Enauta Participacoes SA

BOVESPA:ENAT3

Earnings Call Transcript 2018-Q2

[Operator]

Good day, ladies and gentlemen. Thank you for standing by. At this time, we would like to welcome everyone to the QGEP's Second Quarter 2018 Earnings Conference Call. Today we have here Mr. Lincoln Rumenos Guardado, CEO of the company; Ms. Paula Costa Corte-Real, CFO and IRO; Mr. Danilo Oliveira, Production Director; and Jose Milton Mendes, Exploration Superintendent.

We would like to inform you that this event is being recorded. [Operator Instructions]

Before proceeding, I will mention that forward-looking statements might be made during this conference call. Relative to QGEP's business perspective, projections and our operating and financial goals are based on the beliefs and assumptions of QGEP'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, it depends 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 QGEP that 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, QGEP's CEO, who will start the presentation. Mr. Guardado, you may begin.

[Lincoln Rumenos Guardado, executive]

Good day, everyone. Thank you for participating in today's conference call to review our second quarter results where we will also present our business outlook heading into the near future. Firstly, let me say that we are very pleased with QGEP's position in the market today and with the progress that we have made over the last several quarters in executing our strategy to maximize our company's growth potential and to maximize shareholders' return, mainly reflected in the sharp increase in QGEP's share value. And we would like to highlight that currently, the company market cap should pass BRL 4 billion. We appreciate the continued interest and support from our investors and analysts as we move forward with our investment plan.

Please go to Slide 2 where we present the strategic highlights of the second quarter 2018. First and foremost, I'd like to highlight that our improved second quarter results were driven by considerable operating progress. Total production in the quarter reached 1,450,000 barrel of oil equivalent, reflecting the diversification of our revenue sources, which is something that we continuously seek considering that Manati Field presented a significant pickup in production volumes, thus being the key driver of higher revenues and cash flow in the quarter.

Considering [ first in June ], QGEP was the biggest independent Brazilian company in the ranking of oil producers according to ANP data and the seventh biggest in the total rankings, which includes all companies in terms of barrels of oil equivalent. We will try to maintain this position of production. Our operating income actual results benefited from 2 months of production at the Atlanta Field where we flowed first oil on May 2, 2018, representing a major milestone for the company as you all know. We have also commissioned the seismic data for the 6 blocks in the Sergipe-Alagoas Basin. These blocks represent the most relevant -- the core of our current exploratory portfolio, and we are all very keen to move ahead as quickly as possible with data shooting and interpretation in a basin that is known to be of high potential. Finally, our farm-out process is ongoing for the 2 Pará-Maranhão blocks in which we have 100% working interest with the business from several companies.

At this point, I would like to turn the call over to Paula, our Chief Financial Officer, for a review of our second quarter financial performance, and I'll come back after that. Paula?

[Paula da Costa Corte-Real, executive]

Thank you, Lincoln, and thank you, all, for joining us today. As always, I will review our results for our most recent quarter followed by an update on our cash flow and CapEx for the quarter. I will then turn the call back to Lincoln to discuss our operating achievement and our business outlook. We're pleased to report very strong results for the second quarter, stemming from an increase in demand for our gas from Manati and start-up of production at Atlanta Field. Thus, we have been able to boast a strong performance in terms of profitability, cash flow generation and overall financial strength. So let's see the numbers.

Beginning on Slide 3. In the second quarter, for the first time, we have posted the results of 2 producing assets. QGEP's gas production in the quarter totaled almost 200 million cubic meters, while oil production for 2 months of the quarter at Atlanta was 16,739 barrels per day.

Starting with Manati. The field averaged a daily gas production of 4.9 million cubic meters in this year's second quarter, up 9.3% over second quarter '17. This increase was primarily due to drier weather conditions during the quarter, which created increased demand for gas-powered thermal electric plants. Manati Field has been the main driver responsible for our strong cash flow generation, providing significant funds for us to continue investing in attractive opportunities in our sector. As you all know, Atlanta Field flowed first oil in May of this year. Production for the 2 months of the quarter averaged around 10,000 barrels of oil per day. We forecast an average daily production of 13,000 barrels a day for the coming quarters. Please go to Slide 4.

Revenue in the quarter was BRL 158 million, up 38% year-on-year, reflecting the higher production from Manati as well as the contribution from Atlanta Field.

Oil revenue from Atlanta in this period was approximately BRL 32 million next to QGEP. Moving on to costs.

Please turn on Slide 5. For the quarter, total operating costs were 45% higher than the same period of the prior year with increase primarily attributable to the Atlanta operation. Considering Manati alone, cost totaled BRL 44 million, down 23% year-on-year, mainly benefiting from an insurance revenue of BRL 8 million related to an incident occurred in one of the flow line last year. Of the total BRL 84 million in total costs, approximately BRL 39 million referred to the straight up of Atlanta Field, equivalent to roughly $410,000 per day for 100% of the field. This cost should remain stable at this level for the first 18 months of operations at the field. These higher costs in the quarter were also impacted by higher depreciation and amortization expenses and royalties related to higher production from Manati as well as Atlanta's initial production.

Our exploration cost has trended down this year -- in this year's second quarter, 70% lower year-on-year as fewer funds were spent on seismic data acquisition in the quarter. In this period, we started processing seismic data of the 6 blocks in the Sergipe-Alagoas Basin, an area where we benefited from cash called by our partners, ExxonMobil and Murphy Oil, as part of the farm-out agreement of 2017.

By contrast, last year's higher cost related to seismic data processing for our 100%-owned blocks in the Pará-Maranhão Basin.

On Slide 6, general and administrative expenses were 83% lower year-on-year, primarily due to the reversal of the first stock option plan granted in 2011, which had a positive impact of BRL 10 million.

Moving on to profitability. We are now on Slide 7. Total EBITDAX in the quarter was BRL 101 million, more than double compared to the same period of the prior year. These solid results benefited from both operating improvement leading to higher production, and the start-up of production at Atlanta and lower general and administrative expenses. With that, we generated net income of BRL 85 million in this quarter, up from BRL 61 million in the same period of last year. Along with our Board of Directors, we continuously review all capital allocation options with a view to generate the best long-term returns for the company and its shareholders.

Moving on to Slide 8. In the quarter, CapEx totaled $20 million with the majority or 72% invested in the Atlanta Field.

During the second quarter, we also began the process of seismic shooting for Sergipe-Alagoas Basin. On the slide, you can also see the breakdown of our capital expenditures for full year 2018 and 2019. For the current year, we are budgeting capital expenditures of $60 million, which is $10 million lower than what we have disclosed previously. The majority, or $39 million, is allocated for development of the Atlanta field. This includes equipment for the drilling of a third well. The remaining funds will be invested in exploratory activity with approximately $10 million allocated for seismic shooting for our Sergipe-Alagoas blocks and $5 million for seismic data acquisition for the blocks acquired in ANP's 11th bidding round. It is worth noting that historically, we have funded our CapEx requirements with internally generated funds or with the IPO proceedings. Over the past year, funds received from the sale of Block BM-S-8 and some farm-out agreements have increased our liquidity and provided even more financial flexibility for the company. Lincoln will review our capital allocation priorities in a moment. As always, we will remain disciplined in our use of capital while continuing to invest for ongoing growth.

In summary, we are very pleased with our second quarter results and are confident in our prospects moving into the second half of this year.

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

[Lincoln Rumenos Guardado, executive]

Thank you, Paula. On Slide 9, we provide an update on our operational activities in the second quarter. As mentioned earlier, there was a considerable increase in gas production at our 45% owned Manati Field due to dry weather conditions, which led thermal power plants in northeastern Brazil to use fossil fuels to supplement hydroelectric power. Based on average daily gas production of 4.8 million cubic meters from January through July and on the current run rate, we are pleased to confirm our initial guidance of $5.1 million cubic meters of average daily gas production in Manati Field for full year 2018.

These volumes do not take into consideration any material pickup in industrial demand in the region in the second half of this year. In July, Manati Field produced on average 5.2 million cubic meters per day, confirming, therefore, this increase in the need for gas in the region.

The main highlight of the second quarter was certainly the flow of first oil from the Atlanta Field, which became our second-producing asset. As Paula mentioned, the Atlanta Field reservoir is meeting our expectations and our daily production from May to June averaged 10,000 BOEs, which is below our initial estimates.

I always like to highlight the main merit related to the Early Production System, so we can have the right conditions to follow the behavior of the reservoir, and undoubtedly, the production already seen are in line with such behavior. So maybe the best or the greatest challenge we had for the Early Production System was precisely to do this assessment of the flow of the early initiatives we had, our efforts and also the behavior of the reservoir, which is fully working based on the data we monitored so far. Undoubtedly, there was a malfunctioning, a mechanical problem in the well pump. This has been assessed, and this happened right after the startup of production in the 2 wells, which has forced us to use the pump on the seabed, which was expected to happen later on. As a reminder, the well pump installed by QGEP has a very long residency time, 4 years, with regards to the FPSO, and it might be the cause of this malfunctioning that we've seen so far of these pumps that are close to the reservoir. However, our average production was approximately 13,000 barrels of oil per day in July, confirming what we said before. We are searching for new ways to increase production, but at this time, we estimate that average production will remain around the current level, in other words, 13,000 barrels of oil per day until the drilling of a third well.

Further information will be provided later on about the actions that are in progress, which also stem for drilling this well and also benefiting from the use of a rig in the field. The Consortium has been performing a technical economic assessment to replace nonoperational pumps as soon as the third well is drilled. Danilo can give you further information during our conference call. However, I can say that we had already the approval by our board and Barra Energia, our partner, to perform the intervention -- the work over in both wells trying to replace the pumps for other pumps. This is very recent information, and it confirms our belief, our trust in the capacity of production of this reservoir. Otherwise, naturally, we wouldn't have to do this intervention, and allied to the third well, we may recover the bulk of this production, which we mentioned before.

So as you may recall, the company also has an agreement to sell total oil produced in the Early Production System. In the second quarter, approximately 486,000 barrels of oil were transferred. The total net to QGEP was 146,000 barrels of oil, and the oil was sent, above all, to refineries on the West Coast of the United States and in Asia. And by the way, we are creating an economic, commercial stream for this oil as well. It is heavy oil, and therefore, there are many good characteristics like the low presence of CO2. So right in the beginning of marketing this area through a very renowned company, which is Shell.

The performance of the reservoir, combined with the production and pricing outlook, has led the Consortium to decide to move forward with a third well, which completes the Early Production System. It's also worth bearing in mind that we have a limited capacity in our plant at 30,000 barrels of oil per day. We expect to conclude a tender to charter a rig by the end of this month. Drilling is expected to take place in the first quarter next year with first oil expected in the second quarter of 2019. With the third well online, the average daily production in the field could increase roughly 10,000 barrels of oil per day, which is what we already achieved when the well pumps were working in the first 2 wells. In 2019, the Consortium will decide whether to move forward or not based on the data collected; to move forward with the full development system in Atlanta, which would bring the production capacity to a peak at 75,000 barrels of oil per day.

With regards to our exploratory asset, we continue to be quite enthusiastic about our position in the Sergipe-Alagoas Basin where QGEP holds a 30% interest in 6 adjacent blocks in partnership with ExxonMobil and Murphy Oil. As I mentioned earlier, we have already started the acquisition of 3D seismic data. Everything is going well. Interpretation of the data will take place throughout 2019, and drilling may be started by 2020. The prospects already identified in these areas are considered to be medium to low risk with potential for high volumes, due to their proximity to several discoveries performed by Petrobras in adjacent blocks. In fact, we expect the extended well test at the adjacent Farfan discovery to take place later this year, and we expect it to bring good news about the area. And once again, it contains one of the best oils in the country, approximately 30 degrees API in excellent reservoirs. In addition, we also made progress in the farm-out process that will launch early this year. Our main goal is to attract partners for our stake in the 2 Pará-Maranhão blocks in which we hold 100% interest. We are also awaiting the environmental license for the block located in Foz do Amazonas basin before proceeding with a farm-out process for that asset. And you're all very much aware of the debate about the drilling license in the area. In addition, we and our partners are evaluating the next steps with regards to our Ceará and Espírito Santo blocks in Santos Basin by Total and ExxonMobil, respectively. [indiscernible]

Please turn to Slide 10. As you can see, QGEP's portfolio is well diversified in terms of risks, and our assets are located in most of the main producing basins along the Brazilian coast. In addition to providing geographic diversification, this diversified portfolio generates a wide range of risk and return scenarios. We're closely monitoring discoveries by other operators in this basin, and I highlight again that despite the sale of block BM-S-8 where there was a discovery of a giant structure, which is Carcará, we are still interested in pre-salt reservoirs, always driven by our will to be involved in these leading processes.

Slide 11 summarizes our key messages and our competitive edge, boosted by our achievements in the first half of this year and by our strategic positioning heading for future planning and results. I highlight that we are very pleased with our strong year-to-date financial results. And as for our operating results after August 1, we reached a milestone of 1 million barrels produced at Atlanta Field, which is certainly something to be celebrated, and which will be an important growth lever to this company in the short and mid-run. In addition, the sale of our 10% interest of BM-S-8 where Carcará discovery is located, which we announced just 1 year ago, was a major inflection point for QGEP, represented a positive return on investment, significant cash inflow and a substantial reduction in our future capital commitment. This has enabled us to develop a capital allocation plan, which covers key priorities, namely maintain financial flexibility to fund existing projects without leverage needs; retain the capacity to acquire assets that deliver growth in line with a compatible risk profile already set by the company, with a potential participation in pre-salt bidding processes; and therefore, continue to reward shareholders through regular dividend payouts.

As we know, we performed a special dividend payout of BRL 1.54 per share earlier this year, and we will continue to assess such opportunities, in keeping with the capital required to unlock the value of our current asset base and the opportunities we see on the short-term horizon. It's always important to highlight the current more open scenario and the attraction of these players to Brazil. These have been instrumental aspects to optimize our portfolio as we recently saw in our participation in QGEP's bid and our expertise as an independent Brazilian company that knows the fundamentals of the E&P industry in Brazil, therefore, positioning us as a unique partner. We always consider our competitive edge in this regard. Our first half results have benefited from our strategic focus on diversification of revenue sources and QGEP is ready to report continuous growth in the following months. We are ready to continue posting progress in the second half of 2018.

Slide 12 summarizes very briefly our competitive edge. What makes QGEP stand out in Brazil's increasingly attractive oil and gas industry and highlights the efficiency of our operations and the ongoing optimization of our portfolio generating consistent, robust financial results in the short and mid-run. We always bear in mind that our activities, which also has a mid- to long-term unfolding as well.

I always like to send a message of optimism of whatever is happening now. We're also learning quite a lot with Atlanta operation and daily optimizing our logistics, optimizing cost for the benefit of the Consortium, our partners and investors. This is an increasing learning progress, and the outcome will be seen in production in this and in future views that we certainly will be participating in as an operator or partner. We firmly believe in the short-term future of our company.

This concludes our presentation. And now, I would like to open the call to questions.

[Operator]

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

[Luiz Carvalho, analyst]

Lincoln, Paula, Danilo, I have 2 questions. The first is about Sergipe-Alagoas. We saw with the players of the industry, regarding the wells of Petrobras that your blocks could -- that there's some kind of bidding process in the future when you start drilling those blocks. So I'd like to know 2 things: first, is there anything that we should expect from Sergipe-Alagoas? And secondly, would you be interested -- are you having any conversation to sell your stake at these blocks with a farm-out? And my second question is regarding Atlanta. Assuming the current productivity close to 13,000 and perhaps adding the third well, the question is, assuming this level of productivity, would you look forward with the full development project? And the third question regarding the oil differential.

We see a smaller spread considering heavier oil and the Brent crude oil. So I would like to know what is your discount for your oil compared to the Brent crude oil benchmark?

[Lincoln Rumenos Guardado, executive]

Luiz, thank you for the question. As always, you are very knowledgeable, and we expect to answer your question. Well, it's not very simple but don't have any negotiation with Petrobras. What we know is that Petrobras should do the EWT at Farfan, and with all of the 3D seismic data that we have in that area and in neighboring areas, that referenced our evaluation. So with all that, there might be some continuity of Petrobras discoveries for those areas where we are. So that is possible. Farfan is one of them, but it's still based on 2D seismic data. So we know well these reservoirs. Normally, the deposit has stacking. So there is a possibility, at least considering our 2D seismic data, that we can perhaps -- we have to prove them with 3D seismic shooting. So there might be a continuity stretching to our areas, and it is for this reason that the Consortium with ExxonMobil and others makes sense these areas that are with Petrobras, because that's the way we can have the best correlation that we see for these blocks. So there is a unitization possibility, but there's nothing ongoing at this point. There's no reason for that because we haven't got full knowledge yet. We'll only get that, that knowledge with 3D and then we drill a well only when we have 3D seismic data. But we feel confident that part of these discoveries, that the trend of these discoveries will stretch to our areas. And a well, we'll have to confirm that. It's a bit too early, but yes, there is a chance that this will happen. Undoubtedly.

The Petrobras farm-out, that's your second question. It's important, but we find it a little difficult to participate isolatedly. If in the future, given some discovery in our block, and if -- once Petrobras has started the farm-out and it's in excess to approach Petrobras, QGEP would be good. For sure. But it's not something that decision that QGEP can make on our own because the Petrobras project involves a large volume of oil already discovered. And we imagine that this is a deep pocket for Petrobras to do it alone. But in the future and if we have a discovery in our block, something that could be enabled, could be approached by Petrobras if they are not able to pursue this earlier. I think this is an area that is triggering or sparking a lot of interest. Given the consensus at the Aracaju port, there is a demand for gas. Most likely, there will be a demand for oil as well. So we see only growing economic interest in the Sergipe-Alagoas area.

[Luiz Carvalho, analyst]

If I might ask a follow-up question regarding that area. I don't remember having seen public data regarding volume. Do you have any idea of what we could expect in terms of volume for that accumulation, not specifically about your block, but about Petrobras block as well? Do you have any idea, just in order of magnitude?

[Lincoln Rumenos Guardado, executive]

No. No. We hear rumors, but it's nothing official. It could be 1.5 billion barrels of oil of volume recoverable, but this is just market rumors. Petrobras has never confirmed that. What we know for a fact is that they have 6 discoveries with very high success rate. In terms of the publicly released information, it could be close to 80% of the wells that Petrobras drilled, wildcat wells and appraisal well. So that's the kind of data that we have. But that area indeed has a high visibility in terms of seismic data, et cetera, but we haven't got any official information that could underpin these volumes. Most likely, Petrobras, along with their farm-out process, could have informed the market because they're doing the farm-out, but they're maintaining the operation, which is a renewal of their belief in those areas. They're maintaining their operations in all of the blocks. To us, that gives us a little comfort that they probably want to accelerate things. Of course, I cannot speak on behalf of Petrobras, but the fact that Petrobras is maintaining the operation on, it means that they still have interest in that area.

Regarding productivity and its impact on full development of the wells, I will turn the floor to Danilo because he can give you more color on what we have already achieved and about our belief that this might become a special element for our decision.

[Danilo Oliveira, executive]

As Paula and Lincoln mentioned during the presentation, the Early Production System at Atlanta is behaving exactly as expected in terms of productivity. Both wells in the first days of operation produced way beyond what we had expected, over 10,000 barrels per day each. But considering the time that they had -- that they were waiting for a year for the pump to start operating, like I said, between the FPSO and the pump for electric connection that are [ subsea ]. And what deteriorates the functioning of the pump when we say that the life span is 12.5 years, it's not the pump itself -- the bottleneck is not the pump itself, but the transmission of electricity from the FPSO to the pump. We think this is an [ excessive ] time, so much so that these well pumps are 2, and we installed 4. And the fourth that we installed in the subsea are working perfectly -- in the seabed are working perfectly because each one of the pumping moves in the bottom of the sea have 2 pumps. So productivity is really good. We're monitoring the pressure of the reservoir with a pressure gauge at the level of the reservoir. We're making -- predict exactly the pressure that we had imagined. It shows exactly the pressure that we had predicted. And regarding the loss of charge that the well pump that is broken is impacting the reservoir, the pressure of the reservoir is about 240 kilos, just to give you an idea. And we are losing 35 to 45 kilos just to overcome these 100 meters of pump -- would it be 3,500 to 4,500 barrels of oil in each well. So 35,000 to 45,000 barrels more, but the productivity is okay. We are considering drilling the third well. We are seeing how to charge the rig, and we should close that contract and sign that contract by the end of the month.

We have evaluated the cost. We have made proposals for the partner to replace the pumps that are in operation -- [ inoperant ] in the well. And considering also the rig that is going to drill the third well, considering the cost of the rig, which is affordable in our estimate. And I -- just before this call, I learned that the partner is also approving these workovers. With that, we should bring it back to our estimate to 27,000 barrels per day. We should reach that production in the second quarter of 2019. So the plan is to drill the third well, put the third well into production, stop one of the wells, do the workover -- about 45 days to do the workover and to replace the pump, put the first well that we did the workover on into production, stop the second well, do the workover and the same process and having all 3 working well.

So we have to tell you that we're totally happy with the engineering of the Early Production System project. To give you an idea, the temperature at the reservoir is 41 degrees. Very, very low. That was the concern that we always had because the oil freezes at the temperature in the bottom of the sea. So we had flow lines that were special with thermal lines of insulation. So we are leaving the reservoir with 41 degrees, and we can bring the oil to the FPSO at 40 degrees. So it's a very, very good result. Also, what we do to preserve the flow lines to avoid freezing even if there's a long-lasting downtime. In May, we had 13 stoppages at the FPSO. In June, 10 stoppages. In July, 5 stoppages. And in all of them, we applied exactly the methodology of conservation replacing by diesel oil, replacing -- or filling the flow lines with diesel oil, which gives us the proof that our system is robust, and that it can guarantee production. So we are already looking into the full development system so that we can make the necessary changes along 2019. We feel confident about the Atlanta. And regarding the oil sold, a confidentiality release and so we cannot disclose the value. But what I can tell you is that the discount compared to Brent crude oil is compatible with any oil with this API, 14 degrees API. It is compatible, and according to our discount estimate, for confidentiality reasons, we cannot disclose this because we have a number of offtake offers in several places, and we are not authorized to disclose this number. But I can assure you, it is within -- it is in compliance with our estimates that we have informed the market.

[Luiz Carvalho, analyst]

Just one follow-up to the second question. So assuming the data that you currently have, would you move forward with a full development system? Is that a fair statement?

[Lincoln Rumenos Guardado, executive]

Yes, it is. The oil price is very stable. The forecast, very close to this price of $70 a barrel. It makes a full development system feasible, and we are preparing the whole process to submit this to the partners in mid-2019. We are just waiting to -- for the consolidation of the EPS. And then we'll submit for partners' approval.

[Operator]

Our next question is from Gustavo Allevato, Santander Bank.

[Gustavo Allevato, analyst]

When it comes to Atlanta production, I have a question. What would make you stop production? What is the level that would make you stop activities in the region, and what about starting the drilling of the third well? Is it only a problem with a pump? Or any other problems related to the EPS?

[Lincoln Rumenos Guardado, executive]

Gustavo, we apologize, but the connection is not good. We couldn't hear you well. I'll try to repeat what we managed to understand. So you want to know the level of production that is needed to stop production of a well or the field. This is not clear to us. Secondly, you want us to confirm what caused the change from 16,000, approximately 10% to the current 13%, and if this was caused specifically by the pump. So I ask you, if these are really your questions?

[Gustavo Allevato, analyst]

You're right. These are my questions.

[Lincoln Rumenos Guardado, executive]

Naturally, or I confirm, what is the meaning of the EPS. The Early Production System is a project. It is not really a pilot project because it already entails investment, production of 3 wells. But the purpose is to gather data. The main role is to bring this data so that later on, we can work on our forecast of the full development system where we have an upfront -- a higher upfront of CapEx. So the EPS should meet this need. Now we went beyond that. We try not only to make investments to gather data, but also wanted to have some kind of return, and that's why we thought about a system to 3 wells so we could have at least, to say the least, the operational cost or the operating cost matched. Today, we know that even with 2 wells, our cost is lower than the operating revenue. And with a third well, it could get even higher. So theoretically speaking, one well could not continue to produce if production would not even pay the operating cost. So we're very far from this scenario. We are very far from this scenario. Our current production is already reasonable stable, and this production provides an operating return that is above the cost. Unless we have a mechanical -- a very serious mechanical problem in the EPS, unless we had something unexpected, water production, for instance, is something irrelevant today. This is not the oil-water contact, but water that pushes the oil. So unexpected water production would undoubtedly lead us to shut down the well, not because we cannot have the oil and water being produced, but it's just that the plant cannot treat the water for disposal purposes. And that's why we design this EPS to keep on producing up to 3 or 3.5 years, which would be the most proper number today. This is when we expect to see water production. And then this is a well that will be closed -- remain closed, just awaiting for the full development system, which has an expected production and water treatment. So this is the condition, and it's an extreme condition. I can tell you it's an extreme condition. Now with regards to production, it's right. We started delivering well. These 2 pumps started well, like Danilo already explained, and plenty of conditions to go even deeper if you need more information.

So our forecast was based precisely on this ramp-up performance. We have a ramp-up. Today -- well, not anymore, but at that time, we had ramp-up production, and everything was doing well until we had problems in the pump. So we maintain our early production, which was beginning to be delivered and was just awaited for the new announcements. And that's when we managed to come to a number adequate to disclose to you. It is our responsibility to disclose these facts to you. But just as we changed to 13,000, I underscore again, that this is owing to the pump. This is related to the pump. The well pump, because those on the feedback are working within our expectations. A natural load for the seabed and the pump that is close to the reservoir. So this is what led to this factor and luckily, to all of us, it was not the arrival of water but just up to now, so far, everything is within our mathematical model, which was even based on tests that we have performed when we drilled the well. So we do have some confidence to support this with a drill stem test. And when we had this [ fader ] in the pump, it was still within our expectation.

Now with the third well and the well pump, it shows to us this trust and confidence we've had on the data that we collected from this reservoir. So we do expect to go back to the initial 10,000. And like Danilo said, we just heard today we have the confirmation with our partner that we have the approval for workovers in both wells. And with the removal of the pump, we'll be able to precisely find out what happened to the pump, if it's a mechanical fault or -- Danilo said, it's only normal to have this. I mean, sometimes, you can also have electricity problems with seawater. It is not a perfect match. And we also have a history of these pumps in Campos Basin, more than 100 installed and usually problems are related to connection. So like we said before, we expect to invest. We don't know precisely what the amount will be. This is very recent, but we already considering recover our production in these 2 wells and also drill the third well.

[Gustavo Allevato, analyst]

Okay, Lincoln. Just a follow-up question. Could you tell us more about the production level in July? It would be really helpful to have this kind of information to our projection.

[Lincoln Rumenos Guardado, executive]

The connection is too bad, but you wanted to know the production level in July. Is that okay? Our production in July, was that your question?

[Gustavo Allevato, analyst]

Yes.

[Lincoln Rumenos Guardado, executive]

The average was 13,000, 13,400, 13,500. Sometimes, we had a stoppage. Sometimes, in the FPSO, because it is still in the stabilization phase. We even have an operational level above 95% in the FPSO, but it's improving day by day. So when that happens, sometimes we can stop for 1 hour or 2, and the average goes down. But we even had 13,400 or 13,500, so on average in July, 13,000. This is what we're disclosing to you.

[Operator]

Next question was sent via webcast by Mr. [ Sergio Simon ]. The question is, according to messages from the management, QGEP intends to have dividend payout. So as a shareholder, my question is, do you know when this dividend payout will take place? For investors planning, it is important that we know if you intend to do -- to have dividend payout in 2019, as you had in 2018. Please elaborate.

[Lincoln Rumenos Guardado, executive]

Thank you for your question. Regarding the use of our cash, this is an ongoing discussion at the level of the management of the company involving the management, the Board of Directors because this involves a long-term planning for the company. At this moment, we haven't got any amounts, deadlines, or dates, or even a definition whether we are going to be distributing a special dividend. What we currently have in our policy is $0.15 per share. This is something that we can predict, and it is something that we have been doing over the past 2 years, $0.15 per share. And as for a special dividend payout, they will happen as we identify a surplus of cash vis-à-vis the planning for the company. You still have options for cash allocation that we are studying. We don't want to negatively impact the growth of the company or the fundability of the company. It's just because we distribute dividends in the short term. We need to grow the company. So we are studying options. If in the future, we identify a surplus cash, then yes, for sure, we would be remunerating our shareholders. As to the rationale of the management of the company, this is how we've been proceeding in recent years and it is how we intend to continue. But the main, the core focus of the company is to grow the business. But whenever we identify a surplus cash, we will consider remunerating our shareholders' liquidity to our shareholders, which will improve their profitability.

[Operator]

Next question was also sent via webcast by Mr. [ Claudio Miller ]. Number one, when will you be replacing Atlanta's pump? And how long do you estimate the system will be down? Second, is there any strategy to reduce the discount vis-à-vis the plant? And what is the penalty if you break the contract with Shell? Do you -- are you planning any larger FPSO? What about Petrojarl with the EPS? Or did you operate just confirm a well in [ ANS ] and CLM-372 (sic) [ CAL-M-372 ]? And finally, what about -- how will you continue to make decisions about Atlanta?

[Lincoln Rumenos Guardado, executive]

All right. Let's try to answer these questions in order. When will we replace the pumps at Atlanta? As I mentioned, as soon as we drill the third well, which is scheduled to begin in the first quarter of 2019. So the replacement of the pumps would be happening in the second quarter of 2019. Estimated time -- estimated downtime is 45 days for every replacement. As for the strategy to reduce the viscosity with the [ brand ], that's very hard because that depends on the world market. Oil are marked in terms of discount to the Brent depending on their weight; density, which is degrees API; and based on their qualities or defects in their composition, if they have CO2, if they have sulfur. So as Atlanta is a new oil, it starts with the degree API discount, 14 degrees API. And that discount will increase or be reduced according to what each refinery will use, or according to what the refineries will do with that oil. And that's why we don't disclose the discount because every refinery will do their distillation and see what their margin of profit is. Penalty, if we breach the contract with Shell, if we entered the contract with Shell, well, this is a contract involving the 3 partners. It's a joint uptake with Shell. And the penalty if we breach the contract is not confidential, of course, but yes, there is a fine in case of termination of the contract. Just like if they terminate the contract, they'll have to pay a penalty as well. But we are not envisioning any problems because Shell is one of the mainstream players worldwide. So at the moment, we are very happy with their operation. As for the full development at Atlanta, no. We haven't got any FPSO in mind. The process should be similar to the Early Production System. We should issue a specification, open a bidding process with the -- our suppliers and based on the bidding, we're probably going to have 24 to 30 months to build or to adopt an FPSO.

As for Petrojarl, we have a contract. When we charge Petrojarl, we knew that the production time frame would be 3 years. We signed a contract for 5 years. In other words, it can be extended. If there's a delay in the full development system, it can be extended up to 5 years. Petrojarl is fine. The contract with Petrojarl is fine. There are no surprises there.

And what else -- what the question was? If the operators confirm for 2019, a well in Espírito Santo 596 and CAL-M-372.

For the Camamu-Almada, [ Ebony ] is waiting for an environmental license. The block is stopped at the moment. The concession clock has stopped. So far, the Consortium is assessing the best alternative as soon as we get environmental license. We have a commitment to drill this block 372, but we have to run assessments as soon as we have the environmental license.

As for Espírito Santo, we have the possibility of entering a phase of extinction. Our time frame of exploratory interest, we happen to find anything regarding the drilling of Espírito Santo block. Sergipe-Alagoas, as mentioned, the expectation of the partners is to start drilling by 2020. All partners are very optimistic, and we are starting 3D seismic data and expect it to start the drilling campaign in the Sergipe-Alagoas by 2020. And I could add to what Mendes said that for CAL-M-372, we have a budget for 2019 for this. We maintain this provision, but we have to consider what Mendes said.

There are some decisions to be made by the operator. But this is in our CapEx, I think, $16 million, not for Espírito Santo because this decision is not up to us, as mentioned.

[Operator]

Our next question is also from the webcast. [ Calvin Homani, Omega ].

First question. What is the estimate for the execution of the production individualization agreement for payment of 38% of MBS 8 (sic) [ BM-S-8 ] sale, the remaining part? Second question. In the release of the first quarter, you said the cash position would be further strengthened with the receival of 70 million (sic) [ 70% ] portion related to farm-out agreement in Sergipe-Alagoas blocks [ phasing ], but these amounts have not come in yet. When are they expected to come?

[Paula da Costa Corte-Real, executive]

Paula speaking. As in your question about unitization or individualization of BM-S-8. Because we have very similar consortiums within BM-S-8 and the extension of Carcará discovery, which is outside BM-S-8, it does make the process much easier. Our internal expectation, and it's just an expectation, it is not yet part of that negotiation of the individualization agreement. This portion might come around 2020. In a couple of years, 2.5 years precisely, that's our expectation to receive the last portion. As for the 17 million (sic) [ 70% ] farm-out in Sergipe-Alagoas, they were fully received.

[Operator]

The next question, also via webcast, is from [ Claudio Miller ]. If Dommo still making decisions in Atlanta.

[Lincoln Rumenos Guardado, executive]

Thank you. The answer is no. The documents we have and which rule governance of the consortium. The joint operation agreement does not allow companies in default to be involved in decisions. They haven't involved payments for a while. So the operator's decision and the decisions made by the consortium don't have involvement of Dommo why they are in this status that they currently are in terms of the block and the default.

[Operator]

[Operator Instructions] We are now closing the Q&A session. I would like to turn the floor back to Mr. Lincoln Rumenos Guardado for his final statement. Go ahead, sir.

[Lincoln Rumenos Guardado, executive]

Very well. I would like to thank all of you for joining us on this call, for the questions asked, and we hope that we have answered your question. With this change in the guidance for production, but also making it very clear to all of you that we have positive beliefs and expectations because of everything that we've had so far with Atlanta. Just like we expect the continuity of gas production at Manati at the levels disclosed to you, which undoubtedly, will bring us a lot of joy along 2018 and '19.

And I would like to end this presentation highlighting that as soon as we have more elements regarding the chartering of the rig, this process is progressing well in terms of selecting the rig that will drill the third well. And as soon as we have -- for this, we need to have the rig and the cost related to the drilling of the third well. That will be the reference for the workovers that we'll do in our wells, then we will be informing you in terms of the CapEx involved, et cetera.

I want to say that things are unfolding as expected, and for everything that we expected to do regarding wells, regarding drilling decisions, I want to reaffirm that had we doubted this production capacity with what we've got so far, we would not be making the decision to drill the third well because what we got was very relevant and led us to discuss a third well. And I would also like to clarify that part of the equipment has been commissioned for quite a while now. And we are now beginning the commissioning of the rest of the equipment that will support not only drilling, but also the completion of the third well. And that will be also supporting other actions involved in the workovers to replace the pumps. I expect that I will be able to bring you more novelties in the short term and to maintain you, above all, informed of what is going on. To us, transparency is very important. But we are convinced that the future of the company will continue to be bright, a future of growth and being active in the oil and gas industry in Brazil, and always bringing value to our shareholders.

I would like to stress that our Investor Relations department is always available to you for further clarification, as well as all of us in the management and all QGEP technicians. Thank you very much, and have a good day.

[Operator]

QGEP's conference call is concluded for today. Thank you very much for your participation. Have a good day.