Enauta Participacoes SA

BOVESPA:ENAT3

Earnings Call Transcript 2019-Q2

[Operator]

Good day, and thank you for waiting. At this time, we would like to welcome everyone to Enauta's Second Quarter 2019 Earnings Conference Call. Today, we have here with us Mr.Lincoln Rumenos Guardado, CEO of the company; Ms. Paula da Costa Corte-Real, CFO and IRO; and MR Danilo Oliveira, Production Director. We would like to inform you that this event is being recorded. [Operator Instructions]

Before proceeding, let me mention that forward-looking statements that might be made during this conference call relative to Enauta's business perspectives, 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. Forward-looking statements are not a guarantee of performance. They involve risks, uncertainties and assumptions because they relate to future events and, therefore, 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 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 proceed.

[Lincoln Rumenos Guardado, executive]

Good afternoon, everyone, and thank you for once again participating in today's call to discuss our second quarter and first half results and our outlook as we head into the second half of 2019. Let me start saying that we are pleased with the progress we made, particularly operating progress in the second quarter, and we are expecting even better performance in the third and fourth quarters of this year.

Moving to Slide 2. As you can see, there are several highlights worth noting. I'm going to mention them initially, and then along the presentation, we'll come back to those highlights.

First, our second quarter results benefited from having 2 producing assets for the entire quarter, whereas in the same period last year, our production at Atlanta Field did not begin until early May after a stabilization phase, a production stabilization phase.

Second, the news from our Atlanta field operations is very positive. Our third well at Atlanta came online in the second quarter, and its initial flow rates are very encouraging. Our workovers in the other 2 wells are on schedule, and oil sales pricing is good. Production from our Manati Field asset was impacted by several factors resulting in a considerable decrease in production, as you are all aware, because we informed the market. We will discuss these factors in more detail later on.

Also, we were pleased with the final AMP ruling in the second quarter when they formalized the transfer of Dommo Energia's stake in Block BS-4 to the other members of the Atlanta Field consortium. In other words, Enauta and Barra Energia.

Finally, there was additional progress made in our exploration activities as we prepare for the drilling program expected to begin at the end of next year at our major exploration plain, Sergipe-Alagoas basin, and we are seeing additional opportunities to further optimize our exploration portfolio.

I will now turn over the call to our CFO, Paula Costa, to review Enauta's second quarter financial performance. Paula, over to you.

[Paula da Costa Corte-Real, executive]

Thank you, Lincoln. Good day, everyone. Our second quarter results continue to demonstrate the effective execution of our strategy. We delivered another solid quarter of growth trends in both revenues and cash flow. Total production in the quarter was 1.3 million barrels of oil equivalent, which reflects a full quarter of production from Atlanta.

Let us now look at our producing assets by field, starting on Slide 3, with Manati Field, which averaged daily gas production of 2.8 million cubic meters in Q2 '19 compared with 4.9 million cubic meters per day in the same period of the prior year. It is important to keep in mind that we're comparing against a very strong quarter last year when production benefited from drought conditions in Northeastern Brazil, which led to increased demand from thermal power plants. While in this last quarter, we had the inverse effect with the reduction in the demand for gas in that region.

Moving on to Atlanta, the field has been flowing oil for over 1 year by quarters and have reached a milestone of 5 million barrels of oil produced. This year's second quarter had a full quarter of production from 2 wells with an average production of 12,800 barrels of oil per day. This compares with 12,300 and 12,400 barrels of oil per day in the prior 2 quarters, respectively. The slightly higher level versus the prior quarters reflects the startup of the third well with its higher initial flow rates, still with only 9 days of contribution in Q2.

Please go to Slide 4. Before getting into the financial details of the quarter, I want to remind everyone that we adopted IFRS 16, accounting for leases since the beginning of 2019. As shown on this page, IFRS had both a positive and negative impact on our P&L and balance sheet. Along the second quarter '19, the company revised the incremental cost of debt rate as well as its amortization method resulting in a higher impact from IFRS 16.

On the P&L, the key impacts to point out are the increases in operating costs because of depreciation and EBITDAX. By contrast, operating costs, ex depreciation, were lower as [ were ] our net financial expenses and net income. IFRS 16 does not have an effect on the cash of the company. In the earnings release, we have provided the P&L with and without the impact of IFRS 16.

Now turning back to our results, starting on Slide 5. Revenue benefited from the increasing contribution from Atlanta, which partially offset the lower production from Manati. The contribution from Atlanta also benefited from the company's now 50% ownership in the field. Total revenue in the quarter increased by 16%, with Atlanta accounting for 57% of total revenue.

Of note, in the month of June, Petrobras did not take all of its monthly production under the take-or-pay contract. Thus, we have accounted for the BRL 13.7 million in trade accounts receivable. We will recognize the revenue upon future delivery of gas to the customer.

Moving on to costs, starting with Slide 6. Operating costs totaled BRL 144 million, up from BRL 84 million year-on-year, with the increase primarily attributable to costs related to the ramping up of production from Atlanta, including first oil from the third early production system well, along with costs associated with repair on the first of 2 wells amounting to around BRL 2.7 million. Approximately 75%, or BRL 109 million of the total operating costs were associated with Atlanta and also reflect our increased working interest. It's worth highlighting that the adoption of IFRS increased operating costs by BRL 8.4 million.

Observing Manati, our operating costs were BRL 35.4 million, which represented a decline of 20%, reflecting lower royalties on paid special participation, R&D and lower depreciation of the field because of production. The estimated expense allocated to Enauta for scheduled maintenance, which was disclosed earlier, was approximately $1.3 million and was capitalized, not impacting the results of this quarter.

On Slide 7, general and administrative expenses of BRL 14.5 million were back to a more normalized level when compared to Q2 '18, which had benefited from a reversal of the provision for the company's first stock option plan granted in 2011. This resulted in reported G&A costs being BRL 10.3 million lower in Q2 '18, a similar effect that happened in the first quarter of '19.

Let us now move to Slide 9 (sic) [ Slide 8 ] , let's look at our profitability. Our adjusted EBITDAX benefited from both higher production and adoption of IFRS 16. EBITDAX in the second quarter of BRL 99.9 million was basically flat, with the same period of the prior year. Second quarter '19 includes an approximate BRL 33.5 million benefit from the adoption of IFRS 16. Excluding this effect, EBITDAX in Q2 '19 was BRL 67 million, reflecting the lower operating results and higher administrative expenses. Our net income was BRL 20 million in the quarter compared to BRL 85 million in the same period of the prior year.

Moving on to Slide 9. Let's talk about capital expenditures. On the slide, you can see the breakdown of our projected capital expenditures for 2019 and 2020. In the second quarter, CapEx totaled USD 30 million, with a majority or 85% invested in Atlanta Field. For full year 2019, we're projecting expenditures of $63 million compared to $73 million in 2018, mainly due to investments in Atlanta before initiating production with the interconnection of existing wells and acquisition of some long lead items related to the third well. The majority of CapEx planned for 2019, or approximately $42 million, is allocated to Atlanta Field. This includes the drilling of the third well and repair of the pumps on the first 2 wells, which will be accounted for as operating cost impacting the results of the period. The remaining funds include mostly investments in Block 50 Sergipe-Alagoas Basin.

For 2020, we have an aggressive capital expenditure program planned at $125 million, which is about double our 2019 CapEx. 2/3 of the spending has been allocated for the development of Atlanta field as we move from EPS, early production system, to FDS, full development system, assuming the consortium decides to proceed. We are also planning to start acquiring equipment for future drilling at the Sergipe-Alagoas and Pará-Maranhão basins.

Over the years, our CapEx requirements have mostly been funded with internally generated funds. As always, we maintain a cash position sufficient to cover our funding requirements for the next several years. We will remain disciplined in our use of capital while continuing to invest for growth.

We ended the quarter in a very strong cash position of BRL 1.5 billion, and we further reduced the borrowings in comparison with the second quarter of '18. We remain committed to maintaining a healthy balance sheet.

I will now turn the call back to Lincoln for his strategic and business review.

[Lincoln Rumenos Guardado, executive]

Thank you, Paula. Now we will provide additional detail on a number of the second quarter highlights, I mentioned in my opening remarks. Please move to Slide 10, which gives an update on our Manati Field operations.

As you can see, Manati production levels were very low in the second quarter, reflecting several factors. Due to scheduled maintenance work, production at the field was shut down for 8 days in the second quarter, following an 11-day shutdown for the same reason in the first year's first quarter. It was legal. And undoubtedly, it was an average production impact.

While this was a factor in the year-on-year decline, more relevant is the persistent lack of industrial demand. And this was also combined with a greater availability of other sources of natural gas due to pricing arbitration for this gas, particularly NGL. We recognized that this is more than a one-quarter issue, and we're evaluating how we can work together with our partners in order to improve the scenario over the long term. The good news is that Enauta is protected on the downside by a take-or-pay contract, as you all know, and that calls for us to be financially compensated based on full year production of 3.8 million cubic meters per day for this year. Thus, we are able to maintain our guidance, our full year 2019 production range of 3.8 million cubic meters to 4.1 million cubic meters per day as revenue, albeit at the low end of the range for the reasons we explained before.

This projection does not take into account any unexpected positive developments, which are positive, such as a meaningful pickup in the industrial demand in the Northeast. And the field is ready and prepared to accommodate within some production limits. We have a very efficient infrastructure in Manati, and it can quickly ramp up production and access demand from the Northeast region within the field's current production capacity.

In the meantime, as you can see from Slide 11, progress at Atlanta Field has more than offset the current contraction at Manati. I'm pleased to report that activities at Atlanta Field are progressing very well. And in some areas, the results are even ahead of our expectations on many fronts connected to our asset portfolio. Second quarter Atlanta fuel production levels were quite positive, averaging 12,800 barrels of oil per day. Undoubtedly, still related to 2 production wells, but also benefiting from 9 days of production from the third well, which was completed in June of the current year. This third well has excellent reservoir characteristics and high initial volumes of 15,000 barrels per day, and they remain as such up to date. As a result, we expect third quarter production levels this quarter to be sequentially higher, given that we'll have a full quarter's contribution from this third well, and it has maintained production at very satisfactory levels, slightly above 15,000 barrels. Undoubtedly, we have to acknowledge, this also surprised us very much in the positive aspect.

The Laguna Star drillship has moved to 1 of the 2 initial wells in the field in order to replace the malfunctioning pump. That procedure was completed, and currently, we are in the ramp-up phase. The initial ramp-up actually started in the earlier hours of the morning, opening the well known as 2H which is the first one that was drilled and completed in the field. And therefore, the well is already directed to another well, [ 3H ], in order to replace the pump. Considering all these activities on schedule, we expected to have 3 wells producing by the end of the third quarter. And we are very satisfied with the decision made, showing that changes to the pumps brought expected results.

In addition to benefiting from higher production in the second half of this year, we also expect to continue to see favorable pricing trends for our Atlanta oil. As you know, we have an agreement with Shell to take all of the output from the early production system. The oil we are producing is virtually sulfur free, actually 0.35%, which is in compliance with new regulations for tanker fuel, the famous IMO 2020, to be implemented starting January next year. Additionally, there are current heavy oil shortages in the marketplace, owing to contraction and limited production in some countries. As a result, the prices we received for our oil netback in Atlanta in this second quarter already include logistics costs. And had an average discount vis-à-vis Brent oil prices from USD 12 to USD 14 per barrel, which is quite substantial. This represented a premium of approximately USD 6 over prevailing prices 12 months ago, and we expect this trend to continue for the remainder of this year. Always bear in mind that IMO is a [ structural factor ] to low sulfur content oil prices. As I mentioned earlier, the final ANP ruling issued in June confirmed the transfer of Dommo Energia's working interest in the BS-4 consortium, to be equally divided between ourselves and our partner, Barra Energia. This reaffirms our working interest position of 50% in the block, in which Atlanta Field is located. Instruments for the asset transfer have been signed, and the E&P proceeding has been concluded.

And finally, between the end of this year and beginning of next year, we expect to make a decision alongside our partner, Barra Energia, on the implementation of the full development system in the Atlanta Field. As Paula mentioned, we have allocated capital spending in 2020 should this decision be made, and we believe it will move in this direction. The full development system would involve the drilling of up to additional 9 wells in the field. Once you have all 3 wells producing at the field and additional visibility on pricing of Brent oil and relevant economic data vis-à-vis the future CapEx, we'll be in a better position to make that decision and you will be informed about it.

Slide 12 is an update on our exploration activities. As you all know, our 30% working interest in 6 blocks in the Sergipe-Alagoas basin is the cornerstone of our exploration program from short to midterm, and we are very pleased to see the recent news that Petrobras has confirmed hydrocarbon discoveries and some blocks, actually, 6 blocks adjacent to ours, including an extended well test that is expected for the end of this year. We continue to evaluate seismic data together with our partners, ExxonMobil, the operator, and Murphy Oil. And that process is ongoing. We'll receive final seismic data by year-end. And at the same time, applications for an environmental license have been submitted by the operator and preparations are underway to secure the acquisition of long lead item equipment required to commence drilling there as of the end of 2020. In other words, we are in a very speedy process vis-à-vis this schedule.

As for other exploratory news, we are moving forward with the formal process. It's a slow process, involving several steps and stages, but our 2 blocks in Pará-Maranhão block, in which we have 100% stake, and we are encouraged by the response from potential partners. We expect this process to be completed by year-end.

In addition, we're analyzing the opportunities for Enauta to participate in the upcoming ANP bidding rounds scheduled for the second half of this year. Before we make a decision to participate or not, we will consider the opportunities within the context of our strategy to operate a diversified portfolio that provides significant upside potential while limiting the risks associated with very long and high-cost exploratory and development activities. In other words, our financial discipline naturally continues to be something very important in the decision-making process.

In summary, on Slide 13, as you can see, we are looking ahead to announce this positive second half performance. The key driver of this progress will be our Atlanta Field operations, where results should benefit from several factors, including higher production, stable or flat Brent prices and our higher ownership position with a stable netback and growing day by day.

Enauta's compensation from Manati Field production is protected by the obligations of the take-or-pay contract that is enforced, but we're hopeful that market dynamics will improve and result in higher demand for our gas, considering significant changes that have happened in the sales scenario and also an increase in gas as a source of energy in the country. Our exploration activities are progressing on schedule. I would say that even with a good progress, with the positive news from blocks adjacent to ours in Sergipe-Alagoas, reinforcing our expectation that this is an area with high exploratory potential.

Additionally, we view the current environment for energy development in Brazil as quite favorable, and we believe that Enauta is very well positioned to benefit from increased investment interest on the part of large international energy companies, involving not only oil and gas, but also other renewable sources.

Operator, now I will open the question-and-answer session. Thank you for participating in today's call. So let's move now to the Q&A.

[Operator]

[Operator Instructions] First question comes from Gustavo Allevato with Santander.

[Gustavo Allevato, analyst]

I have a couple of questions. First has to do with the full development system decision. I'd like to understand what made you postpone the decision of the consortium regarding the full development in 2020? My second question has to do with the take-or-pay contract at Manati. Is there any possibility, and is there any negotiation on going to renegotiate the take-or-pay contract with Petrobras? And my third question, which is more direct, is when do you expect to receive the remaining payment from the sale of Carcara to Equinor? I knew that there are some conditions precedent. But when do you imagine that these conditions will be met, so that you can receive the remaining of the payment?

[Lincoln Rumenos Guardado, executive]

Thank you, Gustavo, for the questions. Well, actually, there wasn't a great change regarding the decision to move forward with the full development system. We believe that we are actually on schedule. There was perhaps a little delay here and there in the exchange and repair of the pumps, particularly because of bad weather. At this time of the year we have recurring bad weather and it doesn't really allow us to work in subsea conditions. But along the year, we expect to have all 3 producing wells. Then it is important that we decide that we have the track record of 3 producing wells because we had 2 initially. We have planned for 3, and now we have the possibility of the EPS producing at the expected levels. We want to have 2 or 3 months of production so that we can monitor and so that we can define what could be the future system. As you know, we expect to drill another 9 wells, in total, 12 wells. But it was important to have a very solid base of knowledge regarding productivity. And I tell you this because we, ourselves, we're positively surprised with the production of the third well, 15,000 barrels. In our numerical modeling and in the beginning of the field production, we expected 12,000, 13,000 barrels. We thought that, that would be the production capacity of the well. So 15,000 barrels were very positive news regarding the production capacity of the field and how the pumps are performing.

So we have to bring to our decision-making process regarding how many wells will be drilled and how they will be drilled, considering our track record. So let's say that by year-end, or beginning of next year, when we said that, it's just that we want to include data from production. But -- and definitely, we are not changing the final date, which was end of 2022, beginning of 2023. Most likely in 2022, this is what we expect to happen.

Then with the slight postponement, perhaps of one or 2 months only, but this is just so that we can accumulate the knowledge from all 3 wells vis-à-vis the production we had in the third well, in which we will now see, with the new pump that will start producing today. So the well 2H has been opened. There will be a slow ramp-up, and that's when we're finally going to have a clearer idea of our production capacity, which we said should be between 25,000 and 27,000 barrels a day.

Regarding Manati, I will turn the floor now to Danilo. But I can tell you, there's nothing along those lines, but Danilo can give you more color on what's happening.

But before that, I can answer your third question regarding receipt of the rest of payment. We have seen a lot of activity in this area, which is operated by Equinor. They are drilling wells, and we're following these events in the news. But we see a lot happening with Equinor intending, and I am repeating this, I have no knowledge of what Equinor intends. But from what we saw, Equinor intends to have the first FPSO between '23 and '24, and doing a reverse engineering. For them to be preparing for production, we believe that they would already be prepared to order the unitization of the 2 areas in the second half of next year. So this is what we expect. We expect that by the end of the second half of next year, they will have the individualization or unitization process in place, which is a trigger for the payment of the third portion of our sale, which amounts to about $144 million.

Okay. Now I'll turn the floor to Danilo. And if you're happy with the answers, okay. If not, do return with a follow-up question.

[Danilo Oliveira, executive]

Gustavo, regarding the Manati take-or-pay contract, this is an agreement that includes the sale of the whole reserve from Manati. We do not envision any possibility of renegotiating the contract. Petrobras didn't talk about that, and we didn't take that initiative either. Therefore, the contract should continue until the end of our production at Manati. We do not expect any changes to the contract, so we are considering real price adjusted every year on January 1, according to inflation rates, with a take-or-pay -- with an annual take-or-pay clause. So we don't envision any changes.

[Operator]

Our next question comes from Luiz Carvalho with UBS.

[Luiz Carvalho, analyst]

I have some questions about Atlanta. Lincoln, you mentioned that the third well production is around 15,000 barrels. But at the same time, with all 3 wells, we would have a total production of approximately 25,000 barrels. So I'd like to understand how the initial 15,000 relate with the expected average when all 3 wells are up and running.

My second question is, when do you expect to account for this additional reserve coming from Dommo? I understand that in the latest approval by ANP came about, I just want to understand exactly how this will unfold, not only in terms of reserve, but also -- but when we can expect this? Would it be in the third quarter? And my third question is more direct to Lincoln. Today, given that your production is almost double, with the third well, considering the average that you expect when all 3 wells are running, in the scale from 0 to 10, what is the probability that the full development system will be approved? Or possibly, perhaps, you could elaborate what could happen so that the full development system would not be approved? So in a scale from 1 to 10, around 8, more than 8?

[Lincoln Rumenos Guardado, executive]

Well, Luiz, thank you for the questions. The 3 intriguing questions, as always, but very relevant one. So I'll turn the floor to Danilo.

Of course, it makes sense. If we have 15,000, what will happen. But obviously, Danilo will be able to answer your question. And the other 2 questions, I will answer. Well, let's talk about Atlanta first because I think that this would help shed color on the other 2 questions as well.

[Danilo Oliveira, executive]

Okay. Luiz, very well. So in Atlanta, before we started to drill the third well and correcting the pump malfunctioning, we had a production guidance of 25,000 barrels a day, more or less, 15%, which leads us to a production of 28,000 barrels or so. So this third well, when it started producing, it produced really well. So with the third well plus the prior 2, the way that we're producing, that would take us to a production of 27,000 barrels a day, with the third well and the 2 first wells as they were. But we have replaced and repaired the pump in the second well. It is already producing. At the end of today, we should turn on the pump because it is in the state of natural production to fill up the column with its oil. And we expect an increase of about 3,000 to 4,000 barrels a day in this well. And the same applies for the other well. So this is our expectation, but we will only give you a guidance after we have proven our simulations are correct. So in the third quarter, we should produce with 2 wells [ all the time ] about 20,000 and 23,000 barrels a day. And by the end of the third quarter, we will have the third well and we will have achieved the guidance, which ranges at 25,000 more or less, or more 15%. Our expectation is that we're going to have 25,000, plus 15%.

[Luiz Carvalho, analyst]

So could you think about something close to 20,000?

[Danilo Oliveira, executive]

We maintain our guidance, 25,000, plus 15%. That is the top guidance, about 28,000 barrels a day.

[Lincoln Rumenos Guardado, executive]

Very well, Luiz. It's a good thing you asked, because we have a reserve certification by Gaffney, Cline & Associates, that was published of one 1P, 2P 224 million and 3P, 250 million barrels. So very much in line with what we had seen before. And also with the drilling of the well, we are quite sure about these reserves. But these values have already been incorporated in our reserves. By year-end, we had about 120 million barrels in our reserve of barrels of oil equivalent, and this percentage has been included in the assessment of our reserves.

And the same thing regarding ANP. With the ruling that we got back in June with ANP's decision, now every dollars [ in ] reserves have been totally incorporated to our reserves. There might be a little pending item there, but to us, this topic is in the past. It's water under the bridge, and their reserves have been incorporated to our portfolio and to our results. This result is of the fourth quarter of last year. Because the decision was backdated to the beginning of the arbitration process date, so this has been already incorporated. The 50% ownership is already part of our asset. To us, there are no more legal appeals that can be made.

And regarding the full development, our belief is that the full development will happen, and we believe it more and more. Now whether if it's 80%, more than 80% chance of happening, that's just guesswork. But I'd say it's more than 50% pro full development. We are working between 1P and 2P. That's greater than 50%. And the reason is that we see a certain stability in oil prices. We are also evolving and improving our logistics approach so that we have optimized our netback.

And we are seeing some changes in the pricing outlook for heavy oil Brent prices, either due to OPEC conditions, problems of other countries that are cutting down production. So there is a shortage of a heavier oil. But IMO 2020 is a great push for us. We believe we like to joke in-house that IMO was an index for profit for us because we didn't count on such a big reduction in demand for low-sulfur oil, which is the characteristic of our oil. It's 0.35, and IMO is going to require 0.5. So our oil is at the threshold. We can say that mixing a diluting [ oil ] can even be burned. So every day, we see the industry fundamentals with an increased demand for oil and more and more our certainty, not always, not only regarding our reserves but the production capability that our wells have proven. So our belief is growing.

Now of course, there are gateways, and we have to respect these gateways. We have to look at future prices, and I have answered the question about this. Danilo also talked about the production of all 3 wells. Of course, we always have to look at our materials list and left to decide are we're going to drill another 9 wells, are we going to drill another 6 wells. So how many wells and how to drill them, so this is what we are questioning now. What would be the best approach for the field? Observing the current production to date, accumulated production greater than 5 million barrels so that we can have the best return for the field. And undoubtedly, that will reflect in the type of FPSO that we will need.

So we have an additional time. We have always said that we need some additional time to have a tailor-made decision, observing the best return on invested capital. We haven't disregarded the challenges that the field faces. But every day, we get more and more confident that we are going to have enough capability to be able -- enough buffer to be able to operate and have a good return on Atlanta.

[Operator]

The next question is from Leonardo Marcondes with Itaú.

[Leonardo Marcondes, analyst]

Lincoln, Paula, Danilo, I have 2 questions. My first question is about the Atlanta project. In the release, you also mentioned 50,000-70,000 barrels per day for full development. We believe it's slightly below what was in the original design of the plan. What about the platform? How would it adapt to new oil prices in your viewpoint? And what about the lifting costs in the new project? My second question is about Dommo's case. Now that ANP had already approved it, I would like to better understand the next steps to complete the process. These are my 2 questions.

[Lincoln Rumenos Guardado, executive]

So full development system in Atlanta, the development plan that we discussed and we included or submitted to the agency was designed at a Brent oil price of about $100 per barrel. So this design, the CapEx required to this project was offset by the sale of oil for that price. We had to update to the current reality, Brent at $60 per barrel level; and we adapted our FPSO, the current FPSO to a level compatible or matching the investment required so we could have a return with this production from 50,000 to 70,000 barrels per day. We haven't made a final decision yet about which one we're going to start with, but it's very likely that it will be from 50,000 to 60,000 barrels. But we haven't made our final decision yet. During the period, we're still going to decide the price levels, so we can make a final decision.

As for the lifting cost level, it is lower compared to the current one, lower than the current one. And this is more related to higher production and much higher production; and the only basic difference in terms of the operating cost is the chartering of the FPSO, additional, I would say, at least 20,000 to 30,000 barrels per day easily offsetting this new level of FPSO chartering. So the FPSO, I would say, would be at a level or the future level of the anticipated production system at Atlanta, so the early production system. So 30,000 is the current, and by year -- by the end of the quarter, it should go down to 20,000 or 21,000. And if prices go down, we might reduce even further. Okay?

[Leonardo Marcondes, analyst]

What about Dommo's case?

[Lincoln Rumenos Guardado, executive]

This case has some steps about fundamentals. The first 1 was the 2 decisions made at the tribunal, the Arbitral Tribunal, irreversible when it comes to the documents available; and it allow the agency to decide to transfer Dommo's rights on BS-4 to us and to Barra Energia. So this is documented. All the documents were submitted. All the registration is completed. What still remains though is a third phase of this case with the tribunal [ on central ] and there are some complaints about the partner's proposals, et cetera. And this is in progress, and we expect to have a trial early next year. Business as usual, submitting evidence, some complaints. And both companies, therefore, are exchanging documents required by the Tribunal, and we expect to have a decision by year-end or early next year. More precisely, we don't see any change of a setback going backwards with this decision at the Tribunal, not even the agency, even though Dommo, at its discretion, may decide to do otherwise. But anything that is a standard in our judiciary process was already done and today is already registered in our name and also under Barra Energia's name the percentage and some pending dispute about other factors that are in the court in Paris. And we expect to have everything settled in the first half of next year. And we are very confident with the reasons [ that round ] our evidence submitted to the tribunal. So that's what's still pending. So we can bring this process to an end.

[Operator]

Our next question is from Fernanda Cunha with Citibank.

[Fernanda Perez Da Cunha, analyst]

A follow-up question about Atlanta. Lincoln, Paula, Danilo, could you comment on the netback of Atlanta now that we're already considering a production of 25,000 to 27,000 barrels per day? In the last call, I remember you mentioned that with a higher production the discount was expected to go down. So what should we expect to see in terms of improvement in the discount that is from $13 to $15 per barrel today? And along the same lines, I also want to know what else we could envisage for lifting costs. I know you've been working with 8% discount on top of the $410,000 per day. And now with a higher production, should that expect to see an increase in discounts as well? Secondly, my second question is about a possibility by Dommo for any potential adjustment for Atlanta, for instance, any complaint trying to have a reimbursement by the consortium of the signature bond or the CapEx that they spent in the first basis.

[Lincoln Rumenos Guardado, executive]

Thank you, Fernanda. Danilo's going to answer later your first questions. But regarding Dommo, they do some complaints about formal cash calls. They could have an argument justifying their default. So that is not how to have a claim for a return of something in the past when they made a decision on their own. It was their decision, so we simply cannot have this kind of -- in our opinion, in our attorney's opinion, there is no claim about -- reasonable claim about this reimbursement, [ maybe ] some of the cash calls and also our access to a couple of accounts that were escrow accounts owing to their default at that time. And that was a requirement at that time. So we don't see how this would be exercised today.

The Tribunal already acknowledged that the documents, and they also grounded the decision both of the Tribunal of Enauta and [ BS ] valid. And therefore, there is no kind of compensation vis-à-vis what already happened. What we have is a little dispute vis-à-vis former and past cash calls and expenses that occurred and also cash balance in the consortium. So that's what we still have, and we expect to have the trial next year.

[Fernanda Perez Da Cunha, analyst]

Do you have an order of magnitude about the cash call that they are claiming?

[Lincoln Rumenos Guardado, executive]

We cannot give you any data. That's an important dispute. It's something confidential. Simply cannot disclose what it could be. And that's based on a tribunal decision. It's confidential. This is still in the evidence collection, evidence gathering phase, so this wouldn't allow us to make any disclosure. But that's not a point of concern.

[Danilo Oliveira, executive]

Danilo speaking. Let me answer your questions about Atlanta. Two aspects here. Firstly, Atlanta's operating costs. Today, our level of operating cost gives us a lifting cost of $30 per barrel approximately. Starting 18 months of operation with Teekay, this cost will go up, over into the 18 months of discount, something around $480,000 to $500,000 per day. But that will be fully offset by our increasing production. In other words, despite an increase in operating costs, the cost per barrel is expected to go down from $29, $30 in to approximately $19 per barrel. So this is for operating costs.

As for the oil netback, we operated in the second quarter with an average between $12 and $14. And just as a reminder, discount represents 2 parcels. The first parcel has to do with the discount, the effective discount about oil quality and discount related to logistics to take the oil to our refinery unit. So these 2 Phase 2 parcels will go down in the current quarter. Firstly, the cost of heavy oil, and basically heavy oil that is sulfur free, has dropped a lot the discount with Brent oil. And secondly, with a greater production, we'll manage to have a tanker built up more effectively, faster and therefore, with lower costs. So we expect to lower this discount something below $12 in the current quarter, something around $11 per barrel, but we're confident it will go down.

[Operator]

Our next question is from Bruno Montanari, Morgan Stanley.

[Bruno Montanari, analyst]

Regarding Atlanta, I know that ANP has rules that your ownership is 50%. Is the idea that you will maintain the stake with Barra or perhaps have partners to try to monetize the part of what you received to contribute to fund your full development system? And my second question, I'd like to understand your appetite in the auctions. Could you give us an order of magnitude of how much of the company's liquidity could be invested in the next rounds along the coming years. In rephrasing, what would be the minimum cash that Enauta would consider to work with? And one quick last question. Now with the volatility in oil pricing, is the company rethinking its hedging strategy for the coming year?

[Lincoln Rumenos Guardado, executive]

Thank you, Bruno. Well, we didn't have any inflation to sell. We have a policy that we have tried to follow in recent years. Of course, these things don't happen overnight. Drillings sometimes get delayed as you all know, and you remember license will take longer to be issued. So -- but our fundamental is to diversify our sources of revenue. This is what we are trying to do. Some actions didn't work out, some acquisitions, which were not compatible with our portfolio and with our pocket. But we continue to seek diversification of our revenue sources. Along those lines, we never thought of selling Atlanta. Of course, if there is a need in the future, if there will be an interest in the asset that will favor us to move towards another investment because our exploration area, as you know, is expected in the next half -- 1.5 to 2 years is expected to be underway, we are thinking about Sergipe, Pará-Maranhão Basin, those are the higher possibility areas currently. Of course, it all depends on other things.

But then, in that case, we could think about monetizing. Undoubtedly, yes, we've done that before with Manati and that helped us. However, currently, we see some actions in terms of funding that can also solve the problem. Reserve base is what -- reserve-based lending is what we have in place for such projects, projects of this nature, particularly projects -- production projects, which are being implemented. So there is a trend to improve our funding method, which doesn't necessarily include selling. Well, undoubtedly, if there's interest in the future, if there is a partner that tried to sell in the past and we need to accommodate for that, undoubtedly, we are open to this possibility.

So as to have a liquidity in the company, they will allow us to continue with our policy to increase production and have more liquidity. And I take this moment to answer your second question, we always want to have cash that will allow us to fund our investments in the next 2 years. This has been our rationale and oftentimes helped by a divestment, which is what happened in Carcará that gave us a little buffer and a natural hedge because that is in dollars in our Atlanta production, also includes revenues in dollars. So that gives us more flexibility but again, always maintaining the possibility of taking part in the auctions, which is what has been happening.

For the upcoming auction, for example, I can tell you, I would like to participate in the transfer of rights because that's practically oil in the tank. But there might be an entry price, which is higher than our capacity. But the other 2 rounds, yes, we are looking into it. But there might be an area that, within a limit of working interest, will allow us to have a play there. This is part of our minimum cash. We continue to have an appetite in the auctions. And currently in the pre-salt, we believe that we need at least one pre-salt area that will fit into our long-term view of having excellent-quality oil and that has gas.

So again, all of these things are part of our 2 to 3 years' time frame. When you think about Atlanta, we'll need to go to market and use its different drivers. And it might include a small divestment that would then subsidize another development. So yes, all of these things are possible. But undoubtedly, we have always allocated a certain percentage that will allow for growth, growth that is more than vegetative in our portfolio, as you saw in Sergipe. Why in Sergipe? Because it has a high exploratory potential. So we concentrated our investments, and we always aim to diversify. This has been our corporate strategy. Okay, Bruno?

[Unknown Executive]

Bruno, let me talk about our hedge strategy. You asked about, which would be our position in this volatility scenario. Our strategy exists to ensure the fundability of the company and to help us sail a volatile market in terms of foreign exchange or commodity price. For foreign exchange, we normally look 3 years ahead. We have a decreasing table in terms of how much we want to protect from foreign exchange volatility. And for commodities, we have worked with options, put options, and we'll look at a shorter term because for longer periods of times, options can become very expensive. And our goal is exactly this: to [ say ] sail through possible volatility scenarios with some peace of mind for the company to ensure cash and fundability that we need for our investments. In case of volatility, we do not intend to change our hedge strategy. On the contrary, I think that now we are -- we're disciplined to maintain our strategy and to ensure the fundability of the company in the future.

[Operator]

Your next question comes from the webcast from [ Claudio Miller ].

[Unknown Analyst]

What is the status and expected deadline to end the exchange of pump in Atlanta? Is there any FPSO of 50,000 or 70,000 analysis, do you expect to drill in Atlanta's pre-salt?

[Lincoln Rumenos Guardado, executive]

[ Claudio ], so your first question, that is of the first pump exchange. As mentioned before, we have concluded the exchange of the pump. We have reopened the well. The well is producing without using the pump so that we can fill up the whole column with well fluid and part of the flow line. So the intention is that, today, this afternoon, we will turn on the pump. So we haven't got the results for the pump, but the workover went smoothly. Everything was tested and is working well. So current status is the well is producing, and the third well is closed. The third well where we're going to have a workover is closed and Laguna drillship is on the well for the workover.

Second question regarding FPSO, no, we don't have an FPSO for 50,000 to 70,000. This will be the object of a bidding process. We'll call on 4 to 5 companies, experts in chartering FPSO. We will mention what we want to have to process Atlanta's oil, and then we will wait for the bids. So currently, we haven't got this FPSO, and we expect to have 24 to 30 months to build this FPSO. So it would arrive here in mid-'22 to start production.

As for Atlanta pre-salt, yes, we do intend to go to Atlanta's pre-salt, but this will only have a rationale when we start drilling in the full development system at Atlanta. And the pre-salt will very likely be drilled during the campaign of this platform that will be charted to drill the wells in the full development system. Nothing before 2021 at least.

[Operator]

The next question from [ Venizios ] from [ Big Capital ].

[Unknown Analyst]

Should Brent amount go -- be below breakeven? At Enauta, will all investments be maintained?

[Lincoln Rumenos Guardado, executive]

Undoubtedly, this problem is the problem we live with. It's not only today. Since we started production in any field, what we do is to extend the investment. Obviously, if we have a breakeven point that is too challenging or sometimes below our operating cost, the first thing is to try to lower the operating cost. And therefore, there are always measures, well, mitigating the effect on a long term. Well, this kind of problem may happen occasionally for a little framework. So in all operations of oil, we have events of that nature. And it will depend on the long term on a whole range of points. But naturally, we follow this up. We increasingly focus our efforts, so the breakeven point goes down and all the actions described today by Paula, by Danilo, they all have to do with this.

Hedge is another element. I may be below the break-even point, but my head is above it, so I'm hedged, at least partially protected. And all the actions that we've been made to optimize our operations and vis-à-vis the stoppage of the tanks, so it's always along the same lines. And should that happen, we can also extend this even further. It's a classical way to extend your investments in order not to have such a strong upfront with no right compensation for every field.

So undoubtedly, these are important points, and we are always trying to prevent it or at least be protected. So under stressful market conditions, we have the right measures. And I mentioned 2 of them, the classical ones, and already working on this, which is hedging of oil prices, not currency price; and also this optimization of our operating methods and logistics as well that are improving day by day. So we've been following it up. And this is also part of some of our risk. But there is no economic reasoning to keep on investing in an area if you don't see the adequate return on investment.

[Operator]

The next question from webcast from [ Hana Dubahoso ].

[Unknown Analyst]

Is there any plan to repurchase stock since they are very depreciated?

[Paula da Costa Corte-Real, executive]

No, we don't have a buyback program approved by the company. Should it happen, we will have to disclose it to the market, but we don't have any buyback program. We expect to use cash to invest in activities like Lincoln mentioned and diversify our portfolio.

[Operator]

[Operator Instructions] This concludes today's question-and-answer session. I would like to invite Mr. Lincoln Guardado to proceed with his closing statements. Please go ahead, sir.

[Lincoln Rumenos Guardado, executive]

Well, again, I would like to thank all of you for joining us to review our second quarter earnings results. I think that this conference call was very fruitful. We had very good discussions, and I'm sure we were able to give you a little more color on what the company is seeing. Again, our Investor Relations department is available if you need further clarification. And so given all of the challenges ahead of us, we intend to bring you good news in the third quarter and fourth quarter as we have always delivered. Again, I would like to thank all of you and again, make our Investor Relations department available. We, the management, are also available if you need any further [ clarifications ] . Have a good day. And I wait for you in the next conference call.

[Operator]

This concludes 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.]