Good morning, everyone, and thank you for waiting. My name is Marília. I'm Investor Relations Director at the company. We'll be starting our results call for the second quarter of 2026. The presentation will be conducted by our CEO, José Firmo, and our CFO, Rafael, followed by a Q&A session with our executives. This call is being broadcast exclusively online and will be made available on our company's investor relations website. Please submit your questions through the Q&A icon so I can read them at the end of the presentation. Microphones will not be open. Before we continue, I just would like to clarify that all the statements presented during this call related to business perspectives of the company, projections, operational and financial goals are based in beliefs and premises from the executives at PetroReconcavo, containing information that is currently available for the company. Future considerations are not a guarantee of performance and are involved in risks. I'll hand the floor to Firmo we can get started. Thank you, Marília, good morning. Thank you for joining us for our presentation of the results of the second quarter of 2026. The period was marked by the continuation of the geopolitical instability that began in the first quarter, with direct repercussions on the international oil market, including volatility in oil prices significant fluctuations in the financial markets. Throughout the quarter, our strategy of cost efficiency, capital allocation, and marketing enabled us to capitalize on the upside of this volatile environment, resulting in improved financial performance. Net revenue totaled BRL 808 million, an 18% increase compared to the previous quarter, stable compared to the same period of last year, driven primarily by the rise in Brent prices improved in oil sales contracts at the Potiguar Asset, as we announced on May 7th of this year. EBITDA totaled BRL 396 million, a 28% increase compared to the previous quarter, reflecting the company's ability to capitalize on the rise in oil prices, as well as its focus on cost efficiency. Year-over-year, there was a 6% increase compared to the second quarter of 2025. Net income was BRL 203 million, a 64% increase compared to the first quarter of 2026, 15% lower than the same period last year, significantly influenced by the effects related to mark-to-market valuation of financial hedging instruments swaps associated with the company's debt. Regarding that, we ended the period with a net debt of BRL 1.4 billion, equivalent to a leverage ratio of 1.01x net debt over EBITDA. On the operational front, average production was 24,100 bbl of oil equivalent per day, down 1% from the previous quarter 12% lower than the same period of 2025, primarily driven by a difference at Tiê, which in the second quarter of 2025, was at its peak production following a drilling campaign and produced approximately 2,200 bbl additional average BOED at that time. Accordingly, we reaffirm our commitment to creating value for our shareholders, we are announcing the distribution of BRL 100 million in dividends, equivalent to BRL 0.34 per share. I also would like to highlight that as part of our commitment to ethics and integrity, on July 1, PetroReconcavo received the Pró-Ética Company 2025/2026 recognition, an initiative of the Office of the Comptroller General, the Brazilian CGU, carried out in partnership with the ETHOS Institute. The seal recognizes Brazilian companies that voluntarily undergo an assessment of their integrity structures, promoting a corporate environment characterized by integrity, ethics, and transparency. Finally, in addition to the addenda signed with Brava in April, which I mentioned earlier, we signed a new contract for the sale of crude oil from Rio Grande do Norte, which will be in effect from October 1, 2026, through December 31, 2030. After the close of our production fields in the Potiguar Asset happened in December 2023, we decided to implement our operational resilience strategy announced to the market in March 2024. The signing of this long-term oil offtake agreement with Brava marks the achievement of one of the most important objectives in this strategy. This new agreement signed with Brava represents much more than a simple marketing agreement. It solidifies a long-term partnership based on predictability, operational efficiency, and value creation for both parties. Now, we have a five-year contractual horizon providing greater visibility for the company's operational and commercial planning. In a capital-intensity industry like ours, predictability is an extremely valuable asset. It allows us to plan investments, optimize operations, and make long-term decisions with a greater degree of confidence. In addition to predictability, the contract creates economic incentives aligned with increased efficiency throughout its supply chain. The more efficient we are in delivering the volumes produced, the greater our ability to capture value will be. This marks a milestone in the evolution of Brazilian onshore sector, which is beginning to build an integrated supply chain that rewards operational efficiency, delivery reliability, and logistical excellence. Another aspect worth highlighting is the security of market access provided by maintaining our commercial relationship with Brava. The refinery remains an extremely efficient solution for monetizing the oil produced in Rio Grande do Norte, offering proximity, operational predictability, and high reliability in the removal of produced volumes. When completely implemented, we'll have simultaneous access to local refining market, new domestic routes, and the international market. The diversification increases the business resilience, reduces operational risks, expands our ability to capitalize on market opportunities, and strengthens our competitive position for the coming years. The company's average production declined by 1% compared to the first quarter of last year, primarily due to lower production at Miranga and Tiê. As mentioned earlier, the second quarter was marked by a capital expenditure control strategy with a focus on cash preservation and disciplined capital allocation. In this context, we slowed down activities with a greater short-term impact on production, especially drilling, and focused our efforts in implementing the secondary recovery programs that have been under development since last year. It's worth noting that our initial goal this year was to reduce CapEx while keeping production levels relatively stable compared to 2025 average. However, the lower volume of well interventions and new drilling and a greater focus on injection is resulting on an average production for the half year that's approximately [86%] below expectations. This decision continues to be based on the strategy of balancing current production sustainability with the generation of reserves and value in assets that will be much more significant in the future. This slide help us understand an important part of our capital allocation strategy. Currently, seven of the company's 10 most important fields have new secondary recovery projects being implemented or under development, and we continue to expand this program across various assets in our portfolio. Looking at the average daily volume of water injected in the second quarter of 2026, it is possible to see the different stages of maturity of these programs. At the Tiê field, there was a 40% increase. Sabiá da Mata, the injected volume was 7x higher, and Sabiá Bicudo also increased volume of injected water by nearly 3x compared to the same period last year, reflecting the progress and maturation of these projects. If we include all the fields, including [Valo] and Remanso, with the more mature secondary recovery, our average volume of injected water has already achieved a higher level in the second quarter of 2026. From a technical standpoint, the main objective of water injection is to maintain reservoir pressure and promote a more efficient drainage of hydrocarbons. We were able to increase our recovery factor of reserves, extracting a larger portion of the oil originally contained in the reservoir. Consequently, we reduced the natural decline curve of the fields and extended their productive life. From an economic perspective, these projects also offer a significant appeal. Although they require substantial initial investments and have a longer maturation cycle, reservoir repressurization increases the efficiency and expected economic return of future workover and drilling campaigns, thereby strengthening the profitability of investments allocated to the development of company's reserves. In addition, water injection contributes to the addition of reserves and extension of the field's cycle. In practical terms, it's a tool that allows us to extract a materially greater volume of hydrocarbons from reservoirs over time, maximizing the economic value of the assets and sustaining their production for more years without any structural impact on the quality of the assets and improving our ability to grow in the future. I'll hand the floor to Rafael so the presentation can be concluded. Thank you, Firmo. Good morning. The second quarter CapEx reflects the strategy presented by Firmo in the previous slides. We ended the quarter with BRL 193 million in investments, a level that is in line with the plan established for 2026 and significantly lower than the levels observed throughout 2025. The reduction was concentrated primarily in investments for our reserve development, which totaled BRL 174 million for the quarter, about 40% below the figure for the same period last year. Due to the decision to slow down drilling activities to allow for the maturation of the water injection projects that have been implemented in recent months. As these projects promote reservoir repressurization and improve hydrocarbon drainage, we expect future drilling and workover campaigns to yield better productivity and economic return metrics. Even with the lower investment levels, the company's production remained stable when comparing the second to the first quarter of the year. We continue to execute important strategic initiatives. In the quarter, we carried out our first scheduled maintenance downtime at Guamaré UPGN since we began jointly managing the asset with Brava, and we were able to confirm that in practice, our joint efforts led to efficiency and cost gains during the shutdown or downtime. During the drilling front, we completed two new wells at the Potiguar Asset, one injection well, one production well. In workovers, we refined our process for selecting the best opportunities and monitoring post-intervention performance, prioritizing projects with greater operational efficiency and economic returns with promising initial results. On the facilities front, we continue to invest in projects focused on asset integrity and the expansion of water injection infrastructure, both in Rio Grande do Norte and Bahia. This quarter demonstrates our discipline in capital allocation. We reduced the pace of short-term investments, preserving cash and returns. We continue to direct resources toward structural projects. It is worth noting that water injection remains one of the company's top capital allocation priorities. For 2026, we estimate to invest approximately 17% of the CapEx in projects related to the implementation or expansion of water injection systems, reinforcing our commitment to initiatives that increase the recovery factor of our reserves and sustain long-term value creation. Turning now to revenue, we had a very positive quarter, with net revenue growing 18% from BRL 684 million in the first quarter to BRL 808 million in the second quarter. The main driver was the significant improvement in the pricing environment. Between quarters, we observed a sharp rise in international oil benchmarks. On average, ICE Brent and Dated Brent, to which we are exposed, rose by approximately 25%. An important point is that despite the existence of hedge contracts, we were able to capture a large portion of this positive movement. Our average realized price by BOE increased by 19%, capturing a significant portion of the rise during the period, going from $60.10 in the first quarter of 2026 to $71.50 per BOE in the second quarter of 2026. In addition to a rise in Brent prices, the improvement in revenue was also driven by the addenda agreed upon with Brava and implemented starting in April. This addenda led to a reduction of approximately 40% in the average fixed discount applied to oil sales contracts in Rio Grande do Norte, in addition to improvements in the variable price adjustments mechanisms. The effects of this combination of a stronger Brent price and improved commercial conditions are evident in oil revenue, which grew from BRL 442 million in the first quarter to BRL 594 million in the second quarter. A rise of approximately 34%, more than offsetting the rise in hedge losses and a slight decline in production volumes. On the gas side, it is important to highlight the 10% increase in the average realized price, which reached $10.26 per MMBtu, equivalent to approximately $62 per barrel of oil equivalent. Despite the improvement in the quarter, the average price was impacted by the decline in sales of natural gas liquids due to [NGL] plant Guamaré downtime, and the price of processed natural gas has not yet fully reflected the recent rise in Brent prices due to the contractual pricing methodology, which provides for quarterly adjustments. The last adjustment made in May was based on the average prices observed between January and March 2026, and the next adjustments scheduled for August will incorporate the average prices observed between April and June 2026, reinforcing expectations of greater value capture over the coming months. Here, we see our oil hedge position and its impact on the company's financial results for the quarter. For 2026, approximately 65% of our 1P oil production is hedged. For 2027, the figure drops to 37%, and in 2028 to 9%, which ensures cash flow predictability while allowing us to capture upside potential from positive movements in Brent prices, as shown in the previous slide. With regard to hedge accounting, the settlement of NDF contracts in the second quarter of 2026 resulted in a negative impact of BRL 89 million on revenue. In addition, the mark-to-market of the portion of these contracts still outstanding is recorded in shareholders' company's equity, affecting the company's results only as the contracts are settled in the future. Transactions conducted via zero cost collar are not considered hedge accounting, and therefore impacted the quarter's financial results, both through the installments already settled in the second quarter in the amount of BRL 50 million and through the mark-to-market of future contracts, the accounting effect of which is also recorded in the period's financial results. Finally, it is worth noting that no new hedge positions were entered during the second quarter of 2026. Total costs and expenses rose 10% in a quarter due to an extraordinary increase in gas purchases, which rose from BRL 5 million in the previous quarter to BRL 44 million this quarter. This increase is directly related to the scheduled downtime at Guamaré UPGN in June, when the company had to purchase gas from third parties to ensure supply under firm demand contracts. Royalties, on the other hand, fell from BRL 60 million to BRL 56 million due to the ANP's recognition of credits related to prior periods. I believe, however, that the main highlight on this slide is the continued trend of efficiency gains that the company has been achieving in its core business. The second quarter marks the fifth consecutive quarter of reductions in operational and administrative costs and expenses, which showed BRL 285 million compared to BRL 293 million in the first quarter of 2026, and BRL 333 million in the second quarter of 2025. The sequential reductions demonstrate that efficiency initiatives implemented over the past few years continue to yield consistent results. We observed a significant reduction across several lines. Midstream costs decreased from BRL 54 million to BRL 52 million, reflecting lower expenses related to processing, distribution, and transportation. General and administrative expenses fell significantly from BRL 57 million to BRL 47 million, driven primarily by lower personnel and consulting costs. Total lifting costs increased by 2%, rising from BRL 182 million to BRL 186 million. On a per unit basis, the lifting cost per barrel increased from $15.82 to $16.8 per BOE, reflecting primarily the appreciation of the BRL against the dollar and lower cost dilution resulting from reduced production. The company continues to proactively advance in its structural agenda for improving efficiency, but we know that we must continue to take action to strengthen our ability to expand margins and protect cash flow under various price and production scenarios. Turning to EBITDA, we can clearly see how the combination of improved pricing and operational discipline translated into growing results. EBITDA rose from BRL 310 million in the first quarter to BRL 396 million in the second quarter, a 28% increase in rise with the Dated Brent prices during the period. The main factor behind this result was the growth in net revenue. As discussed earlier, even with a production stable and largely hedged, we were able to capture a large portion of the rising Brent prices, further aided by the improvements in the baskets of derivatives and commercial terms resulting from the content amendments at the Potiguar Asset. On the cost side, the main negative impact came from an extraordinary increase of BRL 38 million in gas purchases during the downtime at Guamaré UPGN, as previously mentioned. Despite this, we managed to expand the EBITDA margin from 45% to 49% in the second quarter. The almost four percentage points increase demonstrates the company's ability to translate a more favorable pricing environment into additional earnings and cash flow. Looking at netback, the results are also quite robust. During the quarters, taking into account the product mix, commercial discounts, and NDF hedges, we achieved net revenue per revenue of $71.50 per BOE. The break-even cash cost totaled $30.85 per barrel, generating a positive margin of approximately $40.41 per barrel. In this slide, we highlight the company's financial strength and low level of leverage. We ended the quarter with a cash position of BRL 1.62 billion, slightly below the balance recorded at the end of the first quarter. This performance was supported by strong operating cash flow, which totaled BRL 252 million for the quarter, highlighting the business' recurring ability to generate cash. From a debt perspective, we continue to maintain a comfortable structure. Leverage ended the quarter 1.01x net debt to EBITDA, remaining at a low and controlled level. The average cost of debt in U.S. dollars remained around 6.12% per year with a duration of 3.7 years, which ensures financial predictability and flexibility to navigate different market scenarios. This combination of consistent cash generation, low leverage, and a long-term, low-cost debt profile reinforce our ability to finance growth with capital discipline and sustain recurrent returns to shareholders in a responsible manner. Now on cash flow. This was yet another quarter that underscores the resilience of our business model and our ability to convert operating results into cash for shareholders. At first glance, reported free cash flow showed a slight decrease, falling from BRL 80 million in the first quarter to BRL 74 million in the second quarter of 2026. This comparison must be analyzed in light of seasonality of the company's interest payments. In the second quarter, we had a net cash outflow of approximately BRL 72 million related to interest and swaps on the debentures. While in the first quarter, this effect amounted only to BRL 15 million. This is a financial flow with seasonal pattern that is unrelated to the operational performance of the assets, nor the business cash-generating capacity. When we isolate this effect, the trend becomes quite clear. Adjusted free cash flow has been growing consistently over the past few quarters, rising from BRL 38 million in the third quarter of 2025 to BRL 146 million in the second quarter of 2026. This evolution reflects a combination of improved realized prices, disciplined capital allocation, and ongoing reduction in operating and administrative costs and expenses that we presented earlier. The company's operating cash flow continues to improve and has reached its highest level in recent quarters, which has allowed us to announce yet another JCP distribution in the amount of BRL 100 million to be paid in August, in addition to the BRL 100 million distributed in May and the BRL 100 million in dividends to be paid in December, reinforcing PetroReconcavo's commitment to creating value for our shareholders. With that, I will hand the floor back to Firmo. Thank you, Rafael. In conclusion, I just would like to highlight the publication of our fifth sustainability report, consolidating the main advancements in the project in ESG in the past year. We have impacted more than 21,000 people through our social projects. We have expanded the participation of women in leadership positions and conducted more than a billion purchases from local suppliers. We have also advanced in training women for working in the energy sector and strengthening our integrity culture with a new code of ethics, and we continue to invest in the communities where we operate. Our educational projects have benefited more than 12,000 students, and we celebrate the recognition from Mata de São João in Pojuca municipalities, reaching the first and second place at a rate for children learning how to read and write. In the integrity agenda, we have been acknowledged as a Pró-Ética Company, reinforcing our leadership in governance and integrity. We are the only company in the state of Bahia and the only company in the oil and gas sector from the Northeast recognized in this edition. This only reinforces that our value generation goes beyond operational and financial indicators. Our commitment is to continue to develop a sustainable and efficient business that is capable to generate long-lasting benefits to all stakeholders. Now I'll hand the floor back to Marília so we can start our Q&A session. Thank you, Firmo. Thank you, Rafael. Our first question is from Bruno, from Morgan Stanley. Production is about 9% below the average of 2025. However, the initial expectation was to have a production relatively stable year-over-year. How do you see the dynamics for the second half of the year? Are you still comfortable with this perspective? And what would be the main drivers for the evolution of production till the end of the year? Thank you for your question. Those were the main drivers for that. Firmo mentioned in his presentation the peak of production we had in Tiê after the new drillings, and the average production was lower in the first half of the year. We also had, from the projection in productions, there was a reduction in our drilling schedule. We drilled fewer wells, and from the wells we did drill, two were injection wells. And of course, the recomposition of production was lower in the period. And we also have production uptime that was impacted, especially in the last month, in the month of July, with the downtime in our gas plants, so we could perform scheduled maintenance, and we also have the Guamaré downtime, some major events that led to these non-recurrent downtimes. Looking ahead, our perspective is to reach stability. That's what we have been working for, similar to what we do in the first half of the year, with some positive trends, especially when it comes to injection. Tiê has clearly demonstrated a response to the project we started last year. As mentioned previously, we are injecting volumes that are above the production volumes in both formations we produce, and that is resulting in an increase in production that we are demonstrating every month in the Tiê field. Other investments in water injection in other fields that will certainly help us and keep our stability. Besides other efforts that are connected to cost efficiency. We're searching for production efficiencies as well to reduce unscheduled downtimes, to keep stability, and if possible, even increase production. Just adding to that, when we made the decision mid-last year, it was a strategic decision to redesign the management efforts for subsurface. We are now focusing our strategy post low-hanging fruits from the asset acquisitions, where we grew production a lot, but of course, also grew the short-term drop. This was quite a conscious decision we took assessing the company's portfolio. This year the decision was, let's restrict CapEx and focus our CapEx mostly in the secondary recovery projects. The expectation is to maintain average production year-over-year. That was the expectation. It was not possible. We clearly saw that the first half of the year was quite challenging, and we have made adjustments, not only in the order of activities, but also in our production perspectives. Our perspective is to keep stable productions from now until the end of the year with the acceleration of the projects, understanding what is the activity perspective we might have and production for last year. Overall, that is the effect from the CapEx reduction decision, but obviously, we still have a lot of work to do to determine the expectations for next year. For this year, our expectation is to remain at the same level of CapEx we have today with a production activity at the same level as well. Eventually, July was below expectation, of course, we want to produce above the 24,000 BOE a day in the next months. Our second question is from Yuri Pereira from Santander. In the quarter you converted six wells, two in each field. You recovered the injector in Miranga, recovered the integrity of injectors in Remanso, and started a pilot for polymers in Água Grande in Tietê. This is a more intense repressurization agenda that the market is pricing. There was a growth quarter-over-quarter. Could you give us more details on the current recovery factor for the wells and where the company believes we can get with this program? What's the expected response time for the reservoirs? That was a very detailed analysis. Congratulations on the research. I think you described it in our strategy in many details. The strategy was basically, today, we have a return on capital analysis that when we elevate the production to 28,000 bbl, 27,000 bbl like we did last year, sometimes even above 28,000 bbl a day. We saw that this strategy required a change and an acceleration in our focus in secondary recovery projects, which is part of our track record. We know how to do that, and we have been doing that with a great deal of success, especially in the Remanso Hub. It is a new stage. We have going through a careful stabilization of going back to production quite fast and have a focus on increase more to the mid and long-term. In injection secondary recovery, we should not have defined ambitions, especially for the six, 12 and 18-month horizon. We expect to have a good recovery more in the midterm scenario. At the same time, we must follow this every day. For Tiê, we started this effort in 2024 when we started development of Tiê, injection started in 2025 and was now consolidated in 2026. We already see the return of those initiatives. That's for Tiê. We have to be careful when it comes to the other six projects we are doing. Some are already migrating from a pilot stage to an implementation stage, we have a greater expectation. Overall, what we will see at PetroReconcavo is organic growth in production, more to the midterm, with return on capital increasing. That's the strategic design, and that's what we will keep on doing. As we acquire more specific data on those returns, of course, those will be included in these presentations to give you visibility. For now, we can speak quite comfortably about the Tiê returns because this project has started two years ago, and we clearly see that we will have the Tiê production reaping the results in the next months. It's important for us to be careful and to multiply reserves in the future and eventually bring this increase in returns. Next question is from Tasso, from UBS. When we look at the probes fleet, you still have some loans to third parties showing that perhaps you don't have so many projects in-house. Just an update on the drilling projects. Without a doubt, the biggest or the strongest change we have promoted was on our drilling schedule. For the others, were changes that were not so much in activity, but more on focus, with a focus on injection projects. In drilling, this is absolutely common in this market and onshoring, especially in secondary recovery. It's normal to first mature the drilling project as a response to the injection project or as a consequence of that. Projects continue to mature. They are divided in two large groups. The group of projects that are in our reserves report, projects that are already known and are being developed. These are more dependent on the injection program and will happen further in the future. At the same time, projects that we started develop last year, especially the ones connected to reservoir or new reservoir development, and also reservoirs that we have tested, horizontal deep ones. The process we had last year is still being matured, so we can develop new drilling projects. These are following the same path we predicted last year. For others, we reallocated them so we could focus on the secondary recovery projects. The goal is the same, to have these projects so they are executed the moment they will give us the biggest ROI or return on capital allocated. That allows us to make those choices. However, our ability to have the best onshore drilling company in-house, in my opinion, allows us to use this equipment externally, so they keep on running and increase the level of use of the equipment and also make sure they are generating value because they are generating revenue and EBITDA to the company. It's an adjustment that the company could do, especially because of how competent the company is when it comes to our drilling capacity with a very positive feedback from our external partners hiring our drilling services. Next question is from Eduardo in Itaú. Considering that the company has prioritized investments in secondary recovery and injection with a capital return focus on the long term, is there any possible implication on your reserves report? I think that Troy's answers give us a very interesting foundation on the technical perspective of the strategy, because the strategy is using the knowledge and the proven ability we have. We are doing this balancing between investments that, of course, can lead to short-term results in production. We continue to see this happening every month and, at the same time, doing what we do best, which is to multiply reserves in the reservoirs and, of course, extract them with the maximum return on the capital deployed. That's the decision. That's the technical foundation behind the decision, and we are absolutely certain that the company has a future, not only in terms of production maintenance, but also production growth that will come through a more consolidated structure of the secondary recovery. Our next question is from [Rajeev] from BTG. He wants to understand the CapEx strategy, especially looking for the next 12 months. Should we expect similar CapEx levels we had in the second quarter for the next quarters? As the company advances in the secondary recovery projects, what will be the impact on CapEx? I can take this one. Thinking about our plan currently, we still haven't discussed next year's budget with the board. Initially, we see the end of the year and next year as relatively similar to what we have observed in the first half of this year, both in terms of absolute value of investments, around BRL 800 million-BRL 850 million a year, as well as in terms of the investment profile. We have a very strong foundation of workover with a mix in our workover portfolio that's a little bit greater than we had in the recent past, especially in terms of the implementation of the secondary recovery projects. The drilling campaign, a little bit slower than the last two years, but possibly with increase as we start to see the results from the secondary recovery projects and a certain level of CapEx for same business facilities and expansion of water injection capacities that will be similar. Overall, a similar profile to what we had this year. That's what we see in the initial plan development for next year, reinforcing our focus on water injection and workovers. Next question is from Citibank. We're going to shift gears and talk about the contract or the Brava agreement. With the signature of the long-term Brava agreement, it's possible to quantify the expected impact in the discount reduction in the Potiguar asset. What would be the new average discount level that we should expect from oil sold in Rio Grande do Norte starting in October? I think the correct answer starts by saying that this agreement is in line with our interests. Of course, there are variable components. We saw this in this quarter for both companies reporting a significant improvement in their derivative spreads. It's a contract that encourages that value to be shared. It's an agreement that brings a lot of benefits for this concept in terms of average discount. The best proxy that I have for that, even though this is an agreement that has a variable component for the future and must be seen in that way, we have to look at results from this quarter so we understand what's to come. This was an agreement that has an amendment of three months that was being effective, where we were riding and facing the challenge of developing a longer-term contract, something that we hadn't been able to do in the past few years, an agreement that would allow us to have more predictability in terms of volume and commercial relationships. This is a very positive advancement because now we have work to do to increase efficiency. Overall, I would say that the best proxy we can use to try to understand how the future discount levels will be is looking at this quarter. Once what we were able to do has creates a very strong anchor for the commercial conditions for this quarter, including the same derivatives basket variables for the future. Of course, we're always working to get better all the time. We see the entrance of P10 next year that will allow us to operate in an even more resilient way, but it fits really well in this agreement we have with Brava. I think this quarter is a good proxy for that. Next question is from Eduardo from Itaú. How does the Brava agreement signed yesterday has impacts the tanking building project? There is no impact whatsoever. I perfectly remember getting here in the first week and facing a unique event in the history of the company, which was the closing of 100% of the Potiguar Fields for 12 days. That event showed us that besides the deferred production from those days, we also had a huge challenge that appeared months later for stabilizing the dynamic conditions of the reservoirs. This was a decision we made at that time that we would keep a strategy to have operational resilience that would allow us to have flexibility, instead of having just a single outlet. Strategically, it works more than anything else to ensure that we won't need to stop these fields and distribute this one way or another. However, the use of P10, how that's going to be structured, volumes, and more information about the operation, we still are going to develop that in the next few months until P10 is ready, so we can have the highest efficiency possible. This is work we start now. Definitely what we all celebrate right now with the Brava signature is the fact that we have achieved our goal of acquiring a more resilient production. I never wanted P10 to replace the refinery option. I always wanted for us to build a structure, which is exactly like the one we have right now with more operational flexibility. I consider this to be extraordinarily valuable for the company, and we generate dozens of millions of BRL of future value for the company in the future when we make this type of decision and can implement it. It took us some time. There's no simple way to go about this, but we are very positive about the possibility to generate value that this structural decision now brings. Perfect. Shifting gears once again. Now we're going to talk about lifting cost. I'm going to combine some questions because they are quite similar. Bruno from Bank of America mentioned that-- Sorry, it's not Bruno. The Bank of America team mentioned that the lifting cost achieved its highest level since the IPO. How can we look at this indicator from now on? And the Safra question is, where do you think the largest contribution for a possible drop in lifting cost will come from? Production growth, or do you still have any other structural measurements to take in terms of cost? Perhaps from a broader perspective and thinking about the total cost for the company, I tried to mention this before. When you look at midstream lifting cost, G&A, and even the CapEx, if you think about from the total tax perspective, our total expenditures, we have had a significant reduction looking at the absolute numbers in BRL million when it comes in comparison to a year ago. The combination of lifting cost of G&A and midstream that goes to OpEx dropped about 15% or BRL 50 million per quarter in comparison to the levels we had in the first half of 2025. It was a big effort. Now zooming in on lifting cost, our production cost and extraction is calculated in BRL. 90% at least of the cost is calculated in BRL. What we manage is how much we spend in BRL every month, every quarter. This is at a reasonably stable level for the first two quarters of the year. Actually, since the fourth quarter of 2025, we all had already seen a reduction, and we're close to BRL 180 million per quarter, which was also a reasonable reduction when it comes to what we had in the previous year. Of course, since production dropped about 11% in the period and the dollar depreciated about 11% as well, the reduction in the absolute cost was eventually translated into a growth in the unitary cost per barrel in BRL. We're going to double down on these efforts. It's sort of baby steps. We've been tackling different costs, and searching for optimizations. This is an ongoing effort. And of course, we count with improvements in production and the FX rate. We expect significant drops. Regardless of external variables, we'll keep on working. We have made some efforts, especially when we look at the components of our lifting cost. People, repaying wells, there are a number of initiatives trying to reduce the failure frequency of these wells, and we have been quite successful in that. Part of this accomplishment in the reduction we had in the last year actually came from that. Cost of power, we signed a contract in self-production for some time ago. There are different components, and we're working on all of them to keep lowering this cost. I don't think I need to add anything to that. Talking about hedge, Leonardo from Bank of America has a question that I'm going to combine with a question from Safra. With the volatility in oil prices, could you tell us a little bit about your hedge strategy? Safra says that no hedge operations were done in the quarter. How are you assessing the possibility of resuming these operations? The hedge discussion we have internally happens quite frequently. They're constantly revisited. Overall, the company's hedge strategy is anchored in creating stress scenarios. Frequently, at least once a quarter, but also monthly internally, we do that. We create stress scenarios. What could happen with the company if the oil falls, I don't know, $45, $50, $40 per barrel? We would discuss these different scenario designs, and then we calculate how much volume of barrels we need to hedge to ensure the minimum investments that we deem appropriate, even in a scenario of drop in oil prices, so we don't go down a negative spiral of production. That is the methodology that we follow quite frequently here. Of course, we consider gas contracts that we have. They bring sort of a natural hedge, and we roll that out. Since we already have a hedge portfolio that's quite robust for this year and the beginning of next year, we have decided not to add anything, especially because of the high volatility. Certainly, this is a topic that is constantly discussed and updated in our board, and we are always searching to, of course, protect the company from a stress scenario and allow us to navigate a possible stress scenario in a safe way. Perfect. Shifting gears again and talking about gas. I have a question from Rodrigo from BTG. If you could help us remember what are the financial effects from the gas purchase, and now with better prices in the third quarter and fewer purchases, do you expect to see a relevant gain in your margin for gas or sales margin? I think I can take this one first. Your understanding is perfect, and that's what we tried to demonstrate in the presentation. This quarter could have had even a greater increase in the EBITDA if we hadn't stopped the refinery, the treatment plant, actually. We stabilized gas purchases to keep it at a minimum level in the last quarters. We clearly saw that in the presentation. There was a one-off sale because of a scheduled downtime, which was quite well executed. I always talk about this theory when in onshore, companies join forces to improve the systemic efficiency of the onshore business in Brazil. The Guamaré acquisition, but more than that, the joint operation of Guamaré has already demonstrated not only cost levels that are below expected quite fast, as well as major advancements like this one, with a downtime period that happened 10 days faster than what was planned. We needed to purchase gas to deliver this time, and that has an effect because overall, we purchase very close to the price, so there is no material financial loss. However, there is a loss when we do not sell our gas and our liquids. That has a negative impact that is quite big in our company's results. That is what we shared. Without a doubt, this is a quarter where we start to capture. It is not going to be this one. The next quarter, we will start capturing that more definitively. The effect of the increase in the oil prices and the gas from the first quarter, we will capture that without the purchase of gas. It is a quarter in which the financial results for gas will certainly improve. He asked an update on the Bahiagás negotiation. Bahiagás did the RFP, and we are participating in the process. The process is evolving, the companies have presented their projects, and now we follow the natural path. We are almost out of time, but we do have some questions about dividends that I think it is important for us to cover. So, Montanari's questions. The company has announced the distribution of dividends at JCP in a recurring fashion. How do you see that when you think about the more adequate leverage level? Is there a leverage range that makes you comfortable and that you use as a benchmark to balance future distribution to shareholders? I think I can start. The first answer that I can tell you, Montanaro, is that leverage and dividends are completely disconnected discussions for us. Leverage level is connected to investments and our ability to generate new projects, whether they are midstream or acquiring midstream or a possible M&A that a company wishes to do, or even investments in our own reserve development. What we did, since the company changed our level of investments, when we ended the payments of asset acquisitions, we started to generate a lot of cash. At that point in time, we discussed a strategy of every quarter doing an assessment with the board about capital allocation, considering our investments, M&A opportunities, and consequently, everything we would get in terms of cash generation would be discussed with the board for a possible distribution or buyback. The structure remains the same and working, but it is exclusive. It is a discussion about cash generation and not about leverage. The company's leverage is at a comfortable level, and it is at this level because of the projects and M&As that today are not mature enough to happen. I believe that our leverage will always be a possible discussion if the company finds opportunities, both internally and externally, to allocate capital. I would just add that if we rule out the M&A opportunities, we also see structurally the company trying to keep a reasonably low leverage level compared to our peers in the market. We have an internal policy that foresees that this leverage is below 1.5x, and we are really below that. So, right now, we are not really discussing increasing or decreasing leverage levels. Our final question from Lucas: How do you see capital allocation choosing between dividend distribution and buybacks? This is a discussion we have with the board. We always present them with the options. For now, I see that, especially because we have quite a favorable window in terms of JCPs, the decision of the board has been that the best option is to distribute that as dividends, and each shareholder or investor decides if they want to buy shares or not. I think this has been the primary discussion. The JCP mechanisms allows us for this decision to be as advantageous as others for the company. Of course, we have been trying to prioritize JCPs, thinking about the tax efficiency it generates for the company. Of course, we frequently discuss different alternatives for buybacks as a capital allocation strategy. We have covered it all, we are also at the end of our time together. If you have any further questions, please make sure you contact our team. Thank you so much. Thank you for your attention, have a great day.