Hello, good afternoon, everyone, and thank you for joining our earnings call. The first quarter of 2026 marked another important step in Brava's transformation.

More important than a strong quarter on its own, we believe these results underscore a structural shift within the company. Today, we have a more efficient, more resilient operation with greater capacity to create value for our shareholders over business cycles.

We saw operational progress, strong EBITDA growth, positive cash flow, and continued deleveraging, all while maintaining capital discipline and a focus on execution. The quarter demonstrated simultaneous progress in operations, strategy, and finance, underscoring that Brava today combines operational growth with financial discipline.

We posted record net revenue of $596 million and record adjusted EBITDA of $310 million, more than doubled the result quarter-on-quarter. April production already shows a significant recovery, reaching 80,000 barrels of oil equivalent per day, above the target for the first quarter 2026.

We also continue to make progress in operating efficiency. Lifting cost fell to just under $11 per barrel, one of the lowest levels in our recent history.

We reduced capex by 57% compared to the previous year and generated positive free cash flow, even after making significant payments on the acquired portfolio. Perhaps more importantly, we delivered our fourth consecutive quarter of deleveraging, ending the period with a net debt-over-EBITDA ratio of 1.8 times.

Now let's talk a little about reserves and our portfolio. Over the past few years, we have built a significant, diversified platform with long-life reserves, and this slide clearly illustrates that evolution.

We have gone from producing 19,000 barrels of oil equivalent per day in 2020 to approximately 80,000 barrels currently. In addition to scale, we now have a well-balanced portfolio of onshore and offshore assets with different risk profile, return, and cash cycles.

Another important highlight was the update of our reserve certification, reaching 459 million barrels of oil equivalent in 1P reserves, or nearly 80% of the company's 2P reserves. This underscores that Brava not only generates cash today, but also has assets that are both relevant and sustainable for the future.

The company has evolved from being merely a story of operational turnaround to becoming a major oil and gas platform in Latin America. Turning now to ESG.

At Brava, ESG is directly linked to operating efficiency, risk management, and value creation. We continue to make progress on this agenda, always in close alignment with the company's financial and operational performance.

Today, we have direct integration between the ESG group and various other departments across the company, strengthening governance and transparency. We have maintained low levels of offshore emissions, made progress in real-time operational monitoring, and continue to invest in safety, integrity, and training.

We have also strengthened our social agenda with investments in local communities and significant progress in compliance and governance programs. For us, ESG is not just a narrative, but it's execution, risk management, and operating efficiency.

Turning now to some operational highlights, the operational recovery began to emerge more clearly throughout the quarter, and I will go over the key operational highlights. Starting with the production slide, April already shows a consistent pickup in production, reinforcing that we are already in the early stages of this recovery and operational stability.

The period still had some one-off operational impacts observed early in the year, mainly at Atlanta and Potiguar. The most important here is to look at the trend.

April already delivered 80,000 barrels of oil equivalent daily, representing the best month of 2026 so far, and showing a recovery in production. Offshore assets continue to be the company's main driver of growth and efficiency.

I'll now turn the floor to Carlos Travassos, our offshore officer, and I'll be back to speak about our financial highlights.

Very well. Thank you very much, Luiz.

Good afternoon, everyone, and thank you all for being here at the call. As you can see from the slide, I'm going to focus here on our campaign, the Atlanta and Papa-Terra campaign.

I'd also like to highlight a few points regarding our operating results for the quarter, production results and for Atlanta, Papa-Terra, and Peroá, which performed very much in line with our plans. There's nothing out of the ordinary to report.

In any case, I'll be here and fully available to answer any questions you may have about these assets, okay? Very well.

To talk a little about this slide, the main message I want to convey is that the campaign is going exactly as planned. I'm going to give a slightly more informal presentation, sharing some more operational details of this campaign.

Looking at the timeline and milestones, I think the major event of this quarter, in addition to the start of drilling itself, was obtaining the license, which was a key milestone. That went exactly as we had anticipated.

We had already mentioned that we didn't expect any issues regarding the license, given the interaction we had with IBAMA, and that was confirmed. We obtained the license without a hitch and began our drilling campaign.

To give you some details about this campaign, as we're starting with Papa-Terra. We will drill and connect the two wells at Papa-Terra in the fourth quarter of 2026, and Atlanta will follow in 2027.

We're sticking to exactly the same dates that we set back when we made this investment decision. We are absolutely on track, on time, and on budget.

Talking a little now about the operational side of this campaign, there's a video I'm going to play in a moment, which will present this information in a slightly more playful way. You'll notice that we run this campaign in batches.

Wait, now what does that mean? What's this batch business?

To put it briefly, our wells are drilled in phases. Specifically at Papa-Terra, there are five phases.

Each of these phases means that I'm deploying certain types of equipment. You'll see in the image.

Actually, I'll go ahead and put the video to play while I'm talking. The video has no sound, and as a disclaimer, I won't be narrating the video.

Since I will not be narrating the video... Please hold.

There was a sound cut. Please hold.

Zoom screen has frozen. Please hold.

Brava Energia's video conference call will resume in a couple of moments. As expected, and then we move to the other phases.

These images are from Papa-Terra 52. We completed the two phases at Papa-Terra 52 and moved on to Papa-Terra 53.

We will therefore proceed through three phases at Papa-Terra 53, and then we'll return to 52 and finish up the well. We'll finish drilling and completing the well, and then we'll begin connecting this well.

Folks, that's basically what I have for you today, and once again, I'm here to answer any questions you may have. I hope you liked it, and I'd appreciate it if you could give Godoi some feedback on whether this format works, we can make adjustments for the next call.

I'll hand over to Jorge Boeri to go over details on the onshore operations. Thank you very much.

Thank you, Travassos. Today, I'd like to briefly discuss the progress made in the Potiguar Field project.

As we mentioned earlier, in October last year, we had 85 facilities in operation. Far, 51 facilities have resumed operations, while 34 still remain partially in shut down.

It's important to note that of the 51 facilities that have resumed operations, only 13 contribute directly to production. The other 30 were 38 consists of 36 sat facilities needed to test the wells and two water injection facilities that support secondary recovery projects.

Since the start of the partial suspension of production in Potiguar had been declining and reached its lowest point in February. After that, in March and April, we recorded two consecutive months of increased production, demonstrating the effect of the facilities returning to operations.

During April, we set up a task force to submit the vast majority of pending facilities for ANP's review. At this time, only four facilities remain, which are expected to be submitted during the first half of May.

ANP is reviewing and approving an average of about nine facilities per month. Given this progress, we estimate the full production will resume by the end of August.

It is also worth noting that by the end of March, the Sanhaçu and Benfica fields, our main gas-producing fields in the Potiguar Basin, will resume production. Looking ahead, we expect to resume steam injection at the Estreito field in May, and also resume operations at the Fazenda Belém field.

Fazenda Belém, in addition to resuming steam injection and operations, we will also begin nitrogen injection, making the start of the development phase of our EOR project. I recall last year that we conducted nitrogen injection in a pilot phase, and given the positive results obtained, we are now moving forward to the development phase.

In summary, we continue to see a gradual improvement in operation with a recovery in production and greater predictability for the full normalization of Potiguar in the coming months. In addition to what was said about ANP's performance, I would also wanted to mention that the remaining of the onshore operation is performing very well.

Specifically in Bahia, we are achieving very good results in operations and production, and we are also continuing to work on our workover campaign to restore and recover production across all fields. With that, I conclude my presentation and turn the floor over to our CFO, Luiz Carvalho.

Thank you.

Thank you, Boeri. Now, speaking about the financial results, the results have begun to more clearly reflect the operational improvements the company has been delivering quarter after quarter, and we will talk a little bit about the highlights of the period.

Starting with revenue, the combination of improved monetization and greater operating efficiency drove record revenue for the quarter. We had record net revenue of $596 million, reflecting primarily a better pricing environment, greater operating efficiency, and more efficient monetization across the portfolio.

Atlanta deserves special mention, with no significant discount to Brent during this period. It is also important to note that oil prices began to rise more sharply only in the second half of February, part of the scenario is not yet fully reflected in the first quarter figures.

We enter the second quarter with a more favorable operational and pricing environment. Now moving on to the slide on EBITDA, margins and cash generation have begun to reach new levels, reinforcing that Brava is becoming structurally more efficient and resilient.

Adjusted EBITDA reached a record high of $310 million, with a consolidated margin of nearly 52%. The offshore segment achieved extremely robust margins, close to 68%, reflecting operating efficiency and better monetization.

Another key point is the expansion of operating cash flow per barrel across virtually all the company segments. Today, we see that the company is converting more production into cash.

Now moving on to lifting costs, the slide on lifting cost shows that operating efficiency remains an absolute priority for the company. Offshore lifting costs fell to just under $11 per barrel in the quarter, a significant reduction when compared to previous periods.

Atlanta and Papa-Terra continue to evolve towards highly competitive levels globally, and we see additional room for improvement through production growth, cost discipline, and greater operational dilution following the drilling campaign. Onshore, we continue to work to stabilize production to capture additional efficiency gains.

Our focus is not just on growing production, but on growing production with returns. Now referring to capex, now we have entered a much more efficient phase of capital allocation.

Investments fell 57% vis-à-vis the previous year and 33% when compared to the previous quarter. This trend clearly illustrates the company's transition, when we have moved from a more intensive phase of project implementation to a phase of cash capture and operational optimization.

Naturally, we will see an increase in disbursements over the coming quarters with the offshore campaign, but within a highly disciplined framework of capital or return on capital. In summary, I would say that the intensity of investments has decreased, while cash generation capacity has increased.

Maybe this slide best reflects the actions we have been taking. Deleveraging is no longer just a plan, but it has become a concrete execution.

We ended the quarter with approximately 1.1 billion USD in cash and a leverage of 1.8 times, significantly expanding the company's financial flexibility. We moved from 3.4 times a year ago to the current level through operational execution, reduced capex, and a consistent improvement in cash generation.

We've seen a shift in value from debt to equity in the recent period, and the trend is for this process to continue going forward. Now speaking about cash flow and debt, and building on the previous slides, we now have a much more robust capital structure that is well-positioned to weather different oil price cycles.

Even after significant payments related to the acquired portfolio, the company generated positive free cash flow in the quarter. We also continue to reduce portfolio obligations, expanding the maturity profile while lowering the company's cost of debt.

The combination of robust cash, a manageable amortization schedule, and operational improvements significantly reduces the company's financial risk. Now speaking about hedging, this has been a focus for investors, and we believe we are well-protected while preserving exposure to the upside in oil prices.

Our strategy remains well-balanced, and we have not made anything significant additional moves in recent months. We have consistent protection through collars, puts, and NDFs without margin calls or over-hedging risks.

At the same time, we have maintained significant exposure to positive oil price scenarios and capitalize on favorable conditions on interest rates and crack spreads throughout the quarter. The hedging strategy aims to reduce volatility without limiting value creation in a year that has proved more challenging than we have experienced from a macroeconomic perspective.

In summary, the bottom line, taking into account the various variables that make up our revenue, has been quite positive for the company. Now looking ahead to the remainder of 2026, we view this as the year of operational stabilization and value expansion for equity.

The company's next steps are quite clear. First, stabilize production while maintaining operational safety.

Second, we will continue to accelerate the deleveraging process. Thirdly, we will execute the offshore campaign on schedule and within budget.

Finally, we will continue to advance the Brava efficiency program focused on structural cost reductions and contract optimization. The main takeaway is quite simple.

We believe that there is still significant disconnect between the company's operational and financial performance and the current perception of value. As I said before more than once, more than just being good oil operators, we seek to be good allocators of capital in the oil and gas industry, and we want a Brava that does not depend on high commodity prices to generate shareholder value.

Today's Brava is more efficient, more resilient, and much better prepared to face the industry challenges. Now before we move on to the Q&A, on behalf of the company's entire executive team, I want to thank everyone at Brava once again.

We have shown resilience, dedication, and commitment during a period of so many changes in the sector. You are the ones who make everything happen.

Thank you for your attention so far, and now we can open for Q&A.

Good afternoon, Luiz, Travassos, and Boeri. Thank you for taking my question.

I have two questions. For the first, it's hard not to touch on this, regarding the tender offer of Ecopetrol.

I'd like to understand the timing, next steps, when do you think this will be completed, and when would you be sitting with the potential new partner to discuss possible changes in the strategy, if any? Still on that topic, perhaps Boeri could share with us his view on the technical ability of Petrobras in offshore.

My second question is about evolution of trading prices as we enter Q2. Still on trading strategy, there was another offshore company considering buying VLCCs.

As an important exporter of oil, have you considered this possibility? Thank you.

Thank you, Vicente. Before I start answering, I would like to apologize for the technical glitch during the first part of the call.

Power went down in our building. It took a little longer for the generator to kick in.

If that happens again, please stay with us, cuz we'll be back. I'll answer the first and the last part, and leave the onshore part, as you suggested, to Boeri.

In terms of timeline of the tender offer, well, it's not very clear in the letter we received from Ecopetrol. What we can say is that there are some conditions precedent for the tender offer to happen.

First, we need CADE approval, approval by the antitrust agency of Brazil. We have to submit the process jointly, Brava and Ecopetrol.

We should be doing it soon. Initially, the understanding of our attorneys is that this will go through smoothly.

CADE has 45 days to analyze it, and if we don't hear from them, the project is approved. In parallel, the company, at a request of the board of directors, is trying to get some waivers from financial instruments that we have, particularly debentures, some debentures that Brava has.

For our bond, we don't see any need, because you're talking about a lowering of the rating, which we understand will not happen. Bilateral instruments are negotiable and more flexible in that regard.

Where we're dedicating a little more attention is to obtain these waivers. Yesterday, we published the call for the general assembly of debenture holders, and I think that we need 21 days, and then another period for a second call, and that would be a second step.

In parallel, Ecopetrol, as the acquiring party, will need to follow through with the tender offer. These three processes move in parallel: CADE, the waivers we need to get as a company, and the tender offer to be conducted by Ecopetrol.

I imagine that the company has some time to publish these documents, and then things will follow the regular timeline of a tender offer, if I'm not mistaken, 21 days. Again, it's hard to precise the exact timing of the tender offer, but if we consider all this timeline, I believe between two and three months, if there are no setbacks, that should be it.

Before giving the floor to Boeri regarding the capacity of Ecopetrol, they produce 750,000 barrels practically all onshore, I think in Colombia, and I'll let Boeri mention details on this.

Vicente, good afternoon. Ecopetrol, as almost all state-owned companies in Latin America, is strongly capable.

They have an expertise in onshore fields. The difference of Ecopetrol from the rest, in addition of being expert in onshore, they are experts onshore with heavy oil.

That's the case of Atlanta and Papa-Terra. A good part of our onshore portfolio has heavy oil.

Our technical team was in Colombia about a year and a half to two years ago, and some of the steam generators come from Colombia, and we believe that they have greater expertise of onshore heavy oil fields compared to Brava. Brazil has great experience, on the other hand, in offshore.

It's totally different than what they have in Colombia, we believe that this is going to bring technical strengthening. It's going to be a potential to increase efficiency in our field.

Moving to your last question, Vicente, about trading prices, no, we did not consider acquisition of a VLCC. Of course, that requires investment.

Secondly, it requires scale, and Travassos can talk about this. I'd like to remind you that our oil has different characteristics from the physical standpoint: API grade, contaminants, acidity, etc., in our case, it would not make sense.

What I can tell you before I give the floor to Travassos is that we have seen an improvement in the reference price. The first quarter, we had an average offload price of $74, while we see now a reference price in April that is higher.

Take the example of BC-10, that had a maintenance shutdown between December and January. This, one way or another, forced us to sell that offload at a price below what we normally practice.

Now for Q2, we see a reference price which is much better. Not to mention the crack spreads, which, as we have followed, are very volatile.

We also see an improvement. We used to sell with a discount to Brent, and today, Atlanta now is selling at Brent plus.

If everything remains constant, although the oil dropped almost $15 down in the last few days, we understand that the average for Q2, again, I stress, if the same scenario we are seeing remains, we should have a reference price which should be substantially better in Q2. Would you like to comment on the VLCC?

I think that your answer was very complete. You mentioned the word scale.

This decision has a rationale when you have scale for this kind of operation, because today we have basically two assets in which we're doing workovers, sometimes concomitantly, we kind of looked into that, but it doesn't make sense for us. At the moment, it's not in our radar.

It's very clear. Thank you very much.

Thank you, Vicente.

Hi. Good afternoon.

Thank you for taking my questions. I have two questions.

My first is about the new wells at Papa-Terra. Can we have an idea of your expectations of the certification?

What are you expecting regarding these new wells in terms of peak of production, plateau, and depletion? My second question is about the lifting cost.

We have seen a lifting cost that remains kind of flat, and please correct me if I'm wrong, but over the last two quarters, it's kind of flat. I'd like to understand if there's any room to reduce the lifting cost more, given the same level of production, or whether the improvement should come by increasing production once we have the new wells at Papa-Terra and Atlanta coming online.

Thank you.

Shall I start then? Let's speak about the new wells at Papa-Terra field.

Our expectation is to reach a production plateau by year-end. We will connect the two wells, and there's no reason why we should have a gradual, very gradual ramp-up.

We'll be starting production in the last quarter, and we're absolutely on track with the campaign. It is unfolding exactly as planned.

Today, we will start phase four of the first well. Just like I showed you in the video and I explained in my presentation, we are drilling in batches.

We are in the fourth phase of well 53, and then we're going to change the equipment and fluids we use in the process, and then we get to the fourth phase of 52. We do have production capacity.

Of course, there's always a concern when we think about providing a guidance, but what I can tell you, and then you'll be able to calculate the average for the year, I think that will increase production by 2,000 barrels on the average for the year. We have the potential to get to these amounts of barrels.

Again, we're talking about starting production at the end of the year, we would have a production increase that would be substantial at Papa-Terra. As for the lifting cost, we have room to reduce the lifting cost, and not just by increasing production.

We see a reduction of the lifting cost at Papa-Terra. As we mentioned before, we are prioritizing activity at Papa-Terra, and as of March 2027, will take over the operation.

To give an idea in total numbers, we'll reduce our extraction in $23 million in the year with this initiative, and this will bring a significant reduction. Today, the lifting cost at Papa-Terra is about $23.

It is, well, the visually two units. We're talking just about Papa-Terra here, and this will come down to 13 next year with the reduction of the extraction cost and with production increasing, and we see that Papa-Terra will become very competitive.

Yes, Marcondes, we do have room to reduce the lifting cost in addition to increasing production. If I may add something else, Léo, in terms of a flat lifting cost, that's not really true if you look at the different segments.

In onshore, there was a reduction. In offshore, we had a reduction, while onshore, given the partial suspension of some facilities, there was an effect.

We have an effect of the denominator that is being impacted, and we expect this to resume soon. That's what Boeri mentioned, the number of facilities that are returning to operation.

To add to what Travassos said, we do have an opportunity to reduce the lifting cost ahead, not just by reducing costs at Papa-Terra, but given a basic effect, a scale effect, with the addition of the new wells. Thank you very much.

Thank you very much for the answer.

Hello. Good afternoon, and thank you for taking my quick questions.

I think my first question is to Luiz. This quarter, we already saw a cleaner result in terms of operating adjustments in terms of production.

If we take a closer look in cash generation, excluding non-recurring settlements and even excluding working capital and M&As, which are a one-off in the quarter, we still arrive at a cash generation closer to neutrality in the quarter. I would just like to hear your update about that, and how do you see the company's cash generation capacity going forward in the coming quarters of the year, also considering the new Brent scenario?

My second question, and maybe it could be answered by both Travassos and Boeri, along the same lines of increased capacity in cash generation, if the company had a lot of exceeding cash and more investment, a higher investment appetite, where do you see the best possibilities or opportunities for organic growth, either in onshore or offshore? Where would you like to anticipate investments or to invest more?

Thank you, Tasso. I will start, and then Boeri and Travassos.

The first quarter, as a reminder, this was a cleaner quarter, but there were still some residues from maintenance BC-10 that ended in mid-January. There was also an issue with Atlanta's pump that, one way or the other, also impacted the average of the quarter.

As you put it quite well, if you look at the first quarter, there were some earn-outs and M&A commitments from the past that were carried over, and somehow they also impacted cash consumption, coming from these installment payments. There was also the payment of $50 million for Tartaruga Verde that will be posted in the second quarter.

When it comes to cash generation, if you look at the first quarter, and again, I was even reading the reports from some analysts, and I could see the work that we're doing to clarify cash generation operations. Some people think that we retain cash, and some people think that we are dispersing cash, we just have to organize a rationale about what would be a recurring cash generation or a pro forma cash generation.

Maybe this will help you better. Going forward, we have to remember that in the second quarter, capex will accelerate going forward, because the campaign started at the end of March.

Therefore, we didn't use a lot of capex in the first quarter, but in the second quarter, the campaign will be running in full throughout the second quarter and the following quarters. As I said, in terms of realization prices, it will be lower.

We do not have any M&A commitment from now until the end of the year. We will have the return of the amount that we paid for the acquisition of Tartaruga Verde, and the second quarter, there will be a higher impact.

The impact of the hedge in the first quarter was very low, 19 million BRL, it wasn't relevant. In the second quarter, we expect to see a higher impact.

It's still too soon to say what the impact will be, given all the volatility in oil prices, but our reading is that higher oil prices, that leads to a higher impact on cash, but net and net, if it's for the company, for the amount that was not hedged, there will be a lower cash impact, but obviously, revenue will also be lower. That may be a little worse, slightly worse, but we are less volatile, given the hedging strategy that we are pursuing recently.

Now before I give the floor to Travassos and Boeri, and they will be able to talk about onshore and offshore respectively, all of the approvals of all the projects not only go through an operating criteria and risk assessment, but we also look at opportunity cost for the company, and verify whether it fits or it's in line with our budget, and remember that we tried to acquire 50% of Tartaruga Verde, and that would contribute to cash generation and the deleveraging of the company. Therefore, we analyzed not only onshore and offshore, but we look at the entire picture involving the P&L of the company, how can that impact our cash generation, and we also look at the operational side.

Boeri, you go first.

I'll start speaking about onshore and Bahia. In Bahia, we have two additional projects that will be added to our gas production this year.

One is the trading of Socorro. Socorro is an isolated field.

It produces gas and oil, we separate gas and oil, gas is reinjected. This year, we'll start trading this gas.

In addition to that project, more sales is translated into more costs, but this will certainly improve Bahia's cash. The second thing is that the other project in Bahia is a reservoir of half pressure that is competing in capacity with the rest of the operation of the asset, and then we are doing some work to bypass the compressor, and then we want to put this guy at the Pitanga Formation, and this will increase revenue in Bahia, mainly due to gas, and clearly, this will lead to a reduction in lifting cost.

Now as for Potiguar, since the very beginning, since the day that we got that operation, we were surprised with our water production. There was a bottleneck in Potiguar.

There is a maximum water capacity that cannot Well, it's about 150 cubic meters of water, but we produce 98, 98.5% of water in our wells. We had a limitation.

If we were accelerating a campaign, we had to close other operating wells. What did we do in the meantime?

About a month and a half, we started operating a pipeline that can capture part of the water in the field, one in Canto do Amaro and the other one in Salina Cristal, and this led to a capacity to flow water of 100

and 15, we have 15,000 cubic meters of additional water. This was a drilling campaign that now could generate more value.

I had to shut down producing wells in order to incorporate new production. That was a one driver of production in the future.

The drilling campaigns are a very good way to increase production, and recently, we added a workover rig to capture the opportunities we have in that operation. Clearly, our major future growth driver are the EOR fields.

We are not running the pilot yet, but the pilot should start in 2026 with nitrogen injection. We developed a pilot last year, and now this year, we are now developing EOR in nitrogen.

These are the growth drivers both in Bahia and as well in Potiguar.

With onshore, we were not very intensive in drilling, but the capex were mostly earmarked for the offshore campaigns. Even then, we have good growth opportunities, because when we talk about Peroá, we have Peroá 2.

That's a well where we intend to do a workover. We put together a consortium with Total, and we will be sharing a rig, and with that, we intend to increase gas production in Peroá.

We don't have any figures yet or any numbers yet, but the outlook is very good. Even in Papa-Terra, in the current campaigns, we haven't yet made decisions about the investment.

We do not have any estimate of expenses, not even for next year, but in Papa-Terra, we see very good opportunities in the central part of it. We have conducted some studies, and then we see possibly something around four injection wells and between six to seven producing wells.

Again, this is very infant study. We are looking into it, but it represents organic growth in Papa-Terra.

As for Atlanta, that will depend very much on the performance of these two wells. It is the northeast side of the reservoir, but it's in our radar, but obviously, it depends on the productivity coming from the northeast well.

It's a separate reservoir in Atlanta. That's organic growth.

We're constantly looking for opportunities. Papa-Terra, you're very familiar with it.

We have about 3% of recovery factor, and certainly, more opportunities will come along. To summarize everything before we jump to the next question, this is the beauty of the company's portfolio.

Some people think that this is very complex, onshore and offshore, but onshore, Boeri says that we have a lot of predictability in our production, given the situation of the wells. Capex, I think, Boeri, is easier for us to accelerate and reduce.

Oil prices are down now, and we just approved some workover projects. In the offshore area, we have more scale, which is very important for a commodity business like ours.

Therefore, we can manage somehow not only our portfolio, but the investment per se, given the conditions of the P&L of the company and macro conditions that allow us to capture the best value possible. Thank you.

On my side, a question is about part of the questions you talked about prices in the first quarter and improvements in the second quarter. Could you explain again how does that work?

Also, my question is whether in the second quarter, you anticipate any sale or whether there is any low still that allows you to be so confident about price improvements in the second quarter? Thank you.

Yuri, in fact, in the first quarter, as I mentioned, at BC-10, we had some impact not only in terms of volume because of the scheduled maintenance shutdown by Shell that started at the end of '25 and ended in early '26, but due to that maintenance shutdown, we still had to get some load, and so our realization price at the end was much lower than what we usually get from that field. Now moving on to the second quarter of '26, and assuming that production will be at the current levels, or even the numbers from April, we will certainly reach twice the volume we had in the first quarter, with a realization price that is significantly better when compared to what we had in the first quarter.

I'm not going to give you any precise figures, because it certainly depends on market conditions, and the market conditions have been quite volatile in the last few months, but we understand that both in terms of volume and realization price, BC-10 should bring a significant contribution to the results for the second quarter. Thank you.

Hi, everyone. Thank you for taking my questions.

I actually have two. First, I'd like to get an update on the arbitration process, and perhaps you're expecting a verdict this coming quarter.

Perhaps you can share with us how long should we expect the results for Papa-Terra, and when should we have a final return regarding the arbitration process? Second point is about taxes on discussion we had in a conference call very close to the decision regarding export tax.

When we look at the offloads sold by Brava, part of that offload is used for bunker. There's a characteristic to the offload.

Perhaps this could be one way of characterizing Brava's oil as bunker and not as oil. There are a number of legal points and legal discussions of the industry with the government regarding the tax, but I'd like to hear from you what you're thinking about this.

There's this, and also, in the case of Brava, the hedge. Fair or not fair, if a company hedges oil, what are you discussing internally?

What can you share with us, because we would like to understand what would be the final impact on the company? These are my questions.

Thank you.

All right. Thank you, Barra.

Regarding arbitration, arbitration is unfolding, and as for the timeline, we would have a final hearing in Q4 of this year, and that's when the decision of the arbitral court would be made. Remember that there was a preliminary decision judging the merit of the forfeiture, which was favorable for Brava.

This quarter, we had a very in-depth discussion with the auditors that audit the company's balance sheet. Some of them, we could consider 100% of Papa-Terra with the decision of the arbitration tribunal.

We had also a favorable decision by CADE regarding the feasibility of us taking over in terms of market concentration. Recently, at the beginning of this week, we had a decision which I believe is part of the ANP process, a decision by ANP that we could go forward with the process.

There are other instances at ANP, including some coordinations plus the collegiate coordination to really give us a green light in terms of this working interest. Again, we're having this discussion with the auditors.

We don't want to include in our balance sheet something that could require a reversal adjustment in the future. We understand that the process is unfolding well, with favorable decisions for the company.

Hopefully, in the coming quarters, we will advance in that direction. In terms of export tax, as this was signed overnight in mid-March.

We were taken by surprise, just like the whole industry, and this is public information, most of the companies went to court to ask for their rights and to go against that tax. We understand that the government wants to collect more tax.

Now from the standpoint of Brava, we're doing the same. We are trying to get our rights enforced, and there's some nuance here.

Qualifying Atlanta's oil as bunker, well, that implies in a whole technical process, which I guess would take some time. Now speak about the expected duration of the tax.

We don't know whether we could have a final decision to qualify our oil as bunker. Now in our approach to the court, we mentioned that the tax applies to the physical volume of exports, while we do have some financial hedge contracts which make Brava not capture 100% of its production at spot price, at reference price.

Of course, this is all very technical, okay? We've had some contacts with the courts again to try to have a valid claim.

As a reminder, this kind of decision is liable to appeal. For the 2023 tax, for example, there are still companies today trying to get back or be reimbursed of the impacts they had in 2023.

In terms of modeling and cash generation, I would consider that the export tax will impact Brava. Ballpark figure, if we do the math of Atlanta, considering Atlanta production, BC-10 plus Papa-Terra, this will give about $10 million a month, $30 million in the quarter, and we expect that this impact will remain.

In talking with some politicians and other companies, the tax would last five months, starting in mid-March, and it would be applied for five months. A provisional measure is valid for 60 days.

It can be extended for another 60 days. The general understanding is that when the Congress is in recess, the timer stops, we would have another month.

We don't feel that there's a right atmosphere for this to be approved or voted, but we're working with a scenario of an impact on the company.

Good afternoon, Luís, Travassos, Boeri. I have a follow-up question.

I'd like you to elaborate on capex. You spoke about this, capex for the year, and we have drilling at Papa-Terra, the connections of the wells, and so on and so forth.

What would be the capex, not in terms of numbers, but in qualitative terms? Will there be peaks and valleys over the quarters?

Then in 2027, the campaign will take place at Atlanta. Qualitatively, could you give us some color on the capex when we are going to have the big capex milestones in the coming quarters?

That would be my first question. My second question has to do with the export tax.

You just mentioned, Luiz, the export tax at Papa-Terra. What potential negotiations can take place so that Papa-Terra oil will remain in Brazil, so that it will not have this effect of the export tax?

What are you thinking about this? Lastly, I'd like you to elaborate on Atlanta.

In Atlanta, there was a problem with the pump. Perhaps you could explain the problem you had.

Was it a one-off event? Are you looking at the other pump?

Are you taking any preventive measures to prevent this kind of problem from reoccurring with the pumps at the field? Thank you very much.

Three questions.

All right, Rodrigo. I'll answer the first two, and the one about the pumps will be answered by Travassos.

Capex was about $70 million in Q1, with practically no impact of the drilling campaign, because we began the drilling campaign at the very end. I'll be very careful, Rodrigo, not to give any guidance, because we don't have a formal guidance.

A drilling campaign costs, ballpark figure, close to $1 million a day, considering costs of the rig, equipment, etc. With the $70 million we had in Q1, if we add that cost looking forward, we're going to get close to a number of our capex.

We are not estimating any concentration of the capex on Q2, 3, or 4. The trend is that this capex will be spent in a more linear fashion over the quarters while the campaign is being executed.

I think that this will give you quite enough color in terms of what we expect for disbursements. As for the export tax, what we can say is that, yes, Papa-Terra does pay the export tax, although our offload is not being directly exported by us.

I cannot give you a lot of detail on this, given the confidentiality agreement we have with the offtaker, but basically, we as producers, as Brava, we are expected to pay the export tax for Papa-Terra, although this offload is being sold domestically. Would you like to comment on the pumps?

All right, of course. Before we speak about the pump itself, it is important to clarify the scenario.

We operate a heavy oil field, which is the deepest in the world. That does bring a technical challenge, which is inherent to the activity.

It is only natural that issues will come up and need to be solved. What happened with the ESP, the electric submersible pump, there was not a serious problem.

I don't want to get technical here, but this pump has a system that protects its sealing, and this system has a fluid, what we call a barrier fluid, used to protect the sealing, and we got consumption above expected. We adopted a number of protective measures for the equipment, and the problem kind of solved itself, and now we no longer have any problem with the pumps.

All three ESPs pumps are running smoothly. Just for you to understand, this is equipment that a lot of technology to it, and it's pioneering technology.

The equipment is running really well. The pumps are performing well.

We don't expect any new problem. Again, if that kind of problem happens, we have a spare pump sitting right here in Brazil in case we need to replace the pump.

If needed, we have all of the resources to repair the problem, but we are not expecting to use this spare pump, not in the short, medium, or long term. Perfect.

If I can have a follow-up question in a related topic. Perhaps we have a one-year visibility of work for onshore.

That you have a lead time, a reasonable lead time, if you want to execute projects in Q2 of next year, you have a lead time to get the equipment. We spoke a little about Atlanta, perhaps you need to check the productivity of the wells that will be drilled at Papa-Terra.

Some things have been mapped out. We spoke a little about Peroá.

For a while, we haven't spoken about Malombe.

What would be the list of major projects offshore, thinking about Q2 2027? Perhaps it's too early, but what would be the next big project in this list of projects?

Indeed, it is too soon to affirm what the investments will be. As this investment decision process includes a number of things.

We mature the thoughts. We start with a very conceptual design, and just to share with you, the study we did at Papa-Terra, I mentioned the producing wells, the injectors, we called an outside company to validate our data and information, and they confirmed all of it.

Now we're at the moment of refining. It's not enough to have oil.

The oil has to be economically interesting for the company. As we speak, we are refining all this information to submit it for approval.

This will not happen in 2027, perhaps in the second half of 2027. For Malombe, we get that frequently, and we frequently give the same answer.

Yes, we are assessing Malombe. Malombe is in a queue of the portfolio in terms of opportunities, a queue of opportunities.

It is an interesting opportunity. We requested a postponement of the commercialization authority by ANP.

We're waiting for ANP's reply, and then Malombe will be in the queue of the portfolio. Again, we're being very disciplined in terms of capital allocation.

Right now, we have capex, significant capex, first to allocate, and we are allocating capex with a lot of discipline. We're doing well on budget, on time.

That's what we will do. We'll start production.

Let's validate these production, and only then can we think about organic growth, but again, with a lot of caution, discipline, and respect for our investors' money. Just

to add to that, Rodrigo, we have organic growth already contracted. If you get the average of the wells that are into production at Papa-Terra and Atlanta of about 40% after the campaign, when the wells are up and running, there's an investment cycle.

Really like what Travassos said, in alignment between the operational team and financial team. Again, we have quite a relevant organic growth contracted in the end of 2026 and over 2027.

Again, we are in the process of deleveraging the company. This was the fourth consecutive quarter where net debt dropped.

For the first time in a long time, we got to a less than two times net debt-over-EBITDA ratio. Again, like I normally say, it's not a guidance, but ideally, for an independent oil and gas company to have a ratio below 1.5 times, actually, closer to one time.

Still, we have to capture this potential organic growth to reduce our cost of debt, to reduce our gross debt, to bring leverage to more comfortable levels, and again, to make the company more resilient when we have lower oil prices. Like I said in the final part of my speech, we don't want to have a high prices of oil to create value.

We want to be able to work with lower oil prices, knowing that the company will behave well even facing a more challenging scenario.

Good afternoon, Luiz, Travassos, and Boeri. Thank you for taking my questions.

I have two topics. One, given the significance of the topic, can you elaborate about how hedges performed in the financial results?

I don't know whether there is something related to NDF or a zero-cost collar, or whether has to do with pricing the entire inventory rather than just the ones in the period. Could you please comment on the general effects of hedging in the results?

The second topic, maybe addressed to Luiz and Travassos, speaking about Atlanta, my impression, and please correct me if I'm wrong, the decline seemed to be slightly higher than what we used to model here. If you could comment on that, please, I would appreciate it.

Also, I would like to understand the interaction of that decline in Atlanta and the timeline of the wells and the capacity of the platform, once you have the two new wells, whether the platform will be completed and maybe if you do the management of the wells, you can produce more water, or maybe not. I would be willing to hear your comments.

I will answer the first question, and Travassos the second. There is no mystery about hedge, our hedge.

There is nothing uncommon when compared to other peers. Everything has to go through the financial income.

We use MTM with the future curve, and as contracts are maturing, then you have a cash impact, be it positive or negative. What it is yet to mature, we have to market down due to accounting purposes, we have to market down that MTM forward.

As I said, in the first quarter, the impact was not very relevant, 19 million BRL, because in March, there were some contracts that would mature in April, from now on, the impact would be slightly higher. I understand that the market will look at hedging and will try to look at the impact, but I think sometimes I talk about this mismatch, because you manage a company, and Travassos is looking at projects for 2027, and Boeri doing nitrogen injection, and also we have to manage cash generation for the next quarters.

We started the year with a leverage level 2.4 times we had in the past 3.3 or 3.2, and the scenario not very long ago, everybody was saying and agreed that oil prices would reach $50. To be honest, you couldn't play hero and say, okay, let's go for it.

We have this fiduciary duty of maintaining the company in health conditions and safe as well. Travassos and Boeri, they talk every day about operating safety, and my hat has to do with the financial health of our P&L.

Looking back, I think I would do exactly the same thing. We protected what we needed to protect to ensure cash generation for the company throughout the year 2026, because again, the macro scenario was more challenging, and there was a visible commitment of our investment, and so we decided to go in this direction, remembering that this is not like a hedging strategy that would linger forever, because even though the leverage of the company reached a level closer to a comfortable level, it's not to say that today is not comfortable, but even more comfortable than what we have today, certainly, I think more likely this policy will be reviewed.

We don't have any urgent need to hedge as months go by. Okay.

Speaking about the decline, Regis, we talked about heavy crude fields. It starts with an aggressive decline, and it starts high, and then it's gradually reduced.

Speaking about Atlanta's decline in the last three months, in 90 days, the decline is around 23%, and it's coming down. This number is coming down, the curve is becoming more horizontal in a timeline.

It is in keeping with what we had in mind. It's not any more aggressive than expected.

You also said that in terms of the well timeline, it will start in the first quarter of 2027, and again, we don't want to give any guidance, but there will be a decline, but with the addition of the new wells, we believe that we will be very close to the total capacity of the FPSO Atlanta. We have some flexibility in our operation.

The unit is capable of accommodating or producing 50,000 barrels a day, but it doesn't mean that with that, we would need to close wells, because we do have flexibility, we are very comfortable with what the wells will deliver.