Enauta Participacoes SA

BOVESPA:ENAT3

Earnings Call Transcript 2020-Q2

[Operator]

Good afternoon, and thank you for waiting. At this time, we would like to welcome everyone to Enauta's Second Quarter 2020 Earnings Conference Call. Today, we have here with us Mr. Lincoln Rumenos Guardado, CEO; Ms. Paula Costa Corte-Real, CFO and IRO; Mr. Danilo Oliveira, Production Director; and Mr. Jose Milton Mendes, Exploration Superintendent.

We would like to inform that this event is being recorded. [Operator Instructions] Before proceeding let me mention that forward-looking statements might be made during the conference call relative to another's business perspective, projections and operating and financial goals are based on the beliefs and assumptions of Enauta's management and on information currently available to the company. They involve risks, uncertainties and assumptions because they relate to future events and therefore, depend on circumstances that may or may not occur in the future. Investors should understand that general economic conditions, industry conditions and other operating factors could also affect the future results of Enauta and could cause results to differ materially from those expressed in such forward-looking statements.

Now I will turn the conference call over to Mr. Lincoln Rumenos Guardado, Enauta's CEO, who will start the presentation. Mr. Guardado, you may begin.

[Unknown]

Good morning, everyone, and thank you for waiting. We had a little technical problem with our connection. And again, I'd like to thank you for your patience. And again, thank you for joining us on this conference call to discuss second quarter 2020 results. Once again, we are reporting from home as all of us in administrative positions continue to be working remotely and we are following our field operations remotely. I hope you're all well and able to carry on with our professional and personal activities in this very difficult moment that we are all living.

We have some very good news regarding the results of our company for this quarter. So let's begin on Slide 2. Again, in the second quarter, as could be expected, our focus remained on the health and safety of our employees and on relevant definitions for our business in the short, medium and long term. However, at this moment, always we'll be maintaining a special focus on the short term in light of the pandemic that we are still facing in Brazil and worldwide and also focusing on the Brent price scenario, which recovered at faster pace than we expected.

In the end of the first quarter, on this perfect storm of Brent price in the pandemic worsened the situation of the international market. So given all that, we maintained our crisis management team active, which has been working really well supporting us. And our operations are following rather strict protocols, which have been quite effective to control the spread of the virus in our facilities, particularly our offshore operations.

Well, Manati resumed production in May. And we are at the final stage of negotiating an agreement with Petrobras. After receiving our force majeure notice in the end of March because of an abrupt contraction in the demand for gas in our market. As for Atlanta, the consortium is still discussing the full development system. We are now resuming these discussions more strongly. And we are still discussing the drilling of the fourth well, aiming to maintain production at the field and to supply the growing demand for low-sulfur oil, which is the case.

Of Atlanta's oil, we had a final offtake shift to China. Posits, some investments have been postponed. We reduced our CapEx by around 40% for the 2020, 2021 period. Of course, this has an impact on our cash and on the maintenance of our cash, which is really important at this time.

During Q2, we also maintained our strategy to purchase Brent options, hedging approximately 48% of the company's production for the next 2 quarters of the year and the first quarter of 2021. This guarantee some protection against commodity price volatility.

Slide 3 brings some data on the Brent scenario in the first half of 2020, which was shown to be for sure, one of the most volatile, if not the most volatile in the history of oil production worldwide. This is totally unprecedented, something we have never seen in the past years when we had production and demand increase. Up to 2 months of the pent-up demand due to the pandemic, in other words, in March and April, May and June saw a consistent recovery in daily consumption of oil barrels with a positive effect on price, which reached around $41 per barrel in this quarter, up 81% in the second quarter.

A good deal of this recovery undoubtedly happened on the back of the economic rebound, driven by China also coupled with OPEC+ production cuts, including Russia and also coupled with the substantial shale oil production reduction in the United States. And this should remain since there is not much elasticity in the production of shale oil in the United States. Since then, oil prices have continued to grow now, through a lower pace, and now Brent is priced today at around $44 per barrel with a trend towards slow but steady appreciation, considering everything we've seen from the agencies and several private institutes as well as banks.

So we are monitoring this extremely volatile environment of close, but focusing on the commodities long-term scenario, which is what really underpins our investment decisions. So looking ahead, U.S. shale oil production is likely to decrease in the United States. And as we said, this production is not very elastic. And this is an important factor to be monitored because it is likely that we'll see reasonable production reductions in the United States.

Please go to Slide 4 for an update of our producing assets, Manati and Atlanta, which is what we follow always very upwards. The good news about Manati is that production resumed in May. The company is negotiating an agreement with Petrobras. We are at an advanced stage, this is an amendment to the agreement that we have with Petrobras. And this is unfolding really well. We have received compensation for the month of April, May. And we have built June production. And the compensation for these 3 months is based on the agreement with Petrobras. In Q2, daily average production was 1.1 million cubic meters, reflecting the months when production was halted at the field, particularly during March and April, that was a difficult month.

In the end of May, production was resumed. For that reason, in the end of July, the company disclosed a new financial compensation forecast for 2020. Always reminding you that this is based on a take-or-pay regime. And corresponding to an average daily gas production of 2.3 million cubic meters with a margin of plus or minus 10% because we always have to take into account market needs.

Atlanta Field recorded an average daily production of 25,800 barrels of oil in the second quarter of 2020, almost double the volume produced in Q2 '19, and in line with our forecast. In June, the water volume levels required separation from oil and treatment for this charge. We began to commission this process for the FPSO facility. And it can only be done at this stage because we have to characterize the water, serenity and everything that comes with it. Volume is also necessary for this commissioning. During this process we cannot solve a issue, which forced us to shut down 2 producing wells and 2 temporarily reduce production at the field. So as to -- all of the December is required to sell the oil while this problem is completely solved.

We should say that COVID-19 made transport of people a little more difficult of the people who would come to help us, including TK's personnel to help solve the problem. And we expect that with everything that is being done, we expect it to be operating normally already in August. As the issues that we faced, and I want to stress this, these issues are not related to the reservoir's behavior, but rather to performance issues of the FPSO, particularly in the water and discharge -- the water separation and discharge plant. Well, TK will cover the repair cost. In lower production, also reduced the FPSO charter costs due to the fact that the processing plant sales to perform according to contract trends.

Increased production in Q2, coupled with a renegotiation of supplier costs at approximately 11% is operating costs, with the lifting cost to drop by almost 50% in the second quarter of 2020, totaling around $15 per barrel compared with $29 per barrel in Q2 '19, and compared with $21 or close to $22 per barrel in the first quarter of this year.

We reduced production at Atlanta due to water separation problems led us in July to revise our average annual production forecast to 23,000 barrels of oil per day in 2020, with a variation margin of plus or minus 10%. We also disclosed an average daily production forecast of 18,000 barrels of oil for 2021 at Atlanta. Due to the fact that the FPSO is at maximum water treatment capacity for this FPSO Petrojarl 1, which requires production control in the wells. Due to the homeostasis, we have a problem with water separation and in the operation of the plant.

For 2021, with the continued production of the field and water production that always grows at a certain pace, we will reach a maximum water treatment capacity of around 7,000 barrels of water daily. Well, a mitigating action for this fact might be drilling before as well, which we are discussing with our partners. And this fourth well, in principle, should not have as much water production as the older wells that have been producing for longer. So we could recover part of this production by the end of 2021, and we believe we'll be able to drill the fourth well.

With regards to the next steps for the full development system of Atlanta, the requests for proposals for the FPSO charter remains postponed. It's been postponed, it hasn't been forgotten. We are working on it. And now with a little more emphasis. But the consortium is discussing, as I mentioned, to the approval to drill the fourth well. And this fourth well is to increase our revenue given the opening of new markets for our oil. And IMO 2020, which has helped us have very low discounts for Atlanta's oil. Following price monitoring and the evolution of the COVID-19 pandemic are the main factors for these decisions regarding the FPSO and the fourth well.

But in our view, the market is doing well. And we don't expect to have a second wave of the pandemic, which could impact the economy worldwide. And hopefully, we'll continue with our decisions.

Moving on to Slide 5. We will update our exploration efforts. We are maintaining our plans to drill one exploration well by mid-2021 in Sergipe Alagoas. ExxonMobil, the operator, has already filed an environmental impact with the annual report to IBAMA, Brazil Environmental Agency. And in the second quarter, we finished processing final seismic data. So now we can choose the locations where we will -- we can drill the first exploration well in Sergipe Alagoas Basin.

In the Pará-Maranhão Basin, the farm-out process remains on hold due to uncertainties regarding the bid to obtain the drilling license. But undoubtedly, we continue to be approached by interested parties as this basin is very close -- with the same oil system. So it's very close to the French Guiana and Suriname region with many recent major discoveries, particularly now in Suriname. The 2 companies, Total and Apache with volumes potentially greater than 1 billion barrels of oil equivalent.

So what we're seeing is that these discoveries are getting closer and closer to Brazilian borders. They are moving east. So the farm-out process is expected to resume by next year if we obtain the drilling licenses from IBAMA. So that we can proceed more statically activities in those basins, particularly in Pará-Maranhão.

Another important change in this quarter happened in the East Bank. In the Espírito Santo Basin blocks with the operation of the blocks now transferred from Equinor to Petrobras. We maintained our 20% working interest in deepwater since Espírito Santo Basin, and Petrobras now holds an 80% interest and is now the operator of these blocks. So this is a very broad overview of everything that is happening. Undoubtedly, the pandemic has required some fast-acting from us regarding the maintenance of our cash. But now I think seem to be improving, particularly with economic growth, we will go back to discussing those decisions that were postponed. And that will allow us to continue our operations and to improve more and more our production, always planting the seeds for the future.

I will now turn the call over to Paula, who will comment on our financial results as well as comment on our future outlook for Enauta. Paula, over to you.

[Paula da Costa Corte-Real, executive]

Thank you Lincoln, good morning to all, and once again, thank you for joining us once again. I will begin on Slide 6, explaining the nonrecurring impact recorded in the quarter, which affected our financial metrics, especially EBITDAX and net income. These impacts were, well, an impact of BRL 121 million from the transfer of Dommo's 20% interest in Atlanta Field B.V., increasing our working interest to 51%, BRL 62 million tax credit from the favorable decision to exclude ICMS from the PIS and COFINS calculation basis from 2009. So this decision goes back to 2009. And BRL 46 million in revenue from hedge from our oil that we had bought last year.

On the next slide, Slide 7, you can see a summary of our results compared to the same period of last year, and we do that with and without these nonrecurring impacts in order to provide more transparency to our figures. The increase in Atlanta production, combined with the impact of hedges is more than offset the 59% decrease in the average oil sale price compared to the second quarter of last year as well as the 57% decrease in revenue from Manati caused by a lack of production in the field in part of this quarter.

As a result, our net revenue grew 33% in the period. EBITDAX reached BRL 310 million with a nonrecurring impact. And BRL 150 million, excluding these impacts. Similarly, net income reached BRL 128 million or BRL 4 million, excluding these nonrecurring impacts. Atlanta accounted for 86% of our revenue in the quarter, considering that the Manati field resumed production only at the end of May. And although we had receivables vis-à-vis April and May. But we got from non-produced gas owing to the contract terms, it comes as advanced. So it does not affect the revenue in the quarter. So the revenue eventually was highly affected by this time, in which the field was out of production. So this receipt has a cash impact, but not an impact on the company's earnings right now.

Now on to Slide 8, where we present our cash and debt. We closed the second quarter with a cash balance of BRL 1.6 billion even after a dividend payout of BRL 300 million for 2019 results on April 28. Our debt of BRL 232 million is 100% denominated in BRL as are most of the long-term maturities. So we did not see an impact on financial expenses owing to FX and the volatility that we saw in recent months. Our net debt over EBITDAX ratio dropped even further this quarter, still negative at 1.4x. Actually, we have net cash at the company.

These figures undoubtedly keep us in a very comfortable position, particularly at this time of uncertainty. So we can get through this volatile period with some tranquility and ease.

On Slide 9, we break down information on the hedge contracted for Atlanta oil production. Over the last few months, when prices return to $40 levels, we decided to buy more options to hedge a higher portion of our production in the future, particularly for the end of this year and early next year, which is winter in the Northern Hemisphere. We understand, at this time, we might see some volatility in prices should we have a second wave of COVID.

Today, we can have Brent options at an average of $56.7 per barrel corresponding to 48% of production expected for the company in the third and fourth quarters of 2020. Note that in the second quarter, the positive impact from hedge on our revenues reached approximately BRL 50 million. And when we consider the premium from options maturing in the quarter of BRL 4 million, the positive net impact on the company's revenue was BRL 46 million. As you can see, on the right-hand side of the slide, considering the hedge, the expected breakeven point for generation of operating cash in Atlanta in the third quarter of 2020, will drop from $31.5 per barrel to $6.8 per barrel. So a 1-digit or single digit, which is very important for the company.

And in the fourth quarter of 2020, the effects of hedge operations that we already had contracted, our breakeven point for operating cash generation moves from $26.9 per barrel to $16 per barrel. Enauta maintains a comfortable operating position through the end of the year due to contracted hedge positions with capacity to support production even with Brent at single-digit levels or lower levels.

On Slide 10, we have our CapEx. As Lincoln mentioned in the beginning, primarily as a result of the postponement of the full development system and drilling of the fourth well, we reduced our investment plan by approximately 40% from $181 million to $110 million, being $35 million for 2020 and $75 million for 2021, plus or minus 20%.

Please note that despite this decrease, the drilling schedule for the first well, the first exploration well of the Sergipe Alagoas Basin in 2021 remains on track. Of the $35 million budgeted for this year, $15 million has already been invested in the first half, 40% of which in Atlanta. For 2021 of the $75 million expected, the company estimates $27 million for Atlanta, including drilling of the fourth well and $37 million for blocks of the Sergipe-Alagoas Basin where drilling of an exploration well is expected for next year.

To conclude, we will talk now about our priorities and how we are preparing for the post-crisis period. On Slide 11. Moving now to Slide 11. As usual, for Enauta, we will continue to be prudent in our decisions, especially those related to capital allocation aiming to preserve cash and protect value as was the case with our lower CapEx and the use of our hedge policy in a more disciplined and efficient manner. The global oil price scenario has been showing a positive trend with stable speed directly related to the behavior of the pandemic and a possible second wave as well as its impact on world economy.

In Atlanta, our low-sulfur oil continues to record high demand, including new regions, new destinations, new buyers, for instance, like China. In Brazil, we are experiencing the second month of industrial recovery, and we'll continue to monitor all market developments. We also pay attention to new opportunities that may arise both in terms of participating in bidding processes and auctions and good acquisition opportunities that make sense for our portfolio composition.

Last, but not least, I would like to mention the transition -- energy transition. We understand that a transition to a low-carbon economy is a process that is already in motion and will take a few decades to materialize. But Enauta is aware of the environmental impacts of its activities. The start-up of the Atlanta field resulted in the accelerated evolution of tools used to quantify CO2 emissions, identify reduction opportunities and determine action plans and investments required to achieve this goal.

In 2020, we maintain our participation in the carbon disclosure project, disclosing to all stakeholders, our actions to monitor and control greenhouse gas emissions. And publishing inventory of emissions, which is verified by a third party. In June, we also announced our addition to the sustainable ocean principles promoted by the UN Global Compact, which was created in 2019, and focuses on responsible practices in the oceans. Because of our relationship with the maritime and coastal environment, we already work in compliance with SDG 14, life below water. And this new step emphasizes our expectations and the urgent need to attack and recover the health of oceans, which is where we operate. With this association, we will work alongside business leaders worldwide to establish clear expectations disseminated to the entire industry for a healthy and productive ocean.

In the second quarter, we also published our sustainability report based on the global reporting initiative guidelines. This year's version is already available on our website, and I recommend and invite you all to access it and learn more about all our commitments, metrics and initiatives adopted by Enauta.

With that, I conclude our presentation. Operator, you can open for questions.

[Operator]

[Operator Instructions] Our first question comes from Luiz Carvalho with UBS.

[Luiz Carvalho, analyst]

I have 2 questions. Lincoln, I want to go back to Manati. And to understand how we should think the field's activity, given this new scenario. First, because of this force majeure in notice and this clause that Petrobras is trying to enforce, I would like to understand a little more how the negotiations are involving. You said the negotiation is at a final stage and also the reason by Petrobras, if this would have any impact in your contracts for that field?

My second question would be regarding Atlanta. Paula mentioned that oil prices returned to close to $45 per barrel, but it's still very close to a breakeven for Atlanta. And of course, the company has a more long-term view of this. So I'd like to understand your rationale and what you're thinking regarding the development of the field given this new normal in the oil business.

And my final question, perhaps addressed to Paula. Paula, just to gather a sense of what you're thinking. You talked a lot about resilience in about protection of the company's cash. And going back 10 years, the company has been very conservative in terms of cash provisioning and cash position. So I'd like to understand, how this new scenario changes, not in terms of cash preservation, but perhaps in terms of capital allocation, for new investments, new well being drilled and so on and so forth?

[Unknown]

Thank you, Luiz, for attending the call and for the questions. Well, we have quite a few questions. So I'm going to speak a little about Manati. And then Paula will speak about the break-even and about the new normal. But I can tell you about what we are thinking about Atlanta and she will add information regarding cash preservation. Indeed, Petrobras made the statement, not only with us, but also with other partners because of the pandemic, and we quickly acted. They informed us of a force majeure notice, which was almost seen in lateral, but then we started negotiating. We sat down with them and discussed and told them that we understood everything that was happening and a drop in demand for gas at that moment. And we talked about renegotiations, just like we renegotiated with our suppliers. So we sat with Petrobras and it was a very good discussion. We tried to calm down and to understand each other's point of view.

Of course, we had a cash provision, all of the partners, not just us. So we sat together, and we came to terms about a transition and about what's coming in the future. But I can tell you is that we resumed production at the field in May. And already in the scope of this renegotiation with Petrobras, in June, we regularized production, the same in July. And basically, what we agreed was back in the months when production was lower. We have received compensation in April and May from Petrobras. In June, we have built for the correspondent production and things are normalizing as of July.

But what we agreed upon, and this is still being written because it's going to be an amendment to the contract, but what we are -- well we are agreeing that volume that was not taken can be taken later along this year or perhaps next year. So this is more or less the idea that we are discussing involving the consortium and Petrobras. This is what we have to tell about this renegotiation.

So it's a postponement. The market is coming back. Petrobras is coming back and really composing everything. But undoubtedly, there is some volume which was not produced, and which led us to change a little bit forecast for this year for an average daily production of 2.3 million cubic meters a day. What is not taken, could be taken, and it will depend on market conditions. Regarding the leasing, this was for the first alliance years plans, but you asked about the contract. In our contract, it's with Petrobras. And so we talked with Petrobras about this.

If Petrobras assign this contract to somebody else or distribute, then they can do it. Petrobras also has gas from other regions of the country, so they can respect the contract with Bahia and Sergipe in several ways, using Manati or some other gas that they have. So to date, we don't see any interference affecting us. Not because this was published by Petrobras during their process of divestment in these areas.

So to date, we don't envision any problems, but we might have is one more consumer in the area. We had a traditional consumers of Manati gas, they consumed about 1 million cubic meters a day of gas. And now when the activity resumes, I think that this is actually going to be a guarantee that we will outflow our gas and not just our gas, but the gas from the whole of the Northeast. We are happy to see that gas consumption will continue to grow in the Northeast, not only because of Manati immunity, we'll have production for 2, 3, 5 year stops, but we'll also have Sergipe. So we see that there are new consumers and new players in this market. And this makes us very happy. And hopefully, this will be a win-win situation for all.

Regarding Atlanta, we see still a lot of volatility out there. But what I can tell you is that we are all concerned and focused on our operating rates even that we're facing today. Of course, there was a drop in production, but we also had a reduction in our operating costs. We mentioned those, $15 to $16 rounding up and $21 in these 2 quarters considering our hedge position. We now have a hedge policy, which is established at the company, used to be a currency geared policy not geared to the price of the Brent oil. And this hedging position has helped us weather the storm of the pandemic. So we see a higher breakeven $37 to $40 per barrel for Atlanta, but we don't see this as a concern because the Brent oil being selling at this value. It has reached $40, and we are forecasting an upward trend gradually.

So for Brent, of course, there will always be hiccups, but when we decided to bid for the FPSO, the FPSO accounts for 40% of our operating costs, not of the lifting costs, but operating costs as a whole. And of course, this is going to be a very important factor for us to have a pretty good idea of how to proceed. But our breakeven, looking at the FPSO market today, we are not facing such a serious crisis, but still what we expect that we'll have a breakeven around $40, perhaps dropping depending on the way in which we develop the field with a certain elasticity and capital allocation.

This is what we're envisioning, but a more precise number we'll have later on. So that we can start bidding in the coming months. This is the kind of work that we're doing now, not only to optimize things, but also looking at the future Brent market so that we can do something that will be very responsible. We were quite ahead in this process when we had the pandemic and the abrupt drop in Brent oil price. So we had to be rational at that time, but now we're resuming. So this is kind of the range that we can expect for the Brent breakeven in thinking about 50,000 and lifting costs. Perhaps around 20 -- a little over $20 for the full development system.

The one thing is what we expect and the other thing is the total cost, but the range that we can expect and looking at the market, looking at what's happening and the potential FPSO opportunities and potential opportunities that might interest, we expect this range around 40.

Now I will turn the floor to Paula to speak about our cash position and perhaps she can shed more light regarding our breakeven. Paula feel free to add to what I said.

[Paula da Costa Corte-Real, executive]

Thank you, Lincoln. Hello, Luiz. Thank you for the questions. Regarding breakeven, I think that Lincoln explained well. We're still working on the bidding of the main contracts. Perhaps the main contract for the full development system is the FPSO contract. We are still working on the bidding. It's hard to calculate the breakeven, if we don't have these costs already refined. So undoubtedly, we have to use the market better, and things will bring us more accurate values, first to calculate the breakeven of Atlanta's full development system.

In our most conservative scenarios and the lows of all we have for the future oil market, looking at 2023, when the field would start operating until 2028, we're talking about oil of about $57 per barrel. Today, if you look at this market today, so this number seems to make sense considering the parameters that we have for Atlanta. But the breakeven numbers and investment numbers will be a lot more refined when we can read the market better as the market will adapt to lower brand prices, which helps us in the decision-making to invest in our projects.

Now speaking about cash, resilience and hedging. Our hedge policy for the commodity -- specifically for currency, we look at a longer 3-year period. But for commodities, specifically, we always look at the next 12 months because normally we work with put options and when we look at the long term, exposure to oil is part of our business. A good deal of our assets are reserves. A good deal of our value is based on reserves. And I cannot hedge all of the unproduced reserves. So with our hedge fault, we try to protect ourselves from this volatility moments as we have recently and to ensure the fundability of the company to weather these more turbulent times.

Regarding cash allocation, I think that the company was always very prudent in using our cash. I think we made some important news since our IPO, given the acquisition of the Santos Basin BM-S-8 that ended with the Carcará discovery, BS4 and how and when we became more aggressive in Sergipe-Alagoas, which is a basin in which we believe a lot in terms of the exploration potential. And these were important steps taken by the company.

The fact that we are capitalized and can enjoy these opportunities, made a huge difference. And it is a little of what we've seen now. We understand at this moment when we have market volatility, we will lead the repositioning of many of the oil companies. This kind of repositioning can bring good market opportunities and with an affection. We have all of the variables in place. We are capitalized. Our technical team is prepared to enjoy these market opportunities that arise.

In recent years, the company moves when we believe we have excess of cash. So these will be the opportunities mapped. And given that the company is a cash cow, the extraordinary -- we have this extraordinary dividend payout. This has happened in the last 3 years, and it's part of our capital allocation at Enauta when we have a surplus of cash. So what I can tell you today is that we have quite capitalized we understand that the repositioning of some companies will bring good opportunities out there, and this is what we are seeking. We expect to have good projects to add to our portfolio. And that would make strength in our portfolio, always proceeding with caution and prudence. This is the company's DNA. This is what has brought us this far. And we always want to preserve the value of our portfolio and longevity of the company. This is what we are pursuing.

[Luiz Carvalho, analyst]

My next question goes back to the first point. The Petrobras contract in Manati, I didn't really understand. Indeed Petrobras has assigned immunity to another player. The contract remains valid with Petrobras or with the new players, the new consortium?

[Unknown]

In principles, Luiz, our contract is with Petrobras. And out of it at the right time, we'll have to sit with them and see the maintenance of the contract with a new player. And of course, the guarantees associated to the contract, we have very little information so far. But Petrobras from what we understood was signing the contract for 1 year. This is in the documents disclosed by Petrobras for their divestment program. This is still a little fuzzy for us the way we should be doing it. But from what we understood, Petrobras would be assigning the contract to another player for the period of 1 year, and then Petrobras would come back. So as far as we are concerned, our contract remains with Petrobras. Petrobras continues to be the guarantor of the contract with us.

[Operator]

Our next question is from Guilherme Levy with Morgan Stanley.

[Guilherme Levy, analyst]

I have 2 questions. The first question is the following. I understand there were several factors, which contributed to lifting costs in Atlanta. I would like to better understand how much each one of these factors contributed to this put cut, 380, just to have a better understanding about the trend for future quarters. I would like to understand the oil price influence or contract renegotiation as a factor and also the water treatment plant impact. Second question, do you have an update about any expectation for the last portion of Carcará sale?

[Unknown]

Levy, I'll answer your question about Carcará. And then I'll turn it over to Paula and Danilo, and they will give you an explanation about lifting costs. If there are operating drivers, we did have operating drivers and also financial drivers with the reduction of contracts. So Paula and Danilo are going to give you more color about what happened to costs and why the effect was not so strong, lower production, but also lower cost. But regarding Carcará, we've been following the process, considering what's happening in the media as well. Equinor, for instance, is very dynamic vis-à-vis Carcará. And even expecting production for late 2023 or '24. They have an FPSO in operation in Brazil with 220,000 barrels per day. And this has been noticing initiatives from those who are already doing fine, it declared the commercial potential of the field in December last year. And following the rules vis-à-vis A&P, Equinor has 6 months to deliver a development plan.

In such development plan should had been delivered the problem of the pandemic, for instance, also had an impact. Coronavirus made it harder to work on our actions, all companies, including A&P, but it should have delivered the plan by late June. A term of 6 months after the commercial statement, to deliver the development plan. And the individualization agreement of production, which is actually a negotiation that companies and consortiums do with the FPSA (sic) [ FPSO ]. It is a schedule to this plan. So we believe that considering there has been no delay owing to all the problems that we're facing, Equinor should have submitted this plan in late June or early July, and this unitization is part of that. And the agency has 6 months, that's the time frame, that's the time for the company to issue a response.

So my answer is, there is a chance. If you think about the whole picture, and everything that is, including these challenges, corporate administrative challenges faced by all of us, so maybe part of it could happen this year. The chances are they will come in the third quarter, the remaining $144 million that Equinor is expected to pay us. And probably in the first quarter, considering not the maturity terms contracted with the agency and regulation, but considering the scenario in the world and also in Brazil, some kind of difficulty. So that's our forecast.

This year is still a possibility, but chances are it will happen in the first quarter of 2021, precisely owing to everything that is happening right now. But we can see that Equinor is being very diligent and is very fast, agile in terms of the plans and all the contracts for the so-called today Bacalhau field, which was renamed with Carcará discovery, Bacalhau. So that's information we have access to. This is the more official information, considering explaining simply the time required from the commercial potential statement, which was issued in December last year. So we are really looking forward to having this money because we have a lot of plans for it.

And now I'd like to turn it over to Paula and Danilo, so they can tell us more about costs and also about the operation aspects. Paula and Danilo over to you.

[Paula da Costa Corte-Real, executive]

Good morning, Guilherme. This is Paula speaking. I'll try to answer your question about the cost, and then Danilo may add to my comments, and I can turn it over to him. Operating costs, I think there were some variables, which had an impact on this reduction of which brought this reduction. And they may or not have a more perennial impact. Firstly, we have thought of our costs denominated in BRL. So we have a rise in FX rate. When I look at cost back to the dollar, costs were slightly lower as a result of FX. As for contracts, we had a negotiation. We even announced it previously, we had a renegotiation involving some contracts over the pandemic. And this has to do with the drop in Brent oil and all challenges related to the pandemic, so we managed to reduce contracts related to the operation. And these contracts alone, excluding FPSO, would lead to a reduction of approximately 10% of operating costs. So this window of negotiation varies according to the supplier. But it remains as long as we are going through this crisis and lower Brent and the pandemic.

There was another important factor in effect this time related to the FPSO, and I'll break it down into 2 different parts. One part is the TK contract. There are some portions that are variable, depending on Brent prices. So for lower Brent, naturally, there is a reduction in the amount of the tariff. And the second part, involved some problems that we faced, particularly from June onwards. The worst impact was in June. And this was related to the separation agreement of water. And it eventually affected the company's production, our average was 25,000 barrels in the quarter. And consequently impaired TK's contract with the FPSO. So it also brings a cost reduction proportionately. And it continues as long as we have to trade water and separate the water with a direct impact on the operators or charter performance in the FPSO.

So we expect this problem to be fixed within the next weeks or the next month. And once the problem is fixed and solved, we would go back to production levels closer to what we had before and consequently costs closer to what we had before. So if we take into account Brent around $40 as it is today, considering $40 or $45, I would say that we will see operating lower than what we had first quarter.

However, higher compared to the current quarter. The third quarter is partially affected by Teekay and the performance of the agreement. It still bring this lower cost in FPSO. But when you consider a longer horizon, then we expect to see costs between what we saw in the first and third quarter. And remember that the 10% reduction last as long as we are in the pandemic. And also consequently, Brent being impaired as well. So we've been trying to turn this project into the healthiest project possible, the more sustainable possible and we are counting on the partnership of some suppliers, and that's why we managed to have this reduction and have a reasonable impact on Teekay's performance.

So what we have today is to check on a quarterly basis in dollars, maybe it dropped down 20% and 10% related to contract negotiation in the remaining 10% or 11% in the quarter average. Remember, this is concentrated in June. But as a quarter average, this would be related to the FPSO's performance.

Danilo, anything to add? Is that clear Guilherme? Any further questions?

[Guilherme Levy, analyst]

Now it's crystal clear.

[Operator]

Our next question from Leonardo Marcondes with Itaú BBA.

[Leonardo Marcondes, analyst]

Lincoln, Paula, Danilo. I hope you're all doing well. My first question is about Atlanta's discount. We can see a faster adaptation than expected in the naval industry vis-à-vis IMO 2020. Regarding this, I would like to better understand how you see the marketing of Atlanta oil in the short-term and also how it should develop in the mid to long run? My second question, I'd like to better understand the company's mindset about your portfolio management. In my perception, and please correct me if I'm wrong, my perception is that the company is more focused in Atlanta's full development system and the exploration campaign of Sergipe-Alagoas. These are products that are under your visibility. So how do you see the company in the coming years with regards to these assets? And do you see a path of growth to the company coming from other sources, for instance, M&A in the short to mid run.

[Unknown]

So let me talk about the second question first. And then Danilo is going to show you -- is going to give you more detail about marketing for Atlanta's oil and all the variables that you're pursuing today in markets and not only prices for the oil, but also checking the full development system, Danilo will explain more about it. Regarding management, you are right. We are heavily focused on Atlanta because that's what's generating cash to us. It's even bringing information to us today, telling us how we can be as efficient possible to turn the full development system even more resilient to everything that is happening or all the variations in oil prices and also the future. We are not working today with oil at $80 in the future, but we have forecasts companies that even worth this $80 in the futures market, but we believe that this project truly provides us with several options. And the data collected has helped tremendously to set the full development system. And that's why we are not in the bid yet.

We are first checking the evolution of the oil, and we've been trying to make use of several options for the field. So we can have some ease and calm to come to a decision. Sergipe undoubtedly brings a lot of opportunities in the future. We can see what's happening. Sergipe is already a production basin. Actually, it's the first in Brazil, in the ocean and in Brazil, the first with deep waters with Petrobras after the discovery. So we are very hopeful in Sergipe. We've been exploring it and looking forward to it for a long time. The latest discoveries in Guianas and Suriname. They have the same oil system, not only do they leverage Sergipe and Alagoas, but also leverage our areas in the equatorial basin, particularly Pará-Maranhão, but also in France, everything that is happening is analog in Suriname and in other countries. So this is analog to everything in the equatorial system and also in Sergipe. Sergipe is closer.

Possibly next year, at this time, next year, we'll be drilling it. There was a slight postponement owing to the pandemic because purely and simply, we are awaiting for the drilling license for Sergipe. That's all we need. Everything in terms of seismic data for the 9 blocks, just in 1 block, we still have 1 piece to work on seismic data, but with no impact on the current decisions. All the rest is ready. And the operator is already making all the actions needed to buy long-lead items and to work on the drillship bidding process. Not only in Sergipe, the operator has other areas in Brazil, which, by the way, is good. It allows us to have a longer campaign and provide operational gains. But Sergipe, undoubtedly, when it comes to operations, is our first focus, followed by Pará-Maranhão. And as for cash in the short and mid run, that's Atlanta, with the possibility of having another well and the full development system in the mid-term by the end of 2023, which is what we imagine to happen and depending on decisions that we can make by year-end.

And undoubtedly, we also consider some kind of acquisition, but acquisitions have to make sense to our portfolio. Certainly, we have to keep our eyes open and have our cash ready to whatever may happen in Sergipe, not only investment wise or investment in Atlanta, we also expect to see some kind of financing for that. We do not intend to fund the full development of Atlanta with the company's cash, a part of it at first, okay. But Sergipe, depending on the first results, we might have a very fast exploration, which has to be taken into account. It's ready to go within 1 year. However, it doesn't prevent us from keeping an eye on opportunities in the market. We've been doing that. But these opportunities have to make sense. What do I mean by making sense? They have to be better than current capital allocation opportunities. There should be some production visibility. We've seen many areas that are in the final phase expected production between 4 and 5 years, 6 year tops, and we want something slightly longer. Therefore, allowing us not to have to go back to the market in a short time frame.

Today, what we still see in some of the opportunities that are coming up or which were offered particularly last year, is that these are incrementals of oil with a lot of field activity, actually a different kind of company. You have to change substantially your company in order to get into more mature areas, particularly those sold by Petrobras, like hubs, areas with 3, 4 or 5 platforms under production, which is not really the environment in which our company is promoting itself. So we keep our eyes open, that's correct. And undoubtedly, there is room for any possible acquisition or any merger that makes sense to our portfolio. It has to make sense. We don't keep an eye so much on our exploration because our portfolio already considers short and mid-term with equatorial basins, Sergipe, low risk, short-term and anything other than that has to fit into the operation. And today, we are more focused on checking what may come up and diversify our revenue source, maybe start of production or production with visibility beyond 8 years. So we can really expect to have any new discovery in production. So a lot of things to happen. We expect to have even more, but we are keeping an eye on these opportunities.

Leonardo, if you have any further questions on that, count on me. But first, I would like to give the floor to Danilo to share our marketing strategy for the oil. And standards that we currently have with the sales.

Over to you, Danilo.

Danilo?

[Danilo Oliveira, executive]

Danilo speaking? Can you hear me?

[Unknown]

Yes, we can hear you.

[Danilo Oliveira, executive]

So Atlanta's oil is being showed today at a level of Brent plus, variation, but we are negotiating at Brent plus levels. Please bear in mind that the number we announced and disclosed for Atlanta's oil considers this portion of the oil value, which is Brent to us, minus logistics costs, which are cost to pay, the demurrage or the time it takes to load the vessel and the freight to destination. So we are working on short term, considering short term, the early production system, and we don't expect to see any changes. We have premium above Brent, and logistics costs will remain the same. Once we move to SB, things will be reversed. Possibly adaptation of transportation to the standard for low sulfur, there will be some adaptations. And this cost of Atlanta's oil owing to the quality of oil might have a decrease. So we are working around Brent minus 4, Brent minus 5, which was the same that we had at the beginning.

On the other hand, we have gains for logistics. We will no longer take 30 days to load a vessel. It will happen in 24 hours, and they can have more oil also optimizing the freight. So we don't see big changes in the final price of Atlanta's oil in the refinery. We are working with Brent minus 1 digit as it is today, okay?

[Operator]

We also have questions coming from the webcast. Next question by Frank McGann, Bank of America.

Could you please give us more color on the gain with the 20% working interest of Atlanta's that we received? And how is this addressed in terms of cash flow?

[Unknown]

Frank, this is Lincoln. I will turn the floor to Paula, because she can shed more light in terms of how this is going to be treated from the financial standpoint.

The last piece of news that we have is the consequence of a very long process. So I think that Paula can answer your questions better. Paula?

[Paula da Costa Corte-Real, executive]

Hello, Frank. Thank you for the question. And I will answer in Portuguese. Regarding the 20% actions of AFDC. They have no cash effect whatsoever. What happened is that we have an investment in AFDC, which was recognized in Enauta's balance sheet. It was a 30% investment. When we increased it from 30% to 50%, in other words, the recognition of the additional 20% was the result of this whole process of excluding Dommo from the BS-4 Block. So we had some arbitration processes that happened in parallel. Some of them are still ongoing actually. But first, we have a ruling from the proceeding related to the concession of the BS-4 Block here in Brazil. And when this happened, we reflected this in our balance sheet here. And recently, with the decision of another arbitration process, now involving the structure of the best companies related to Block BS-4. We transferred the 40% originally in the hands of Dommo. So we transferred 20% to QGEP, which is part of Enauta, and the remaining 20% to our partner, Barra Energia. So what we are recognizing in our balance sheet now is the accounting effect of this 20% stake in AFDC. Of course, we have the balance sheet value of this 20%. And this is what was recognized with this impact of approximately BRL 120 million. But it has no cash effect for the company at this moment.

[Operator]

Next question from Frank McGann.

Regarding the ICMS tax credit excluding PIS, COFINS from the calculation basis, how should you expect to proceed regarding that?

[Unknown]

Well, I turn the floor back to Paula one more time. So she can explain effect of this tax credit.

Paula, please answer to Frank's question.

[Paula da Costa Corte-Real, executive]

Yes, we recently had a favorable consideration. And in fact, this decision also was positive for other companies. So we had a material fact to disclose when the reference form was filed, when we recognized the impact of the exclusion of ICMS from the PIS, COFINS calculation basis. So this happened in 2014, it goes back 5 years. So this impact was retroactive to 2009. So BRL 62 million recognized is actually the tax credit impact, and about BRL 20 million of the BRL 62 million is the financial restatement, given that some of these values are retroactive to the year 2009.

Now way this will be received is being analyzed by the company. It will be probably through government debt. And we believe that according to our lawyers, we estimate that this will have a cash effect along the next 2 years so that we can monetize this value that was collected -- or that was withheld extra in prior years, given now that ICMS should be excluded from the PIS, COFINS calculation basis. So we recognize that BRL 62 million in our results. But this amount is still being discussed as we mentioned in our release. It can be greater than BRL 62 million. It really depends -- it really depends on the court's ruling regarding how this value will be modulated and how it will be calculated. So it's minimum of BRL 62 million. This is the amount that was recognized by the company in our results because we are conservative, but it can be a higher amount. So I guess that the cash effect of this, which was your question, should we see within 2 years according to our attorney's opinion.

[Operator]

Next question from Leonardo.

Why haven't you contracted the FPSO? Can the FPSO reduce the lifting cost, which is crucial at this moment.

[Unknown]

Thank you, Leonardo, for the question. I think I can answer and then Danilo can add. Well, we were very close to bid the FPSO when this whole serious pandemic problem began, which forced us to interrupt the bidding process, and we didn't yet have this brutal crisis in the oil and gas industry. We knew the crisis was coming, but we didn't really know what the consequences would be of that crisis and how long it would last. But this is the crisis that haven't gone away completely. There is still the possibility that a second COVID-19 wave will come. And that could again change the macro and microeconomic environment of several countries.

So at that time, it was not just us, but we had to react in a prudent fashion. So we decided to stop the bidding of the FPSO. But this does not mean that we abandoned the idea to bid for the FPSO and the full development system. We simply postponed the decision because of this terrible slowdown of the economy until '21. Now as things start to pick up again, and this is happening now, we are reviewing the way to develop the full development system, trying to optimize it from the economic and technical standpoint so that the full development system will be resilient to the new trend. But fortunately, oil prices began recovering actually faster than what we expected. And everything leads us to think that the prices will continue on this trending appreciation curve. And as mentioned by Paula, this allows us to expect price oil above $50 as of 2022, 2023, perhaps reaching $58 or $60 by 2028. So if these trends do materialize in that way, then we will consider the FPSO again. But that's not only that. There are some technical aspects as well, and I can give the floor to Danilo, if he wants to add more regarding our decision on the studies that we are conducting.

Danilo, anything to add?

[Danilo Oliveira, executive]

I think Lincoln has said it all. We were ready to bid for the FPSO in the beginning of this year, soon after Carnival in February, when then the crisis came over us contracting oil prices and that led us to stop and think and postpone things. But now with oil prices becoming kind of balanced at around $40, $45 with an upward trend, now we intend, and we are completely prepared to bid. The companies have been contacted. We are discussing with them the engineering, design, some performance aspects for the vessel, and we just have to make the data official and this should happen if everything goes well by the end of this month.

[Operator]

The next question Renato Tawking.

Could you give us some guidance for Atlanta's lifting cost for 2021? Do you expect to maintain at the level of $15 per barrel despite a reduction in the production expected for 18,000 barrels per day for 2021?

[Unknown]

In 2021 -- Paula, be ready to talk. In 2021, we expect this to have on production -- going back to the production of 3 wells. We are expecting to have the maximum capacity of water treatment in the FPSO, it's limited. We've only said that, that it was limited. The FPSO was expected to be for 3.5 years. And we had to extend it owing to all these problems, the crisis in 2014 and '15, and also the current crisis. So the FPSO needs more time and allocation. And the normal water production because the oil produces with the water and luckily, there is water because it tries to displace. The moves of the water keeps the right pressure in the reservoir for production. But there will be a capacity limit in the FPSO, which is 7,000 barrels of treatment per day, and it will reach next year. So this reduction of 18,000 barrels, because the reduction is owing to capacity limits or constraints, we won't have the effect that we see right now in the reduction of the operating costs because now it is a vessel limitation. It's not performance. This constraint was already part of the original plans. And therefore, we will not -- we're not saying that we want to have a reduction. We even want naturally to pay more, provided we deliver more. It's not a matter of performance, but penalties or it's a fault.

So that is not going to happen in 2021. And if everything goes as expected, we will reach this capacity and led to the estimate production around 18,000. But let's assume it's 20,000, we will go back to the standards that we had before in lifting costs prior to the pandemic, which will be around $20 or $22 per barrel with Teekay's contract going back to normal conditions with a certain premium according to the level of production and the level of Brent value. Brent goes up, and we shouldn't see any kind of penalty, which is what we see right now. And that's not what we expect to see, but it did help our cash flow. So we expect to be around these numbers if production is between 18,000 to 20,000, as expected. 18,000 is what we recorded, and we have the historical level so to speak, of the end of last year, which was around $450,000 or $460,000 per day as operating cost. So that's about it, $20 to $22.

[Operator]

The next question comes from Lucas Ganso.

When should Atlanta's production go back to normal in August? So why was such a significant reduction for 2021?

[Unknown]

Danilo is going to answer your question. It results from what I explained before, but maybe Danilo can give you more color. Exactly what I said, but Danilo can give you more technical specs about the constraints in the treatment. Over to you, Danilo.

[Danilo Oliveira, executive]

So just as a reminder, Petrojarl has a capacity, processing capacity of 30,000 barrels per day. And water processing capacity of 6,000 per day. So the thing is, once we start year 2021, we'll be beginning a production of 30,000 barrels per day of liquid, out of which between 4,500 or 5,000 will be water. And this water volume will increase. So once the water hit 6,000 barrels per day, I will have to go down my oil production, because I cannot treat more water and oil comes with more water. So I begin to decrease my production. So the production will go down in order to constantly maintain water production at 6,000 barrels per day. So production started around 25,000 barrels per day in January and February, and it will go down over the year until it comes to an average of 18,000 barrels per day per year.

Now that's not a reservoir problem. If we had a vessel, with the capacity to treat water, the 3 wells would produce 30,000 barrels of oil per day. Or close to that number because then I might take water to even higher volumes. And that what would happen in the full development system. In the full development system, we have a vessel with a capacity to treat 160,000 barrels of water. So wells may produce at full capacity because the water will be treated. Also another reminder is that we had already considered that in our projections, so much and so that we schedule the drill of the well in the first quarter of 2021 to replace the one that produce more water. So replacing, having now oil and increasing oil production in the system. But unfortunately, with COVID-19 and the reduction in Brent price, the drilling of the well was not feasible. Once Brent goes back to $40 or $45 levels, we can bring it up to the table again. And right now, we are having conversations with our partners in order to resume or to come back to the decision to drill the fourth well, which would have happened in the end of last year. Unfortunately, year 2021 is impaired by the limit water level limited by the FPSO.

[Operator]

Next question is from Leonardo.

Why don't you invest in Sergipe 2020? The company has cash and it's a promising area with a high profitability of outflow of oil with a lifting cost, perhaps lower than Atlanta's. Areas with a low lifting cost should be a focus of the company to protect from risk scenarios?

[Unknown]

Leonardo, we fully agree with you 100% -- 110% in agreement with what you said. But it's not what we want. Exactly that's motivates us. So I'll ask our exploration superintendent, Mendes to answer about these activities and what has prevented us from investing even more in Sergipe than what we are doing, because we do agree with you.

[Jose Mendes, executive]

Leonardo. Thank you for the comment. Indeed, as Lincoln mentioned, we do share the same point of view. If dependent on us, we would already have a drilling rig drilling in Sergipe-Alagoas Basin. However, we have to follow the segment data acquired. We have even informed in our release that the final processing of 3D seismic data was only completed in this quarter. And we're advancing rather well in several stages of processing of the seismic data acquired. And we would have to define a location to drill. And as Lincoln mentioned, we also have to wait until we obtain environmental license to drill. In Sergipe-Alagoas, we are very anxious to start drilling the wells and we are following up close, our schedule, our budget and schedule of activities. It is evolving really well. We are following this with our partners. We are very much aligned in the consortium in terms of ranging the main prospects that we have mapped in the area. So we have to take into account the seismic processing. We have to obtain the environmental license and that is why we are waiting until mid-2021 to start drilling Sergipe, because we also, as much as you, very anxious about drilling in that basin.

[Operator]

Next question from Ms. Ana Luisa Egues with Brasil Energia.

The first well of Sergipe-Alagoas Basin will be drilled in which block?

[Unknown]

I want Mendes to answer this. Mendes, please shed more light in this. We have 9 blocks in the area. And there are different variances there. We are evaluating everything in what would be the best option, but perhaps Mendes can you give you more color on that. Mendes?

[Jose Mendes, executive]

So this is information restricted to the consortium. So far, we have aligned our priorities, but this is the kind of information that we are not disclosing to the market. We have to find the main prospects that will be drilled in this basin. I think that very soon, we should have more information to give you in terms of in which block we would start our drilling activities in that basin.

[Operator]

Next question from Arnon Rodrigues de Carvalho.

I would like to know the company considers dividend payout on a half yearly basis?

And also another question from Diogo Neves.

Why does the company need to have so much cash, even though CapEx is so low, why don't you pay more cash to shareholders?

[Paula da Costa Corte-Real, executive]

Thank you for your questions. Obviously, you should all know that the company has a dividend payout program, $0.15 per share annually, and it started in 2013. And we are having good results every year. And we pay out the dividends. For the last 3 years, we also had some extraordinary dividend payouts, which were very significant. Including this year, BRL 300 million, and our idea, but first, our cash is to maintain the company's operation with perennial growth and investments for the future. There is no doubt about it. And that's what we propose to our investors. But from the moment that there is surplus cash, which does not impair the implementation of the strategy and the company's operation plans, particularly in a 2 to 3-year horizon down the road, then normally, we do, do more dividend payouts. All the monetization in the forecast, which was anticipated, for instance, like happened in the sale of Carcará, we had a payout. We were naturally anticipating the future growth of the company in terms of revenues, earnings, and they may somewhere in the future, even change our style or our plan of dividend payout. But today, we prefer to work on these payouts more extemporaneous, so to speak. We have 3 in a row, actually, from the moment the cash hits a level, which is considered to be enough to implement our strategies and fulfill our commitments, not only in the current year, but 2 or 3 years down the road. That's what we've been doing. And the company and also the Board of Directors tries to perform this payout, not only to the company management item but also to preserve undoubtedly its ability to invest. As the company has been doing this well, and I can tell you we've been very bold in such payouts. So don't worry. Whenever there is a surplus, and at the same time, no concern with mid- to long-term investments and particularly in short to mid run, we'll be working on dividend payout. That's the policy of the company, but provided it doesn't impair the investment capacity and also the growth capacity to work in the future of the company. Undoubtedly, this is in our DNA, and we want to share with investors all our additional gains that we've achieved so far.

[Operator]

The next question is from Carlos Eduardo.

Is it a driver to accelerate drilling in Sergipe-Alagoas? Can Manati also benefit from this field?

[Unknown]

Let me answer on top of what we have. And Danilo, if you want to add anything, you have a very good knowledge about the gas market. And you can also make comments. The gas is very important to Brazil, very important to consumers and highly important to the gas market. We are gas producers in Manati undoubtedly. The more consumers we have, so much the better. The more distributing companies we have the better it will be. And also the more carriers we have, the better it is to all of us. Manati's life is shorter, maybe 4 or 5 years maximum, 4 years for sure. But Sergipe is an area that has a lot of appeal for gas, particularly associated gas. We also have free gas in Petrobras discovery and what really matters is that Sergipe's gas is also associated to oil just like pre-salt and volumes associated are similar to pre-salt, slightly lower but still very similar. So we hope Sergipe, in terms of discovery has a good potential to monetize gas combined to oil or maybe discovery of free cash that may happen in the area as we've seen before. So this is important. From the moment, it brings more consumers, particularly industrial consumers and also carriers or midstream, and it may increase the demand for gas in Brazil. For 15 years, we move from 2% to 9% of the matrix. It doesn't grow more today, owing to infrastructure limits -- infrastructure to flow this gas. And the higher the consumption, the more we'll manage to work on more competitive prices for the guidance. And that's the good merit of this role with access to ducts and pipelines and changes to the tax structures between states, everything will make consumption more intense. And because you believe gas is the energy involved in transition, that's what we will sustain transition in the next decade. So oil, gas and other kinds of power. So it will be very good. But always bear in mind that we, as producers, also need to invest in infrastructure, not only to flow the gas but also to distribute the gas. And we expected to be included in the equation once we have the discussion and the approval of the gas flow.

Danilo, would you like to add anything?

[Danilo Oliveira, executive]

No, Lincoln. I think you said it all. You talked about this gas field or the gas law that will drive, for sure, the gas market.

With regards Sergipe, we're going to have a relevant gas production. Unfortunately, this will provide late for us because Manati is in a declining stage now, 3, 4 years of production pause. And even so we have our commitments with the take-or-pay contract with Petrobras. The Petrobras provides us all of the support we need for Manati. So the gas law will not, in my opinion, influence Manati.

[Operator]

Next question by Vincent Zancan.

Could you please explain how you intend to diversify Enauta's gas stream or revenue streams? It's just that oil or do you intend to invest in solar energy, wind energy and so on and so forth?

[Unknown]

Vincent, what I can tell you is that this is definitely a trend for the whole market, the whole energy market, particularly, wind power associated with gas production. Now the size of our company, and in terms of our diversification and revenue streams, do not allow us to invest directly in alternative revenue sources yet. We don't have a lot of commitments in the future regarding oil exploration and production, which should consume our cash. But you see the company was born producing gas. We like gas. Gas is undoubtedly our means to be stated in this new economy, 1 with a low-carbon footprint. And we want to participate in this trend through gas. Undoubtedly in the future, nothing prevents us from investing in alternative assets, particularly associated to the production of oil and gas. This is happening all over the world with the major oil companies. And they are also investing in electric power, wind power to be consumed by the company's FPSOs and other maritime structures. This is a good path that we might follow in the medium to long-term, because this is an alternative to generation, reducing the consumption of hydro-generated energy, which is to treat the oil and gas. And it could mitigate the increased need for new fuel.

So yes, this is part of our company, although we are gas producers and gas is already a cleaner source of energy. So other alternatives are also possible. But it is always important to keep in mind that we must have a path to follow. Things cannot happen too drastically abruptly. So we see the major oil companies increasing the use of alternative energy sources. Then it doesn't mean that we are not paying attention to those alternative choices of energy. We do indirectly. For example, we do a lot of activities in environmental preservation where we operate in net projects in the Pará-Maranhão Coast, so-called the North Coast, and we invest a lot in preserving the mangrove. That area has the biggest continuous mangrove area, and we have 3 blocks there. We're going to start working in the Campos and Santos Basin to also preserve the mangroves there. So our priority includes this environmental focus in this transition. So the time will come when we will include this in our productive system. This is already present in our company with a focus on environmental conservation. This is to reaffirm our belief that the oceans are our home. This is our mother. The oceans are our home, and we need to protect them. And investments will come over time and we expect that this could come through alternatives sources of energy, perhaps working with other companies that are investing a lot more muscles in this kind of approach. So yes, this is possible in the medium to long-term.

[Operator]

Next question by Ms. Ana Luisa Egues at Brasil Energia.

How you're planning in your drilling for PAMA-M-265 to PAMA-M-337 in 2021 or 2022? If so, how many wells, when and where?

[Unknown]

No. I guess that we have answered part of that question before. But to give you a more detail on this status because we have 100% working interest, and we will also proceed with PAMA with that area. But to give you the current status, given the delay in environmental license, not just for our blocks, but for all areas in the Petrojarl basins, I will turn the floor to Mendes. Maybe she can give you more detail in terms of the schedule for these areas. Mendes?

[Jose Mendes, executive]

Ana. Given our blocks in the Petrojarl margin are suspended because we don't have visibility regarding environmental licensing. What we have discussed with the official agencies, A&P and IBAMA is that we need to move forward with the final process. As soon as we have obtained the drilling license for these areas. And we will need time to go forward with the farm-out process to have a partner all more than 1 to make the necessary investments in drilling. So PAMA blocks, we are in a more advanced stage than in Foz. We have discussed with A&P and IBAMA that in the current phase, we would imagine that we could be drilling PAMA by the end of 2022, perhaps beginning of 2023, possible be after that. Given the current stage of the licensing project, we have an obligation to drill in block 337. That's our priority to drill. The number of wells, of course, will depend on the initial results. We have a number of prospects in block 337 and in block 265 and 1 block in Foz do Amazonas. So basically, the best estimate would be end of 2022 for PAMA, beginning of 2023. And in 2023 onwards for Foz do Amazonas.

[Operator]

We are now closing the question-and-answer session. I would like to turn the floor to Mr. Lincoln Rumenos Guardado to proceed with his closing statements. Please go ahead, Mr. Guardado.

[Unknown]

Thank you very much. I would like to renew our thank you to all of you for your patience for waiting. You had to wait a little longer. First to begin the call today because we have some technical problems. I'd like to thank all of you for your questions, for your interest. I think that this quarter is a nonrecurring effect presented quite important results. We're able to overcome the problems with initiatives that the company's staff has been adopting, particularly in terms of the operating point of view, in terms of renewal of contracts and always with financial discipline, which is in our DNA. We have some initiatives also to protect the company is hedged. The contract Brent has positioned because we don't have a perennial and continuous growth of the company and to increase the revenues. But always with a solid foundation. We like our foundation which is important for the company. We always want to be prepared for unexpected events as the pandemic that is happening. In our track record, our history has helped us overcome these moments, they are so difficult. Hopefully, we intend to very soon resume investments in Atlanta, Sergipe Basin, so that we can confirm our position in the oil and gas industry in Brazil. I would like to wish all of you a happy end of day. Be careful with everything that is happening on the health standpoint. And again, I'd like to stress that our Investor Relations department is available to all of you, if you have any further questions, if you have any further doubt that you want to clarify. So again, thank you very much for attending this conference call. I'd like to thank all of you for your questions. I'd like to thank my team, and we remain available. Have a good day.

[Operator]

That does conclude Enauta's conference call for today. Thank you very much for your participation, and have a good day.

[Statements in English on this transcript were spoken by an interpreter present on the live call.]