Enauta Participacoes SA

BOVESPA:ENAT3

Earnings Call Transcript 2019-Q3

[Operator]

Good day, ladies and gentlemen. Thank you for waiting. At this time, we would like to welcome everyone to Enauta's Third Quarter 2019 Earnings Conference Call. Today, we have with us Mr. Lincoln Rumenos Guardado, CEO of the company; Ms. Paula da Costa Corte-Real, CFO and IRO; Mr. Danilo Oliveira, Production Director; and Mr. Jose Milton Mendes, Exploration Superintendent. 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. They involve risks, uncertainties and resolutions 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.

[Lincoln Rumenos Guardado, executive]

Good day, everyone, and thank you for joining us for the conference call to discuss the results of the third quarter of 2019.

I would like to begin with the quarter's good news. We successfully completed the workovers on the first 2 wells, which resulted in 3 producing wells at Atlanta. Oil production in the quarter will double compared to last year, reaching 30,000 barrels per day, 100%. This is the FPSO's maximum capacity in the Early Production System, EPS.

With that, the consortium approved the start-up pricing for chartering and FPSO with capacity of 50,000 to 70,000 barrels of oil in order to implement the Full Development System, or FDS. This is excellent news for us. The FDS considers the drilling of up to 9 additional wells and will be implemented in phases. In the first phase, 5 wells should be drilled by the end of 2022, when we expect production to begin; 5 additional wells and another 4 wells should be drilled starting in 2023.

In this way, giving us a total of 12 wells in the Full Development System at Atlanta Field.

For this number of wells, total investment is expected to range from $1 billion to $1.5 billion for the 5 wells or for the 9 wells, respectively.

In this Sergipe-Alagoas basin, we acquired 3 more blocks adjacent to our current 6 in ANP's first permanent offer auction held this year. With our consortium partners, ExxonMobil & Murphy Oil, signature bonuses for these blocks amount to BRL 7.9 million, with BRL 2.4 million net to an Enauta Energia to be paid early next year.

It is always good to highlight that this newer acquisition reflects the optimism that we have regarding the exploration of this basin.

In a nutshell -- I will now turn the floor to Paula, who will get into more detail about our assets in the next 3 slides. And then she will comment on our financial results for the third quarter and for the 9 months of 2019. Paula, please.

[Paula da Costa Corte-Real, executive]

Thank you, Lincoln. Good afternoon, everyone.

Slide 3 shows the highlights for Atlanta. It is important to highlight that the discount compared to Brent for our oil has been narrowing. It ended the quarter at around $10 to $12 per barrel, including logistics costs to deliver the oil to the refinery that is currently at just 1-digit difference compared to the Brent and continuing on a downward path.

The marketing strategy for our oil has been very effective, helping us gain important new U.S. clients based in the Gulf of Mexico, in the West Coast of the United States and also in India and Singapore, which have had the growing interest from refiners and Brent oil, and it gives us comfort and confidence to move forward with the Full Development System. For Atlanta, as disclosed in the material fact and notice of October 3 and based on the production of all 3 wells in operation, we forecast that average EPS production of 28,000 barrels per day with margin variation of 10%, up or down. This number considers the -- takes into account an interruption in production for a scheduled maintenance in the FPSO of approximately 20 days to take place in the first quarter of 2020, without additional costs to the consortium.

Another highlight was the 44% reduction in our average lifting costs to $16.5 per barrel per day, down from $29.6 per barrel per day in Q2 '19. Bearing in mind that as of November operating costs already reached $480,000 to $500,000 a day, fluctuating according to a few variables, most tied to the Brent price.

This quarter, we also relinquished the Oliva field to ANP due to its low financial attractiveness and investment obligations prior to Atlanta's full development. The relinquishment had an impact of BRL 800,000 fully liquid in this quarter.

On Slide 4, we talk about Manati. With thermal power plants resuming operations, there has been increase from August onwards, and we expect it to remain high in the fourth quarter. Average daily gas production in the quarter stood at 3.8 million cubic meters, lower than in the same quarter of last year. Please note that they released a new guidance of financial compensation equivalent to production of 3.8 million cubic meters per day for 2019. For 2020, we estimate a financial compensation equivalent to the average production of 2.8 cubic meters a day, with a 10% variation up or down. The gas contract ensures a minimum pay regardless of production since we have a take-or-pay provision. These projections reflect the natural decline of Manati Field in production since 2007.

And getting to the financial highlights on Slide 5, you can see our revenue, which increased 72% quarter-on-quarter and 42% year-on-year due to both the increase in production and the reduced discount for Atlanta oil, as I mentioned before. On the pie chart, you can see that we have reversed our revenue mix, with Atlanta already accounting to 2/3 of our revenue this quarter, more than offsetting the decrease in average production from Manati that we saw in the field until August.

Slide 6 shows the breakdown of costs. Total operating costs increased 64% year-over-year. And this was less than the revenue growth in the period, even taking into account the recognition of BRL 58 million in the quarter related to workovers in Atlanta Field wells. The adoption of IFRS 16 had several impacts, increase of BRL 62.9 million in operating costs, partially offsetting the BRL 52.7 million in depreciation. Of this amount, BRL 29.8 million referred to the positive impact on costs from IFRS 16 adoption in Manati contracts.

As a result, the net income due to IFRS 16 adoption was BRL 10.2 million. It is worth noting that operating costs of Manati Field decreased 45% compared to the 9 months of 2018, reflecting lower royalties, lower government tax, R&D and depreciation due to average production in the period.

On Slide 7, we have general and administrative expenses and exploration expenses. G&A expenses have been in a downward trend. We are a lean company in constant pursuit of greater operating efficiency. The decrease in both the quarter and the first 9 months was mainly due to the reversal of stock options granted to employees who are no longer working at the company.

Exploration expenses increased in the quarter, mainly reflecting the provision of BRL 27 million resulting from potential contract penalties for noncompliance with the minimum [ resource ] required for Local Content in Block BM-CAL-5 relinquished to ANP in 2015. The consortium operator in Block BM-CAL-5 filed an administrative defense with ANP within the legal term. Among other items, this defense will request a suspension of the proceeding in light of the possibility of entering into a consent decree or contract adjustment term, TAC in Portuguese, which is still in discussion, with Enauta provisioning its share of defining the restated amount of BRL 27 million until this administrative proceeding is concluded.

The increase also includes expenditures of BRL 800,000 related to the relinquishment of the Oliva Field and other costs of seismic processing and environmental licensing studies for drilling activities in the Sergipe-Alagoas blocks.

On Slide 8, we have our profitability measured by EBITDAX and net income. Comparatively, both periods were impacted by the higher comparison basis of 2018 due to the -- due to part of the proceeds from the sale of Block BM-S-8, which was posted in that period.

In Q3, '19, however, EBITDAX was positively impacted by IFRS 16 adoption due to operating costs, excluding depreciation, and increased 60% to BRL 188 million. Net of this effect, EBITDAX in Q3 '19 would be $126 million. In the 9 months comparison, the highlight is EBITDAX stability despite the benefit -- of a nonrecurring benefit of the sale of BM-S-8 in 2018 as a direct result of increased production and better pricing of oil from Atlanta.

Net income in Q3 '19 was $42 million, down 24.6% compared to Q3 '18, mainly due to the provision for Block BM-CAL-5 penalty that affected exploration expenses, as I mentioned earlier.

On Slide 9, we present our cash and indebtedness. We ended the quarter with a strong cash position of BRL 1.5 billion. As for our indebtedness, we further reduced our total debt by almost 12% compared to Q3 '18. Although cash generation from the EPS at Atlanta combined with our own and now the cash funds is enough to fund the necessary investments for a commercial development system, we are considering financing part of these investments with both long-term third-party capital sources such as debentures and bonds and project-based models such as reserve-based lending. This is a financing line with a collateral structure that is based on the value of consortium reserves, and repayment is made with revenue from the sale of oil produced at the field. This will help us optimize our capital structure and maintain the company's liquidity.

Now I will turn the floor back to Lincoln, who will talk about our CapEx and future prospects. Lincoln, over to you.

[Lincoln Rumenos Guardado, executive]

Thank you, Paula. Moving on to Slide 9, CapEx. You can see that the breakdown on investments planned for 2019 and 2020 are on the picture. In the third quarter, CapEx amounted to $13 million, of which 78% or $10.2 million was invested in the Atlanta Field. CapEx for the full year 2019 will total $63 million as projected compared to $73 million in 2018. This is mostly related to investments in Atlanta before production began in the first wells, more specifically interconnection of the wells to the FPSO. Most of the investments planned for 2019 or approximately $42 million relate to the Atlanta Field, already including drilling of the third well, which was below our budget, the expected budget. The remaining funds mainly include investments made in the Sergipe-Alagoas Basin blocks.

For 2020, we have an aggressive $125 million investment program, which is roughly twice as much as our 2019 CapEx. Approximately 70% of these expenditures of $90 million have already been allocated to the development of the Atlanta Field as we move from the Early Production System to the Full Development System. We are already planning to start acquiring the equipment for future drilling of 1 well in the Sergipe-Alagoas Basin.

On Slide 11, we show the highlights of our other exploratory assets. As Paula mentioned earlier, we acquired 3 additional wells or 3 blocks, actually, in the Sergipe-Alagoas Basin in this quarter, with the same working interest. So now we hold 30% of 9 wells in that basin. Consortium will continue to evaluate seismic data from the first 6 blocks already received, and final data should be processed throughout 2020.

A request for an environmental license to drill in the area has already been filed with IBAMA. And we intend to start the drilling program between late 2020 and early 2021.

With regards to the farm-out of PAMA and Foz do Amazonas blocks, the process was interrupted due to a delay in the date of issuance of the pending drilling license. It's worth mentioning that several companies have expressed their interest. And we should resume this process as the drilling licenses progress, not necessarily only in this area but including the whole equatorial margin since undoubtedly that's a key component to any investment decision by companies, including ours.

And also with respect to the blocks the Espírito Santo Basin, Equinor, our partner, informed the consortium that it decided not to remain in the concessions 2 blocks; without, Enauta and Petrobras will continue to evaluate the area. Petrobras took Equinor's share and is expected to be the new operator in these blocks.

Moving on to the last slide. I would like to emphasize that the company is closely monitoring the recovery of the Brazilian oil and gas industry. It's a virtual cycle, not only upstream but also expanding downstream, midstream, throughout the energy chain in Brazil. However, our industry is currently one of the largest drivers of growth in the country, and Enauta is very well positioned to keep growing in this scenario.

As I mentioned in the beginning, we've doubled production, particularly with Atlanta in a little over a year. And we're now getting ready to double it again by the end of 2022 and early 2023.

Heavy oil supply has been declining with a decrease in production in Saudi Arabia, Iran and Venezuela, areas that produce heavy oil as well. And it was the main item behind the cutdown on OpEx.

Meanwhile, the global marine industry is getting ready for the implementation of the IMO 2020 rule, which will reduce fuel sulfur content in bunker fuel to 0.5% from 3% down to 0.5%. The oil in Atlanta is a heavy oil with only 0.35% sulfur content, which means that the demand for this oil is high, therefore leading to a considerable reduction in the discount compared to Brent, as we already mentioned.

With regards to the gas industry, the federal government launched the new gas market, a program to boost the natural gas market through greater competition and incentives for investment in offload, infrastructure, processing, transportation and distribution, in other words throughout the value stream. The program will also include means for the better use of pre-salt gas, which should also include over the coming years the Sergipe-Alagoas Basin where we have gas, and we also hold a working interest in 9 blocks.

But I highlight that the main target behind this basin continues to be oil and top-quality oil. So we're very excited about our prospects, and I want to underscore that we will grow strongly in the upcoming years with a Full Development System in Atlanta and the start-up of drilling activities in Sergipe-Alagoas. Enauta is an expert in Brazil and has a strong track record in establishing business partnerships with global companies entering the country or already in the country. We are still interested in acquiring working interest in pre-salt, a medium to long-term strategy, and in line with our financial capacity in the short and long run.

These were my final remarks. We can now open for the Q&A. Operator, over to you.

[Operator]

[Operator Instructions] The first question is from Leonardo Marcondes with Itaú BBA.

[Leonardo Marcondes, analyst]

Actually, I have 2 questions. The first question is about the discount about Brent oil in Atlanta. You said that it went down between $10 to $12 per barrel in the third quarter, and it keeps on going down in the fourth quarter. But I'd like to know if you give us more color, what do you expect to see in this current quarter? And what about the expectations for next year once we have the implementation of the IMO? The second question is about Full Development System in Atlanta. Could you give us more color again? We would like to know how you envisaged the FPSO market. And how you expect to conclude or announce the contract of the Full Development System. These are my questions.

[Lincoln Rumenos Guardado, executive]

Leonardo, Danilo is going to answer your question. He'll answer the question. If necessary, if you need more support, Paula and I are here for you as well.

[Danilo Oliveira, executive]

Leonardo, Danilo speaking. As for Atlanta's discount, like we mentioned, last quarter it was between $10 and $12 discount. Currently, we are running this current month of October and November discounts below $10 added to the quality of oil and logistics as well. We've seen that similar oils to ours have been traded at Brent oil prices. And that's the target we want to hit. For the moment, we can see a downward trend. It is happening, but we'd rather not to show any numbers or figures now. We have like a dispute of offers when it comes to the Brent oil discount, and it's on a case-by-case basis. So conclusion, lower than $10 today but going down and down at every load -- off-load. As for the FPSO, we still need in order to be in the bid, which has already been approved by our partners and our Board, we want to conclude any documentation related to the full system that we expect to see, not only the FPSO but FPSO for subsea systems, which means control umbilical lines, equipment and wells. So last month, we hired an engineering company which will do the final review of the documents. And we intend to have a simultaneous launch this year, including the flow lines.

[Operator]

Next question from Gabriel Barra with UBS.

[Gabriel Barra, analyst]

I have a couple of quick questions here. The first is about Atlanta. You have a contract with Shell to sell the Atlanta oil. My question is can you continue with this contract after the Full Development System? Or will you have to sign a new contract? How does this work? Second question. Regarding the OpEx for the workovers of the first 2 wells, you have mentioned $45 million, and it was a little under that amount. So I guess you have more efficiency, but will there be anything left to pay in the next quarter? And regarding PAMA and Foz do Amazonas, is there a target date to solve the problem with the environmental agencies?

[Lincoln Rumenos Guardado, executive]

Okay. Thank you. Shell is the one we hired to absorb the oil from the EPS. So during the Petrojarl operation in the EPS, Shell will be handling that operation. Yes, there is a possibility to continue the process with Shell. But according to our JOA, we would have another bid. So by the end of the EPS, Early Production System, little before it and depending on the position of the consortium partners, we can have a direct negotiation with Shell that would involve an inspection or move to a bid. So there are 2 options there. Regarding the workovers of the well, unlike the drilling of the wells, you will remember we had about 16 days stoppage because of sea conditions. In the workovers, we didn't have any interruptions. [ We thought ] that it clean, fast, efficient and that it gave us approximately $10 billion worth of savings. We didn't have to stop any of the positioning of subsea equipment or during the care of the workovers. So that allowed us to have savings and led to a very efficient operation. And regarding the margin, maybe Paula will answer your question.

[Paula da Costa Corte-Real, executive]

Well, hello, Gabriel. Regarding licensing in the equatorial margin, we have had frequent meetings with IBAMA, the Brazilian environmental agency. And we're updating the studies that were submitted at the time that we requested environmental license. We are -- or they have been asking to all of the operators what their prioritizations are in terms of the different consortia priorities. Our priority in our case is for PAMA. And we are sparing no effort to update our studies and carry out new studies to meet IBAMA's request. And hopefully, by end of next year, early 2021, hopefully, we'll have the license for PAMA, Pará-Maranhão. So that as Lincoln mentioned before, we can proceed with the farm-out and get the partners that we need to proceed and to start drilling in that area. The area, in our opinion, is very attractive, both PAMA and FZA. And -- but our priority in our conversation with IBAMA is Pará-Maranhão, PAMA.

[Operator]

Next question from Rodrigo Almeida with Santander.

[Rodrigo Reis de Almeida, analyst]

I have 3 questions. One has to do with the Atlanta lifting cost, if you can give us color in terms of what we can expect looking forward since we're going to have a higher combination of costs in terms of chartering and high production of around 30,000 barrels. Do you see the lifting cost remaining stable? Do you think you can reduce it even further? And my second question has to do with the 50% of [ Baja ] at the [ Quanta ]. Do you see any possibility that you will get more working interest from them? Could you share this with us? If there's an opportunity, do you think this would be interesting? And my third question has to do with capital allocation. It is clear that you want to optimize the structure. Do you have any target leverage with the Full Development System of Atlanta? In other words, what percentage of the Full Development, do you intend to fund through debt?

[Lincoln Rumenos Guardado, executive]

Rodrigo, Paula will answer your question regarding lifting cost and will also tell you what we are thinking in terms of funding for Atlanta. And then I will come back to your second question about Barra.

[Paula da Costa Corte-Real, executive]

Rodrigo, this is Paula. Regarding the lifting costs at Atlanta. As of November, we are talking about an operating cost of between $485,000 and $500,000 per day, which was because the FPSO chartering contract returned to the original values. In other words, we ended that period of the first 18 months when we had a discount regarding that contract. And it does have some variables that can change the cost a little bit. And most of it related to Brent oil price. So starting with this basic CapEx $480 to $500 a day, our production guidance is around 28,000 barrels per day. We are talking about a lifting cost of $18 or $19 per barrel. This is what we're expecting looking forward, but I'd like to remind you this cost depends on some variable, contract variables that can bring some variation over time. But what we are expecting is a lifting cost of around $18 to $9 per barrel.

Now moving to your third question, and then I'll turn the floor back to Lincoln, who will answer your question regarding our strategy regarding [ Baja ] working interest. Now regarding capital allocation for Atlanta, I think that the -- for the Full Development System, with an opportunity to increase the leverage of the project because most of the risks associated with implemented -- to the implementation of the project have been mitigated. We'll know how the reservoir behaves, the productivity of the wells. And venues have been better and better at that field. So we see an important room to increase the leverage of the company and improve our capital structure. Because today, I think we are very much focused on using our own capital for our projects. For the Full Development System, we can lever -- we can leverage about 50% of our CapEx, but we're still running initial modeling because the design of the Full Development System is being discussed internally. We are still defining capacity of the FPSO. So it involves bidding for the FPSO, contracting the FPSO, the production curve. So roughly speaking, we would fund about 60% of our CapEx through debt, which would take us to a net debt over EBITDA ratio of about, I guess, 1.5x to 2x. So very comfortable levels actually in terms of leverage for the project. But again, these numbers are initial. They're being discussed depending on the design that we choose for the project. If the FPSO have a capacity of [ 50 ] or 70,000, how many wells will we drill? 9 or 5. So we'll start with Phase 1 drilling 5 wells. And then at the second stage, we would drill up to 4 additional wells. So the cash generation for the spread space will help us fund the last 4 wells. So all of that has to be factored in this equation for the project, but we have good prospects in terms of leverage, which would improve the capital structure for the company. Now Lincoln will talk about our working interest at Atlanta.

[Lincoln Rumenos Guardado, executive]

Well, Rodrigo, yes, we know that Baja is interested in selling their stake of Atlanta Field. And what we have seen in the last perhaps 2 years but particularly in the last 12 months is a brutal appreciation of Atlanta. Atlanta became a great deal. We have production stability. We have price stability. As Danilo mentioned, we see an increment or a better discount of our oil vis-à-vis Brent oil price given the circumstances of other producing countries and structural points such as IMO 2020 that has come to stay. And in our opinion, it will have a little long-term impact in the selling of this kind of oil.

So looking at Atlanta and looking at what's happening in Brazil and I'm going to exclude the transfer of rights because that's a different magnitude, nothing comparable. But looking at the latest deals in Brazil, Atlanta, in our opinion, is no doubtedly the best. 2P reserves up to 240 million and 250 million. It just needs still to be proven. But Atlanta today -- and I don't have a proxy to be a seller for Baja. But Baja, where we get 120 million barrels, so in the latest deals, we've seen that there are no compatible volumes with this magnitude. So Atlanta is undoubtedly an excellent opportunity. Whoever wants to play in Brazil, we would be interested in it or if you want to increase your position, which would be our case. However, we have a policy, and we have seen some opportunities in the market, but we always take into account our policy to diversify revenues related to that because we see Manati coming to end of production in 2023, '24. And we are considering the scale-up that we can do at Atlanta in the coming years. So in principle, we don't know what their selling price will be. We have some prerogatives in terms of that sale because we have the JOA, the partners relationship, et cetera. But in principle, we would keep to our policy of diversifying our revenue sources as a way to have stability so that we can plan our capital allocation, our financial planning, et cetera. In principle, we would not looking -- we will not be considering that purchase. But again, this will depend on their selling price. But to us Atlanta, whether it belongs to Baja or to whoever comes along has appreciated substantially. When we consider the results coming from Atlanta in terms of production, the Full Development System decision, the increment in production and the commercial effects in the market for this kind of oil. So is that a good opportunity? Absolutely. But to us, we always focus on diversifying our revenues instead of scaling up and relying solely on 1 field, but we'll only know what to do when Baja kicks off their process of selling their share of the stake.

[Operator]

The next question is from Fernanda Cunha with Citibank.

[Fernanda Perez Da Cunha, analyst]

The first question is about Carcará. I'd just like to go back CapEx you mentioned. I think you mentioned around $1 billion to $1.5 billion. Could you give us more detail about the breakdown between drilling work, completion work? Can we still consider the same amount that you mentioned to be $5 million?

And another question about the size of the FPSO. We also considered 80,000 barrels per day. If I'm not mistaken, the current guidance is 50,000 to 70,000 barrels per day. What led to the reduction in the size of FPSO? I mentioned Carcará, but I'm referring to Atlanta, I apologize.

Now the other question is about Carcará. Could you please also give us more color about the timing for the relinquishment of Carcará reimbursement? Can we still consider the pretax $145 million amount? And if I may, just about Sergipe-Alagoas, when should we expect to see -- or what is the timing for the first oil of the exploration campaign? And could you also tell us more about the idea of the size of the campaign, how many wells that you're planning to drill?

[Lincoln Rumenos Guardado, executive]

Fernanda, you corrected yourself, right? If it were Carcará, oh, it could also be an option, 10%, probably close to the same range, the same value. As you can see, the price per barrel, CapEx per barrel would not be so different. Carcará possibly has 5 or 6x more. As for Atlanta and CapEx and the size of the FPSO, Danilo is going to answer your question the reason why we had these changes, okay?

[Danilo Oliveira, executive]

Okay. Fernanda, Danilo speaking. Let us begin with CapEx. Like Lincoln said before, our CapEx is between $1 billion and $1.5 billion or 100%. In reality, $1 billion for the first step, the first phase or 5 wells drilled and completed and interconnected to the new FPSO, plus $500 million in the second step, a second phase in order to drill and add another 4 wells.

But first, the CapEx breakdown. I would say 50% for drilling and completion and 50% for the remaining work. The amount spent for this well is a good base value to be used. So we're using a utilization factor owing to the continuation of the campaign. It is not a hiring work for a well, but for 4 wells, another 5 wells and perhaps an exploration well in Piapara. We expect to see some gains when it comes to the cost that we expected to see for the well in Atlanta. As for the size of the FPSO, we mentioned 80,000 barrels per day. That was back in 2012. In the Full Development System that we proposed to ANP at that time with a barrel price at $100 -- around $100. And once we had a drop in the dollar rate and the world crisis, we worked on these numbers. And for some time now, we have been considering a decrease going down in Atlanta. We mentioned 70,000 a long time ago. And in our latest conversations, we highlighted the possibility of being from 50,000 to 70,000. And that's what we use in the bid, depending on the market, depending on the market offer. So that's the range between 50,000 and 70,000. For 50,000, we would expand the production period, which as it happens today. So in the EPS, in Atlanta, we can have 35,000 barrels per day, and we are at 30,000. So that's why we have a guidance for full year of 28,000 approximately plus or minus 10%. And that's for the Full Development System. Should we go for an FPSO of 50,000, then we're going to have 50,000 as expanded level. And if you go for 70,000, then the peak production will be 70,000, however, with a quicker or faster drop.

[Paula da Costa Corte-Real, executive]

This is Paula speaking. As for Carcará, $155, which is 38% of the price. And our expectation, the trigger for payment is utilization of the concession area with a sharing area, which has the same consortium except for the other which is in the sharing other concessions, we expect to be concluded by the end of 2020. Mendes is going to tell you more about the timing for Sergipe-Alagoas.

[Jose Mendes, executive]

Fernanda, first of all, thank you for being so bullish, already speaking of the first oil in Sergipe-Alagoas. So first oil depends a lot on the features of the discoveries that are coming up. What we've seen from our operators in the development of their discoveries in Guyana region is that they really sped up the process. Between the discovery and the first oil, it will be around 5 years. So we're working on this horizon of 5 to 6 years in-house for a possible discovery. Naturally, it will depend on the features and characteristics of the discovery, the size, the level, oil to gas ratio, so it largely depends on what we get from the discovery and expect to have a clear picture about the time for first oil to happen.

[Operator]

The next question is from Luiz Carvalho, UBS.

[Luiz Carvalho, analyst]

Lincoln, Paula, Danilo, Gabriel asked many questions. But if I may, I'd like to go back to the same topic. First, Lincoln, could you help us better understand the auction, the 6-round dynamics? I read recently an interview with you. Could you give us more color about the dynamics and why you believe that the bid was not enough for other areas? So that's my first question.

And the second question, I believe one of the risks that we see about the case has to do with CapEx commitments moving forward. You have approximately BRL 1.2 billion cash. Paula, correct me if I'm wrong, but I think you mentioned in the IPO 10 years ago. But today, your commitment of cash for the future with the development of Atlanta and Sergipe-Alagoas and maybe other possibilities and other prongs in this 6-bidding round, maybe this cash may be drained, so to speak, despite the cash generation that you expect to see in the future. So Paula, what is the mind-set in this regard consider you have other possibilities now with reserve-based lending? And what about allocation of capital and also the use of cash?

[Lincoln Rumenos Guardado, executive]

Luiz, this auction, it's quite controversial, actually. There were several different theories, assumptions. And I believe it will bring a lot of headway, a lot of progress. If you think how the system and the sharing system, it led to some uncertainties, particularly when it comes to the transfer of rights. So it raised some questions, and we have 4 auctions. We were involved in one of them. Related to blocks in the permanent offer, we acquired 3 blocks. We were awarded 3 in Sergipe with a very good price, but we always expect to see some competition, which we didn't face at that time. There was a common denominator, a very high bonus, and that was something common in the 3 bids for the 6-bidding round and the 16th transfer of rights. Maybe in the 6-bidding round, there was some depletion, so to speak, when it comes to finance companies. The 16th did have some competition, very few blocks that were there. I guess just 1 or 2 remain. But the ones that were awarded, there was a lot of competition for them, particularly Total's walk with 1, BP and Petrobras around 4 million-something. And naturally, there was a lot of cash demand as for the transfer of rights. In addition to bonus, maybe lack of information was an issue, lack of adequate information for adequate financial analysis by companies and negotiations, and this has been heavily discussed in the industry as a whole. And in the 6-bidding round, I think there was a depletion of funds, for instance, which prevented Petrobras to cover everything on its own. The remaining part of the 30% it had the right to have it. It had the right. It was entitled to have 30%. So it was really tough to give evidence or the design of the consortium, and that's why it didn't move forward to cover 100%.

I can honestly tell you that there were attempts. And we tried to be involved as well. However, the makeup of a consortium that brings together several companies considering the bonus that was required, it is not something just to be done by a couple of companies. It takes more companies, small or large companies, but many companies. It takes some convergence about a working interest, the area, how much each of the parties is willing to give. And that was tough convergence from the moment that the capacity and the space we had. The window for that investment was very narrow by the amount of the bonus. So that was a challenge. And the whole industry expects the government to revisit the bonus because there is competition behind it and at the same time make some headway in the appraisal and evaluation of the real need of a sharing contract. No doubt that Petrobras, if it considered, it expressed interest in several areas. It took a couple of them and had a lot of benefit. And undoubtedly owing to this challenge, particularly a commercial challenge and financial challenge, Petrobras' one was the big winner of the auction. But maybe this kind of challenge will not happen in the future again. We expect it won't happen. Think about company like us, then it will be easier for us to be involved in this kind of auction, always respecting our constraints, which is your second question that will be answered by Paula now. It is our liquidity. We preserve our liquidity, and I can tell you that we always bear this mind. And that's why we could not be into some deals, which doesn't mean that we gave the auction up. Please note was only in its early stage. So when it comes to prospects and also production, we have no doubt about it.

And now I turn it over to Paula. She's going to give you more detail on CapEx and cash.

[Paula da Costa Corte-Real, executive]

Paula speaking. Luiz, let me talk about the financial aspects. Today, we have BRL 1.5 billion cash. You mentioned BRL 1.2 billion. This is our net cash, and we have 2 debts and 21.3 net cash; 2 debts which are long term in the balance sheet of the company. When you look at our portfolio, if we think about our effective commitments today, what we see on the radar in the short term is this final development system at Atlanta. Like I said before, there is room for leverage, definitely. The project is -- well, has no risk with regards to reservoirs, exploration. The productivity is known. The reserve is known. So we can see some appetite for leverage and also for the debt in this project. And therefore, our capital structure is more healthy and solid as a company. So that's to finance, the bulk of CapEx in Atlanta development.

As for Sergipe-Alagoas, we have a commitment with the wells, but we have 9 blocks in the basin. So we know it is not only going to be just 1 exploration cost. The number of exploration wells will depend on the results we achieve. It's a highly potential area. Our technical area is very confident about the results that we can achieve in this area. But give any magnitude for CapEx right now is not possible today. These numbers depend on the results achieved in the area. So actually, as for leverage, that's a good problem, and it will be higher as the more oil we have and the greater development we can achieve. And there will be several equations. Like Lincoln say -- said, we preserve our liquidity, and we are very diligent when it comes to the financial ability of the company. We have internal models taking into account some CapEx, but -- so you can be in exploration costs and you can have a reserve for development as well. And depending on the results, you also open more windows to equate the capital needs. Today, for instance, 30% in the area. So maybe if we need to go down in my working interest, it could be an opportunity. But prior to that, we have to consider increasing the debt in the balance sheet naturally within acceptable parameters without increasing the financial [ ability ] risk of the company. We would have a lot of room here in terms of our stake existing in the area and also in the leverage balance and also the flow of the Full Development System, helping us to have more room in the balance sheet. And finally, the company's appreciation in the future. We might also consider other methods for funding to the development of Sergipe-Alagoas. But today, for us, it's not a hinderance -- not an impediment for our finance. We still have room for new investments based on our long-term financial capacity.

[Operator]

Next question from Christian Audi, Santander.

[Christian Audi, analyst]

I have 2 questions. The first, you have a substantial improvement in the lifting cost given the increased production. I just like to understand what you expect for the future. Do you see this trend continuing at this magnitude? Or will it improve but a little slower?

My second question has to do with what you mentioned, Lincoln. If the government doesn't make any adjustments to the whole auction process, well, I guess that all of the changes will happen next year, and I'm talking about the pre-salt here.

Do you think that if the changes are made that you would be more encouraged to participate more in these auctions via consortium given an expected change to be made by the government to drive more participation in these auctions?

[Lincoln Rumenos Guardado, executive]

Christian, regarding the cost, Danilo can explain a little bit more, bring you some color on this in terms of what we can expect with an increased production.

[Danilo Oliveira, executive]

This is Danilo. Christian, let me try to understand. For the EPS, the costs have been defined. We have long-term contracts for that. And we expect these numbers will remain, as Paula mentioned, around $18, $19 lifting cost for this first year. And obviously, in another 2 years, this might increase the level given a decline in production because we expect a decline by 2021, 2022. For the Full Development System, we should not see an increase here, despite an increased production, 50,000, but we should expect also a cost increase. At least in our calculations and forecasting, we see this remaining the FPSO of 50,000. The daily usage rates should be higher, but this will be easily offset by production. So in our estimates, in our studies, we consider a lifting cost not higher than $20, okay?

[Lincoln Rumenos Guardado, executive]

Christian, this is Lincoln again. Christian, if I were to answer yes or no, I would say yes. Because what happened was very educational, I guess, to bring all of us and particularly the government to a reality check. I would say that the companies were a little fatigued to be in this growth spiral with the bonuses, et cetera. It doesn't reduce the attractiveness of the result, but what happened will probably bring more rational bonuses. Perhaps there will be some flexibility in the future contracts -- sharing contracts, if they continue to exist. So that could attract more companies to play this game, companies of different sizes because the more companies we have playing this game and the more operators -- and we can even be an operator in the pre-salt and why not? Because our company is positioned for that. But the more operators that we have the better for a company of our size because we can participate according to those conditions that I mentioned a little earlier within the limit that we set for ourselves in terms of revenue source diversification that result as high capacity of prospection and very low risk, et cetera. And with a growing off-road infrastructure that is already happening, so that allows us to think about the midterm and have a possible revenue source. Now this is not a promise that we are going to bid or that we are going to win something, but I see this with good eyes. And I expect an improvement in terms of our possibility to bid considering what happened in the 3 auctions. All 3 auctions were extremely educational for all of us, for all of the stakeholders. And we want to have new players. We've seen this with 2 new companies, QPI, Petronas, that arrived to play and play strongly, and this was great. But we didn't see a continuity in these auctions, but this should happen. It is what we are hoping for. It is what we are expecting as long as the government will make the necessary corrections. The government will need to make these corrections. They will need to evaluate this whole thing. And I believe that this will increase our chances of participating more in and looking at the upfront and also looking at the long term in terms of our exposure. So we believe that this might be compatible with Enauta as long as we bid within our limits of 10% to 20% on average, which is what I believe in. And I believe that the country will gain if the government makes changes for 2020.

[Christian Audi, analyst]

Very clear, Lincoln. Now these changes, are these changes easy to do regarding the bonuses? I guess so, but do you think that the other changes will be easy to make in the short term? Or do you expect these changes to come in the long run? In other words, can this be done so that these auctions can happen again in the second half of 2020? Or are these changes more complex and will require a more active participation of the government and political capital of the government?

[Lincoln Rumenos Guardado, executive]

Well, I'm not going to mention the possibility of the transfer of rights. I think it became kind of evident from what we read in the papers that was -- that they lacked clarity in terms of what should be the value and the assumptions for the Petrobras reimbursement. I mean this is what I read about because we didn't participate in that. We didn't discuss it. So it's hard for me to speak about it. But they should come back, the transfer of rights. But it should come back with more clarity in terms of what should be discussed with Petrobras, how and at what amount. And I think that the government and Petrobras will evolve on that. Petrobras is also interested in these areas to be sold for their own financial planning but I believe that once the government understands better the bonuses. This is up to the government. And the minimum profit oil -- so that -- there can be a neutral effect in terms of what I am risking and what I'm going to give back to the government. So the minimum established will need to be changed. And I think that perhaps this inhibited the bidding by some companies.

Now regarding changes in the regulatory part of the equation, a possible reduction in the presence of Petrobras because they have the possibility to a number of the areas. The papers have been writing a lot about this, and the industry has been talking about it, about the elimination of Picanha, a restriction pre-salt area. This would already help the auctions, and it wouldn't be a decree, a regulatory change that would be as strong as simply the extinction of the sharing system -- production sharing system.

Can this happen? Yes, we hear a lot of comments, but still in the aftermath of the surprise that we had with very little participation of some oil companies. I think that we have room to advance, so those can come from different profit oil and different bonuses, maintaining the sharing regime and perhaps come from a change in terms of Petrobras and the extinction of Picanha. These seem to be simpler than is the extinction of the model itself. But if they advance, I think they will advance towards one single model, which would be ideal, a single concession model. This is clean, and it allows for a better economic assessment and government assessment. It will be a lot easier to evaluate the auctions. And I think that they are going to move forward.

[Operator]

Next question from the webcast by Vicente [ Vanco Franke ]. The proceeds policy for 2020, will it be maintained? Or will it change vis-à-vis 2019 and '18?

[Lincoln Rumenos Guardado, executive]

Well, we already have a preestablished policy of dividend payout, $0.15 per share annually. This is a policy we've been maintaining since 2013, and we intend to continue with that policy until we have a higher and more predictable cash flow. Because when that happens, the policy can change. But for now, for 2020, what we expect is the policy to be maintained in 2019 and in 2018 and the dividend payout, which was extemporaneous particularly because we had a cash surplus. And we needed less cash for our policy in terms of participation, particularly geared to Sergipe-Alagoas expansion, but we were able to execute our strategy. And so we decided to have these 2 dividend payouts in 2018 and '19. For 2020, what I can tell you today is that we maintain our intent to distribute what we have in our policy, $0.15 per share. But we're always looking into these things. And we'll have to see how we can execute our strategy that we have just mentioned. We are going to have a reasonable outlay of cash for the Full Development System for Atlanta, and there will be other auctions. So there are other elements, other biases that interfere with dividend payout. But what I can tell you today -- and also I must mention that this is not a decision by the management of the company only. This involves our Board of Directors, et cetera. So our intent so far is to maintain our policy. Now in the mid to long term, we will change the policy provided that we predict an increase in our revenues.

[Operator]

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

[Lincoln Rumenos Guardado, executive]

Well, my friends, thank you very much for joining us today and for your questions, which I believe gave us an opportunity to detail more our presentation. And I hope we have answered your questions as much as possible. And hopefully, we have reduced your uncertainties. But I want to underscore that we are very optimistic about the performance of the company in the future. I want to underscore that our Investor Relations Department is always available. You can get in touch with us at any time for further clarification, and we'll keep you informed because we have a very important pipeline of events to happen until the end of this year with new bidding loans, and we'll keep you posted so that you can have more and more information to evaluate and discuss with us the future of our company. Thank you very much, and have a good day.

[Operator]

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

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