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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 Third Quarter 2018 Earnings Conference Call. Today, we have Mr. Lincoln Rumenos Guardado, CEO of the company; Ms. Paula Costa Corte-Real, Chief Financial Officer and Investor Relations Officer; and Mr. Danilo Oliveira, Production Director. We would like to inform you that this event is being recorded. [Operator Instructions] Before proceeding, let me mention that forward-looking statements might be made during this conference call. Relative to QGEP's business perspective, rejections and operating and financial goals are based on the beliefs and assumptions of QGEP 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 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 Guardado, QGEP's CEO, who will start the presentation. Mr. Guardado, you may begin.
Good day, everyone. Thank you all for joining us today to review our third quarter and year-to-date results and to discuss our latest developments and to review our expectations as we head into 2019. To start, I am pleased to report that we achieved very positive year-over-year comparisons in the third quarter. This positive result has positioned QGEP for a year of significant growth in 2018 and has set the stage for another year of growth for us in 2019. Our total production for the third quarter reached 1.7 million barrels of oil equivalent, significantly ahead of the second quarter's 1.4 million. This stems from an increase in the production at Manati Field. There was a sequential increase in Manati Field production and a full quarter's production at Atlanta Field. As a note, QGEP is the operator at Atlanta with still a 30% working interest. In September, we announced that we contracted Laguna Star drillship to drill the third well of Atlanta's Early Production System, EPS. And then, after this operation, we will proceed with workovers in the 2 wells already in production. We plan to replace submersible pumps located inside the wells that have malfunctioned but that worked well in the beginning and then started presenting problems. This should considerably increase the pump's production level as of the first quarter of next year. Once the elections are complete, likely by the end of the 2019 third quarter, we expect the Atlanta EPS production to range from 25,000 to 27,000 barrels of oil per day. With the start of production at Atlanta Field, the company's market risk management policy was revised to incorporate in addition to the foreign exchange risk already monitored, that has been monitored for a while, the oil price risk and the interaction between these 2 components. The company is constantly evaluating the possibility of hedging future oil production and in this period has acquired a put option for part of its oil production. Paula will go over the details on this operation shortly. After recent ruling by the London Court of International Arbitration in the Dommo case, this was a ruling in our favor, and we expect to increase our Atlanta ownership position to 50% as soon as the procedures of the relevant Brazilian operations are finalized. It is important to remind you that we have managed the whole revenue coming from oil production for the 40% that will be theoretically Dommo's, but that is now being managed by the operator. And in terms of exploration activities, seismic shooting has been completed at our key prospects, the 6 contiguous blocks that we own in the Sergipe-Alagoas Basin in partnership with ExxonMobil and Murphy Oil, bringing us another step closer to when we will be able to begin the interpretation process to evaluate the potential of these blocks. As part of our portfolio optimization strategy, we recently relinquished 2 blocks in the Pernambuco-Paraíba Basin and began the relinquishment process for the Camarão Norte discovery. These write-offs are being reflected in this year's third quarter earnings. At this point, I will turn the call over to our CFO, Paula Costa, after which I will come back with a deeper dive into our business developments and outlook.
Thank you, Lincoln. Good day, everyone. We continue advancing the execution of our strategy focused on improving even further our financial performance and at the same time creating a platform that sustains growth opportunities in the long run. We will discuss here today the financial results of the third quarter '18. I'll give you an update on our balance sheet, cash flow and investments in the quarter. Then, I will turn the floor back to Lincoln. We are pleased to report very solid financial results in the third quarter. The combination of stable demand for gas from Manati and the full production of Atlanta Field along the whole quarter led us to deliver a very positive performance in terms of profitability, cash generation and financial robustness. Let us see the numbers. Let us begin on Slide 3. This was the first quarter where we had 2 assets producing throughout the quarter. Gas production net to QGEP reached 216.6 million cubic meters, while oil production in the third quarter was 355,000 barrels. Atlanta Field accounted for 12% of our total production in the quarter. Gas production at Manati Field averaged a daily production of 5.2 million cubic meters per day in the third quarter, stable in comparison with 5.3 million cubic meters per day produced in the third quarter of last year. Quarter-on-quarter production grew 6%. This increase reflects mainly this quarter's dry period, which generated higher demand for gas by thermoelectric power plants. Moving to Atlanta Field. First oil was produced in May and the third quarter was the first having full production, which reached on average 12,900 barrels per day greater than the 10,000 barrels per day posted in the first 2 months of production in the second quarter of 2018 and in line with our most recent guidance. On Slide 4. Revenue in the quarter increased by 63.3%, totaling BRL 221 million already reflecting higher production at Atlanta Field and the stable production at Manati Field. Revenue from Atlanta was approximately BRL 84 million or 38% of QGEP's revenue in the quarter. Let us talk about costs. We're on Slide 5, please. Total operating costs were 147% higher year-over-year. And this increase is essentially attributed to the start-up of production at Atlanta Field, which impacts lifting costs as well as total depreciation and amortization expenses. Of total operating costs of BRL 146 million, approximately 60%, or BRL 87 million, are directly associated with Atlanta Field. Considering only Manati Field, costs totaled BRL 59 million in line with the same period of last year. We had lower maintenance costs, which were partially offset by higher expenses with depreciation and amortization and production costs. As a reminder, maintenance costs last year totaled BRL 7 million and included costs reflecting platform painting and maintenance at Manati and repairs to a damaged flow line. Our exploration expenses grew 87% in the quarter compared to the same period of the prior year resulting from funds spent for seismic shooting in the 6 blocks located in Sergipe-Alagoas Basin. On Slide 6, general and administrative expenses increased by 34% year-over-year due mainly to expenses related to the stock option plan and high spending with consulting firms, partially offset by greater expenses allocation to blocks operated by QGEP. Now let's talk about profitability on Slide 7. Our solid EBITDAX result reflects mainly our higher operating result. Total EBITDAX in the quarter totaled BRL 118 million, up 55% year-over-year. Net income was BRL 56 million in the quarter, down 8% from BRL 61 million in the third quarter of last year. Profitability was impacted by higher amortization costs, in other words, with no cash effect, mainly associated with Atlanta Field and by exploration, nonrecurring exploratory costs. However, in the 9-month period, net income grew 82% reflecting greater production, higher revenue and better operating result in addition to QGEP receiving payment of the second portion of Block BM-S-8. Let us now discuss our balance sheet and cash flow. QGEP has managed to maintain a healthy and consistent balance sheet. We have an elevated cash position with low leverage. We have managed our business in a prudent fashion, and consequently, we have been able to generate consistent cash flow for our operation. In the third quarter, operating cash flow totaled BRL 150 million compared to BRL 74 million in the third Q '17. Together with our Board of Directors, we continuously review our capital allocation option and need to generate the best return for the company and its shareholders in the long term. Moving onto Slide 8. Let's talk about our CapEx. In the quarter, investments totaled $7 million with the biggest portion, or 81%, spent at Atlanta Field. During the quarter, we also invested in seismic shooting for Sergipe-Alagoas Basin. On this slide, you can also see details of our investments for the years 2018 and '19. For 2018, investment should be at $60 million, the biggest portion of $40 million refer to the development of Atlanta Field, including a small portion to drill the third well. The remaining will be spent in exploration activities with approximately $50 million going to seismic shooting activities, $10 million for the blocks of Sergipe-Alagoas and $5 million for blocks acquired in the ANP's 11th bidding round. In 2019, we are budgeting a CapEx of $70 million, the largest portion $38 million or 54% of that CapEx will be allocated to drill the third well and to commission equipment for Atlanta's full field development. With Atlanta starting to produce oil, the company's market risk management policy was revised. The main objectives of the market risk management policy are to protect the company's cash flow to mitigate events, which might adversely affect -- affect the company's financial flexibility or access to funding and to preserve the company's financial solvency. The company is constantly assessing the possibility of hedging its future oil production to increase the predictability of its cash flow and to secure the foreign exchange assets that it needs to fund its investment plan and operations in foreign currency, thus minimizing the need to -- the need for supplementary foreign exchange hedge with derivatives. Currently, the company has a put option for part of its estimated 12-month oil production corresponding to 439,000 barrels at a cost of $70 per barrel. The average cost of acquiring these put options was $2 per barrel. I'll now turn the floor back to Lincoln who will make a strategic review and talk about our businesses.
Thank you, Paula. Moving now to Slide #9. We'll have a closer look at our full asset portfolio. Let us start with Manati. As Paula mentioned, our average daily production this quarter totaled 5.2 million cubic meters, very close to the 5.3 million cubic meters we produced in the last year's third quarter. When compared with the second quarter 2018, our production increased considerably, up over 7%, which puts us on track for full year 2018 average production of 5 million cubic meters per day in line with our guidance and slightly ahead of 2017 levels. Volumes at Manati Field have primarily reflected higher natural gas usage to fuel power generation in the northeast part of the country due to a lack of rainfall rather than a pickup in industrial demand. As we look ahead to 2019, based on similar demand factors, we project annual average Manati Field gas production of approximately 4.3 million cubic meters per day, give or take 5%. Actually, this decline reflects the natural depletion of the field as it enters its 13th year of production next year. The good news is that despite the expected decline in the field, we expect to be able to sustain high operating margins on Manati's production. The other good news is the expected increase in production at the Atlanta Field next year, which will more than offset the lower production from Manati field. In the third quarter, the [ area of ] production in the field was 12,900 barrels of oil equivalent from the 2 existing wells, utilizing pumps on the seabed given the malfunction of the pumps inside the wells. Apparently, it was a connection problem, and we'll fix it as we do the workover already in the first half of next year. Secondly, we have contracted a drillship, Laguna Star, to drill a third well in the field in the first quarter of 2019, and we have already ordered all the necessary equipment. Importantly, the rig has the capacities to replace the malfunctioning submersible pumps in the 2 existing wells. A process that should take approximately 45 days per well. Our plan is to activate these capabilities once the third well has achieved a stable production level and to move ahead with the pump replacement, 1 well at a time. Our goal is to have 2 wells producing at Atlanta at all times. We expect to have 3 wells online by the end of the third quarter of 2019, possibly before that. At that time, we expect average daily production from the Atlanta Field to range from 25,000 to 27,000 barrels of oil equivalent. The third well will complete the Early Production System at Atlanta in the second half of 2019, and the consortium expects to decide on the full development at the field on that occasion, obviously always mitigating factors like price of oil, productivity, et cetera. As Paula mentioned, we have already allocated $46 million in capital expenditures to this project in 2019. The price of oil will be key to the consortium's decision on this expansion. Another factor that may influence the price we received from Atlanta's oil is the International Maritime Organization's recent change to bunker fuel regulation setting a lower global limit for sulfur in fuel oil used onboard ships. The new standard goes into effect on January 1, 2020, and should benefit demand and, obviously, pricing for our operation and production given that the oil from the Atlanta Field has very low sulfur content, which is outstanding for planned and also bunker production. Another positive element in the Atlanta Field is the positive ruling by the London Court of Appeals, or LCIA, concerning the disposition of Dommo Energia's ownership position in Block BS-4. The court ruled that the 40% working interest that Dommo had in the Block should be split between QGEP and Barra Energia, which means that each of us would have a 50% ownership stake retroactive to October 2017 where the arbitration was started. The final ruling requires approval by the Brazilian authorities, which we expect to occur within the next several months. When we consider the higher production levels to be achieved in Atlanta in 2019, the potential for increase prices, the use for bunker and the ruling increasing our ownership from 30% to 50%, it is clear that any expenses associated with repairing the well pumps and their replacement will be quickly offset by these highly positive factors with an impact on our revenues. On Slide 10, we focus on exploration activities, the cornerstone of which is our position in the Sergipe-Alagoas Basin. As you know, we have a partnership with ExxonMobil and Murphy Oil in 6 contiguous blocks that are in close proximity to significant discoveries by Petrobras. The shooting of the seismic data that we contracted has been completed, and we expect to receive the preliminary data. We're right in the beginning of the processing phase, and we expect to have the data at the end of the first quarter of 2019. Once we receive the data and perform the additional evaluation with our partners, we'll be working on mapping out a drilling program for 2020. An extended well test at the adjacent Farfan discovery by Petrobras and according to the press, it is scheduled to take place before year-end and other measures are also being made. These are the production as far as we heard from recent news about FPSO contracts. As for our farm-out process, our two 100% owned blocks in the Pará-Maranhão Basin is moving ahead according to plan. We have seen good indications of interest and hope to have the process completed in 2019. In our 100% owned Foz do Amazonas block, we are awaiting an environmental license before proceeding with a farm-out process. 3D seismic data acquisition and processing for blocks in the Ceará and Espirito Santo basins has been completed and the consortia is in the process of interpreting data to better understand the exploration potential for these blocks in the near future. I would like to highlight that QGEP continues to be disciplined in the ongoing evaluation of our exploratory portfolio to ensure that our resources be earmarked to the most promising prospect for a company of our size and risk appetite. As part of this ongoing portfolio optimization strategy, we made the decisions in the third quarter in order to streamline and screen our exploratory assets. These actions include the relinquishment of 2 blocks in the Pernambuco-Paraíba Basin awarded in ANP's 11th bidding round almost 7 years ago. Additionally, after evaluating several development plans and the potential unitization of the adjacent area, the consortium of block BCAM-40 concluded that the area is not economically viable and began the process to relinquish the Camarão Norte discovery. Obviously, there is no economic value to monetize the area. And this was a decision that became more mature over the last year. Slide 11 summarizes where we stand today and provides additional information and insight into our opportunities as we enter 2019. I'm pleased to report that we're firmly on track for growth in 2018 thanks to a combination of operating achievement and the benefit of a large asset sale and farm-out success. We are very proud of the accomplishments of the last 18 months in which we could monetize our interest in the Carcará discovery, diversify our revenue sources with production from the Atlanta Field and optimize our entire asset portfolio. As we look ahead to 2019, we're expecting another year of solid growth for several reasons. Firstly, we'll have a full year of volumes and revenues from 2 producing assets with a lot of stability throughout the year, Manati Field and Atlanta Field. Despite Manati's lower year-over-year production levels, it will remain an important cash generation for the company, and we will have 12 months of production from Atlanta in 2019, compared to 8 months in 2018. Secondly, we expect to have 3 wells producing from the Atlanta Field in the second half of next year and to have our ownership in the field increased to 50% compared to 30% this year, a significant impact on our revenues. Also, please bear in mind that the Atlanta Field provides a natural hedge to QGEP against Brazilian currency fluctuations given that we sell our production in U.S. dollars. Thirdly, we'll be well positioned to take advantage of opportunities to add to our asset portfolio as we'll enter 2019 with a significant cash position and strong balance sheet and a reasonable capital expenditure budget that we can fund internally. With 2 ANP bidding rounds set for 2019 and additional potential to acquire assets, we believe that this financial flexibility is a major strength and differentiator to QGEP. At the same time, we'll have additional data on our large Sergipe-Alagoas opportunity that will provide the information we need not only to assess the potential of these blocks, but we're also confident that these are actions that will change the size and the growth potential of this company. Moving to Slide 12. You can see the operating strength that we consider key to our success and that we plan to leverage to take QGEP to the next level, mainly our deep technical expertise, our production efficiency and the ongoing optimization of our portfolio. Thank you for your interest in QGEP, in our company, and I would like to open the call to questions now. Thank you very much.
[Operator Instructions] Our first question comes from Bruno Montanari with Morgan Stanley.
I have two questions. The first, such good news published about QGEP constellation using the [ paper ] to pay the coupons of -- the coupons. Have you started paying for the drillship that will start operating the third well to be operated by the company? And if not, if the drillship cannot be operated, is there a Plan B, is there an alternative for QGEP to proceed with drilling the third well and the necessary workovers to change the submersible pump? My second question has to do with Dommo's arbitration process. I'd like to understand could you walk us through the final approvals. What is preventing you from consolidating 50% working interest at the field? And with that consolidation, does this change your CapEx script for the next 2 years?
Bruno, this is Lincoln. Hello, thank you for the question. Well, the drillship is scheduled to start operating with us in February of 2019. It is being contracted and it should remain part of the month of November in a contract. Also contract with Petrobras, this is a high-performing drillship as far as we know and as far as we could observe in the contracting process. It is a drillship that has very high performance according to Petrobras requirement. So we'll continue. And it will only come to us in February. After each contract, we'll have to do some work. And specifically regarding your question, no, there is no prepayment of any sort for the drillship. We would only pay for it as the drillship arrives in accordance with normal operating standards of a drilling contract. Regarding the news that you mentioned, yes, we definitely read that piece of news. It's not nothing -- it's nothing really new. It's something that has been mentioned before by QGOG, and we don't see any problem with this phase of the market, that was well known to the market and was well known to us as well, it has -- due to the financial restructuring. And this is not exclusive to this company by the way. All drilling companies had to go through this kind of problem with a reduction in the market. So we continue to see this, a number of companies that participated in the bid or were in the same potential situation, but we don't see any potential interference regarding these actions. And no concern regarding the drillship, but we have the usual guarantees in these cases for this type of contract, including a letter of performance normally operated by the owner or the financer, continuing -- continuity of contract with the drillship. By the way, it's a letter of quite enjoyment, and ideally we should have contracted to face this -- to deal with and honor these obligations, but we don't see any risks related to that. We are not concerned about the continuity of the operation in the foreseeable future. With regards to the arbitration process, I'll turn the floor back to Paula, who will give you more details regarding the procedures that still remain.
Hello Bruno, this is Paula. As we informed, we have the completion of the first phase of the arbitration process. That is when the Tribunal considered the forfeit provision to be executed. They authorized transfer of Dommo's stake to Barra in QGEP. This is what we call a discovery phase or clarification phase among the parties. It is a phase that will not change the ruling, but one of the parties might request clarification or correction in the wording of the sentence, but it will not change the ruling substantially. After this clarification phase, that's when we start our internal procedures to reflect this in our accounting. We expect to have the 50% working stake reflected in our accounting, possibly during this year, this will impact our results and future CapEx when we look at the CapEx. Because you asked about the impact on CapEx, if you look at the 2019 CapEx, what we have is a proportion of what is reflected in our balance sheet, 30%. When that 30% working interest increases to 50%, there will be a proportional impact. An impact which will be felt in CapEx, operating costs, operating revenues, costs of workovers, et cetera.
Okay, and just to clarify. Final approval after the clarification phase, does it come from ANP? Who are the authorities involved?
The clarification phase is related to the arbitration process and the Tribunal. When the clarification phase is over, then we have the procedures here with relevant authorities, we are talking about CADE, ANP, the antitrust agency, and the pertinent process to transfer the concession.
And then you will follow the normal farm-out process?
We will follow the normal process to transfer a concession. And just to make clear, the accounting part is now tagged to the ANP part of the work. We are finalizing the Tribunal part. And this is what I said, we should see this impact in the short term, perhaps ANP will have a schedule that might extend to next year, might not be so short term. But this is the natural procedures that we see normally in farm-out operations [ in at least standard ] procedures, but it takes 2 to 6 months to transfer. So the different phases of process is happening.
Our next question comes from Gabriel Barra with UBS.
Regarding the realization price at Atlanta. Could you give us more color, have you managed to get a lower discount given the lower content of sulfur? And to confirm, the Shell contract that you have is just for the EPS, the Early Production System? And if so, is there any cost that allows you to extend the contract when you have full development? My second question has to do with the hedging policy. In the beginning of October, Brent oil price accelerated, did you use that project -- that phase -- that price to accelerate your hedging? And what would be the ideal strategy for the company? What would be the ideal hedged production? Now you have almost 30% considering an annual proportion. So I would like to know how much would that percentage be?
Hello Gabriel. This is Danilo speaking. To answer your first question. The contract with Shell applies only to the Early Production System of Atlanta. For the full development phase, most likely we will sit with them and negotiate. And we can perhaps consider other traders to see what would be the contracting conditions because we will have 3 years of solid base of Atlanta oil in the market, means we will be in a better position to negotiate and discuss. As for Atlanta discount, sulfur content today is not to have an influence because the requirements of low sulfur content have not entered into [ force ] for bunker fuel. ] But they found the companies that they're hiring for consulting services. These consulting firms tend to say that, when these new rules apply, our oil should be benefited given its very low sulfur content, and because there is a shortage of heavy oil in the market, we think that we will have a benefit, but not now, perhaps by the end of 2019 or 2020. We have a good [ realization ] price for the Atlanta discount, about $500, $15 a barrel, according to Brent oil price. And this is stemming from the low production at Atlanta, with low production, which is too long to fill a tanker. At that price, the logistic cost goes up. Now this should be reduced as soon as we drill the third well, and as soon as we have the 2 producing wells at normal operation, we expect a reduction of at least $4 per barrel with this discount. Okay?
Gabriel, this is Paula speaking. Just adding to the answer about hedge, Paula speaking. The hedge policy, like Lincoln said, it is part of our market risk management policy, there are 2 parts to it. One of them is Brent, the other is FX. Sometimes, they communicate so to speak. The highest risk well is considered to be pegged to the dollar from the moment I have a hedge position. Our policy considers a 3-year forward and hedge percentage both for hedge and dollar, they are reduced over time. And this is how we work on our hedge position by combining both variables over time. As for the data in which the price hit $85, we closed our position, one of the 2 trenches was precisely on the same date. So we managed to capture the right moment for the Brent hedge. Having said that, our policy is more related to production rather than speculation, it's more hedge oriented. So we've thought to be successful at all times. If you think about the short time frame universe, we managed to close as of today, one of the 2 trenches. As for the ideal hedge percentage, it depends on this combination of future cash flow back to commodities and also CapEx and OpEx denominated into dollars. That is what tells the production percentage to be hedged in the future. But our idea is to do some kind of hedge and the tool and the instrument of choice was an option, a put option so with a benefit from a potential rise in oil. The cost was already -- the premium paid. We don't have any more downsize in this operation. And if oil goes up, we keep on benefiting from this rise. However, for that hedge volume, if the oil goes below $70 per barrel, then in this case, we are hedged in this level for the hedged volume.
The next question is from [ Fernando Cornejo ] with Citibank.
I would like to ask a follow-up question. Concerning the first decision by the arbitration court to increase the stake from 30% to 50%, are you discussing any sort of reimbursement for Dommo or payment considering it has already invested on the field? And secondly, can you tell us how much is included in CapEx for the MS 4?
Paula speaking. Fernando, there is no kind of reimbursement. The court decided to continue with JOA provision, which is the exit of a default partner. This is the first phase. The numbers for Dommo, they are public numbers, public figures. So maybe you could talk to the company more directly. We don't know how much it has invested because it's not only QGEP's investment as operator. We also have acquisition prices and other figures related to Dommo and not necessarily related to the -- for future clause, which is [ not loss ] .
The next question is from Leonardo Marcondes with Itaú BBA.
My first question is about Dommo, again. You said, you expect to have an update of the process this year, but is there a deadline for this clarification phase? And secondly, just to understand the company's mindset, is the idea to maintain this additional 20%? Or do you consider to sell this additional 20%? My second question is about allocation of capital, almost BRL 2 billion cash. And you're speaking of dividends for a while now. That's second question. What is the strategy of the company in the future when it comes to allocation of capital? And does the controller party decision or influence has a say in the final decision of the capital?
Leonardo, your questions are very broad. This is Lincoln speaking. The deadline or the limit date for them to post these remarks and clarifications is by the end of November. To submit it to the court, there is also a potential deadline accepting or not. But one thing we know for sure, we have no doubt about the efficacy of the exit decision. This ruling was already taken. The first one had to do with the control of cash flow by the consortium usually by the operator, but the ruling is set. We might see this right of including additional points by the court. But for us, it is by November, and I don't know how long it will take for the court to do it, but like Paula said clearly, when it comes to financials, we're already trying to have these amounts included to our revenues and also to Barra's revenues. We don't think it's going to take long, at least when it comes to the court. As for the 20%, we certainly plan to keep these 20%. We always want to diversify our revenue source. That's what we've been doing all over the years, and actually, we have achieved good results. Atlanta is an example, and Carcará mid-term as well. Today, we are betting more heavily on Sergipe as well, Sergipe's growth. The exploratory process is very much underway, but it's not critical for us to hold 20%. But there is something about our activities. We have this motto of always trying to go for diversification of our revenue sources as a hedge just as we do with gas, oil, heavy oil, that has been appreciated in the marketplace. And we expect to stick to this policy. We don't need any monetization about this 20%, but if any future opportunity arise, we'll always be open to assess and consider anything that may help us have a more proper monetization that guarantee you mid- to long-term revenue in a sustainable manner. This will always be on our agenda. As for dividends, we still have dividends on our radar. We had a strong action this year concerning the bids. There are many opportunities arising and we simply have to assess and we never failed to assess. Some of them had an early exposure, particularly about bonus. It is very high at first. And it was very challenging to be there. Despite our cash position, they're always times, [ one is ] short-term cash and then, our future liabilities about CapEx, et cetera. So it was not possible to take part even though we are involved in the 15th bidding round and we had 2 blocks awarded with ExxonMobil and Murphy with a recent execution of the agreement. So dividends are still in our radar. We expect to have next year -- well, this is not directly related, but it's also an important point. We expect to have the rest of our sale to Equinor/Statoil and this may happen by the end of next year. It's too early to say anything, but today, our decision when it comes to investments, is always trying to check market opportunities, particularly about bids. Brazil is very strong in this trend, a lot of opportunities and that's what we always try to mitigate whenever we decide to take part in bids. It happened with the first time when we had the additional amount paid out because we were participating in the bidding process we wanted with a lower exposure level. And we were very comfortable therefore to have this good return to our shareholders owing to the monetization, a part of the sale of Carcará. And our allocation of capital will always have this in mind. We always try to work on some kind of evaluation and assessment or whatever we can anticipate in terms of production and revenue. When we said today that we involve 2 blocks, it's just because we couldn't have an adequate monetization and that's why we had to relinquish it. Camarão Norte is one of them and also Paraíba-Pernambuco. We realized that today our ability among other factors, our allocation of capital are in lower risk areas and with the potential return in terms of oil and financials at a higher rate. Whenever we change our portfolio, whenever we look at our portfolio, we'll always have to try to lower the risk or try to anticipate our revenues. That's what we've been doing. It's an ongoing attitude and we try to keep on doing this. This question sometimes is related to our participation in other bids. We're always interested in having a stake in pre-salt. It's not so easy though. Although tax conditions are very attractive, this -- or these bids require a lot of effort in terms of bonuses and that's why it challenges our participation. However, in the future, our intention is to be involved in this activity with pre-salt and also checking market opportunities. There is a shortage now. This is more in shallow waters, onshore, which is not in the profile of this company yet. The company made a decision to be focused on deep waters at first. At least for the next 2 or 3 decades, this is the guiding star of our investment for oil and gas in Brazil. Other opportunities simply make no sense to us, but it doesn't mean that we are not ready to assess future opportunities in the market, particularly involving production of first oil. So we can implement a strategy to diversify our revenues. So this is our motto, and as oil prices allow us to do it, we'll maintain it.
[Operator Instructions] Our next question comes from the web by [indiscernible].
Is there a possibility to use the third well at Atlanta to test the Piapara prospect? If not, how can you evaluate this prospect?
Hello [indiscernible], thank you for the question. Well, our contract with the rig is the contract in principle less than 6 months. It was signed for the drilling of the third well and to do the workovers in the 2 producing wells. I must admit that it had been an excellent opportunity given these financial conditions and the daily rates that we're paying -- that we're enjoying, and the whole market and in the whole market, drilling is reasonably depleted in terms of the supply of drillship, rigs and cost. But in our case, ideally, so this drilling need to happen, it would be immediately after the full development of Atlanta because then we would have an expectation of production and we would have a higher volume. And then it would set the base for logistics and infrastructure requirements. And the full development will be generating revenues and we could easily drill the third well. It is one of the hurdles in the past like the condition of one of our partners that inhibited the drilling of the third well, but now we're getting to the end of that process. Very soon, this will be totally resolved, and I believe that the ideal phase to make a decision about Piapara, which is a pre-salt area, 1,500 meters deep, it could really drive us forward. But ideally we would make that decision after the implementation of Atlanta's full development, which should begin by 2020, 2021. And this would be ideally the time to drill the well at -- in Piapara at Atlanta.
Our next question comes from the web by [ Mr. Georgiy ] from Investec.
Considering that 3Q '18 was the first quarter with full oil production, could we consider the volume achieved in Atlanta as a stabilized one? Do you believe that there is still room for improvement in the lifting cost of this field?
Hello, [ Georgiy ]. This is Paula speaking. Regarding the daily operating costs, yes. This is the cost that we were expecting. We had even announced production of 410,000 barrels a day, it could be a little bit below that. That amount should remain as 400,000 or 410,000 barrels per day at least during the first 18 months of production. I'd like to remind you that after the 18 months of production, our estimate is that it will go up to 480,000 barrels a day. In absolute terms, of course, when you compare the cost per barrel, the lifting cost per barrel, then there is a big difference comparing now and next year. We currently have a cost per barrel higher than $30 a barrel. And with the third well and workovers done in the 2 producing wells, the lifting cost per barrel can drop to half considering the production will double without entailing a significant increase in our operating cost. So when we look at cost per barrel, yes, I think that we can benefit a lot in the next year. I think that there was something else to your question.
The next question is, do you believe that there is room for improvement in the lifting cost of the field?
Well, I think I answered that. When we look at the cost per barrel, yes. I think we're going to have a significant reduction in the lifting cost when we have an increased production that will have an impact on the total operating cost.
Next question coming from the web by [ Mr. Juan Jose da Silva ].
My question has to do with the hedge. The company with the acquisition of a put option, could you please explain the percentage of coverage of production? I did a simulation, and I found something around 15% of Atlanta's production. Does this percentage makes sense or not?
Well, if we look at the next 12 months, the percentage is a little higher, closer to 30% of Atlanta's production considering the original percentage of 30% QGEP's working interest without including the extra 20% after the arbitration results. So it's more or less 30% of the production looking at a 12-month universe.
Next question comes from the web from Mr. [indiscernible].
Financial revenues. Will financial revenues be sufficient to offset a possible operating revenue loss with reduction in the Brent oil price?
I think that this links with the prior question, where I have a percentage of the production curve, which is hedged, it is an instrument we will continue to use in the future. Our market risk management policy looks at a 3-year time frame, but the options that we purchased or acquired -- the put options that we acquired after 12 months, but our total policy looks at a 3-year time frame. So this is an exposure that the company will always have because this is an oil and gas company. It is inherent to the industry. What we try to do with our risk management policy, we want to maintain our fundability, our management of risks and maintain our policy in the short term. The instruments that we have protect us as they were acquired. In other words, for the volume, for rate we acquired the put option.
Next question from the web comes from [ Mr. Claudie Miller ].
Are you considering a consortium for farm-in of Petrobras blocks as in the field block ?
This process at Petrobras is quite a recent one. And we are following it up. We haven't made any initiative yet. The reason being that these areas involve discoveries. A considerable volume at least extra officially in our personal opinion. So right now, all we are doing is monitoring these areas and we expect to have an extended well test to happen soon in these areas. But one thing we know for sure, these are areas that require more efficient action with economic elements that can be quite sizable, discoveries with very good oil, so it is not an easy decision to make by a company with our size unless another consortium might come tomorrow, showed its interest in these areas. And everybody knows we do like these areas, we have 6 blocks, they're including the first 2 ones, which we acquired on our own. So we're going to assess. If there is any possibility of a consortium with this kind of interest, there is no doubt that we would like to be involved. On our own is near impossible to do anything in this area.
[Operator Instructions] This concludes today's question-and-answer session. I would like to invite Mr. Lincoln Guardado to proceed with closing remarks. Please go ahead, sir.
Well, everyone, thank you very much one more time for joining us in this conference call to discuss our results, which we believe are very good and with a positive outlook until the end of the year, with great -- with a great outlook for next year, we foresee increase in production includes revenues, but with important decisions to be made, particularly regarding Atlanta and its full development system. And there is a number of issues being followed with our partners and that will give us a lot more capacity to invest in the future in terms of capital allocation. So I believe that we are in a substantial growth path. We are drafting our strategies. We want to reduce the risk of our portfolio, including our production. Brent has helped with price oscillations more related to international policy expense in terms of the demand for oil that remains stable. In our view, we expect a very important end of the year to QGEP and we envision an even more promising 2019, which includes revenues and stabilization of our production. And one more time, I would like to invite you to make use of our Investor Relations department because we're always available. And one more time, I would like to thank all of you for your time and for your questions. Thank you very much. Have a good day.
This does conclude QGEP's conference call for today. Thank you very much for your participation, and have a good day.