Petro Rio SA

BOVESPA:PRIO3

Earnings Call Transcript 2021-Q3

[Jose Costa, executive]

The presentation and comments on the results results will be presented by PetroRio's CEO, Roberto Monteiro; CFO, Milton Salgado and COO, Francilmar Fernandes. They will present the company's results and will then be available during the Q&A. [Operator Instructions] 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's 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.

[Roberto Monteiro, executive]

Good day, everyone. Welcome to PetroRio 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 Tubaro Martelo Field, the famous tieback between the 2 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 trains. So 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 or 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 costs 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. And this is, of course, the results of this tieback.

Still on the operating side, we were able to connect well #10 at Tubarao 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 3,800 barrels a day of oil. So we were also very happy with that result. And more on the financial slide, -- We posted a net revenue of BRL 940 million related to 2.5 million barrels sold in this quarter, specifically with 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 saw 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, and this reflects the lifting cost. Actually, it reflects the lifting cost of the second quarter, which was already a low 1 with a very high Brent oil price. This was also a very pleasant surprise, the higher Brent price, I mean. And 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 costs. 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 4, please. It kind of illustrates what I have said before. Our lifting cost fell 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 #10 started operating only in Q4. But like I said, a good part of the work was carried out during Q3. And then on the bottom of the slide, we see the 2 last indicators, cash position and indebtedness, both variable controlled with a very robust cash in a net debt over adjusted EBITDA ratio that is negative. So this was the 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. And 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 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, Francilmar.

[Francilmar Fernandes, executive]

Hello, everyone. Thank you very much for joining us. Thank you, Roberto. Well, let's start on Slide 5 for an update on the performance of our assets. I will focus on the petro that we control, production and production costs. 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. And in terms of costs, we already feel the effects of the tie back completion in the Polvo and TBMT cluster, but 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 6. Let me detail our lifting cost, which continues, and I believe will always be the main way to protect our company from from external factors. The lifting cost is something that we manage and we work daily to improve it as much as possible. So 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 clearly reflects 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. So the month of July is rather contaminated with general costs related to that. So 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 costs. Once again, the Brent price is not something we manage. So this is just for reference but obviously impacting the profitability of the company, but we have to focus 100% on the lifting cost. And 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. But we are confident that the next quarters will be a lot better.

Moving on to Slide 7. 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. And 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 with Frade, given the good conditions of the vessel operating there and our team. So all of that helped. The asset posted good production despite pressure of natural decline on the reservoir. That's something that we can only recover when we start having a new injection wells working, recovering energy and that will help.

And when the production wells start producing, which is scheduled to happen next year. It is worth mentioning that in this quarter in we restarted injecting into the old water injection wells at the field after we obtained authorization from the relevant authorities but this injection is basically to help reduce the decline rate. So every day, the reservoir pressure goes down a little. And as a consequence, production is reduced. We are able to inject fairly liquid. But it does help some. So the field has been producing for over 2 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 to recontract it. 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 Wahoo with its 4 wells. And 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 way, we will be drilling the wells. So Phase #1 will be basically ODP4, in a virgin reservoir. It is expected to flow first oil and injection wells, which are our priority on both lengths of the field in these specific reservoirs. The redevelopment plan has already been approved by ANP. So now we are focusing on the details of the projects such as well design, how we're going to drill, substitutions to get these wells in operation and all the other operating details that are required to be in place.

Now let's move to Slide #9, 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, sub-sea systems and the performance of the vessel, the FPSO. Some countries focus only on the FPSO, but we look at everything.

And 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 1 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 alpha as we've seen the macro graph where we consolidated in this quarter and operating efficiency of 82%. Down below, we broke it down. So to give you more detail, and you can see that Polvo alpha 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 work over in 1 of them. It started producing again. And at TBMT where we have only a few wells, we were operating with 5 wells now with a start of well #10. It is operating with 6 wells every well that stops as a big impact on production. So to give you some more color at TBMT, we've had well #8 offline since March. We have the 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 restrike 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 completed well 10 started production now in mid-October with, by the way, excellent throughput, I would say, even better than we expected and the rate went back to well 8 to complete the fishing work, install a bump 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 off-line at TBMT after in investigation, we've discovered that the problem was in the subsea system, more specifically in UTA, Umbilical Termination Assembly, installed on this 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 as well. Other than that, Polvo had some shutdowns, particularly in well #12. But these are regular workovers with our rig. We currently have 2 drilling rigs, 1 that stays at Polvo Alpha platform, which handles rig overs and pump exchanges at Polvo and the Kingmaker, which is ready to replace pumps at TBMT. So this is normal. It's part of the life of this asset. We believe that after repairing all of 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 a 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. So 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 Alpha platform with FPSO Bravo, installing the production line, the umbilical that in sales, 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. So 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 bolts, which are huge, and we handled that kind of work at the field.

Well, this work helped us a lot, collect a lot of data and lessons learned. There will be the foundation to be used to infer 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 is 64.3% working interest of the field with the previous 2 stakes acquired. We have strategy -- 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 been 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 wealth project is quite advanced. We have already contracted for 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. So 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 the project to A&P for approval of the development plan. I now conclude my participation and turn the floor to Milton.

[Milton Rangel, executive]

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 9 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. And when we compare that with Q3 2020, we observed 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 '20 was $43 per barrel. So a recovery, which reflects a significant improvement in revenue, margins and so on and so forth. Hence, we will see 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 a relevant financial expense. And this is related to a non-realized foreign exchange variation. So it doesn't mean that we effectively lost BRL 433 million. But this is marked to market and since the Brazilian bureau depreciated vis-a-vis the dollar, and we have liabilities in dollars. This marked to market is done in this way in this quarter. But 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 nonrecurring and nonoperational effects. So 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 9 months of 2020, we sold a little over BRL 1 billion. So 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. Slide #13. I'll explain a little about the company's funding. Starting with the 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 have basically 2 types of debt. One is the bond, which is our main debt, $600 million. And we have another debt for working capital that we are amortizing now in Q4. But for this analysis, Q3 takes into account a debt duration and average debt duration of the company of 4.33 years. So 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. So we continue on our strategy to fully prepay our other debt other than the bond mix currently, they are no longer necessary, and we do not want doesn't make sense to keep paying interest on capital that we don't currently need.

And we can see on the graph on the right, the company's quite comfortable situation. We have cash totaling BRL 4.5 billion 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 and 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 10H, 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. And financial expenses referring primarily to interest 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 '21 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 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 2.5x. The fact that we are at minus 0.5x gives us some firepower that is very interesting for new investments, new acquisitions and so on and so forth. So the company continues to generate a lot of cash and reducing more and more our leverage. As 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.

[Roberto Monteiro, executive]

Milton. Thank you very much. And 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 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. But we are still waiting with the COVID pandemic. So we will keep our guard up. We expect this reduction in number of COVID cases and deaths have come to stay. However, we will keep our guard up as we have turned 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 work over of 2 wells in Tubarao Martelo, well #2 and well #8 in this order. I believe we are almost there at TBMT 2H. And TBMT 8H, 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 3 wells at Frade on production well and 2 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 separation of commerciality by year-end in our consortium. We'll 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.

And finally, a great focus on mergers and acquisitions and inorganic growth. As you all know, we participated in the Albacora in Albacora East process. We are, of course, very excited about these fields and the possibilities they bring. We now have to wait for the final outcome. But I would say this is a very hot topic in terms of inorganic growth for the company. So thank you very much. And I would like to open the floor to questions.

[Operator]

[Operator Instructions] So we'll start was a question by Pedro Soares with BTG.

[Pedro Soares, analyst]

Can you hear me now?

[Roberto Monteiro, executive]

Yes. Great.

[Pedro Soares, analyst]

Roberto, Milton, Francilmar, everyone. I have 2 questions. The first has to do with the lifting costs 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. But as you mentioned, TBMT has suffered with some operational issues, the 2 wells that we talked about and that kind of got in a 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. And in an alternative scenario, if these 2 wells have 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 months, it offered a cushion for up to 50% of October sales. And in this quarter, you didn't mention that. When will you use this approach basically as a protection mechanism. But perhaps you can tell us, if you changed the strategy for November, December, if you have purchased to put options. And one last question, if I could ask about Wahoo. Any development regarding the positioning of IBV, they will participate in the development of the plan. If I'm not mistaken, this was expected by year end. So if you could elaborate on that, I would be grateful.

[Roberto Monteiro, executive]

Thank you, Pedro. I will start and Milton and Francilmar will help me. Let me start with IBV.We have a joint operational agreement JOA with them, and this contract entails a procedure that needs to be followed. And we are, of course, following the procedure. So we have the initial submission to IBV in terms of how we see the field expected production at the field and so on and so forth. So still following the procedure. There is some time for analysis. And there is another 60-day time frame for them to get back to us. And 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. But our expectation is to eventually declare commerciality, possibly in the next few months. So 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 very different than what we have said in prior quarterly calls. As regards to lifting costs, we still haven't captured 100% of the possible synergies. And for 2 reasons. First, we finalized the tie back in July. So 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, so 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.

And there was the production. Although we posted 31,600 barrels in the quarter, although the highest in the history of PetroRio, it fell below our expectations. But when we get well #8, well #2, now with the addition of well #10. All of that will help the lifting cost. It is a $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, but 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 have a downward trend, whether we are going to be able to reduce it dramatically to close to $10 at 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. In fact, we have more benefit to collect related to the lifting cost. Anything you would like to add?

[Milton Rangel, executive]

No.

[Roberto Monteiro, executive]

As for the hedging strategy, Pedro, it's easy to say we had -- we purchased hedging last Friday. The dollar was at 85 actually was 86 and 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, other prices are still high, high strikes, high volatility, which is not to hedge too close to the future curve, but we did it slightly below the future curve.

We are hedging amongst that range from 76 now to 72 more towards April of next year with a strike of 72 in April of 2022. So 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 but 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.

[Operator]

Next question by Bruno Montanari with Morgan Stanley.

[Bruno Montanari, analyst]

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 the project or do something differently to perhaps capture and build on these higher oil prices?

[Roberto Monteiro, executive]

Bruno, as for Albacora, what I can tell you is this is public knowledge is that we bid for both assets. We very much like those 2 assets between the 2, perhaps Albacora [ Ovest ] would be preferable. But we like them both. What we heard -- and 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. And 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. And then later on, I imagine some months, 4 to 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. So Petrobras would call the 2 runner ups to submit a final bid based on that specific contract that was already negotiated.

But just like you, we are waiting. We are waiting for news from Petrobras. There was the 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 NORBE , et cetera, for Frade. We have to go through all of these steps for Wahoo to effectively develop the field. So 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, business 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 did -- if we drilled more wells, I think it would be risky.

[Bruno Montanari, analyst]

Very clear. If I can ask -- if I may ask a follow-up question.

[Operator]

I'm not sure Bruno is still with us. Let's move ahead. If Bruno returns, we'll give him the floor again. But for now, let's have a question by Vicente Falanga with Bradesco BBI.

[Vicente Falanga Neto, analyst]

Roberto, Francilmar, Milton,Jose I hope your team. I have 2 questions. Recently, Petrobras, but the Kathua asset for sale, very near Wahoo. And I'd like to understand your opinion about this asset. Why is it that Petrobras gave up the development of that field despite recent discoveries. And I'd like to know if that he would be interested in that asset, if you would see an opportunity for another tieback?

And my second question is out of curiosity. From the technical standpoint, what is it that,the causes this "Water Contamination" when you do a tieback, which is what happened in Polvo in a nonrecurring fashion.

[Roberto Monteiro, executive]

Let's talk about Kathua. And then I'm not sure you understood your question about water contamination. But let me start talking about Kathua, and then I'll ask you for a clarification regarding your second question. Apparently, Kathua is a marginal asset for Petrobras. If you look from the standpoint of stand-alone development. It is a very similar situation to Wahoo when sold Wahoo and they left, they exited the block. They did so because they saw Wahoo as something with a marginal return for stand-alone development. To us, it makes sense because we have Frade, so it's not marginal for us. And for a potential partner because they would process the oil at Frade, they would benefit from the situation.

So it is a unique situation because we have the Frade FPSO that can process the oil. In the case of Kathua, it would be something similar. The Information we got is that Petrobras did an extended well test at Kathua. They came to the conclusion that the field was marginal to them. And that they had started a process to relinquish the field to ANP. So we proactively talked to Petrobras, and they decided to bring the asset back to the portfolio for sale. In my opinion, Kathua is an asset that will only work well if it is connected to some other field, Frade not the nearby field. There is another one, [indiscernible], which belongs to Petrobras, but Petrobras was never interested in doing that and having a tieback. So Kathua might be a viable asset for PetroRio but not so viable for other players, but we haven't got information. What we have today is Petrobras prepared a public teaser for Kathua. We told Petrobras that we are interested. So we were included in the process. And now we are waiting for Petrobras because they gave some time for people to sign up for the project. And now we are waiting for the end of this period so that we can have access to the data room. We haven't gone access to the data room. The truth is I can't even tell you how big Kathua is. Our team doesn't know. We have very limited information, right, about Kathua. We expect it to be a good deal, but it's very incipient.

And as for the water contamination vacinity, could you please explain because we haven't got water contamination. What is treated and then discarded. So I'm not sure we understood your question. Please clarify.

[Vicente Falanga Neto, analyst]

I had understood Roberto then with part of the oil sold to Polvo, or sold from Polva,it happened with a big discount because it was a nonrecurring event, but a had a high content of water, and I had on the study was because of the tieback. It's just out of curiosity. I just want to understand what caused that. It was not because of the tieback distant. What happened there was -- don't explain.

[Roberto Monteiro, executive]

Actually, there was the treatment system performance issue. It ended up collecting oil with more water. And now we spec the quality of the oil that we have, it has 1% water content. And for some reason for the service provider, there was some more water. So when we sold the oil, there was a discount due to a higher content of water, but it has nothing to do with the tieback. It has to do with poor performance of BW pre tieback. And actually, this is a claim of ours against BW. And this claim is basically focused on the performance of BW in the last -- 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 are being negligent or it's just a random thing, but the truth is that BW performed underperformed, and PetroRio has a claim against BW to have some compensation for that.

So -- but our net result is net of these losses. So whatever comes, it's extra, but we are disputing regarding that. And from what I understood, post tieback, this has been resolved. This was a onetime 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 tie back 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 was less than 1% of water content. And when we sell, we can blend the types of oil. So it's to maintain water content restricted to 1%. This is relatively a usual procedure, easy to do. we didn't have the possibility because we had to empty the FPSO.

[Operator]

Our next question comes from Christian Audi with Santander.

[Christian Audi, analyst]

Can you hear me?

[Roberto Monteiro, executive]

How are you doing, Christian?

[Christian Audi, analyst]

All good. I have 2 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. So 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?

And my question to Milton. It has to do with what you said Milton you are in an excellent financial position and have flexibility to get to a net debt over adjusted EBITDA of 2.5x. That's some firepower. How much does that translate in terms of this firepower? How much this firepower translate into millions or billions?

[Roberto Monteiro, executive]

Thank you for the question, 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 also working with that are production-related. We are living a very important moment to increase production. We have well #10 and we have to bring well 2 and 8 back in production. So 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 of offender 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.

[Christian Audi, analyst]

And regarding the timing, could you repeat the timing, when do you expect well #8 and well #10?

[Roberto Monteiro, executive]

I think in terms of well #10 is already operational. Yes, you're right. In terms of the time frame, we have well #2 in the next 2 to 3 weeks, it should be solved. So we're talking about mid towards end of December. Well, #8 is a more complex operation so we can complete the fishing operation. So it could be expected for the beginning of December. I believe that by the end of December, we are going to have full production.

[Milton Rangel, executive]

Regarding the firepower, I'm going to monopolize the mic here, Christian. We have 2.5x net debt over EBITDA. But this calculation has to be made considering the pro forma EBITDA of the acquired fields. So it's not such a simple calculation x amount of money I have the EBITDA that I have collected. No. You have to consider the EBITDA of 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 billion than $1.5 billion. That would be our firepower. But again, even with this firepower, we would 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 2.5x. We believe that at 2.5x the company is kind of in the cast, not able to enjoy new opportunities. So our mindset is to have that firepower of about $1.5 billion to $2 billion if we reach 2.7 net debt over adjusted EBITDA -- 0.7. So 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.

[Operator]

Our next question is by Regis Cardoso Credit Suisse.

[Regis Cardoso, analyst]

Everyone, can you hear me?

[Roberto Monteiro, executive]

Yes. We can hear you.

[Regis Cardoso, analyst]

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 2 processes run in parallel? I just want to understand the rule of the game.

That is my first question. And 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 month that we should wait and see what's going to happen?

[Roberto Monteiro, executive]

As regards the rule of the game for Wahoo development plan. We divided 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 op com, upcome presentation to the construction. And 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. And 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. So we have this meeting -- important meeting called Opcom.

After Opcom, we have 60 days for the consortium members deposition themselves. After 60 days, the consortium members can act independently from 1 another. And I think the 60 days will be over some time in December. Only after that time, will the consortium or the consortium members will be participating in the initiative presented the declaration of commerciality and the development plan to ANP.

And regarding second question regarding the initial production of TBMT 10 and what we expect regarding the remaining workovers at TBMT. Actually, we started with more than 3,800. 3,800 is what we will reduce about 5 days ago. To give you an overview of the 3,800 have stabilized, we expect this to be lowered a little bit until we get to 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 of 3,800 should land at the level of around 3,000. On the first day we produced, we produced more than 4,300. But we don't disclose this kind of number because they can be misleading. In the first days, production drops. So we monitor the pressure differential every day. And then we finally communicated 3,800. So 3,800 is a relatively normalized number, as Francilmar mentioned.

[Operator]

Next question from Gabriel Barra with Citibank.

[Gabriel Coelho Barra, analyst]

Can you hear me?

[Roberto Monteiro, executive]

Yes.

[Gabriel Coelho Barra, analyst]

I have 2 follow-up questions. One has to do with Albacora thinking about the capital structure because you said you don't want to get to the threshold of 2.5x 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 [indiscernible]. Could you elaborate on the profitable way out in how it works. If they don't accept or if they do accept the plan, what is PetroRio position in Wahoo field. These are my questions.

[Roberto Monteiro, executive]

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 can now process at Friday and not pay anything for that. So the Wahoo Consortium has to pay something for oil processing somewhere in our case, specifically, you would be in Frade. And you have the handling fee that takes into account 2 things. The OpEx that will happen at Frade related to Wahoo. Please remember, we are going to have more production at Wahoo than in Frrade.So the FPSO almost becomes an FPSO of Wahoo, also helping Frade. So we have the OpEx, and we have the cost of capital that has to be remunerated. Have to remunerate the whole investment made, the FPSO and so on and so forth. These 2 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 going to 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 want to come along? They might decide to or they might decide not to. That's how it works. But those time limits have to be respected. There is a regulation as part of the joint operational agreement, and we are following it by the book. That's what we're doing. The outcomes can be to. They can decide to participate with a handling fee if that makes sense or they simply might decide that they do not want to participate. And then PetroRio he 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, it 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 to wait for IBVs reaction.

There was another question -- 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 in the market than the RBL and bank loans. All of the CPM-regulated 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 it is companies 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.

[Operator]

We have 1 more live question by Bruno Montanari, who rejoined the call.

[Bruno Montanari, analyst]

You hear me now?

[Roberto Monteiro, executive]

Yes.

[Bruno Montanari, analyst]

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?

[Roberto Monteiro, executive]

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. But we have a big delay in Brazil. We don't have a lot of development projects. But as things increase, then there will be the supply and demand role, but there is no direct connection with inflation. But we're starting to see some price increase, and we are trying to control for that. You 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 and -- but we can feel some in the CapEx, CapEx and vessels, the 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. So we do see a little bit of inflation, nothing that could raise a flag. But yes, we do see a little bit.

[Jose Costa, executive]

Live questions are over. So in the interest of time, I will take only one written question by Rodrigo . And he asks about the potential CapEx for Polvo and Tubarao Martelo to drill more wells and how this would go about?

[Roberto Monteiro, executive]

Well, Rodrigo, now with well #2 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 PSLV. But with that, the team is very much mobilized at well #2, at well #8. So this year, we are not going to 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 trailing of the well will be.

I believe it's going to be less demanding than what we are doing at Polvo and Tubaro Martelo because the rig is not ours. So we'll outsource a good deal of the work. But we'll have to wait and see how this goes about and more towards mid-2020, we can make some decisions. I have some prospects. I have a prospect in the that stretches into Tubaro Martelo field. We have at least 2 prospects in the [indiscernible] and one area of Tubaro Martelo But this is very insipient 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 we have things in our agenda, and we have to deal with those before we move to others.

[Operator]

All right. So we are going to be closing the Q&A session. I would like to ask Roberto to make his final statements.

[Roberto Monteiro, executive]

Thank you Jose. 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 thinking out of the box of executing our our out-of-the-box thinking. And 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 the important points, you ask good questions. So thank you very much, and I'll see you next quarter.

[Operator]

PetroRio's conference call has ended. I would like to thank all of you for participating.

[Statements in English on this transcript were

spoken by an interpreter present on the live call.]