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Good day, ladies and gentlemen. Thank you for waiting. At this time we would like to welcome everyone to QGEP's First Quarter 2018 Earnings Conference Call. Today, we have here with us Mr. Lincoln Rumenos Guardado, CEO of the company; Ms. Paula da Costa Corte-Real, CFO and IRO; 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 QGEP's business perspective, financial and operational projections and targets are based on the beliefs and assumptions of QGEP management and on information currently available for the company. Forward-looking statements are not a guarantee of performance. They involve risks, uncertainties and assumptions because they relate to future events, and therefore, depend on circumstances that may or may not occur in the future. Investors should understand that general economic conditions, industry conditions and other operating factors could also affect the future results of QGEP 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, QGEP's CEO, who will start the presentation. And Mr. Guardado, you may begin.
Ladies and gentlemen, please hold until we reconnect QGEP. Mr. Guardado, you may begin.
Very well. Good day, everyone. Thank you all for joining us today in a such special day for the company, with Atlanta Field's first oil. But we're here to review QGEP's first quarter 2018 performance, and to discuss our outlook for the year. Before I begin I would like to say that we are very pleased to be delivering effectively on a number of results that stemmed from the actions that we have been discussing with you during the last year. And we appreciate the support of our investors and analysts as we move ahead with our plans to continue to build value to our shareholders. Let us begin on Slide 2, please. Slide 2 contains what we consider to be the key strategic highlights of this year's first quarter. First and foremost, production at Manati Field increased compared to last year's first quarter. And our expectation for production level remains at 4.6 million cubic meters a day during the first half of 2018.
Secondly, we completed the preparation for first oil at the Atlanta Field, which actually occurred from one of the production wells just last week, more specifically, on May 2. This event led us to be very optimistic with our results and future vision, given that it occurred in a moment of strong recovery of the Brent oil price.
Thirdly, we considerably strengthened our position in the Sergipe-Alagoas Basin, which we consider to be of high exploratory potential, after winning 2 more blocks with our partners at the ANP 15th bidding round. We also distributed dividends as we recognize the importance to return capital to our shareholders. The [ difference ] drew an extraordinary special dividend that was paid in April to our shareholders. Last, but not least, net income in this quarter was outstanding, benefiting from a better operational result, coupled, obviously, with the second installment received from the sale of Block BM-S-8. With all of that as a backdrop for the quarter, which is exceptional in our view, I would like to turn the call over to our Chief Financial Officer, Paula Costa, for a review of our first quarter 2018 financial results. Paula, over to you.
Thank you, Lincoln, and thank you, all, for joining us today. We appreciate your participation in our quarterly conference call. First, I will cover our revenues and earnings highlights for the first quarter of 2018. Then I will give you some information on our balance sheet, cash flow and CapEx for the quarter. After which, I will turn the call back to Lincoln. Again, Lincoln himself mentioned that we had very positive comparisons in the first quarter. We have been able to continue our strong performance in terms of earnings growth, cash flow generation and overall financial strength. Our cash flow -- free cash flow allows us to maintain liquidity at a healthy level, while at the same time invest in critical initiatives and other capital allocation priorities, including a special dividend payout. Now turning to the results for the first quarter. Please go to Slide 3. During the quarter, our producing assets Manati Field averaged gas production of 4.6 million cubic meters per day, up 11% from first Q '17. Over the past 2 years, Manati production has been impacted both positively and negatively by weather conditions. For the current year, northeastern Brazil has been experiencing record rainfall so the result [indiscernible] flowed as hydroelectric power plant, once again kicked into action at full capacity. By contrast, the drought conditions experienced in the end of last year show increased utilization of thermoelectric plants powered by gas. Another production highlight is the fact that we now have 2 producing assets, Manati and Atlanta Field, which flowed first oil last week, as Lincoln mentioned. On Slide 4, please, we highlight that our revenue in the quarter was up 12% reflecting higher production in the annual comparison. Revenue increased at a faster pace than production growth, largely due to the small share of condensate that we sold at a higher price compared to Brent oil price. Moving on to costs on Slide 5. During the quarter, total operating costs were 16% lower year-over-year. And as a percentage of revenue, these costs were 13 percentage points lower than first Q '17. This good performance in the quarter, primarily reflects the reduction of maintenance cost this year compared to first Q '17 when we had BRL 11 million of expenditures related to maintenance rig on the Manati platform. This was partially offset by higher depreciation and amortization expenses and royalties, reflecting higher production. Now moving on to Slide 6, where we talk about operating expenses. During the quarter, G&A expenses were 8% higher year-over-year, primarily due to personal expense, including provision for employee profit sharing benefits, reflecting the [indiscernible] of assets and also expenses with the stock option plan. We will limit expenses through our expense management, and G&A as a percentage of revenue was 11%, 20 basis points lower than the same period of the prior year, despite the additional values that I have just mentioned. As for exploratory expenses, we do continue to add to our asset portfolio. Exploration costs were also increasing. During the quarter, these costs totaled BRL 14.9 million or 146% year-over-year. This reflects our acquisition and processing of seismic data, mainly for Sergipe-Alagoas blocks and meta-oceanographic studies for PAMA and FOZ blocks. Let's now talk about our profitability, on Slide 7. Our EBITDAX results benefited from both operating improvements, higher production and better expense leverage and financial gain, and the sale of Block BM-S-8, as the receipt of the second installment was accounted for in the period, equal to BRL 148 million. Net of this gain, EBITDAX would be BRL 59.2 million, up 28% from BRL 46 million posted in the first quarter '17. Adjusted EBITDAX margin in first Q '18 was 50%, more than 600 basis points better than the same period of the prior year. This good performance, obviously, flowed to the bottom line. We generated net income of BRL 159 million in the quarter compared to BRL 43 million in the same period of the prior year, stemming from higher revenues in the current quarter, the proceeds from the asset sale of BM-S-8 that I already mentioned and higher financial income. Excluding the gain from the sale of assets, net income would be BRL 62 million, 45% up compared to first quarter '17. This concludes my comments about our first quarter sales and earnings performance. Now let me make just a few comments about our balance sheet and cash flow for the first quarter of fiscal 2018 -- fiscal year 2018 before I discuss CapEx. Our balance sheet at the end of the first quarter was in excellent shape. Our cash level is high. Our accounts receivables was down, have very little bank debt and other borrowings and our capital base is strong and growing. Overall, our balance sheet and financial spend are strong, which gives us a solid foundation for future growth. Cash flow was up significantly to BRL 172 million compared to BRL 36.5 million in the first quarter last year. As always, we will continuously evaluate all options to determine the best usage of our excess cash and which options will provide the greatest impact in terms of creating value to our shareholders. Moving on to Slide 8 now. Capital expenditures. In the quarter, CapEx totaled $20 million with the majority, or $19 million invested in the Atlanta Field. On the slide, you can also see the breakdown of our capital expenditures for 2018 and '19. For the current year, we are budgeting capital expenditures of $70 million, focused on accelerating development at Atlanta, which will account for most of our spending, targeted at $48 million. All that including the potential drilling of the third well. The remaining funds are earmarked the first quarter for activities as well as for acquisition of seismic data. The expenditure for seismic acquisition this year is estimated at $5 million, already net of the amount but it will be reimbursed to spread our future Sergipe-Alagoas Basin and that agreement. Historically, we have been funding our CapEx requirements with internally generated funds. This has now been significantly augmented with funds received from the sale of Block BM-S-8 and the farm-out agreement. As always, we will remain disciplined in our use of capital while continuing to invest for growth.
In summary, we are very pleased with our first quarter results as we continue to successfully execute against our strategic planning, which is enhancing our financial position. The financial success of this quarter is just part of our story. We feel confident about the positioning of the business and about our ability to continue to execute against our strategic growth initiatives in 2018 and beyond. And to continue to deliver strong financial results. I will now turn the call back to Lincoln for his closing comments. After which, we will open the call for questions.
Thank you, Paula. Please turn now to Slide #9. The first quarter average daily production of natural gas at the Manati Field was 4.6 million cubic meters, and around 10% higher than the same period last year. As we mentioned on our last call, less than 2 months ago, rainfall in northeastern Brazil lead to an increase in the capacity to generate hydroelectric power with a consequent reduction in the demand for gas. With that, we maintain our forecast of 4.6 million cubic meters of gas production for the first half of 2018, at a similar level for the first quarter. Therefore, this allow us to maintain our production guidance for full year 2018 of 5.1 million cubic meters as we continue to assess both weather conditions as well as industrial demand factors to determine whether to change that estimate. We have to mention how happy we are to report early production of our second producing asset, the Atlanta Field in BS-4 block. Like we said, it has a lot of technical challenges. This milestone took place on last May 2, after obtaining all the necessary approvals to start production. The first well is still in the stabilization phase, just as the plant, reaching daily production of approximately 7,200 barrels of oil with a slight variation reaching 8,000 barrels of oil. The potential support [ center ] like 8,000 barrels of production per day. Despite this outstanding initial performance in our assessment during this stabilization process of the plant, we faced operational problems. When the pump -- the well pump shut down, we opted for the pump in the seabed, which is further away from the reservoir, but leading to a slightly lower performance in the same field compared to what was scheduled inside the well. As a result, we expect daily production from the field to stabilize between 10% to 20% below our original expectation of 20,000 barrels of oil from the 2 wells. Later in the second quarter, a second well is expected to be connected and be in production soon. We have gained excellent experience in working in this very technically challenging area. The reservoir is responding in accordance with our expectations. So the longer-term outlook is very good to us, based on the data so far. As you know, our cash flow will benefit from lower daily rates for the next 18 months thanks to our agreement with the FPSO's operator. In addition, our oil sale to Shell will be potentially favored from better pricing for our heavy oil and due to market shortages, as well as the Brent oil increases, a recent phenomenon, and apparently they have a midterm impact. Later this year, we, meaning the consortium, will decide whether to drill a third well as part of the early production system. For this project, drilling would take place in early 2019. Also, as you know, the big decision to be made is whether to move to a full development system, which would involve drilling 9 additional wells to begin in 2020. We have already set aside $14 million in our 2018 CapEx budget for this eventuality, as Paula mentioned before in her presentation. Now to an update on exploration. It's very much related to the auctions contested by the Brazilian government, which provide QGEP with important organic growth potential. In this year's first quarter, we participated in ANP's 15th Bidding Round, acquired another 2 blocks in the Sergipe-Alagoas Basin adjacent to the 4 blocks that we already own, paying the minimum signature bonus. In this most recent Bidding Round, we were joined by our existing partners, ExxonMobil and Murphy Oil, and each have maintained the same working interest percentage in all of the blocks, namely ExxonMobil, the operator, has 50%, QGEP has 30% and Murphy Oil has 20%. We believe that this is a medium- to low-risk exploratory area that justifies the concentration of our interests. In fact, Petrobras is scheduled to an extended well pass at their adjacent Farfan discovery later this year, and it is at the border of the blocks we acquired. Even more important is the relationship we're building with our 2 partners, and the potential for us to work together in the future on other exploration projects in Brazil. The acquisition of seismic data for all 6 blocks in Sergipe-Alagoas basin is expected to start by the end of May. And once the data is fully analyzed, we would expect the road map for a drilling program to be completed by the end of 2019 for seismic data acquisition with drilling to commence in 2020. We have begun the initial phase of a farm-out process for our 100% owned Pará-Maranhão and Foz do Amazonas blocks and that we acquired in the 11th Bidding Round. We hope to have more information on the level of interest in the coming months. In Ceará and Espírito Santo basins, we are still working with our partners, Total and Statoil, to determine the next step in these 2 very important basins.
Please move to Slide 10. As you can see, QGEP's portfolio is well diversified in terms of risk and our assets are located in most of the main producing basins along the Brazilian coast. Naturally, with different risk and [ premium ] scenarios, both in the short-, mid- and long-term basis. It is important for a company to benefit from discovery in the future by other operators in the same basins. Slide 11 brings our take home messages. Firstly, we are pleased with our ability to deliver what we have discussed with you over the last several quarters, and we are very keen in our efforts for the last 5 years. As you can see, our financial results and financial position continue to benefit from the sale of our interest in Block BM-S-8 to Statoil, naturally Carcará discovery. The second installment payment was received in this year's first quarter and the third payment accounted for 38% of the purchase price, totaling $879 million is due to us upon the signing of the production individualization agreement expected to happen in 2019. In addition to bringing in cash resources, our strategic decision to sell this stake significantly reduced our medium-term capital expenditures, freeing up resources to invest in Sergipe-Alagoas, and also giving us the ability to return capital to shareholders as special dividends. This dividend equivalent to around BRL 1.54 per share was already paid in April of the current year, and the market has clearly appreciated this initiative by the company. As to new auctions, we have already applied for the full ANP Bidding Round, which will be in the production sharing agreement model as scheduled to take place on June 7. Should we participate, we would have partners and a minority interest given the capital required for signature bonus payments and the future CapEx requirements for exploration and development of our production. Also, we continue to evaluate farm-in and potential asset purchases. Based on the outcome of these developments, we will consider a further return of capital to shareholders, as I mentioned before through an additional special dividend, as long as it does not impair our ability to invest for future growth. Undoubtedly, this is very much related to any decisions we will make in the auctions that we mentioned before. To close, Slide 12 underscores our investment strength, namely the efficiency of our operations and the ongoing optimization of our portfolio, which has led to very positive results, our financial strength and flexibility supported by robust first quarter results and our in-house technical expertise, which makes us a preferential partner in Brazil. That being said, I close my remarks. And I would now like to open the call for questions.
[Operator Instructions] Our first question comes from Andre Hachem with Itaú.
I have some doubts related to Atlanta Field. The first, could you give us more detail regarding the reduction in gas production? And is it because of the quality of the oil is a little [ harder ] than you expected maybe? And the second question is to what extent was this impacted the visibility of the third well? Because economic visibility apparently has dropped even though you reduced the production. Finally, I would like to understand, how this will impact your decision to implement full development.
Thank you, Andre. I will turn the floor to Danilo. Indeed, we need to explain this. It's not really linked to what you said, and Danilo will answer.
Good day, Andre. Let me see if I understood your question, you are making reference to the productivity of the first well. Okay. Productivity resulted from something already expected, i.e. the non-utilization of the pump well -- of the well pump, actually. This was an assumption. We knew that the pump could fail. That's why we used the well pump, then used the pump in the seabed. It is a little further from the reservoir so we cannot expect the same production as we would have if we were using the well pump. We are producing 7,500 -- 7,800 barrels a day, but this was expected. During the testing, the pump -- the well pump worked perfectly, but there were some signs of an electric problem. It confirmed the productivity of the reservoir as we had estimated, 10,000 barrels a day. But unfortunately, the electric signal dropped to the pump, and we had to use the surface pump. So this productivity was totally expected. And in keeping with the conditions that we planned for this backup pump. Now this does not, and I underscore, does not change the perspective of a third well. On the contrary, it actually encourages the drilling and production of a third well, aiming to increase production and reduce our fixed costs. So there's nothing wrong. And there is nothing going against what we had forecast. Everything is unfolding exactly as planned. Next week, we should connect the second well. The assumption is that the well pump will not work, so we don't want to have any false expectation. And that's why we're signaling a reduction of 10% to 20% -- production 10% to 20% below the initial expectation. And you asked about the full development system. No, that does not change. The early production system targets collecting data, so that we can fine tune the full development system. To date, everything is unfolding as expected, actually, even better, given the oil price. So we will continue our studies. We will continue to capture all necessary information about the production from this well, or maybe the 2 or 3 wells so that we can define the full development system.
Our next question comes from Gustavo Allevato with Santander.
I have a couple of questions. One is related to the decision to drill the third well at Atlanta. What would be the capital list that you would be looking at to decide to drill or not the third well? The second question has to do with capital allocation. Lincoln mentioned in the introduction to the presentation that the company could be considering new assets. Would you focus on producing assets? Or exploratory assets? If you could give us some color on that, I would appreciate it. And finally, I would just like to understand the demand for gas at Manati. You mentioned that hydroelectric power kicked in, in full capacity. So I'd like to know about April and May. Did they remain at the same level as in the first quarter? Did it improve? Did it get worse? Could you elaborate more, please?
Gustavo, thank you for the questions. Regarding the third well, we have our plant that has the ability to process 30,000 barrels. We designed the possibility of a third well. And undoubtedly, one of the drivers that could inhibit the drilling would be a very low Brent oil price, which is not what we're seeing currently. So we have all of the incentive in place to drill the third well and to bring production to as expected. And that would push our revenue. Because the third well will not bring more or higher operating cost to us because they are very well controlled. So that is the driver. The higher the oil price, the greater the drivers to drill the third well. Now what we do want is to have a track record of the initial 2 wells. We want to stabilize the plant. Because this is the process. It's a process plant. It doesn't happen overnight. And with all of that information available, the results of these 2 initial wells, we would plan the third well, which has all of the equipment purchased and procured for it. So that will definitely drive our revenue. It will increment production by 1/3. And without a corresponding cost increase in principle. And yes, we continue to look at possible acquisitions. This is more geared to mature exploration assets or perhaps assets with initial production. The bottom line in terms of a possible acquisition is 5. And possibly there are a number of assets out there in the market. You see Petrobras divesting, some other companies as well. Well, we've had so far a limit. All of the assets do not interest us vis-a-vis the possible increment vis-a-vis the size of the company. For example, [ Para ] . [ Para ] doesn't really -- not part of our DNA. It would bring incremental cost. So what we are interested in production. And the other things that are being operated are too big for our company, and also linked to production. But we will look into anything that is compatible so that we can have a stable production curve forecast, until we stabilize Atlanta, for example. Or until we have another discovery. This is our plan. For that, we have to have a stake, which is compatible to our size or a production, which is compatible to our size. What we see in the market is too big. One example is Marlim, which is very talked about, and the other areas where there was no possibility for our company to volunteer to acquire that. However, we continue to keep our eyes and ears open. And our preference is to acquire something in development or already in production, preferably in development. Because that would give us a little more elasticity to the first capital. And as for Manati, I will turn the floor to Danilo, and he will tell you a little bit about what's happening there and what we can expect looking forward.
Well, Gustavo, Manati. The first quarter we had an average daily production of 4.6 million cubic meters. April continued at the same level, 4.6 million cubic meters. But now in May, there was an increment. And in the last 3 days, production has hit the mark of 5 million -- higher than 5 million cubic meters. We don't know how long this high demand will last. And that's why we didn't make any changes to our guidance for the full year. So we'll still wait and see how the second quarter will behave. But the fact is, in May, there was increased demand. Now we are producing more than 5 million cubic meters a day.
If I may ask a follow-up question on Atlanta. The first offtake is expected when exactly? And what was the discount based on the current price of oil? What is the discount that you expect given the quality of the oil?
Gustavo, the first offload -- well, the FPSO has a storage capability of 180,000 barrels a day. And we intend to have the first offload not with this total. Although the vessel is there next to the FPSO and waiting. But I'd like to remind you, the offload considers a number of oil transfers. So the ship, the vessel, should stay there until the end of the month to receive all of the monthly production load, and we would consider that the first offload. So the first offload -- or the first shipment will have a number of offloads. And the first is expected for the end of next week. And as for the discount, we continue to maintain our estimate of 13 to 15 in the long run. This first offtake, we expect a higher discount because the oil came out a little bit degraded because of some fluids in the lines and in the well. And this is the first load -- this is the first offtake. And it came in with a little unknown element, but we had a number of offerings from refineries. And but we're maintaining our average discount of $13 to $15 per barrel.
Next question, Luiz Carvalho with UBS.
Lincoln, Paula, Danilo, 2 questions. Lincoln, coming back to that point about allocation of capital, just doing quick math, cash generation at Manati for the current year and Atlanta assuming oil close to 70 or 75, can we have an EBITDA of almost 300 this year or even more depending on the production level stabilized or oil pricing discounts, et cetera? Added to your current cash position of almost BRL 2 billion, BRL 1.9 billion, you are at a very comfortable cash position. I know you are considering investment moving forward. You mentioned a couple of potential acquisitions. So what about not only allocation of capital in assets, but like you said, dividend payout, maybe not extraordinary dividend payout, but something more recurrent down the road. This is my first question. Second question may be addressed to Danilo. Danilo, if I understood you correctly, you have an electrical connection problem with the pump in the seabed. You have a problem in the well pump, and then you're using the seabed. So would you think that maybe in the future going back to a production level close to the initial guidance? Or in fact, the pump in the seabed will be the final decision and that's what we have to focus on for the next 3 wells? This is very much related to our expectations that we will be more conservative, and I would like to understand whether this is a final solution. Or if you try to do something about it when the second well comes in, if you're going to try to work on the first one, so you can have a regular production at a higher level in the future.
Luiz, thank you. Naturally, dividend is always an interesting item for everybody. The company likes to have dividend payout and we want to continue doing this. As to changing our future dividend level, with a new policy, naturally it will take further stabilization of the company. Related to our future CapEx. There are many things underway for the next couple of years, particularly, when it comes to Atlanta, which is a decision for the future full development and also exploration in [indiscernible], not to mention our cash flow. So any changes, I'm not saying they shouldn't come. They may come, but they should also stem from a stabilized cash flow and a more predictable cash flow, so we can come to a policy. I understand when you asked about a change in the level. It entails a policy and that's why we have one. But undoubtedly the company is doing everything it can to have a revenue which is compatible to an increased and more balanced dividend payout. But undoubtedly, we'll have to go through these 2 moments for the next 2 or 3 years. And we're going to make significant decisions about Atlanta and also Sergipe. We place our bets on Sergipe. It is a big project vis-à-vis the technical items, but we believe our partnerships are good enough to allow us to make short-term decisions. We have to be ready for short-term decisions. However, any company should also be careful and be attentive in terms of return to shareholders. But we had something that was special. When we should have a second one, considering our production and in the future we'll certainly work in this direction. But right now, we're not considering changing the level until we have a more predictable cash flow. Danilo is going to answer your question about the use of the pump in the third well.
Luiz, excellent question about the pump. There is no possibility of entering again in these wells, at least, before the third well is drilled. We've made a decision, we're going to have pump in the seabed to producing these 2 wells. And upon drilling of the third well and once it starts production then maybe we can assess the possibility of coming back to these wells. Or to fix the pump -- either to fix the pump or simply to remove the pump, the well pump. So we're still considering this. We haven't decided yet. We still need a technical financial assessment and approval by our partners, but we're not going to any repair or fix in these wells before the third well.
Can I just have a last follow-up question? By the way, thanking for including the press release the status of Dommo and how it has been unfolding. But I wonder if you could give us an update, if there is an update, about negotiations. What about arbitration? What can you disclose? Or maybe Dommo trying to tell sell its stake? Do you have any update on that?
I have Paula with me. She can give you further detail. But basically it is like this. We have Dommo's arbitration process, which is still underway. There is some unfolding as to the use of revenues -- Atlanta revenues. And this will be managed by the consortium, mainly by the operator. However, this process, like I said, is still ongoing. The thing is that Dommo's default is increasing, obviously, owing to investments made up to now. And we're still waiting for our actions to unfold in Paris.
Any update?
No. We don't have so much updates since the last call. This is very confidential. We did an arbitration process. We have some internal time lines and schedules, but no final deadline to close the process. We don't have an update, so to speak. What happened was what Lincoln just described. This is public knowledge, arbitration related to Dommo [indiscernible] . And we are awaiting an [ contribute ] with our input through the process in order to have a solution as soon as possible.
The next question comes from our web link. [Operator Instructions] The first question from the web comes from [ Bruno Braga, HAARP Energy ].
What are the technical challenges operated in Atlanta field? Does the field still have further challenges to be overcome? If so, how does the company plan to overcome them in the next stage?
Bruno, the technical challenges have been mentioned from the very beginning, rather the beginning of our project. And right now, once we are in production, this is when we assess how the challenges were tackled. The concepts, the solutions and confirmation of our simulations. Basically, our oil is extremely heavy, very viscous. If I'm not mistaken, it is the deepest field in the world with such viscosity level. So the bottom of the sea at 4 degrees Celsius, align with a precedented isolation, control umbilical, never manufactured by our supplier before. So everything was engineered. And during the pull in and production process, this is when we confirmed the solution that we adopted. So the challenges to have a heavy oil field in production, ultradeep water, temperature of 4 degrees Celsius, only 800 meters to drill a horizontal well with very much consolidated sands. So we overcame this challenge and the field is producing. This is the challenge. As for the future, in the long term -- because these challenges, we'll have to make sure this is part of the plan and also use it in the full development system. So the biggest challenge is over. And now we have to consider application in the future.
Our next question [indiscernible] Junior, shareholder.
Will you be paying any additional dividends this year? What is the production target of the company in the next 5 years?
This is Paula speaking. Regarding dividend payout for this year, the company is not committed to pay any amount in full this year. And as we disclosed, we have some important incidents happening in this first half-year, the 2 auctions. The first auction has taken place, and we have acquired to participate in the second auction. And depending on our capital allocation and on the opportunities, it is possible that we would have excess cash. But otherwise on this score, the company does not have any commitment regarding paying a certain amount or when. And as for the 5-year production target, I will turn the floor back to Lincoln.
Obviously, we have our target. Manati continues to produce reasonably well, 12,000 barrels of oil equivalent today. Manati has an expected life until 2025, '24. We expect to have Atlanta ramp up. Atlanta should be producing the next [ 3 ] years approximately 25,000 or 30,000 barrels. So our production curve will be adding about 8,000 to 10,000 barrels along the coming years because of Atlanta's contribution until we make a decision to go to full development and that's when we expect to have a peak production of 75,000 barrels a day, which should happen approximately by 2021. This is a slow process. We have to drill the wells, interconnect them to the production system, but producing these 12,000 equivalents barrels we could be, in the coming months, we could be adding another 5,000 barrels with the Atlanta production. And with the third well, we could be reaching between 8,000 and 9,000. This is more or less the landscape that we have that we are considering full production ramp-up. We could be reaching by 2020 approximately 20,000 barrels a day. The difference that exists and that is important to mention is that 12,000 BOE of gas is not the same thing financially than 12,000 barrels of oil, given that the Brent oil price now is 3x higher than -- 3x higher in terms of value for the oil barrel. So it is possible that we will be increasing our production by 60% or 70%, but our revenue should increase a lot more, given the value of [ Brent ] to oil is higher than the value of [ Brent ] to gas per barrel.
Next question comes from Eduardo [indiscernible] with [indiscernible].
Paula, the proceeds from the third installment of the sale of Carcará corresponds to $144 million, about BRL 0.5 billion should be received. Is it to be received in 2019? Or is there anything that this can be brought forward to the last quarter of 2018, relevant to impacting the results, since there are no more costs to be deducted? As you can observe in the second installment paid recently.
Eduardo, this is Paula speaking. Regarding the third installment, our expectation continues to be receiving it in 2019, more towards the end of the year. This is an installment that depends on the execution of the production individualization contract. We know that Statoil has been able to work on a very accelerated schedule in their activities of exploration in the area, but still we need to consider drilling of wells also in areas external to the concession area. Also there's a production sharing agreement. So our expectation is that this will come more towards the end of 2019. We don't have any expectation to receive this payment before scheduled.
[Operator Instructions] This concludes today's question-and-answer session. I would like to invite Mr. Lincoln Rumenos Guardado to proceed with his closing statement. Mr. Guardado, go ahead.
Very well. Again, one more time, I would like to thank all of you for joining us in this very important moment for the company, when we are delivering good results and we are taking one step forward. The company is moving to another level with the startup of production. Not always is the value of production that matters but getting it right, and delivering to our promise. As Danilo mentioned, we have to deal with a lot. A lot of challenges. And I think that we're going down a path of excellence. I would like to thank you for joining us. And I would like to highlight that given that we have a lot of novelties, Atlanta being one of them. So in our website, there is a video on Atlanta Field. Very nice video. Very instructive and very intuitive in terms of how production happens in ultradeep waters. And particularly on how production is taking place at Atlanta Field. That's very educational for all of us. I do encourage you to access our website and to watch this video. It has 8 to 10 minutes only -- 8 to 10 minutes long, and it's very instructive, explaining how production happens in ultradeep waters and how this technology is being put into action at Atlanta. Again, I would like to thank you for joining us. And we hope to continue with a pipeline of good news along 2018, bringing all our shareholders and stakeholders good news. Thank you very much.
That concludes QGEP's conference call for today. Thank you very much for your participation, and have a good day.