Good afternoon, and welcome to Prio's Q2 2024 Video Conference Call. I am José Gustavo, IR manager, and I will be your host in this event. For those who want to follow us in English, we have simultaneous interpreting through the globe icon on the bottom of your Zoom screen. The translated presentation is available on our IR website. The comments on the results will be presented by our CEO, Roberto Monteiro, our CFO, Milton Rangel, and our COO, Francilmar Fernandes. After the presentation, they will be available during the Q&A session. At this time, all participants are in listen-only mode. To ask written questions, you can use the Q&A button, or you can use the Zoom Raise Hand feature to ask live questions. This event is being recorded and will be available on our IR website.
This presentation contains information based on future estimates and forecasts, based on assumptions adopted by the company, which can therefore change, and should not be considered facts or be used as the basis for financial projections beyond the plans expressed by the company. I turn the floor now to Roberto Monteiro, our CEO. Thank you, Ze. Good afternoon, everyone. We're going to go through Prio's Q2 2024 results. I'm going to start by talking a bit about the highlights of the quarter, then I'm going to talk about the environment, safety, our people, and then finally, I'm going to talk about our next steps.
Starting with the highlights of the period, I'm going to begin with perhaps the biggest point of attention, which concerns Wahoo's environmental license and the permits we are waiting for in order to resume production in some of our wells, in particular Tubarão Martelo, TBMT, and Frade. This whole quarter, this has been the underlying issue. This issue that has been going on, that has been going on within IBAMA since January, it has impacted us a lot. The Wahoo project has not received its environmental license yet, and coupled with some other wells that have stopped producing. For these wells, we need IBAMA's approval to start producing again. All of this has been held up, and we're monitoring up close the solution to this standstill that has arisen between IBAMA and the government.
We're monitoring this with a lot of attention so that we can resume our growth projects. As a reminder, at Wahoo, we're talking about 40,000 barrels a day, TBMT, about 5,000-7,000 barrels a day. We have one more well, ODP-3 at Frade, which means a little over 1,000, 1,500 barrels daily. So we have a lot of our production being impacted by this situation. This, I believe, is the main point of attention for the quarter. And it's something that had a bit of an impact in the Q2, and now from Q3 onwards, it's going to have a bit more of an impact, mainly on account of Wahoo. Well, even so, we had an average production of close to 90,000 barrels daily, a lifting cost of $7.6 per barrel. We sold 8.5 million barrels.
I would like to highlight our PRIO trading. We got a very competitive commercial discount on the average of our oil sold, a discount of around $3.56, if I'm not mistaken, $3.60 almost. So good commercial discount. A large part of that is due to the work we put into delivering our oil to our customers. All of this together, with both the lifting cost and the trading, coupled with our costs, all of that led PRIO to an Adjusted EBITDA of $546 million, up 60%–64% compared to last year. This was the second highest EBITDA in our history. The highest quarterly EBITDA in our history was in the third quarter of 2023. It was a little higher than this one.
So we posted a strong result, despite this setback with the setback that we've had, that we are still having, we're suffering, especially in relation to environmental licensing. Well, the consequence of this very strong EBITDA is a reduction in our net debt. Today, we have a cash position of almost $1.2 billion, a net debt over EBITDA ratio of 0.4x . So this is an increasingly healthy company generating cash, but yes, with this licensing issue still very latent. Moving on to the next slide, I think it's worth pointing out... I mean, I've already mentioned it, but what I wanted to stress is our cash position at $1.16 billion. Actually, $1.156 billion, and our net debt over EBITDA ratio at 0.4.
So the company is very solid and fully prepared for the challenges that lie ahead, the implementation of Wahoo ... and the M&A opportunities that we've been pursuing more and more, and that are starting to appear in some form or another. The company is very well prepared. I'll hand over to Francilmar, who will talk a bit about operations, then Milton will speak about financial performance, and I'll be back to wrap up the presentation. Thank you. Hello, everyone. Thank you, Roberto. I'm going to start on slide 5, which shows our asset performance. This was another quarter of a lot of struggle, work, a lot of commitment from the entire operations division. It wasn't an easy quarter. We had some production losses due to wells that halted production. We didn't get the authorizations.
We weren't able to carry out maintenance on these wells, which ended up having an impact on production. As a result, we had to work harder on cost management to keep the lifting cost at the acceptable levels that we fight so hard to achieve here. We ended the quarter at $7.6 per barrel. Although one field produced a little better, another a little less, overall, we managed to deliver a number within the range we were looking for. Going a little deeper into our lifting costs on slide six, we see that this quarter was a little higher than in the previous quarter, largely due to the loss of production from some wells. There was one well at Frade, the TBMT wells. So we ended the month of June of this Q2 with a lifting cost of $7.6.
We all remain committed to it, which is the primary focus of the company. We repeat this mantra here all the time, so that everyone works with a safe operation, with the best possible efficiency, which will give us the best production cost. This is what is going to ensure that we have a brand new, resilient company. Moving on to slide seven, let's take a look at the detailed performance of each asset. At Frade, this quarter, we had good efficiency, although we are still suffering from the loss of production from ODP3, a well that had a problem, and we still haven't managed to carry out the maintenance in it, as we need to get the rig in. But for that, we need IBAMA's approval, and there's this whole issue that most of you are following. The approval is taking too long.
This is something that used to come in a very short time, and now it takes months and months. As soon as we have a solution for this, now that the other wells have stopped production, we're going to have a queue of wells that we will have to manage. But we have the resources and conditions to do this, and we are just awaiting a green light. On slide eight, we have TBMT and Polvo. Here we had a tough quarter because we lost wells and production due to the failure of the submersible centrifugal pump, or the ESP, which is the pump that pumps all the fluid, oil, gas, and water. They stopped due to electrical failures, and in this case, we need to do maintenance. We need to replace them.
These are things that happen from time to time, which unfortunately have this unfortunate alignment when three wells stopped in a short period of time. The last well that stopped basically stopped at the end of June, and we're going to feel this even more now in July. The biggest impact on production should be felt in July. We should see now in the operating data for the month, and this puts further pressure on the lifting cost. So we are trying to get around it one way or another. We're going to live with it as best we can until we get the green light to go ahead with the necessary maintenance. But we've been doing this for a long time. We know how to do it. We just need a green light. Moving on to slide nine, we are going to talk about Albacora Leste, ABL.
It was a good quarter at Albacora Leste, with a lot of operations at the field, a big effort to improve maintenance and reliability. We saw improved efficiency at around 85%. We are following the plan. Over the next few months, we are going to deliver major pieces of equipment that we are servicing, the power generation system, the compression system, which will improve the asset's reliability. There are some things that are still fragile, which need to improve, but with some redundancy and some muscle in the asset, we are going to aim to achieve 90% efficiency very soon. Also, in this quarter, we delivered maintenance that was carried out in the subsea system when two new wells were put into production. So production has improved.
Some wells are still in need of maintenance, and we are working on that so that over the course of Q3, we can deliver something more. So we'll continue to work at ABL. In July, to give you a general update, we had a scheduled shutdown at the asset for major maintenance, which is why we expect to see an improvement in reliability in those wells that were fragile and issues related to mechanical integrity and some major maintenance. We stopped, the asset was offline for a little over two days. This will have an impact on production. In other words, it had an impact on production in July, but it's back online. We're already producing normally. Some maintenance on some wells is taking a bit more work, but everything is moving towards stability and improvement of the asset in the coming days and months. Well, on to Wahoo field.
Just a quick update. For Wahoo, we practically have all the materials, all the subsea and well materials are ready for the topside part. We've slowed down a bit in order to be able to do it in line with the drilling schedule, with the subsea installation schedule, so it's under control. The only thing not under our control is environmental licensing. So we are still waiting, doing everything we can on our end. We're always available. It's a field that already had a drilling license, has several wells drilled. It's a deep water region. We're providing all the information. I mean, we can't see any limitation to this, and we're really just waiting for the green light, and we hope to get it over the next few weeks. We're ready for it, with the rig, with the vessel.
Even for the installation vessel, we have alternatives A, B, and C. We're ready for anything. We'll adapt, and we'll deliver as soon as possible. That concludes my part. I'll turn the floor to my friend, Milton. Thank you.
... Thank you, Francilmar. We'll continue our presentation on slide 11, to talk about PetroRio's financial performance in this period. While starting with offtakes, we sold 8.5 million barrels of oil. Considering that Brent, our benchmark Brent, was around $85.35 in the period, and our equivalent selling price, FOB, was $81.86. So we had an implicit discount of approximately 3.49, $3.50 per barrel, which reinforces how successful our trading strategy has been, how well executed it has been. As a result, we had total FOB revenue of almost $700 million. In addition, well, it's worth noting that we had other revenues that fall into that line of non-recurring items of almost $40 million.
This is largely explained by the fact that we were successful in some lawsuits, some tax claims, fiscal claims from the time of Dommo, which we inherited after the acquisition. So in fact, these were possible losses that had been provisioned for, that were contingent in our result. And because we were successful in these cases, they ended up being reversed in the result. But again, it's something that would have an impact on our EBITDA. However, we show adjusted EBITDA, precisely to exclude this type of impact. So with that, our adjusted EBITDA was around $546 million, more than $1 billion in the six months of the year, year to date. A super strong adjusted EBITDA margin of 78%.
Moreover, I would mention another highlight in the income tax and social contribution line, is that we had a high negative figure, a small part of which, around $40 million, is actually related to current tax. Which is the tax that is most present in our day-to-day operations. And the difference, a little over $140 million, is related to deferred tax. So this is an accounting figure rather than a cash one, and it basically relates to the way we present our results and the way we calculate taxes. Our functional currency is denominated in U.S. dollars. Taxes are calculated in Brazilian reais, and in this period, there was a sharp currency depreciation. So our projected taxes, our forecast for future tax payments, had a negative adjustment due to this currency variation.
But still, we were able to turn a profit of $272 million, a very significant result for our quarter. Well, now on slide number 12, we talk about funding, a summary or a picture of the company's funding. I think that the main highlight was that recently, in the last few quarters, we managed to increase the company's duration through a series of transactions, mainly in the local debentures market. But without significantly increasing the average cost of our debts. We went from a duration of 2.33 in the Q4 of last year, to more than 3.5 in Q2 of 2024. And in that period, we only increased by 16 or 17 basis points.
I think it's worth pointing out that we are very attentive to market opportunities, especially with regards to liability management, as we can see in the amortization schedule chart. We have some bilateral debts, mainly maturing in 2025, of $225 million. In the dark green bar, we see our international bond maturing in June 2026. Therefore, we are very comfortable with plenty of time to manage these liabilities. We are also very well-funded, with very little leverage, as we will see further on. Therefore, we are in a very comfortable situation, which allows to see the best time to manage these liabilities. On slide 13, we see the variation of net debt, which is nothing more than a reflection of the cash flow from the first to the Q2.
We started with a net debt of $975 million and reached $740 million in Q2, meaning that we managed to reduce net debts through cash generation, which is basically explained by the strong EBITDA of $546 million. We had a refund of legal fees from the Wahoo arbitration, so that there was a cash inflow. Working capital is quite negative at $131 million, which is largely explained by the fact that this EBITDA includes oil sales, but we haven't received any cash yet, so we increase our receivables in the purchase of inventory and items of this nature. We continue to buy back shares opportunistically, and at certain interesting moments, we ended up investing... I mean, buying $19 million in shares. CapEx amounted to almost $100 million.
That is, life in the company goes on, and despite the challenges of environmental licensing, we continue to invest in Wahoo. We also made investments in integrity, in Albacora Leste, drilling in Polvo, and items like that. Financial result stood at $31 million, plus payment of taxes, cash $40 million dollars, which bring us to this net debt of $740 million at the end of the Q2 of 2024. Now, moving on to the next slide. Here, we talk a bit about our capital structure, debt position, and this is an indicator that we monitor very closely. Net debt over adjusted EBITDA for the last twelve months, which is also the main covenants of our loans.
So we are currently at 0.4 times net debt over EBITDA, which shows quarter after quarter, this drop due to the company's cash generation, which has been able not only to fund our CapEx, but also reduce this net debt. The trajectory, therefore, is excellent. It points to a reduction in net debt and leaves the company super comfortable, funded, and also prepared for new investments. With that, I'll hand over to Roberto, who will talk a bit more about ESG and Prio's next steps. Thank you, and have a good afternoon.
Thank you, Milton. Well, talking a bit about environment, society and people, I would like to draw your attention to the first point, which relates to the rate of emissions. We were at almost 22, meaning 21.9Kgs of CO2 per barrel of oil equivalent.
This was a 9% improvement over the previous quarter. There was a worsening, let's call it, a slight worsening compared to our best quarter, which was the third quarter of last year, I mean, the Q2 of last year, largely due to production volume. The emissions rate is very much related to production. It's obvious that once we have the environmental license, when we manage to implement the project and so on, this figure of 21 Kgs of CO2 per barrel of oil equivalent will drop, I would say, near something below 18 Kgs of CO2. But again, we depend on the environmental license, which in addition to generating jobs, taxes, royalties and so on, will also contribute to a reduction in the level of kilograms of CO2 per barrel of oil equivalent.
In regard to safety and well-being, we just had a safety, safety month campaign throughout the quarter. So in addition to safety, which is also and always non-negotiable for us, we continue with our yoga, volleyball, martial arts programs, jiu-jitsu, in particular, trekking and so on. And that always brings a great deal of engagement among our, our employees, and we will continue to sponsor some events to promote social inclusion through sports, also to support culture and so on. We launched the third edition of Reação Offshore, which is an educational program, aimed mainly at transforming the lives of young people who are not currently in the oil and gas sector today. We bring these young people together in partnership with Instituto Reação and Instituto Todos na Luta.
We train these young technicians and non-technicians to be able to work offshore, and then we select some of these, 180 young people. Those were those selected this year, and then they are ready to join our staff here at PRIO. The young people who don't get this opportunity can join in other years and can also join other companies in the industry. This is a program that helps us and also helps the society by training people to enter the oil and gas market. Now, I'll move on to the last part of the presentation, and I'll talk now about our next steps. Some of them have been repeated here for a very long time. Obviously, the first one being the focus on the health and safety of our employees and third parties. Then the last point is also always repeated.
But now, we are drilling wells. We intend to drill two wells at Polvo, so we'll see if we are successful. If we are successful, we'll put them into production. These are things that could bring 1,000 barrels or 1,500 barrels from each of these two wells. We are still very much focused on the environmental licensing of Wahoo and the permits for the workover, following very closely the possible outcome of this IBAMA situation. Also, we are working hard on the operating efficiency of Albacora Leste. In Q2, we had the best operating efficiency of Albacora Leste to date. It was over 85%. The second-best figure had been in Q4 of last year with 84% and a bit.
Albacora may not be moving at the speed we would like from the point of view of improving operating efficiency, but it's certainly moving in the direction we've set it to be. So we sure recall that we started this field with an efficiency of less than 70, and today we are already at 85, and our goal is to reach something above 90% operating efficiency. In July, we had 13 days of downtime. In addition to these 13 days of downtime, you have to add the ramp down, something that doesn't happen overnight. We've been shutting down gradually. It takes at least four days to resume production, and that's what we call ramp up. The net of this is not 13 days, it's more than 13 days.
But we went through many maintenance items, things that have been neglected in the past, and so we hope that this is another very important step towards improving our operating efficiency. July, obviously, production has been low, mainly due to this shutdown, but we understand that it's an important shutdown, and it's a very relevant one, because it allows us to improve the integrity of the unit and improve the efficiency of the unit. We—in the next quarters, we will focus on the Albacora revitalization campaign. We've finally received and we've already received a large part of the Albacora Leste seismic. So now we already have a very good idea of the campaign. But now, with the reprocessed and improved seismic, we've been able to do some fine-tuning, and then be sure of what to drill, how to drill, and so on.
This is what we are going to do now throughout the second half of the year. So as soon as we have the opportunity, meaning get the environmental license for Albacora, we will be able to carry out a campaign very similar to what we did in Frade. Finally, the last point, which always comes up, is that we continue to be attentive and excited about M&A opportunities. We see some things starting to move in the market, and this makes us excited because, as we know, Prio doesn't work with pure exploration of oil fields. So an M&A is always a super relevant and very important entry point for the company. Well, thank you very much. I would like to thank the determination and discipline of all of our employees and all the people who somehow interact with Prio.
We are always very well received by society, always very well received everywhere. And I would like to say that because of the Wahoo project, it hasn't been the year we had planned. However, the other items that surround us, such as operating efficiency, maintenance, et cetera, we've been able to move forward, and we've been able to improve even more. Well, thank you very much. And with that...
Good afternoon. Thank you, and welcome to the Q&A session to discuss Q2 2024 PRIO's results. We'll start now with Pedro Soares with BTG. Go ahead, Pedro. Good afternoon to the whole team. Hope you're well. Well, I guess I'd like to ask two questions. The first is about Albacora Leste. It's very clear, Roberto, Francilmar, you spoke about the target of reaching 90% efficiency for the platform, especially after the maintenance. But perhaps you could tell us in terms of what you're expecting in terms of production from August onward, if we go back to those levels of 27, 28, is that feasible now, or is this conservative? So that's number one. And the second question regarding production at Polvo, you mentioned drilling of two new wells. When should we expect them? From what I understood, at least one of them is being finished.
I'm not sure about the second one. So what would be the timing for these two new wells to go online and expected production? My second question is regarding Wahoo's CapEx. Obviously, for a lot the reasons mentioned over and over here, it is late, particularly the topside, you slowed down. That's what Francilmar Fernandes said. So perhaps you could help us translate this into … in our model, in addition to those four wells linked to the CapEx. Four wells, kind of easy to imagine. So for the $800 million that were forecast in the beginning, what's still left? We, we just want to understand what is the expected cash outflow in the coming quarters. Thank you.
I mean, the timing regarding approval by IBAMA.
...Well, for Albacora, today we are producing 27 or a little more. Would you like to speak about operating efficiency? When do we think we'll get there? The maintenance work we did will give us better conditions. We opened wells, we're working on some others, and our goal is to leave 27 and get close to 30 during this year. For Polvo? Well, well, let me speak about Polvo. At Polvo, we had a first well, an appraisal well. We drilled in a region where we had a similar well. We confirmed that there's oil, we found it, and now we are designing a producing well. There's a second well for us to research, so it's moving ahead. In terms of timing, should take about 1 or 2 months for the project to be complete. And Wahoo?
Well, as for Wahoo, everything that relates to equipment, we are practically done. We have purchased everything, we've paid for everything. It's all ready. And I mean, pipes, lining, isolation, Christmas tree. I mean everything, pumps, manifold, it's all there, either ready or close to be ready. So we spent everything that we needed for those. I would say that we probably spent close to $600 million. That order of magnitude, I haven't got the precise number. I can find the number and give it to you, Pedro, but it's around that order of magnitude. And the installations will be done later. Installation means drilling rig time, time to drill, all ancillary costs of the equipment involved, that's all taken care of. So and there's also the pipe laying vessel. So something between $500 and 600 million.
The rest will come, particularly after the environmental license. After we get the environmental license, we'll spend about two months, 70 days for the well, about eight months, and we just have to distribute that along eight months after we get the environmental license. I think that this is a good estimate for us to give you.
Clear. That's, that's what I had.
So it's more linked to the drilling. The rest is basically done.
Okay. Thank you, Francilmar and Roberto.
Thank you.
Our second question comes from Caio Ribeiro with Bank of America. Go ahead, Caio.
Good afternoon, everyone. Thank you for the opportunity. My first question is about Peregrino. Some news mentioned that the company would be involved in evaluating the asset, possibly acquiring the Sinochem working interest. Could you give us some more color on how this process is evolving? When do you expect a decision, a completion of this process? That would be helpful. Secondly, still linked to this, I understand that the process is competitive. There are other players interested. And therefore, if the company doesn't go through with the acquisition of this stake, how would you do about capital allocation? Would you be considering other assets for this year, or would you choose to distribute part of the cash generation this year to the shareholders? Thank you. Well, there has been news in the papers that Sinochem is moving or thinking about moving regarding that.
In the past, this was our understanding, so there's not much news here. It is obvious that if this happens, if they move, we're interested. It can be an interesting opportunity for us. We know that today could be a non-op part, and then we might have a deal of the Equinor stake. So of course, it's an asset that is interesting to us. We'll look at it up close and carefully if the process moves forward, well, if the process becomes hot. As regards dividends, and of course, we're always very vocal about first, M&A, seeking the returns that we always pursue. And if we don't find M&A opportunities, then we would consider other ways of remunerating our shareholders through share buyback or dividends. We already said it in the past that we like the Gulf of Mexico, the American part of the Gulf of Mexico.
So today, we are looking into some opportunities in that area. Every three months, we have a meeting about the results, and that's when we discuss these M&A opportunities in more detail. What we try to gauge is whether we have visibility of things that can materialize in the next 12 months. If there are no possibilities of materializing in the next 12 months, then we would adopt a more aggressive share buyback policy, or think about dividends. But if we have something more tangible, more palpable for the next 12 months, our decision is always to keep the cash, to go through with the deal. That's how it works, how the business works. So right now, we are clearly focusing more on M&A deals.
From the standpoint of remunerating shareholders via dividends or share buyback, what we will do is opportunistic buyback of shares. We spent $19 million this quarter, in Q2. That's not very relevant for our cash position. I mean, it's – it really depends. We don't think that our share price is adequate, but there's the IBAMA issue. I mean, the price, the market will price our shares in any way they want. But when there are some share prices that we don't agree with, we'll buy the shares back, because we want to bring serenity to the market. That's how we work. Today, there is a greater bias towards M&A opportunities, and that's why we haven't been speaking much about share buyback and dividends.
I'm not saying there's anything imminent, but yes, we have a constructive approach about M&A in the next 12 months.
Perfect. Very clear. Thank you, Roberto. Thank you, Caio. Our next question is from Monique Greco with Itaú BBA. Go ahead, Monique. How are you?
Hello, Roberto, José, Francilmar, Milton. Thank you for the opportunity to ask a question. My question is about Wahoo, and maybe this adds up to Pedro's question, and then I have another question. About, yeah, Wahoo, you, you gave us a lot of light in terms of CapEx, but could you elaborate a bit more about Wahoo's critical path once all the licenses are in hand, particularly in terms of type, topside works, you know, the pipeline? Because it's important that we understand where the bottleneck is. My second question is, the Q2 experienced a strong exchange appreciation, and the trend remains. So how do you think we should see this exposure, giving it an over-depreciated exchange rate and the lifting costs going forward? Thank you.
Okay, first of all, Wahoo. Environmental license, basically, here we have two avenues at work. One is drilling, and the other one is the installation. Drilling, and I do apologize on behalf of the drilling people, it will take 60 days for the well. I know it's a lot more complex than that, but roughly speaking, every 70 days, or maybe, you know, give or take a bit more or less, there will be a well ready to be connected. In parallel, there is another license, which is the installation license. This license, and, I mean, subsea people will say that it's much more complex than that. You have to lay a pipe from Frade to, yeah, Wahoo to connect the wells. And this process, maybe after the license, should take about two-three months. So after the license, after the vessel arrives, et cetera.
So this is the process. And depending on when the licenses are issued, things will be connected. So after the connection, after two-three months, you get the first oil. And the first oil will happen with one well connected, two, three or four. But it will certainly depend on when you start one, and when you start the other. In a very, you know, simple way of speaking, I mean, people did some excellent work in relation to the vessel. There was a matter, bottleneck. We removed that bottleneck, and with that, we got another vessel, a Sapura. We got a second vessel from Sapura. It would be ready in September of this year, so starting next month. So the window for pipeline laying would be up until December, but we need the environmental license from now until the end of the year.
Well, if that license is not available, we will continue negotiations with Sapura, but this time, I mean, Sapura could sell windows in the vessel starting in January, from January onwards.
... We have an agreement that for every window they sell us, we'll always look at the next available window if, and we say whether we want to keep it or not. Otherwise, they would just keep on going with their negotiations. And I think in terms of the vessels, things are much better now. The major issue here is the environmental license, and because that's what it takes to start as soon as possible. Everything is ready. We had to demobilize some people, because a lot of the things that we hire, we hire from third parties, from other companies. I'm not gonna hire somebody to do drilling, if we're not drilling right now.
So in the Q2, had a lot of these dynamics, and today, I would say, like, we are hibernating, or this is a period of low consumption of expenses, just waiting for things to go back to normal. For an exchange, we always say that our lifting costs, at least half of it, is denominated in BRL and the other half in USD. I think today we would be more into US dollars than BRL, but with the depreciation of BRL, we have a better lifting cost. But we haven't seen large differences this quarter because the depreciation of the BRL occurred mostly in the last 45, 30 days, so it didn't cover the entire quarter. But certainly, it helps us because part of that $7.6 that we maintain in terms of lifting cost, stems from our cost structure.
I'll give you a personal example. I mean, personal in my areas, not in US dollars. Personnel. Personnel is not just half of our lifting costs, of course, but there are many other things involved that in the short term, doesn't move the needle, but in the long run, many of these things get adjusted. That's why I was saying that in the long run, our BRL percentage will be closer to 40%, maybe. Or maybe 35%, but in the short run, half of it is denominated in BRL. Great. Thank you for this clarification. Have a nice afternoon. Thank you, Monique. Our next question comes from Luiz Carvalho with UBS. Luis, the floor is yours. Hello, good afternoon, Roberto, Francilmar, Milton, Ze. Thank you for taking my question. I have two questions, and I would like to revisit the issue of M&As and the industry's consolidation.
You, I think you were the first players to be intermediaries, intermediary companies, you know, in terms of Petrobras' size in Brazil. I don't like that term, but it would be like a junior company compared to Petrobras. Now we see, be it for market share, production volume, and the size of your P&L, there is now another player that theoretically could probably get closer to PetroRio when it comes to competing for potential acquisitions and M&As. Do you think that this could bring higher competition to you? This could mean a higher competition to you. Do you see room for other similar moves of acquisitions of assets or even companies as a whole? So how do you see the landscape of industry consolidation? And my second question is related to the U.S. election.
You talked a lot about going to the Gulf of Mexico, but in terms of the election or what candidate wins, whether that could have an impact on that move. Now going back to capital allocation, this is a question that has been already mentioned. I understand that your priority is still to focus on possible acquisitions, but your deleveraging level would allow you to do that. Even, you know, if you do some basic math, you could do that without having to put your balance sheet at risk, and you still would have some room for dividend payout. So what will be the limit? Very soon, you, you may be, you know, cash net. So what about the acquisition process? I just wanna have a feeling about the timing. Thank you. Okay, I'll start backwards.
Now, speaking about this limit, we like the company having 1x net debt over EBITDA, and we do that considering our M&A expectation. We look at the size of things that are around, and we try to prepare the company, because as being successful, maybe we could at least get to 1.1, like we did with Albacora. We got to 1.1, 1.2 of leverage level, and then we start deleveraging. This is pretty much what it's on our minds.... Well, if we say, okay, we're not gonna buy anything, there is nothing else, there are no more opportunities, so maybe we could pay out $1 billion and nothing would happen. I don't even know that if with that, we would reach 0.6. Maybe at the most, 0.8, and even then, it would be a low level of leverage.
For us, the most important thing is to have M&A visibility. Having it or, or not having it, in our mind, we want to reach that level of 1.1. Today, there is a mismatch because we are super leveraged. I mean, I know that the current level is very comfortable, but I don't like it, 'cause obviously, it's, it's, it's not optimal, it's below that, and I hope that we can change that situation soon enough. We do have visibility in terms of doing something in the next 12 months, but it's very important that we move very carefully, because processes could happen or could not. I, I don't like this position of 0.4. I don't think it's fun. And now, in terms of the U.S. election, one of the important things about the U.S., and the- we like the U.S. because their regulation is stable.
Of course, there are candidates that lean towards one or the other side, but the bulk of the rules, they remain. Of course, there are changes, developments. I mean, there are lots of changes in terms of security. Now, in the recent past, there was a company, I can't recall the name. I won't remember the name now, but there was a company that acquired assets from a major, and they got into Chapter 11, then that major was forced to comply with some relinquishment rules, and this changed a little bit, the way majors look at things. Of course, these things can happen, but we think that these things happen regardless of who is in charge or who is the president. We believe that the U.S. president talks more about new, new leases, new leases.
So maybe there is a more relevant role in the price of oil related to our capacity to go or not go to the Gulf of Mexico. I mean, it's limited. It's not just like you can say, "I'm gonna open more licenses for people to go into the U.S., and then this will increase drastically." No, that's not gonna happen. I think these moves are more limited. Today, we are not seeing any impediment, any major impediment. Certainly, we're gonna look at it very carefully. We will monitor the electoral campaign very carefully, but we think that there is less volatility in the U.S. regulation, and that's why we like that environment. The last question... What was the first question?
No, it was more about competition.
It was about competition. The consolidation, we saw that move, that recent move. I can't say if this new company that was created, that you mentioned, would impact our financial capacity or, or our P&L, or our execution capacity in terms of other projects. I don't know. I particularly believe that this combination of onshore and offshore will increase complexity. I know that there are some people who think exactly the opposite, but I believe that this integration between onshore and offshore increases complexity, because the way to operate, you know, onshore and offshore is different. One is labor-intensive, and the other is not as much. In one case, you have lower margins, and you have more difficulties in terms of offtake, et cetera. And on the other hand, the other case, you have, you know, more relevant CapEx because of prices.
So the similarity is oil production, but the way to operate onshore and offshore is different. So I'm very skeptical to combine. To bring onshore to PRIO, because I think this will mean a deviation of our focus. And I believe on the story of one-trick pony. You have to do one thing, operate offshore, and we are not even doing explorations very well. So that's a no-go for us. And I think that operations in Brazil, in our case, I don't see that coming for us. I think, as I said in the past-
... there, there is that Peregrino thing. There might be a transaction here or there. Maybe another offshore field in addition to Peregrino Field that we may find. But today, I think that this will be a no-go for us in terms of participating in any kind of consolidation in the market, bearing in mind that particular characteristic of onshore versus offshore. Perfect. Very clear. Thank you. Thank you.
Next question from Gabriel Barra with Citi. Go ahead.
Hello, thank you for taking my questions. Some points I'd like to clarify. First, when we look at the assets, you made that you have the Hunter Queen and thinking about more, a tight, a more tight scenario. But because of the IBAMA issue, it just sat there with no service. In some previous conference calls, I actually asked whether you could use this rig. I understand that there is a difficulty in terms of not knowing when you'll get the license. It's hard to get organized around that. But are you thinking about doing that? Do you have any possibility of putting these assets to use while you're waiting for the license? And perhaps, if you look at Frade, Albacora, some overlapping licenses, could we think perhaps about having two rigs operating at the same time?
I remember that the plan was to do it in phases, one at a time, but I'm wondering whether there would be a possibility to do something concomitant to accelerate production cost more towards 2025, 2026. The second point is a more philosophical discussion. You spoke a lot about capital allocation, what to buy, what not to buy, where to go. And perhaps my question is, I don't know whether there is any answer, but what would be the ideal company size for Prio? What would be the ideal size for you to balance the synergies that you have in the operations you do well in mature offshore fields? And also putting into perspective this internationalization to the United States, to the Gulf of Mexico, perhaps it could be a future cluster for the company.
So if you could speak a little about this philosophical point, we just want to understand what would be the very long, long run of PetroRio. Thank you, Gabriel. All right. As regards to rig, yes, we could provide services. We are constantly approached to provide estimates. The truth is, no one is getting the environmental licenses. But yes, we, we are approached, and we have chosen not to go ahead with that. We have used the rigs for a number of things. We used the rig in the beginning of the year for an important maintenance at, at FPSO of Frade. We used it as a heavy lift. This, this rig is a big goal scored. We used it as a heavy lift to take some cargo to Frade.
Instead of going to the market to get some heavy lifting, we used the rig with 150% safety. Today, we have the TBMT wells waiting for permits. Perhaps that will arrive before Wahoo. So getting the rig being used by other companies would be bad, because we are going to have some work for the rig to do very soon. And just last week, we have just installed the acidification system in Albacora. Since we reinject 100% of the water, we need to re-acidify the wells from time to time to improve the injectability index of these wells, the amount of water the wells get. Acidification is more like cleaning the well. And traditionally, well, Petrobras used to do it using an acidification vessel, which is a scarce asset. Petrobras has it in their portfolio. We don't have it.
Whenever we needed it, we would try to look for a window of opportunity to use some. So we did a scheduled shutdown of Albacora, and we did it with a rig. We installed an acidification plant at the rig, and we acidified the wells. So we did it with the same efficiency in a matter of one week. One week, right? So we acidified the Albacora wells. So the rig is shown to be great. Although it's not actually drilling, it has shown to be a great investment, so we're more willing to keep it. I mean, there's no constraint in providing another service, but today we prefer to keep the rig in our portfolio under our full control. Well, you see, the rig is a strategic asset. It was purchased. It was designed to be like a Swiss knife, as we joke around here.
Depending on the market, the rig, we would pay $150,000-200,000 daily. Now it's more than $500,000, in some places, more than $1 million. So having it is already a big plus for the business. Now we have to look for market opportunities. If we get something that makes sense, and if we can do it, yes, we'll use the rig. We have capacity to operate both rigs. If we find a second rig, that makes economic sense for us. Renting a rig at $300,000-400,000 a day, we are not gonna do it. And we won't even find a rig. Even if we had, it wouldn't make sense. But we paid $170,000-200,000 for a rig that's more expensive than ours.
But it could make sense. I mean, so that's what we are thinking, Gabriel. Regarding the ideal optimal size of the company? I think that we have a lot of room. As long as we don't go work in something very different, for example, onshore, which would be totally different than our focus of attention, I think that we have a lot of room to grow. It's just a matter of having the projects. For example, imagine that Peregrino, Peregrino is on the market and, and the Sinopec deal, 40,000 barrels. The reality is that well, we have to put an operating effort. I don't think that there is a limit to growing. It's a matter of what we can do within our mandate, i.e., the return on the investment that we always pursue.
And as for the Gulf of Mexico, to me, either we go there, we put together another cluster, put together a big company in the Gulf of Mexico. To go there to a non-opt 5,000 barrels daily production, it doesn't make sense. Either we go there firmly, and we are monitoring Wilcox, 20K, the higher pressure area, whether it's going to give us a result or not, and if there's a migration of the majors to that area. If we can go there and do there what we can do in Brazil, either this is the gameplay or things will not make a lot of sense. It won't make so much sense for us. But I don't know that there is a limit in terms of barrels. I may give my opinion. It's a matter of the game philosophy. I have a strong belief in defining onshore, offshore.
I came from offshore. I know that reality. We have a work philosophy. We have the Prio method of working. The more specialized we are in our business, the bigger the potential to create value. So it's all about replicating the same working model, execution, or the near field exploration and maximizing, maximizing the effort. This is reproducible. We'll only put our field, our team in the field where it makes sense. Where there's water in the field and the right conditions, it would be interesting for us. So we have to take into account legal assurance and the business dynamic. I mean, we cannot just say that that would be the size of the company. In the past, when we started producing, we spoke about 100,000 barrels daily to become a junior in size. We got to 100,000.
Today, we didn't produce 100,000, but this is momentary. Well, we spoke about 100,000 barrels to become a company that is taking off and that is flying full speed. So that was the mark. But if you look at the rest of the world, there are a few examples. If we look at the super independent companies, they produce 400,000, 500,000 barrels. Some companies do get there. It's not the end of the world. I mean, we don't think that we have to get to a certain number of barrels daily. But our, our focus is not just the, the oil barrel, it's the oil barrel with the right return we should have. But I think that this is totally feasible. We want to continue to be an independent company. If we become a super independent company, great!
There are examples in the world of companies producing 300, 400, 500 thousand barrels daily, and they remain independent. I don't think we are actually close to, not even close to that limit. Okay, thank you. Next question from Bruno Montanari with Morgan Stanley. Bruno? Good afternoon, and thank you for taking my questions. My first question: if you could give us an update on the current level of production at Frade and TBMT, and in the current situation, what would be the end of the year like? It would be interesting. Second question: Is there any extra cost that you incur when you mobilize all the equipment for Wahoo until you get the license and you actually start working there? Is there any maintenance risk involved? Because this whole material is sitting there, mobilized.
Thirdly, out of curiosity, is there any alternative solution for this setback with IBAMA so that you can carry out the workovers? After all, it's not a license for a totally new project. Is there any legal path, any yellow brick road, in case this mobilization of the equipment continues indefinitely? Thank you. Let me address the second question, and then you can speak about production. No, well, getting a permit is easier than a license. There is a philosophical discussion that we have with IBAMA. Our discussion with them is whether it makes sense to get a license, and after the license, we have to get a permit for everything we're going to do.
If they tell us what we need to do and how, we shouldn't be able to go to the agency again to say, "Look, I'm going to do this now, in this way." IBAMA's assumption is that we are going to do it wrong, so we need to get a permit to do it right. In other jurisdictions in the world, we don't have that. Once you get a license, you execute things according to the license. If you do something wrong, you are going to suffer the penalties of the law, because you did something wrong. But again, this is a philosophical discussion with IBAMA. Nothing to be changed. So I think that the permits, well, that's something we need to get. And as for a legal discussion, we try to avoid this as much as possible. It's no use creating this animosity or, you know, start fighting IBAMA.
If we take this to courts, it will be very hard for a judge to analyze the project from the environmental standpoint and just overrule IBAMA. The judge would always say, "IBAMA, this is it. Please give us your opinion." If that is the case, we prefer to just sit with IBAMA, have a conversation with them, which is what we've been trying to do since the beginning of the year. But, you know, that's the path we continue to follow. And Francilmar Fernandes, we'll talk about production. All right, for Wahoo, we didn't mobilize anything relevant. We commissioned all of the items. The rig was conceived to replace the rig we had before. So it's not for Wahoo, it's for the whole company. It worked at Frade, at TBMT, now at ABL. So the rig is like a safe, a safe margin.
One of the works for the rig is Wahoo. Until then... I mean, there's nothing specific for Wahoo. So there's a rig, a rig that works for the whole company. The things we're going to mobilize for Wahoo, when we're going to drill, those things are more specific. They are not mobilized. They don't generate any maintenance. And the new materials are with the suppliers. So we have to pay for storage, but it's not a big cost, nothing that could hurt us, just to give you some peace of mind. How much does the rig cost per month? The rig costs us $3 million per month. Whether we're going to allocate the rig to Wahoo or the rest, this is what it costs for the company: $3 million, and we apportion it accordingly. And as for production, you asked about Frade and TBMT.
Frade, we're ready to go to, go to the field for the project. There's something being studied. This will be more towards the end of the queue. This field will see a decline. We had a more marked decline in the beginning of the year because we had arrival of water in the new wells. To give you an idea, Frade production is kind of 50% from the old wells and 50% of production from the wells we drilled in the last two years. So the new Frade production accounts for a little over 50% of the field's production. Since the wells have a, a pattern, they start producing, and then there is a decline. So we are past that phase now, and we can see a change in the shape of the curve, a curve that is now stabilizing.
So we'll wait the end of the year for a little more decline. The only certainty we have is that the well will produce tomorrow less than it produces today. And we believe that there will be some decline, and we'll see 43, 42. Well, we'll manage that. We are all here for the long run of the company. So sometimes we try to accelerate, to bring the curve forward, but that can make us pay a higher price later. So we are managing this in the best way to ensure the best recovery factor. At Frade 1P, the average per year for 2024 was 46,000 barrels daily. Net of ODP3 would be almost 46,000. We should deliver 2,000 barrels less than that average, something around 44,000 as the average for the year.
And this is the effect of water that arrived earlier in the reservoir. It's very hard to get this precisely, particularly when we have reservoirs like in Frade, where there are fractures. We don't know whether the fractures are connected to the aquifer or not, so there is a difficulty in modeling this business. But we believe that this is business as usual. 1P in 2023 was here in January 2024, we brought it up, and 1P being realized, perhaps it's here now. It's much better than it was before. Perhaps not as great as we had in the past, but, you know, still a much relevant improvement. And it's what he said, to be cautious, we give freedom to the reservoir team, because our mandate here is not to produce oil.
I mean, of course, it is to produce oil, but not to produce oil today, but rather to maximize the recovery factor of the reservoirs. There are cases where we start producing water, and we stop production at the well for a while, so that we won't have a great deterioration in the business. So that's how we work. What about TBMT, just to add? When we complete these maintenances in the field, we'll go back to a level of 15,000-16,000, and we'll see the behavior of these wells. We're drilling again at Polvo, and there's a margin. We might get better news, produce a little bit more. We'll see how the field will behave. An exit point for TBMT would be 17.
Yeah.
Well, ideally, it would be 20, but let's think about 17 or maybe a little bit more. But I guess that this would be a great number. Did we leave anything out? No, perfect. Just a quick follow-up question. During the discussions that you have with IBAMA, do you think that they are more willing to look at your requests for permit versus the Wahoo license? How do you feel? Well, it's kind of a complicated situation, things that have deteriorated a lot. No one can stand this anymore, not even them. But there is an open dialogue that we have with them. We sit with them, we exchange ideas, we have a very long-term relationship. Our operation doesn't, doesn't exist without them, so it's a partnership, and we are trying to work with them in a productive way. What they're telling us is that the permits will be granted.
It's just for maintenance. It has very low impact. There's no reason for this to take too long. If it weren't for this issue, we would get the permits in no time. So we should, we should be getting it very soon. Okay, thank you. Our next question from Vicente Falanga with Bradesco BBI.
Good afternoon, Roberto, Milton, Francilmar, Maíra, and Ze. Thank you for taking my questions. I have two questions. First, about your Gulf of Mexico's M&A.
Vicente, I think we lost you. Let's jump to the next question, then we go back to Vicente. Next question then, while we wait for Vicente's audio. Our next question, while we wait for Vicente, comes from Regis Cardoso from XP.
Obrigado.
Regis, go ahead.
Thank you. Thank you, all. Thank you for taking my question. Congrats on your results. Can you hear me? He says. Okay, okay, I was saying good afternoon to you all. Thank you for taking my question, and congratulations on your results. I have two questions. I would just like to get some more details about how things happen in practical terms. Thinking about implications, not only from IBAMA and also from MP, would there be any risk of IBAMA giving you the go-ahead, and then you stumble into the temporary measure? I mean, or if they are, If ANP is working very slowly or half on strike, do you think that this would be any impact to—there would be impact in Polvo, the pipeline, or Wahoo, and even later on in Albacora Leste? Which one of those could be impacted by ANP?
In terms of IBAMA, I would just like to understand whether there are two separate projects, pipeline and part—so that part of the activities would be released and the other part will still be pending. This leads me to my second question. On the operating side, what format you could have in Wahoo? Because you said that you have the, the window for the vessel until December. Do you believe that this could linger for longer? And whether you would have enough time to fulfill the entire operation by the end of December. With this scenario in mind, would there be the possibility of any given number of wells, meaning one, two, or three, being drilled before the pipeline, and whether it would be possible to start production with any combination? I think that's it. Thank you.
Okay, ANP, certainly that if they get into this model of standard operation, that may hurt us in terms of any authorization that we may need. But for these specific projects, for permits, for TBMT, et cetera, we don't see any problems. But looking forward, things are more fluid. I mean, if we want to work on a well that is not in our development plan for Albacora, and let's say, that requires an amendment or something, if they are still in that standard or half strike mode, that would be a problem. But today, it's probably too early to think about that, because it's far-fetched. If we get IBAMA's license, and if we get the permit for some other further operations, this can be very helpful. That means that we have one year of work without needing any major things from the agency.
So this will give us time for things to be settled. In terms of Wahoo, in fact, it's just the beginning of the work. We could start doing the pipeline in December, and obviously, this will go beyond December, but this does not involve a very long work. It's just the beginning. So we think that there is a reasonable chance that this window will be covered with no problem. We could start with anything. The issue is that the line or the pipe has to be laid. It has to be connected to the FPSO, and these are two parallel process. I mean, drilling and pipeline. I mean, we need the vessel to lay the pipes, and once that is connected to Wahoo, we could conclude with 1, 2, 3, 4 wells, regardless of when it's ready.
And production could start at 40,000, or start at 10 until we reaches 40,000, and it goes on like this. Perfect. Thank you. If you'll allow me another question related to an earlier comment about Albacora Leste and the seismic information. How much of that could change in terms of the reserve certification that we are familiar with in your development plan? That's a good point. I don't know whether the reserve certification would be so sensitive to this new seismic. What we see there is just a better definition of what we've seen in the past. It's not that we didn't have any seismic, and now we do, but we look at 1P. In fact, to have changes in 1P or what makes that happen, it's mostly drilling than anything else. Maybe you could have a change in 2P or 3P. Who knows?
You know. But we look at 1P, so that shouldn't bring about major changes because of the seismic. It could happen if this seismic indicates new wells, and then these new wells will get into our certification. Yeah, that's what happened with Frade, but not seismic itself, you know, impacting the reserve certification. Let me give you some more color. Seismic, we call it 4D. Not only we have a 3D image, it also has a part related to fluid movements. Therefore, this allows us to identify oil that was not, not produced. So once the flow is determined, you, you know, you put more effort here or there, you test here or there, but nothing in the short run. Perfect. Thank you. Thank you, Regis. Our next question comes from Vicente Falanga from Bradesco BBI. You may proceed, sir. Thank you.
Thank you. I just have 1 question about the M&A in the Gulf of Mexico. How do you see the challenge from other competitors who are also looking for other assets, and they probably have more capital than PRIO? How would you like to move in terms of a possible bid? That leverage denominated in US dollars, whether that is also possible in that region. I think that our expectation... I mean, everything we say about the Gulf of Mexico takes into account that we, our IRR is not going to change. Sometimes you say $60 in the wrong, long run. This is one part of it, but on the other side, we look at the production volume, and we look at all of the opportunities to connect wells, synergies, and so on.
So our hurdle rate will be stronger or higher, but on the other hand, we take into account our operating capacity to implement projects, and this is what will happen in the Gulf of Mexico. Therefore, we believe that the answer would be affirmative, and nobody's gonna do anything if it's not an affirmative answer. But it's too soon to say whether it is or it's not. Companies today are putting some Wilcox projects in operation.
Chevron is putting Anchor, Shell, Whale, Beacon will put Shenandoah, and so on. So we have to see whether this will really happen, if there will be a migration. But the thing is, a major, whenever they go to a new area that is more interesting in terms of return, they leave behind an area where they had projects, but projects that were not so attractive. I'm not saying that they are not knowledgeable about that project, but simply they don't want to allocate any more capital to that project. So they no longer sell PDP production. Not PDP, but the one development they can sell with a higher rate of return. And that's why we can do these transactions, because we look, we'll look at the undeveloped or what has been proven but not developed.
We can put that in our pricing because this is what we do, this is what we will do, and the major cannot include that in their pricing going forward, because they won't be able to allocate any more capital to that asset. This is the difference, and that's why traditionally, we can, you know, close good deals. And so we just expect this to be true for the Gulf of Mexico. But it's still too soon to tell. I cannot tell you yes. Yeah, we don't even know any projects. We have only an expectation that this may materialize, so let's wait and see.
Thank you, Roberto. Thank you.
Next question from Bruno Amorim of Goldman Sachs. Hello. Good afternoon. Thank you for taking my questions. Could you please comment a little more on the plan to double production at ABL, assuming that IBAMA will go back to working at normal pace? Please correct me if I'm wrong, but the reserve certification implies that production would double in two years. So what is the game plan to get there in terms of drilling or reopening up wells? That would be interesting. Thank you. Oh, Bruno, in a nutshell, we have eight producing wells and three injectors. That's it. These eight producing wells, a little over half would be new wells, perhaps five new wells and three infill drilling.
The new ones will come online with about 1,000, 5,000, in the infill drilling, a little lower, about 3,000 barrels daily, and two water injectors, so that we can continue to inject all the water produced. I mean, if you put it all together, five wells versus 5,000 barrels daily, that would give us 25,000 plus the three, and we would have to consider decline and the reservoir as a whole. At Frade, we started adding wells with an oil production versus water production that was much higher, and we ended up turning off some wells that produced a lot of water. The same would happen with ABL. It's about managing the reservoir. A great upside we can have there is the seismic, because the seismic can show us new things. This is something very incipient.
And something we could think about is today, at Albacora, the water produced at Albacora, already is compliant with the Brazilian legislation for two months now. So the water produced, we are injecting 100% of the water produced, as we have always done. But today, technically, this water already complies, just like all other fields of Brazil have the water compliance, and the water is discarded out in the sea, just like all the other fields in Brazil do, given that we abide by the same laws, the same regulation, the same parameters. This could change the need for injectors. We could reduce the number of injection wells. This would give us more flexibility in the plan. That's it. Perfect. Could you give us some color on the timeline for the execution of the plan?
I mean, obviously, assuming that IBAMA goes back to working at regular pace, would it be a linear curve ramp up? It's a linear curve for every step, for every well. It should take about 70 days per well to put the well online, and we'll drill one after the other. We could have a producer, one injector, one producer, one injector, and after the three injectors are drilled, we would have only producing wells to be more conservative. I mean, we can do it in any way we want, but it's kind of what it takes to drill every well. The idea is to start just after Wahoo.
Today, our work plan is perhaps TBMT, because perhaps that's what we are going to get first in terms of permits or the possibility to put the rig into work, then TBMT, and then Wahoo, drilling the four wells at Wahoo, and then we would move the rig to Albacora. So net of the IBAMA issue, 'cause it's, it's something to be considered, net of, net of IBAMA, we should be delivering Wahoo, I don't know, in mid of the first half of next year, end of the first quarter maybe, and then we'll start drilling at Albacora. If you wanna be more conservative, you can say we'll start drilling at Albacora in the second half of next year, and then the program for Albacora will last 12-18 months to drill.
There will be a ramp up to get to a maximum production, most likely sometime in 2026. Perfect, thank you very much. That was very helpful. Next question from Rodrigo Almeida with Santander. Hello, good afternoon, everyone. Just some follow-up questions. My question was exactly about Albacora's water disposal. You answered, but I just want to clarify, if you get permit from IBAMA, do you need any ANP approval for water disposal? I think that the Investor Day, this would be in 2025, so I guess that you are on schedule. And for Albacora, another point I'd like to confirm, that is drill with a more global license? It would be, if I'm not mistaken, the third license from IBAMA. I just want to confirm that point. And lastly, I'd like to go back to Milton's point regarding the taxes.
The effect on this quarter is clear. Later, Milton, I want to try to understand with you what would be the effect of deferred taxes for the next quarters, if there will be any effect. Those are my questions, basically. Thank you. Well, Rodrigo, as regards water produced, it's approval by IBAMA. It's not something very normal. IBAMA just got into this process because in the past, when water was not compliant, Petrobras signed a term of adjustment with IBAMA. So they decided to use this as a condition precedent for the environmental license from IBAMA. So with this, now we necessarily need IBAMA, we need the agency. And this is the only hurdle that we see. It is the agency that is supposed to give us the authorization, it's IBAMA. We cannot have two economic agents, for example, PetroRio or another company.
One cannot dispose water and the other one can. I mean, if there's something conceptual there, and IBAMA needs to be comfortable with the quality of water treatment and so on and so forth, but that's more conceptual. But it's basically this: you cannot have two different rules for two equal results. You cannot have two different approaches. So this is what we can say about water injection. And you had asked about the taxes? What was the question? Now, still on ABL, regarding the license, we want to use a global license. I imagine that it includes the eight producing wells and the injectors. And then what can we think about in the future? At IBAMA, we request what we call a regional license, an authorization to drill an X amount of wells per year in the Campos Basin. Campos Basin, because that's where we operate now.
We have what we call PEVO, emergency plan. So everything we have is in the Campos Basin, and we use the global license to say we can drill so many wells in the basin. It's similar to what Petrobras has. We are trying to migrate to this new model because it would remove pressure on the agency as well. Because, I mean, we are going to be doing the same well that we normally do, with the same rig, all things equal. So that's what we're trying to do. An alternative path is to ask for an Albacora license. If IBAMA concludes that they prefer to grant us a license for Albacora, okay, we'll get a license specifically for Albacora. But our request today is for a regional license. As regards to the taxes, I'll let Milton speak about this.
I just want to remind you that what happened in our results, simply put, is we have tax credits due to losses we had in the past. So a tax law carried forward, so this generates a tax credit. This tax credit is denominated in BRL, in reals. So we are forced to make an adjustment in the balance sheet if, if the exchange changes. If the BRL appreciates as we report in dollars, in dollars, the credit is worth less. What, what can change is, for whatever reason, we can produce more oil or less oil, we can use more or less credits. The speed in which we use these credits and the amount of credits counts. So what happened there is we have tax credits, which are BRL-denominated, and we report our balance sheet in dollars. So the credit in dollars is worth less.
It's worth the same amount of BRL, but in dollars, it's worth less. That's why we had to make an adjustment, because of the depreciation. This is just a simple explanation. I'm not an accountant, but that's how I understood the process. Perhaps it's easier to understand. Milton? Rodrigo? To add to what Roberto said, and to think conceptually. Think in the following way, for the PPE of the company. Let's say we buy equipment. Let me give you a conceptual number, $200,000. At a foreign exchange of five, that corresponds to BRL 1 million. But our functional currency is the US dollar, so we pay taxes in BRL because we are a Brazilian company. So for taxation purposes, we have BRL 1 million. Then we project our depreciation, we do a calculation with the IRS based on BRL 1 million.
Let's suppose exchange rate increases to six in the following quarter. $200,000 appears 1.2 million BRL. So this 200,000 BRL difference, you cannot increase your depreciation. For fiscal purposes, it's 1 million BRL, so 200,000 BRL is a negative adjustment because of the exchange rate depreciation. What counts is the exchange rate at the acquisition of the PPE. So I think we have a huge base of assets. We bought at rates of 4.5, 5, and now the exchange rate is 5.5 at the end of this quarter. So this requires an adjustment, because if you look at the result in BRL, which we are forced to disclose according to CVM, you will see a higher asset, and the depreciation can be done wrongly. So this is an adjustment based on the exchange rate depreciation. Perfect. It's now very clear.
Thank you very much. Yeah, clear. No, I can understand now. Thank you. Well, with that question, I think we conclude this, our earnings release video call, and I will like to turn the floor back to Roberto for his final remarks. Thank you very much for joining us today. It's always a pleasure to share our results with you, and I'll see you again next quarter. Thank you very much.