead. Your mic is enabled. Hello. Good afternoon. I think that you've talked about many important points. You mentioned your future plans for Manati with a storage structure. Is there any other or is the operator in agreement to continue to participate in the field with this new role? Now that we are starting to have discussions about transportation tariff reviews, is it essential that the storage transportation tariff be lower than the regular one to make the project feasible, or is it just a matter of improving return? Thank you, Conrado. Pedro, you can answer that question, please. Good afternoon, Conrado, and thank you for the question. For Manati, we are working on a couple of fronts. The first work front has to do with our onshore production and some topics that we have already addressed in this call. Now we have a gas processing plant at Manati, which is very good with the capacity of processing 6 million cubic meters daily of gas, with a lot of proximity and existing connections with some of our gas-producing regions in Bahia. We are trying to have gas processing of Brava's portion in our part in the construction with Manati, using our idle capacity. In this way, we can broaden the sale of gas, which is restricted today given bottlenecks related to the state's processing capability. The second big initiative involves a reduction and a review of operating costs associated with Manati, either associated with the compression plant of the unit or associated to the operation of the offshore platform. In both cases, we already have a huge value benefit for Manati. The third front is when we think about Manati in the future. For a while now, there have been studies underway and with a possible implementation of some pilot projects so that we can take advantage of the existing structure at Manati as a unit to store gas. We currently have an in-depth knowledge of the reservoir. We have a big infrastructure at the platform or onshore, such as the compression units, and a direct connection to a very diverse and broad gas market nationwide, also with proximity to some with TAG. With this, Brava has been leading a subcommittee that is making progress in the possible implementation of this project. We are at an advanced stage. I cannot give you more on that yet. I cannot make promises regarding the timeline. To your question about transportation tariff review, in our opinion, economically speaking, the Manati storage project, if a number of technical requirements are met, is independent of this tariff discussion. The economic benefit for us to have such a broad structure, partially idle, with the reservoir being able to operate in that way, this will allow the economics of the project to be happening regardless of the tariff discussion, although this is quite important for the economic result of this initiative. Thank you, Conrado, for the question. Thank you very much. The next question is from Regis Cardozo with XP Inc. You may proceed, sir. Your microphone is unmuted. Good afternoon, and thank you for taking my questions. I think most of the questions have been answered. I just have some quick follow-ups. When you talked about $50 per barrel as a breakeven, I just want to make sure that this does not consider the effect of all of the hedges that have been contracted for third and fourth quarters. My other question is when you talked about lifting cost in the mid and long range, could you please tell me what, in your view, will be a normalized lifting cost of your main assets, Papa-Terra in particular, and Parque das Conchas and onshore? Also, if you can give me an update in your timeline, what is the schedule for the integrated campaign for Atlanta and Papa-Terra and all along the lines of maximizing cash flow, whether you have some flexibility or you might make some choices where you would preserve some part of the upside and you would maximize cash flow in the short term? I do not know whether you would put more priority in Papa-Terra and Atlanta with the decline. I just want to get an idea of your timeline. Thank you. Thank you, Regis. We already scheduled that campaign for four wells by the end of the year. We will start drilling after the connections. We will start with Papa-Terra and then Atlanta. I think Tabasco and Pizarro already gave you more details. These are wells with a very low breakeven because, as I said before, CapEx consists of the wells and the connections. Everything is already hired, and it is within our CapEx parameters. Breakeven, I think Pizarro already talked about it. We do not have any further considerations to make. In regards to lifting cost, we are working diligently to reduce onshore lifting costs. If it works, if the nitrogen pilots work, we will be able to have an additional reduction of lifting costs. Atlanta and Papa-Terra, what we have to do, I mean, the cost is given for Atlanta. The focus now is increased production and reduced costs with additional production. As for Papa-Terra, the focus is on efficiency. We are working to increase operating efficiency at Papa-Terra. I will turn to Travassos to see if he has any additional comments. Thank you. Maybe I can start with Papa-Terra, which is the offshore we have and certainly the one with the highest lifting cost. At the same time, it is where we have more opportunities. In Papa-Terra, we are still in the process of recovering, I mean, integrity. We still have some rented equipment on board, so we are now recovering the equipment. We are now getting rid of the rental of this equipment. We see great opportunities to reduce costs of our maintenance contracts. This is something that is underway. It is in progress. Therefore, this brings about good opportunities for further reductions. These are just some upsides in terms of lifting cost reduction. You talked about the next wells. We have an integrated rig campaign with two Papa-Terra wells and two wells in Atlanta. There is flexibility in terms of mixing and mingling the wells the way we seem more fit. We have flexibility there in terms of contracts. 80% of the contracts are already signed. This is a campaign that is firm. I mean, the rig has been hired with a deadline for the end of 2026. As you pointed out, we have a low CapEx associated to the value of oil coming from these operations. Basically, that's it. Any more additional comments? I would just like to mention two important aspects. We could look at absolute OPEX for the first quarter of 2025, both for Papa-Terra and Atlanta. We could also grow production and then evaluate things with higher production when compared to that of the first quarter. 35% approximately of additional production in one asset and 40-45% of increased production in the other asset once you compare April vis-à-vis the first quarter. However, costs, particularly in Papa-Terra, I mean, there are still some non-recurring costs in the first quarter. Once we increment production, we should also have a reduction in absolute values, both in terms of non-recurring costs in the first quarter that I mentioned, still linked to the recovery of non-recurring integrity from now on, and also reduction of OPEX costs mentioned by Travassos. We have an important contract in Papa-Terra where we could also have some optimizations that will lead us to reduce the absolute value of the vessel, optimizing costs in Papa-Terra around $22-$24 per barrel. In Atlanta, as we said before, including chartering, in the range of $10-$12 per barrel. Without chartering, that number will fall to $6 per barrel. This is the level that we should reach with offshore. Now, looking at onshore, we already did some important work in Bahia. When we think that the cost in Bahia is around $14 of lifting cost, we are dividing the denominator, not considering the reinjected gas. Now, Boeri and Pedro are working to monetize this gas that is being reinjected, meaning that we increase production with the same cost. We tend to reduce lifting costs in Bahia as well due to that effect of sales of gas that is being reinjected. This is not considered in the lifting cost calculation, which is a very conservative calculation because we are considering the gas utilized for sale or energy sale. These are my comments on lifting costs. I think with that, we conclude the Q&A session. One more reason for us to maintain the assets in Bahia. I do apologize for my poor connection. Thank you so much. I hope to see you soon. Energia's Conference Call is now concluded. Thank you for joining us, and we wish you a very good day.