This event is being simultaneously translated into English. The presentation and comments on the results will be presented by PetroRio's CEO, Roberto Monteiro, CFO, Milton Rangel, and COO, Francisco Francilmar. They will present the company's results and will then be available during the Q&A. At this time, all participants are in listen-only mode. To ask questions live, you can use the Zoom Raise Hand feature, and for written questions, the Q&A button. Both icons are on the bottom of your Zoom screen. This event is being recorded and will be available on PetroRio's Investor Relations website. Before proceeding, let me mention that forward-looking statements that might be made during this conference call relative to the company's business perspectives, projections, and operating and financial goals are based on the beliefs and assumptions of PetroRio's management and on information currently available to the company.
Forward-looking statements involve risks, uncertainties and assumptions as they relate to future events and depend on circumstances that may or may not occur. Investors should understand that general economic conditions, industry conditions and other operating factors could also affect the future results of PetroRio and could cause results to differ materially from those expressed in such forward-looking statements. I now turn the floor to Roberto Monteiro, our CEO. Go ahead.
G ood day, everyone. Welcome to PetroRio's conference call to discuss our results. I would like to start this meeting with a big thank you to PetroRio's team, the whole PetroRio team, because in the third quarter, we were able to achieve a very important goal, which was the connection between Polvo field and Tubarão Martelo field, the famous tieback between the two fields.
In addition to the operating result, which has been giving us very positive numbers, as we will see later on the call, this achievement is very important because it shows our DNA, which is to think out of the box and to realize our dreams. Thank you very much. I know this has required a huge effort by the whole team, not only the operating team, but also the administrative team. All PetroRio's staff, one way or another, got involved in this business, and with that, they helped the company achieve this great feat, this great accomplishment. Well, of course, this led to the first consequence of this achievement, which was a reduction of our lifting cost.
In this quarter, although we haven't yet captured all of the synergies, which we're still going to capture, we were able to post a lifting cost of $12.3 per barrel, the lowest ever in our history. This is, of course, the result of this tieback. Still on the operating side, we were able to connect well number ten at Tubarão Martelo or TBMT. We were very happy with the startup of production, which happened now already in Q4, but a good part of the work was conducted along the third quarter. This well started producing 3.8 thousand barrels a day of oil, so we were also very happy with that result. More on the financial side, we posted a net revenue of BRL 940 million related to 2.5 million barrels sold.
In this quarter, specifically, we sold a little less volume. If you look at our balance sheet, you will see that we ended the quarter with a slightly higher inventory than usual. But this is normal because we sell offtakes of 1 million barrels, and sometimes these offtakes do not coincide exactly with the end of the quarter, and we sell them in the beginning of the following quarter. This is exactly what happened, and that is why we sold 2.5 million barrels. We could also post an EBITDA of almost BRL 550 million, even with this offtake volume. This reflects the lifting cost. Actually, it reflects the lifting cost of the second quarter, which was already a low one with a very high Brent oil price. This was also a very pleasant surprise, the higher Brent price, I mean.
All that led to a net income of approximately BRL 125 million, mainly impacted by foreign exchange variation. We are a dollarized company. We have some debt that is fixed in dollars, including our abandonment cost. When the dollar rate appreciates, there is an impact on our financial statement, which is totally irrelevant for the financial solidity and health of our business because we are a dollarized company, all of our revenues are also dollarized. Now moving to slide four, please. It kind of illustrates what I have said before. Our lifting cost is still in a downward trend. In Q3, we see the lifting cost at $12.3 per barrel, the lowest in our history. Production remained relatively stable at 31,600 barrels a day net for PetroRio.
We would have liked to post a higher production already in Q3, but unfortunately, we were not able to because well number 10 started operating only in Q4. Like I said, a good part of the work was carried out during Q3. On the bottom of the slide, we see the two last indicators, cash position and indebtedness, both very well controlled with a very robust cash. And a net debt over adjusted EBITDA ratio that is negative. This was a very high level summary of what happened along Q3. I think it was a good, actually a very good quarter for the company in terms of achievement of a dream and completion of a huge project. It leaves us in a position to show even stronger numbers in Q4, both from the standpoint of costs and from the standpoint of production.
With that, I will turn the floor to Francisco Francilmar. He will speak a little about the operating side. Milton will speak about the financials, and I will back in the end. Thank you very much. Francisco Francilmar?
Hello, everyone. Thank you very much for joining us. Thank you, Roberto. Well, let's start on slide five for an update on the performance of our assets. I will focus on the part that we control, production and production cost. In terms of production, we see there was a general production increase for PetroRio, up around 8%, stemming from an improvement of Frade in the quarter as we overcame the impact of the scheduled downtime that we had in the previous quarter. In terms of costs, we already feel the effects of the tieback completion in the Polvo and TBMT cluster.
I will be giving you more detail on that, and we see a better number here in this series in this line. Moving to slide six, let me detail our lifting cost, which continues, and I believe will always be the main way to protect our company from external factors. The lifting cost is something that we manage, and we work daily to improve it as much as possible. We see the historical series starting in 2017. On the top left-hand graph, we can see that the lifting cost of $12.3 per barrel is the very best posted by the company. This is clearly a reflection of the tieback completion between Polvo and TBMT, removing FPSO Polvo from the operation with the expected positive effects. We are not at 100% yet because the tieback was completed in mid-July.
The month of July is rather contaminated with general costs related to that. As of September, we started to refine the operation and derive better numbers. On the bottom graph, we can see the comparison between the Brent and the lifting cost. Once again, the Brent price is not something we manage, so this is just for reference, but obviously impacting the profitability of the company. We have to focus 100% on the lifting cost. This cost could have been a lot better if it weren't impacted by some production downtime. Some were scheduled, other stoppages were not scheduled, and that impacted the total cost of the company and, as a consequence, the lifting cost. We are confident that the next quarters will be a lot better. Moving on to slide seven.
Let me give you more detail on the performance of Frade field. In Q3, we can see on the graph on the right that it showed a substantial improvement, a lot due to the recovery after the scheduled stoppage in Q2. This unit had remained in production without downtime since 2018, if I'm not mistaken. We had to have an important shutdown in order to do some work and scheduled maintenance. We were able to return our operating efficiency to close to 99%, which is something that we always pursue at Frade, given the good conditions of the vessel operating there and our team. All of that helped the asset post a good production despite pressure of natural decline on the reservoir. That's something that we can only recover when we start having the new injection wells working, recovering energy, and that will help.
When the production wells start producing, which is scheduled to happen next year. It is worth mentioning that in this quarter, in mid-July, we restarted injecting into the old water injection wells at the field after we obtained authorization from the relevant authorities. This injection is basically to help reduce the decline rate. Every day, the reservoir pressure goes down a little, and as a consequence, production is reduced. We are able to inject very little, but it does help some. The field have been producing for over two years with excellent efficiency and safety numbers, and we are doing quite well at Frade. Moving on to give you more detail regarding a big project that we have going on for the company right now, which is the revitalization program of Frade field. We continue to move ahead full steam. We have the rig contracted.
We have all drilling services already contracted. The rig was contracted under a flexible contract, so we can use it both for the first phase at Frade field and Urucu with its four wells. We have an option to go back and carry out the second phase at Frade, which will depend a lot on the results and on the project portfolio of the company looking forward. Here in this image on the left that you are used to seeing, this is a schematic view showing where we will be drilling the wells. Phase number one will be basically ODP4 in a virgin reservoir. It is expected to flow first oil and injection wells, which are our priority on both flanks of the field in these specific reservoirs. The redevelopment plan has already been approved by ANP.
Now we are focusing on the details of the project, such as well design, how we are going to drill subsea interventions to put these wells in operation, and all the other operating details that are required to be in place. Now let's move to slide number nine, where we will elaborate on Polvo and TBMT cluster. We had a lot more activities in this cluster in Q3. Here, I think it's worthwhile explaining conceptually that here at PetroRio, we consider operating efficiency everything. The ratio between production plant and actual production, considering scheduled downtime, wells, subsea systems, and the performance of the vessel, the FPSO. Some countries focus only on the FPSO, but we look at everything. Another important thing is that in this asset, we have 20 wells producing through ESPs, which are electrical submersible pumps.
These pumps have a given service life of around 1,000-1,200 days, and then they fail. We have 20 wells, and eventually one ESP might fail, and we have to have a system in place, and we do, to work to repair these pumps and have them back in production as quickly as possible. In this quarter, we suffered some pressure first for the scheduled stoppage at Polvo-A. As we see in the macro graph, where we consolidated in this quarter an operating efficiency of 82%. Down below, we broke it down so as to give you more detail, and you can see that Polvo-A has a low efficiency because it spent practically 13-14 days stopped during a month, and that had a big negative impact. In addition, we had problems in the Polvo wells.
Because it has more wells and production is lower, we felt a little less. We had 2 wells that stopped in Q3. We carried out a workover in one of them. It started producing again. At TBMT, where we have only a few wells, we were operating with 5 wells. Now, with the start of well number 10, it is operating with 6 wells. Every well that stops has a big impact on production. To give you some more color, at TBMT, we've had well number 8 offline since March. We had that fishing problem, which means when a metal part falls in the well, we have to kind of fish it out. We have to remove those objects to install the ESP and to restart production. This hasn't been possible yet. We stopped the pump due to lack of material.
The rig was relocated to well 10, completed well 10, and when the completion and connection were complete, well 10 started production now in mid-October with, by the way, excellent throughput, I would say even better than we expected. The rig went back to well 8 to complete the fishing work, install the pump, and resume production, which I expect to happen in the coming weeks. In parallel to that, we had a problem in well 2 that went offline at TBMT. After an investigation, we discovered that the problem was in the subsea system, more specifically in a UTA, umbilical termination assembly, installed on the seabed. We are looking to repair that, and I believe that in the coming weeks, we'll be able to solve the problem and resume production at the well. Other than that, Polvo had some shutdowns, particularly in well number 12.
These are, you know, regular workovers with our rig. We currently have two drilling rigs, one that stays at Polvo-A platform, which handles workovers and pump exchanges at Polvo, and the Kingmaker, which is ready to replace pumps at TBMT. This is normal. It's part of the life of this asset. We believe that after repairing all this, we'll be in a better position, which will translate into a better operating efficiency in the coming quarters. Here, I believe I should make special reference to the performance of FPSO Bravo. We can see it on the bottom graph on the left, and we see that unlike the old FPSO Polvo, FPSO Bravo performs really well with an operating efficiency of over 97% full-time. Undoubtedly, after we solve these issues in the wells, we'll see considerable improvement.
Now, on slide 10, I want to give you more detail on the tieback that was completed in July. We executed the project to connect Polvo-A platform with FPSO Bravo, installing the production line, the umbilical that entails the whole energy piece, and we were able to do it on schedule. We had planned to do it in 1 year. With all the pressure, we ended up finishing the project in 11 months, on budget and on schedule. This was already foreseen in the contract, and now with the tieback in this cluster, 95% of production is ours, and 5% remains with Dommo. This photo on the right is for you to appreciate the size of the flexible lines and spools, which are huge. We handled that kind of work at the field.
Well, this work helped us a lot collect a lot of data and lessons learned that will be the foundation to be used in the future tieback connecting Wahoo and Frade. Our in-house team has captured that experience, and I believe that this will be very helpful. Now let's talk about Wahoo Block, where we continue to hold a 64.3% working interest of the field with the previous two stakes acquired. We have started the negotiation phase with our partner in the block to discuss the development plan, DP, which is basically ready. We have submitted our version. It's being negotiated to be finally submitted to the agency so we can move ahead with the next steps, declaration of commerciality, submit the development plan for approval, and so on. From the technical standpoint, which happens in parallel, we continue in deep discussion regarding...
Well, the wells project is quite advanced. We have already contracted the rig and drilling services. On the other hand, the subsea system, which is the tieback itself, is also at a final stage of negotiation with some companies having submitted proposals regarding the type of technology and how to execute. We are at the final stage to define our partner for this project. All is moving ahead as expected, and I hope that in this quarter, we were able to discuss all these points so we can proceed with the commissioning of the equipment to formally submit the project to ANP for approval of the development plan. I now conclude my participation and turn the floor to Milton.
Thank you, Francilmar. Good afternoon, everyone. To continue our presentation, we are now on slide 12.
We'll speak a little about our financial performance in Q3 and in the nine months of 2021. Looking at the first group of columns that exclude the effects of IFRS 16, and this is one way we like to analyze our results, we see revenue of approximately BRL 940 million on the back of 2.5 million barrels sold. When we compare that with Q3 2020, we observe an improved scenario as well as a better oil price that were quite relevant. We had an average sale price before discounts in this quarter of around $74 per barrel, while the same average prior to discounts in Q3 2020 was $43 per barrel. A recovery which reflects a significant improvement in revenue margins and so on and so forth as we will see.
EBITDA totaled a little over BRL 560 million with an EBITDA margin of 60%. To be highlighted on this table is our financial revenue. We actually have irrelevant financial expense, and this is related to a non-realized foreign exchange variation. It doesn't mean that we effectively lost BRL 433 million, but this is marked to market. Since the Brazilian BRL depreciated vis-a-vis the dollar, and we have liabilities in dollars, this marked to market is done in this way in this quarter. Still, we reported net income totaling around BRL 125 million and adjusted EBITDA of almost BRL 550 million in Q3 with an adjusted EBITDA margin of 58%. We like to analyze adjusted EBITDA because it excludes non-recurring and non-operational effects. Here's a snapshot of our Q3.
Year to date, we see total revenue of around BRL 2.6 billion, a very substantial number. I'd like to remind you that in the nine months of 2020, we sold a little over BRL 1 billion. The company is in a totally different level now with increased production, with new projects and new acquisitions, and a higher Brent price, as we mentioned. Year to date EBITDA margin of around 59% and an adjusted EBITDA of BRL 1.6 billion with a 62% margin, a very strong result. Quite a good recovery compared with 2020. Moving on to the next slide 13, I'll explain a little about the company's funding. Starting with a graph on the left side of the slide, we show the average duration of the company's financial liabilities, the company's debt.
In this quarter, we had basically two types of debt. One is the bond, which is our main debt, $600 million. We have another debt for working capital that we are amortizing now in Q4. For this analysis, Q3 takes into account a debt duration, an average debt duration of the company of 4.33 years. This shows, if you have been following PetroRio for long enough, a great improvement and extension of the company's debt profile, giving us a lot more room, a lot more liquidity for our projects in the coming years with peace of mind, and to pave the way for the company's growth without financial liabilities knocking on our door in the short term.
We continue on our strategy to fully prepay our other debts other than the bond, because currently they are no longer necessary, and we do not want, it doesn't make sense to keep paying interests on capital that we don't currently need. We can see on the graph on the right the company's quite comfortable situation. We have cash totaling BRL 4.5 billion and total debt obligations of around BRL 3.5 billion. In other words, a net cash a little over BRL 1 billion. Putting us in a very comfortable position in terms of liquidity and solvency. Now moving to slide 14, to explain specifically the variation of the company's net cash in a quarter-on-quarter comparison, we see that the company posted an adjusted EBITDA of around $105 million.
We used a good part of the cash generated for the acquisition of Wahoo, so we made payments to Total and BP, referring to working interests acquired from them in the past. We also had our CapEx spending on account of the tieback completion. We also had some drilling activities at Polvo, as well as some activity at Frade, in addition to the completion of TBMT-10, which required a little CapEx. Plus, we paid some taxes. I mean, that is expected when the company generates profit. That's business as usual. Financial expenses, referring primarily to interests paid by the company in the quarter and the payment of hedge premiums. We had contracted hedging some months ago, and payment is deferred, so part of the payment was made in Q3.
With that, we ended Q3 2021 with net cash of almost $200 million, in line with the prior quarter, showing that cash generation is helping PetroRio make a number of investments and such. Now, moving on to slide 15. This slide is about leverage. On this chart, we see that PetroRio is currently in a very comfortable situation. Since Q1 2021, when we had our follow-on, a primary public offering of shares, we raised a lot of cash, and with that, we reduced the leverage of the company substantially. I would just like to highlight here some information that is public knowledge. We have a bond covenant that allows a maximum leverage of 2.5 times. The fact that we are at -0.5 times gives us some firepower that is very interesting for new investments, new acquisitions, and so on and so forth.
The company continues to generate a lot of cash. In reducing more and more our leverage, the company is ready to make new investments in a sound manner from the financial standpoint, and I think that this is noteworthy for those of you who follow us. Well then, I end my part of the presentation here and turn the floor back to Roberto, who will speak about our next steps. Thank you very much.
Milton, thank you very much. I will proceed towards the end of the presentation, addressing the next steps. I believe they are well-known to all of you. We speak about this all the time, but you know, it is always good to make it very clear to all of you where the company is heading.
I believe the first next step is, as always, and we have been talking about this every quarter, a constant focus on health and safety. Obviously, safety, there's no operation. There is no PetroRio without safety. There is no operation if we are not safe. We are still living with the COVID pandemic, so we will keep our guard up. We expect this reduction in number of COVID cases and deaths has come to stay. However, we will keep our guard up as we have done in all recent quarters. From the operating standpoint, which I believe are the most relevant things to be executed in Q4, number 1 priority is to finish the workover of 2 wells in Tubarão Martelo. Well number 2 and well number 8 in this order. I believe we are almost there at TBMT-2 and TBMT-8. I believe it is expected possibly by December.
In addition, we have the preparation to start the drilling campaign at Frade next year. We will be drilling three wells at Frade, one production well and two water injection wells. Obviously, the whole preparation starts way ahead. We are currently in this preparation phase for Frade field. We are also in the preparation phase for Wahoo field. We are in the phase of declaring commerciality. We expect to have the field's declaration of commerciality by year-end. In our consortium, we have a step-by-step approach for this to happen, so we are going through the different steps, and we expect to have declaration of commerciality by year-end, as we have stated over and over, so that we can start executing the Wahoo development project soon after Frade. Finally, a great focus on mergers and acquisitions and inorganic growth.
As you all know, we participated in the Albacora and Albacora Leste process. We are, of course, very excited about these fields and the possibilities they bring. We now have to wait for the final outcome. I would say this is a very hot topic in terms of inorganic growth for the company. Thank you very much, and I would like to open the floor to questions.
Good afternoon, everyone. We will now open the Q&A session. Some people raised their hand to ask questions, so we'll start with a question by Pedro Soares with BTG. You can go ahead, Pedro.
Hello, everyone. Can you hear me now? Yes. Great. Hello, Roberto Monteiro, Milton Rangel, Francisco Francilmar, everyone. I have two questions. The first has to do with the lifting cost. You mentioned that you should continue to capture improvements with the completion of the tieback that happened in mid-July.
From now on, the company should be able to serve a better wave of potential lifting cost reductions because this will start being reflected after Q3. As you mentioned, TBMT has suffered with some operational issues, the two wells that we talked about, and that kind of got in the way. I would like to hear from you. Perhaps you could give us more granularity in terms of what kind of lifting cost reduction per barrel we could expect for Q4. In an alternative scenario, if these two wells had been normalized, how could we quantify the potential reduction in the lifting cost today with the tieback? That's my first question. My second question has to do with hedging. In the second quarter, you talked about some put options that you had purchased for the next months.
It offered a cushion for up to 50% of October sales. In this quarter, you didn't mention that. When will you use this approach? Basically as a protection mechanism. Perhaps you could tell us if you changed the strategy for November, December, if you have purchased the put options. One last question, if I could ask about Wahoo. Any development regarding the positioning of IBV, if they will participate in the development of the plan? If I'm not mistaken, this was expected by year-end. If you could elaborate on that, I would be grateful. Thank you.
Thank you, Pedro. I will start, and Milton and Francilmar will help me. Let me start with IBV. We have a joint operational agreement, a JOA, with them, and this contract entails a procedure that needs to be followed, and we are of course following the procedure.
We had the initial submission to IBV in terms of how we see the field, expected production at the field, and so on and so forth. We're still following the procedure. There is some time for analysis, and there is another 60-day timeframe for them to get back to us. You know, and also everything related to contracting will depend on how the contract will translate into action. What I can tell you is that we continue to be very optimistic and excited about the field, and we are following the contract, the JOA, exactly what it says, how things should be done, and so on and so forth. Our expectation is that they will be analyzing the field, and then they will make a decision if they want to follow us, if they don't want to follow us.
Our expectation is to eventually declare commerciality, possibly in the next few months. You know, there was no great progress in that regard, but our work with IBV continues to happen in the regular way according to the joint operational agreement. There's nothing there different than what we have said in prior quarterly calls. As regards to the lifting cost, we still haven't captured 100% of the possible synergies, and for two reasons. First, we finalized the tieback in July. July is a month that was contaminated by expenses. We still have to make some adjustments in the FPSO regarding gas burning so we can migrate as much as possible fuel to gas. It's all being done. But all in agreement with what we are thinking. But this is still being executed. I mean, this final refining. There was the production.
Although we posted 31,000 barrels in the quarter, although the highest in the history of PetroRio, it fell below our expectations. When we get well number 8, well number 2, now with the addition of well number 10, all of that will help the lifting cost. It is at $12.3 per barrel. Our guidance was that the lifting cost would be between $10 and $12, and I think that in Q4 we should be able to have our lifting cost between $10 and $12 per barrel. If everything goes well, if production materializes as expected, and if we can finalize that fine-tuning, perhaps it will be closer to 10 than 12. It will really depend on how things will unfold.
There might be some monthly variations, but the lifting cost is currently at $12.3 per barrel, and they have a downward trend. Whether we are going to be able to reduce it dramatically to close to 10 in the end of the quarter, that remains to be seen. I believe these things are gradual but continuous. What I can tell you is that we are very excited and that we have more benefits to collect related to the lifting cost. Anything you would like to add? No. As for the hedging strategy, Pedro, it's easy to say. We purchased hedging last Friday. The dollar was at 85. Actually, it was 86 in mid last week. The next day it dropped to 84, if I'm not mistaken, then it went back to 85. So we hedged.
The company is now hedged for the next 6 months. The same policy as usual. 6 months of hedging. The first half, 100%. The second half, 50% of the volume. We did buy put options since volatility is high or the prices are still high, high strikes, high volatility. We chose not to hedge too close to the future curve. We did it slightly below the future curve. We are hedged in amounts that range from $76 now to $72 more towards April of next year with a strike of $72 in April of 2022. This is what we did. We remain firm in that policy. We talked with the board of directors and we thought that it was wise to hedge the company, although volatility was outside normal parameters.
We normally hedge the company when volatility drops, but we thought that there was a premium, there was a price that made sense, so we did that to ensure a minimum cash flow for the company looking forward, and we bought put options as we always do.
Excellent, Roberto. Thank you very much. All very clear.
Next question by Bruno Montanari with Morgan Stanley. Go ahead, Bruno.
Hello, thank you for taking my questions. I'd like to know if you can elaborate on the next steps for the Albacora process. Is it in line with what we could expect? And is there anything that you can do faster to enjoy the positive oil price cycle, perhaps accelerate a project or do something differently to perhaps capture and build on these higher oil prices? Thank you.
Thank you, Bruno.
As regards Albacora, what I can tell you is, and this is public knowledge, is that we bid for both assets. We very much like those two assets. Between the two, perhaps Albacora Oeste would be preferable, but we like them both. What we heard, and you know this is hearsay, we cannot be sure, is that Petrobras was about to make a decision, and we don't know what the decision is to their management. This was our expectation, that in the beginning of November, their management would decide who would be what they call preferred bidder. The preferred bidder is the company that is going to negotiate the contract with Petrobras.
Later on, I imagine some months, 4-6 months from now, something between 3 and 6 months of negotiations, Petrobras can sign the contract directly with the preferred bidder, or depending on the contract negotiation, they can call what they call a final bid. Petrobras would call the 2 runner-ups to submit a final bid based on that specific, contract that was already negotiated. You know, just like you, we are waiting. We are waiting for news from Petrobras. There was a second question there, wasn't there? Oh, if we could expedite projects. Well, Bruno, the truth is, there isn't. We are doing all the development we can at the operational speed that we can handle. We are developing Frade field. We have contracted the rig, et cetera, for Frade.
We have to go through all of these steps for Wahoo to effectively develop the field. You see, after our follow-on and after we issued our bond, we removed the restrictions that we had in terms of adjusting our cash flow to investments. Since then, we have been doing everything that we can as fast as possible from the operating standpoint. What I can tell you is that we would not have the operational capacity to do anything faster, not because of our people, because people can be hired, we can increase the teams, but because of the projects, because of the maturity of the projects. Today, we cannot contract another drilling rig and drill more wells at Frade. Let's imagine that.
It wouldn't be a good idea because Frade has to happen gradually so that we can get data from the wells drilled, their output, so that we can adjust the course if necessary. If we drilled more wells, I think it would be risky. Very clear. Thank you. If I may ask a follow-up question.
Yes. Yes? I'm not sure Bruno is still with us. Let's move ahead. If Bruno returns, we'll give him the floor again. For now, let's have a question by Vicente Falanga with Bradesco BBI. Go ahead, Vicente. Hello, can you hear me?
Yes. Hello, Roberto, Francilmar, Milton, José, the whole PetroRio team. I have two questions. Recently, Petrobras put the Catuá asset for sale very near Wahoo. I would like to understand your opinion about this asset.
Why is it that Petrobras gave up the development of that field despite recent discoveries? I'd like to know if PetroRio would be interested in that asset, if you would see an opportunity for another tieback. As my second question is out of curiosity, from the technical standpoint, what is it that causes this quote-unquote, water contamination when you do a tieback, which is what happened in Polvo in a non-recurring fashion? Thank you.
Vicente, let's talk about Catuá, and then I'm not sure you understood your question about water contamination. Let me start talking about Catuá, and then I'll ask you for a clarification regarding your second question. Catuá. Apparently, Catuá is a marginal asset for Petrobras if you look from the standpoint of standalone development. It is a very similar situation to Wahoo.
When Anadarko sold Wahoo, when they left, they exited the block, they did so because they saw Wahoo as something with a marginal return for a standalone development. To us, it makes sense because we have Frade, so it's not marginal for us and for our potential partner because they would process the oil at Frade, they would benefit from the situation. It is a unique situation because we have the Frade FPSO that can process the oil. In the case of Catuá, it would be something similar. The information we got is that, Petrobras did an extended well test at Catuá. They came to the conclusion that the field was marginal to them, and with that, they had started a process to, relinquish, the field to ANP.
We proactively talked to Petrobras, and they decided to bring the asset back to the portfolio for sale. In my opinion, Catuá is an asset that will only work well if it is connected to some other field. Frade is not the only nearby field. There is another one, Parque das Baleias, which belongs to Petrobras, but Petrobras was never interested in doing that and having a tieback. Catuá might be a viable asset for PetroRio, but not so viable for other players. We haven't got the information. What we have today is Petrobras prepared a public teaser for Catuá. We told Petrobras that we are interested, so we were included in the process, and now we're waiting for Petrobras 'cause they gave some time for people to sign up for the project.
Now we're waiting for the end of this period so that we can have access to the data room. We haven't gotten access to the data room. The truth is, I can't even tell you how big Catuá is. Our team doesn't know. We have very limited information, right, about Catuá. We expect it to be a good deal, but it's very incipient. As for the water contamination, Vicente, could you please explain. 'Cause we haven't got water contamination. Water is treated and then discarded, so I'm not sure we understood your question. Please clarify.
I had understood, Roberto, that with part of the oil sold to Polvo or sold from Polvo, it happened with a big discount because it was a non-recurring event, but apparently it had a high content of water, and I had understood it was because of the tieback. It's just out of curiosity.
I just want to understand what caused that.
Well, it was not because of the tieback, Vicente. What happened there was. Do you want to explain? Actually, there was the treatment system performance issue. It ended up collecting oil with more water. In our spec, the quality of the oil that we have, it has 1% water content. For some reason, for the service provider, there was some more water. When we sold the oil, there was a discount due to a higher content of water. It has nothing to do with the tieback. It has to do with poor performance of BW pre-tieback. Actually, this is a claim of ours against the BW. This claim is basically focused on the performance of BW in the recent months of the contract.
They performed very poorly, knowing that they were, that we were about to cancel the contract due to poor performance. I don't know whether they're being negligent or it's just a random thing, but the truth is that BW underperformed, and PetroRio has a claim against BW to have some compensation for that. Our net result is net of these losses. Whatever comes is extra. We are disputing BW regarding that. From what I understood, post tieback, this has been resolved. This was a one-time off event. Yes, it was one load. When you have a tieback, you have to empty the FPSO that is leaving. You have to sell all of the oil. One thing we could have done if we hadn't completed the tieback, we would start blending the oil.
We would have a tank with oil with more than 1% water and other tanks in the FPSO with oil with less than 1% water content. When we sell, we can blend the types of oil so as to maintain water content restricted to 1%. This is relatively a usual procedure, easy to do. We didn't have that possibility because we had to empty the FPSO.
Very clear. Thank you very much.
Our next question comes from Christian Audi with Santander. Christian, go ahead.
Hello, can you hear me? How are you doing, Christian?
All good. Hope you guys are well. It's a pleasure to see you. Thank you for the conference. I have two questions, one for you, Roberto, and one for Milton.
These one-off problems, these operational issues, from what I understood, and please correct me if I'm wrong, they have been resolved. Have been solved. Moving to Q4, the outlook seems to be a lot more positive because the oil price is high and production is increasing. Is this a fair statement? Are these small issues by and large solved? My question to Milton, it has to do with what you said, Milton, you are in an excellent financial position, and you have flexibility to get to a net debt over adjusted EBITDA of 2.5 times. That's some firepower. How much does that translate in terms of this firepower? How much does this firepower translate into millions or billions?
Thank you for the questions, Christian. I would say that the one-off events related to BW and offtakes have been solved for sure.
We do have some things we are still working with that are production related. We are living a very important moment to increase production. We have well number 10, and we have to bring wells 2 and 8 back in production. These are one-off events that haven't been 100% solved.
The one-off events in terms of costs have been solved. I don't see any great cost overrun in the horizon, but those on the side of production are still being tackled. This is what I can tell you regarding these one-offs. Regarding the timing, could you repeat the timing? When do you expect well number 8 and well number 10?
O h, the well number 10 is already operational. Yes, you're right. In terms of the timeframe, we have well number 2 in the next 2-3 weeks. It should be solved. We're talking about mid toward end of December. Well number 8 is a more complex operation, so we can complete the fishing operation. It could be expected for the beginning of December. I believe that by the end of December, we are going to have full production. Regarding the firepower, I'm going to monopolize the mic here, Christian. We have 2.5 times net debt over EBITDA, but this calculation has to be made considering the pro forma EBITDA of the acquired field. It's not such a simple calculation or it's X amount of money, I have the EBITDA that I have collected. No, you have to consider the pro forma EBITDA of the field that you are acquiring.
We believe that today we have a firepower of more than $1.5 billion. $1.5 billion easily. I would say more towards 2 than $1.5 billion. That would be our firepower. Again, even with this firepower, we will not get to 2.5. We would get to 0.7-0.8. You see, we don't want to have the company leveraged. Although we have the debt covenant that we can get to up to 0.5 times, we believe that at 2.5 times, the company is kind of in a cast, not able to enjoy new opportunities. Our mindset is to have that firepower of about $1.5-$2 billion if we reach 2.7 net debt over adjusted EBITDA. 0.7. That gives the company a lot of flexibility. If we need more capital, our mindset is always to have to resort to debt and equity to maintain that ratio close to 0.6, 0.7, around those lines.
Perfect and very clear, Roberto. Thank you very much.
Thank you.
Thank you for the questions.
Our next question is by Regis Cardoso with Credit Suisse. Regis, go ahead.
Hello, Roberto, José, everyone. Can you hear me?
Yes, we can hear you. How are you doing, Regis?
All good. Good day, everyone. My first question is, could you please describe the process to present the Wahoo development plan? Could you give us a walk through? First you have to submit internally to the consortium, and then with consortium approval, that's when you can formally submit to ANP. Is that how it goes? Or can these two processes run in parallel? I just want to understand the rule of the game. That is my first question. My second question has to do with TBMT-10 production. Initial production was around 3,800 barrels, and I would like to know if this is the regular level or is there anything happening in the first months that we should wait and see what's going to happen?
As regards the rule of the game for Wahoo development plan, we divulged information while we shared pertinent information with the consortium. We prepared and made a technical presentation to the consortium, and then we had what we call an OPCOM. OPCOM presentation to the consortium. There was an initial vote regarding if they would take part in the development plan. We didn't get to a final decision as we were expecting.
Now, considering all the time points in the game, the companies have 60 days, that started some time ago, to come to a decision in terms of which consortium members will participate in the proposal for development. We have this meeting, important meeting, called OPCOM. After OPCOM, we have 60 days for the consortium members to position themselves. After 60 days, the consortium members can act independently from one another. I think the 60 days will be over sometime in December. Only after that time will the consortium or the consortium members who will be participating in the initiative present the declaration of commerciality and the development plan to ANP. Regarding my second question, regarding the initial production of TBMT-10 and what to expect regarding the remaining workovers at TBMT. Actually, we started with more than 3.8.
3.8 is what we were producing about 5 days ago. To give you an overview, these 3.8 have stabilized. We expect this to be lowered a little bit until we get to a stable condition. They will stay like that for some months, and depending on the condition of the reservoir, something to be defined and monitored. Later on, we'll start seeing some decline. I don't know exactly for how long we will have that, confirmed production. Net production 3.8 should land at the level of around 3,000. On the first day we produced more than 4.3 thousand. But we don't disclose this kind of number because it can be misleading. In the first days, production drops, so we monitor the pressure differential every day, and then we finally communicated 3.8.
3.8 is a relatively normalized number, as Francilmar mentioned.
Okay, very clear. Thank you very much.
Next question from Gabriel Barra with Citibank. Gabriel, you can go ahead.
Can you hear me?
Yes.
Hello, everyone. I have two follow-up questions. One has to do with Albacora. Thinking about the capital structure, 'cause you said you don't want to get to the threshold of 2.5 times net debt over EBITDA. One question I have is when you look at the indebtedness, the firepower that you have in the case of RBL, could this be a possibility for Albacora? I just want to understand the cost of capital, so we can do some calculations regarding the return. It would be interesting to understand first capital structure and then RBL and how it can impact the calculation and how the covenant addresses that. Second question about IBV and Wahoo negotiation.
You spoke a little about the process and how it works, but I would like to understand the outcomes, how that works in practice. For example, if they don't accept the proposal for development and the fee, could you elaborate on the possible ways out and how it works if they don't accept or if they do accept the plan, what is PetroRio's position in Wahoo field? These are my questions. Thank you.
Thank you. I will start with IBV. You see, it is evident that we need to have a handling fee. The truth is, the oil needs to be processed somewhere, and the oil has to pay for its processing. You cannot process at Frade and not pay anything for that. So the Wahoo consortium has to pay something for oil processing somewhere. In our case, specifically, it would be in Frade.
You have the handling fee that takes into account two things, the OpEx that will happen at Frade related to Wahoo. Please remember, we are going to have more production at Wahoo than in Frade. The FPSO almost becomes an FPSO of Wahoo, also helping Frade. We have the OpEx, and we have the cost of capital that has to be remunerated. We have to remunerate the whole investment made, the FPSO and so on and so forth. These two things are encompassed in the handling fee. The outcome of the business is we would like to have IBV as our partners participating in the development of the field. Of course, with a handling fee that makes sense. We presented a counter proposal to them. I'm not gonna mention numbers here, but we have submitted a proposal to them.
We would like to have IBV participating with their own stake, of course, but they simply can decide not to for funding reasons, for strategic reasons or whatever. If they choose not to participate, the other consortium member, the operator, has the right to develop that opportunity on their own, which is what we call sole risk operation. The operator can develop the field on their own. They invest the whole CapEx for the field, and of course, they collect all of the results of that specific development. If later on we want to develop Wahoo North or Wahoo South, another piece of Wahoo, we go back to the consortium and we say, "IBV, I have now this opportunity. Do you wanna come along?" They might decide to or they might decide not to. That's how it works. Those time limits have to be respected.
There is a regulation as part of the Joint Operating Agreement, and we are following it by the book. That's what we're doing. The outcomes can be two. They can decide to participate with a handling fee that makes sense, or they simply might decide that they do not want to participate, and then PetroRio will have to decide whether we want to develop the field on our own. Of course, we like the field. If we have this opportunity, we would be very inclined to do it. We acquired the field because we like the field, but of course, we have to wait a little for IBV's reaction. There was another question, Maurício. The debt. All of the debt is part of the business. It's all put in the same basket.
Regarding RBL, our funding strategy is more related to debt issuance and access to the market than the RBL and bank loans. All of them. CVM regulates the RBL in Brazil, but still, there's a part of the guarantees which is quite hard to provide the banks with. From what we saw in the past regarding RBL, the banks require that you sign a trading contract with some other player, and we don't like that at all. With that, RBL kind of loses momentum. When we are a company that has access to the market, and we do, so our strategy will be to go to market. We might get some bank loans, but our ultimate strategy is always to access the market.
Very clear. Thank you very much.
We have one more live question by Bruno Montanari, who re-joined the call. Bruno, go ahead.
Can you hear me now?
Yes.
Sorry, I had a technical problem. My third question was, in your conversations with your suppliers and service providers, is there any inflation that you see in the chain given the higher oil price?
Well, we see that this is very incipient. It's not only related with the oil price. It has to do with the size of the operation. We have a big delay in Brazil. We don't have a lot of development projects. As things increase, then there will be the supply and demand rule, but there is no direct connection with inflation. We are starting to see some price increase, and we are trying to control for that.
We see this happening more on the side of CapEx than on the side of OpEx. Of course, in our Wahoo presentation, we were already considering a certain level of contingencies, so we know how much we have thought about in terms of costs with and without contingencies. But we can feel some in the CapEx. CapEx and vessels, support vessels are in high demand, and that has to do with CapEx because the vessel is contracted and sometimes we have to do spot contracting of vessels for the campaigns. We do see a little bit of inflation. Nothing that could raise a flag. Yes, we do see a little bit.
Okay, understood. Thank you. Live questions are over now. In the interest of time, I will take only one written question by Rodrigo Siqueira.
He asks about the potential CapEx for Polvo and Tubarão Martelo, to drill more wells and how this would go about.
Well, Rodrigo, now with well number two, we had a problem there. Well, luckily, it didn't require a workover that would require that we removed the pump. It was a simpler workover, but we needed a rig. We are solving the problem with PLSV. But with that, the team is very much mobilized at well number two and well number eight, so this year we are not gonna be making any investments regarding new drilling activities at Polvo or TBMT. Right now, we're thinking to start a Frade campaign next year. We'll drill the first well of Frade. We'll see how the company behaves, how demanding the drilling of the well will be.
I believe it's going to be less demanding than what we are doing at Polvo and Tubarão Martelo because the rig is not ours, so we'll outsource a good deal of the work. We'll have to wait and see how this goes about, and towards mid-2022 we can make some decisions. We have some prospects. We have a prospect in the Eocene that stretches into Tubarão Martelo field. We have at least two prospects in the Eocene and one in the carbonate area of Tubarão Martelo, but this is very incipient at this point. Unfortunately, we cannot do anything in that regard. Bruno had asked about the possibility of bringing forward some projects. That would be one possibility if we had more capacity, operating capacity, I mean. If we have things in our agenda, and we have to deal with those before we move to others.
All right. We are going to be closing the Q&A session. I would like to ask Roberto to make his final statements.
Thank you, José. Well, I guess I made my final statements in the end of the presentation. I can only thank the resilience, the persistence, and dedication of PetroRio's team. I think Q3 showed our DNA of thinking out of the box, of executing our out-of-the-box thinking. I would like to thank all of you for your support because you're close to the company. You join us in our conference calls. You bring ideas. You raise important points. You ask good questions. Thank you very much, and I'll see you next quarter.
PetroRio's conference call has ended. I would like to thank all of you for participating