Enauta Participacoes SA

BOVESPA:ENAT3

Earnings Call Transcript 2019-Q1

[Operator]

Good day, ladies and gentlemen. At this time we would like to welcome everyone to Enauta's First Quarter 2019 Earnings Conference Call. Today we have here with us Mr. Lincoln Rumenos Guardado, CEO of the company; Ms. Paula Costa Corte-Real, CFO and IRO; and Mr. Jose Milton Mendes, Exploration Superintendent. We would like to inform you that this event is being recorded. [Operator Instructions] Before proceeding, let me mention that forward-looking statements that might be made during this conference call relative to Enauta's business perspective, projections and operating and financial goals are based on the beliefs and assumptions of Enauta's management and on information currently available to the company. Forward-looking statements are not a guarantee of performance. They involve risks, uncertainties, and assumptions because they relate to future events and therefore 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 Enauta and could cause results to differ materially from those expressed in such forward-looking statements. Now I will turn the conference call over to Mr. Lincoln Rumenos Guardado, Enauta's CEO, who will start the presentation. Mr. Guardado, you may begin.

[Lincoln Rumenos Guardado, executive]

Thank you. Good day, everyone. Thank you all for participating in today's call to review first quarter results accomplishments and our business outlook. Let us begin on Slide 2 where you can see what we consider to be the key takeaways from our performance in the first quarter 2019. First, our results benefited from our 2 producing assets, which brought total production to 1.4 million barrels of oil equivalent and obviously as a consequence of our increased ownership in the Atlanta Field. Secondly, in Atlanta we completed the drilling of the third well at the field on schedule, are proceeding with well completion and should see oil flowing between late May and early June. Thirdly, I would like to highlight that the operator, ExxonMobil, has requested the approval of the environmental license for the drilling in the Sergipe-Alagoas basin in the second half of 2020. Obviously we expect these licenses to be released so that we can fulfill our plan. Fourthly, at our annual general meeting on April 18th, management's proposal was approved, and this has been very much informed, establishing the payment of total dividends of BRL 500 million or nearly BRL 1.91 per share already paid on the seventh this week. At the same meeting, our shareholders approved the change in the company's corporate name to announce to Enauta Participações S.A. Thus we have an active start to 2019 with good results and excellent prospects for the year. I now turn over the call to our Chief Financial Officer, Paul Costa for the financial review of the first quarter 2019.

[Paula da Costa Corte-Real, executive]

Thank you, Lincoln. Our production was 1.4 million oils equivalent to 552 net oils for the company. This reflects a full quarter production from Atlanta Field and ongoing production from Manati. The Atlanta Field accounted for slightly more than 1/3 of our total production in the quarter. Breaking down by field, starting Manati. Average daily gas production reached 3.3 million cubic meters per day in the first quarter '19 compared with 4.6 million cubic meters per day in the same period of prior year. There are a couple of factors that come into play when comparing with first quarter '18, including the scheduled shutdown of the gas plant and lower demand in January this year. As soon as the plant resumed operations after maintenance, average daily production was back to 4.4 million cubic meters. It is important to remember that last year's production benefited from drought conditions in North East Brazil, which led to increased demand from thermal power plants, whereas this year exactly the opposite, with more rainfall, less demand, especially in January. Moving on to Atlanta. The Field has been flowing oil for about 11 months from 2 producing wells with an average production of 12,300 barrels of oil per day. This compares with 12,400 and 12,900 barrels of oil per day in the prior 2 quarters respectively. On the next slide, Page 4. There is a comment on the effects from IFRS 16. Before getting into the details of the quarter, I want to make note that we adopted IFRS 16 standard accounting for leases during the quarter. This had a number of impacts on P&L and balance sheet. And we will discuss this in more detail during the presentation. This slide summarizes the major effects. On the balance sheet, the leases accounting assets was positively affected by BRL 666 million with related compensation reflected in the leases account under current and uncurrent liabilities of BRL 668 million mainly deriving from the chartering contract for Atlanta Field. On the P&L the FPSO chartering contract was removed from operating costs and is now recorded under depreciation. The BRL 3.5 million impact on the financial results is related to the adjustment to present value of total lease contracts. With that, our EBITDAX was positively affected by BRL 31.3 million while our net income was negatively affected by BRL 1.7 million this quarter. This accounting brings no cash effect nor any tax impact for the company. Moving on to Slide 5 now where we take a closer look at our results. Revenue growth has accelerated in the period thanks to the contribution from Atlanta Field which more than offset a lower production from Manati. Revenue in the quarter of BRL 207 million was up 74.5%. The revenue contribution from Atlanta Field was approximately BRL 119 million or 57% of total revenue in the quarter. Moving now to costs. Starting on Slide 6. For the quarter total operating costs of BRL 150 million were more than triple the prior-year level of BRL 47 million with the increase primarily attributable to costs related to the production from Atlanta Field, approximately 76% or BRL 112 million of the total operating costs are associated with Atlanta. Of this total BRL 71 million refer to depreciation, around BRL 30 million higher resulting from the adoption of IFRS 16. Looking at Manati alone. Costs were BRL 35 million, which represents a decline of 24%, reflecting the reduction in royalties, special participation, R&D and depreciation due to lower production in the period. On Slide 7. G&A expenses of BRL 1.6 million were 87% lower than the same period last year, primarily due to a reversal in a provision related to the 2012 stock option plan as the exercised term had expired in the amount of BRL 10.3 million. Excluding this impact, G&A expenses would have reached BRL 12 million in the period. Moving on to profitability, on Slide 8, please. Our adjusted EBITDAX results benefited from both high production and lower G&A expenses. On a reported basis however EBITDAX in the first quarter of BRL 129 million was 36% lower than the first quarter of 2018. First quarter '19 includes an approximate BRL 31 million benefit from the adoption of IFRS 16. We pointed first quarter '18 EBITDAX included a second installment payment amounting to BRL 148 million from the sale of Block BM-S-8 to Equinor. Excluding these effects in both periods, EBITDAX doubled against the first quarter 2018 which generated net income of BRL 51 million in the quarter compared to BRL 159 million in the same period of the prior year. Profitability was impacted this year due to higher costs from Atlanta Field and the sale of BM-S-8. The underlying trends in our business remains strong and we are optimistic about our profitability opportunities for the remainder of the year. Moving on to Slide 9, capital expenditures. On this slide you can see the breakdown of our projected capital expenditures for 2019 and 2020. In the first quarter, CapEx totaled $6.5 million with 72% going to Atlanta Field. For full year 2019 we are projecting expenditures of $65 million, slightly below the $73 million invested in 2018. The majority, approximately $40 million or 62% of CapEx of this year as allocated to Atlanta Field. This includes the drilling of the third well. The CapEx estimated for the scheduled maintenance at Manati Field at quarter end which shutdown production for nearly 20 days totaled almost $2.7 million, and this will be recorded in the second quarter '19. For 2020 we'll have a more robust capital expenditure program planned at $133 million, which is more than double our 2019 expenditures. 2/3 of our spending will be utilized for the development of Atlanta Field as we start the development of the full development system assuming the consortium decides to proceed. We are also planning to drill initial wells in the Sergipe-Alagoas and Ceará basin. The remaining funds will be utilized for the exploratory activity in block CAL-M-372. Our CapEx requirements have mostly been funded with internally generated funds or we simply we have also used funds received from the sale of BM-S-8 and the Sergipe-Alagoas' farmout agreement to support growth. As a remainder, we maintain a cash position sufficient to support our funding requirements for the next several years. We will remain disciplined in our use of capital while continuing to invest for growth in trying to generate more return to our shareholders. Lastly, a comment about our balance sheet and cash flow. We ended the quarter in a very strong cash position of BRL 2 billion and we further reduced borrowings by 11% in the period when compared to the first quarter '18. Our net cash totals BRL 1.7 billion, more than enough for our CapEx needs in upcoming years. As I mentioned earlier in my presentation, we adopted IFRS 16 standard accounting for leases effective January 1, 2019. We have been conservative in how we manage the business which in turn has driven sufficient cash flow to fund our operations and return capital to our shareholders. During the first quarter we generated BRL 107 million in cash flow from operation compared to BRL 204 million in the first quarter 2018 which benefited from the gain on the sale of block BM-S-8. Our capital allocation priority is to invest in our business for long-term profitable growth. When there is cash surplus we'll return capital to our shareholders through extraordinary dividend payouts. I'll now turn the call back to Lincoln for his strategic and business review.

[Lincoln Rumenos Guardado, executive]

Thank you, Paula. Let's move to Slide 10 now where we begin with an update of our asset portfolio. As Paula mentioned, production from the Manati Field was 3.3 million cubic meters this quarter, lower than last year's first quarter as a result of two main factors being one of them weather related. The heavy rainfall in the period significantly increased the use of hydroelectric power in the Northeastern part of the country, reducing demand for our natural gas. And also added to low industrial uptake in contrast to the drought conditions that prevailed from much of last year. Additionally, we implemented a scheduled maintenance program at the field which caused a 20-day production shutdown beginning in mid-March. Even at these lower production levels stemming from both factors, Manati Field remains a high return asset for Enauta due to infrastructure in place there which belongs to the consortium. Additionally, the impact of lower production partly offset by higher contractual prices that went into effect in the beginning of January based on the take or pay contract. Based on our current outlook we continue to project full-year Manati production to average 4.1 million cubic meters per day at the lower end of its initial forecast for the year, always considering that we're still subject to any market demands so we can be in this range, this production range. Please turn now to Slide 11 for an update on our progress at Atlanta Field where average production in the first quarter reached 12.3 thousand barrels of oil per day. This was in line with our expectations and slightly below the fourth quarter of 2018 levels, a situation that will be reversed once the new pumps are installed in the first two wells in production today. We are pleased to report that we completed the drilling of the third well at the Atlanta Field right on schedule very successfully and that we are now currently in final preparations to start production between late May and early June. The rig will move to one of the two initial wells and begin intervention work to replace the pump which is expected to last 45 days between July and August. Once the work over at the well is completed, the rig will move to the second initial well to perform similar activities. We believe it is prudent to expect that all 3 wells will be online before the beginning of the fourth quarter. In other words, between September or late September. At that point we anticipate production from all 3 wells to range between 25,000 and 27,000 barrels of oil per day, always considering that production ramp up required in cases like this. Additionally, we expect the favorable pricing scenario for our Atlanta Field production, particularly Brent oil prices until the end of this year, reflecting worldwide shortage of heavy oil and low sulfur content, which is the case in Atlanta. This combined with a higher production and our increased ownership position, currently 50%, should result in a relatively short payback on this year's additional investment, around $45 million net to Enauta, evenly split between capital expenditures, the drilling of the wells and the completion work and operating expenses, usually connected to the exchange of the pumps. At the end of the year, once we have a track record of production from all 3 wells and greater visibility on future economic factors, the consortium might decide to move ahead with a full development system at the field. We have included $90 million in our 2020 capital expenditure budget for equipment purchases related to additional development of this field. Let's move to Slide 12. This slide provides an update of our exploration activities. Our technical teams continue to carry out interpretation activities of our assets very diligently, and there are not a lot of new specifics to report since our release of full year results just 2 months ago. Our 30% ownership of 6 contiguous blocks in the Sergipe-Alagoas basin remains the cornerstone of our portfolio, our exploration portfolio. And we're analyzing the acquired seismic data along with our partners, ExxonMobil, the operator, and Murphy Oil. Together, we are involved in the planning of a drilling program, and it is scheduled to commence as from the middle of next year. Always bear in mind the granting of IBAMA's drilling permit which was already applied for.Additionally in exploration, the formal processes of our 100% owned Pará-Maranhão blocks is under way and is expected to be completed by the end of this year. We continue to evaluate the Ceará and Espírito Santo blocks together with our partners. And also awaiting for some drilling results which are expected to come over this quarter in both regions over this year. To sum up, Enauta, is on its way to another year of positive operating results in 2019. The Brazilian oil and gas sector remains robust, offering substantial growth potential. Within this environment we are monitoring opportunities that may present themselves as part of future ANP bidding rounds, which could increase other concession rounds as well, the 16th. And this could increase our cash flow over the long term. In the meantime, with a higher working interest and the benefits of a full year of Atlanta Field production which is expected to significantly increase in the fourth quarter of this year, we envisage continuous progress in the periods ahead in order to work on our reserves and improve our operating cash flow at the company. So thank you all for being with us. And now I ask the operator to open the floor to the Q&A session.

[Operator]

[Operator Instructions] Our first question is from [ Rodrigo Almeda ] with Santander.

[Unknown Analyst]

I have 3 questions, if I may. The first question is about production in Atlanta. We've seen the sequential drop that you mentioned before, a natural drop which is expected to be maintained until the pumps are replaced. Could you give us more detail about this natural drop? In other words, what should we expect to see in the next quarter considering a combination of this drop and also the ramp up of the third well? My second question is also related to Atlanta, lifting costs. I would like to better understand the dynamics of lifting costs in the field considering there was a drop in the first quarter maybe related to lower oil. But you mentioned $480 million (sic) [ $480,000 ] in the press release. Is it considering the Brent oil quotation? I would be glad if you give us more color of this increase in Atlanta's cost? And my third question has to do with allocation of capital considering the comfortable cash position. What are the plans in the short term related to dividend payout? You recently had something like that along those lines, but what about a short to mid range? Should it be related to the purchase of assets in the exploratory phase or even your participation in future auctions ANP bidding rounds?

[Lincoln Rumenos Guardado, executive]

Absolutely, Rodrigo. I can be very candid with you. When it comes to production, we had a stabilization in production. And stabilization including distribution of pressures with a slightly heavier drop. But after this drop we have the reservoir already been adapted to the status. And the rate of the drop, of the decrease was dramatically reduced. So today we can say it's back to normal. Please bear in mind that this field presumably does not consider injection of water. Water injection is precisely to prevent any problems because the field has an amount of water that is big and huge compared to the volume that we expect to recover, so it wouldn't be efficient. So naturally there is a drop from the moment production goes up. But we can feel there is some stabilization of this rate. And to date, with the accumulated production the rate is around 8% for the year, 8% per year, which is expected to be maintained if we consider this initial production plan of the early production system. And naturally, with a slightly lower production this drop is also expected to be slightly more long-term with production starting in Q4 and also the future full development system, then we can have the natural regime. Usually these fields have between 12% and 15% of drop rate or decline rate and water is injected to try to contain it. This is not the case. Actually can see the competence of this reservoir in this production. So 8% per year, this is the average we had since the beginning of production in may this year, a year of production actually. I hope I've answered your question. With regards to the lifting cost, Paula is going to give you more detail on this. Because the lifting cost -- what it the impact of the lifting cost? We have to be careful with the definition. It is the lifting per se, it's different from operating cost. I hope you are referring more specifically of the lifting cost, per se, okay?

[Paula da Costa Corte-Real, executive]

Hi, Rodrigo. Paula speaking. When it comes to the lifting cost, like Lincoln mentioned, it does not include all operating costs, no royalties, no languishment or abandonment. So when you think about these two wells that are after their drilling of the third well, we are going to have workover costs that are not included in this lifting cost. But if you think about this cost, the lifting cost, our estimate is $410,000 per day. Actually we have reported amounts below this $410,000. More specifically about logistics. We have lower cost compared to what we planned, the operations that are pending. And we use less than expected. So we've been having lower than $410,000, even though we still maintain $410,000 during the first 18 months of the field's operation. Please bear in mind $410,000. Consider a discount of the FPSO contract. And this is owing to one of the periods of delay of start of production before the arrival of FPSO from Teekay. So we managed to negotiate lower costs for the first 18 months. And for this reason, for the last 2 months of the year, and once we complete 18 months of operation, we expect to see an increase in lifting costs to $480,000 per day. This contract, this chartering with Teekay has other variables, but this is part of confidentiality of the agreement, so we cannot disclose anything right now. Anyway our estimate is that for the next 18 months and from then onwards we can have this increase for the EPS, this increase to $410,000 per day. Now I'll give the floor back to Lincoln to talk about allocation of capital and opportunities of new assets.

[Lincoln Rumenos Guardado, executive]

Answering your question, Rodrigo. We have a stable vision. We have been following very carefully what's happening in Brazil. We believe that we have benefited from these offers that took place. For instance, think about assets. We already in Sergipe-Alagoas basin and we found this opportunity to grow this area in our opinion. In our internal opinion of the company there is a lot of exploration prospects with farmouts. And at the same time we -- well, we have 30% of the equity but multiplying by 3 the number of blocks we have. In other words, if we think about probability, our chances of discovery is much greater. We used to have 2 blocks, now we have 6. We decreased our working interest but just with brief maths I have more gains in probability to recover volume and reserves at a higher amount of blocks. And naturally we do have this relationship regardless of just 1 block. But depending on just 1 block is not good enough. So with the consortium we have strengthened the operation, ExxonMobil and the presence of Murphy. But we keep on having an eye on these assets, and particularly of the bidding round or not which may add value to the company, thereby increasing short-term production which is not so easy currently or by improving our portfolio by lowering risk undoubtedly. And that's why we are having a farmout in Pará-Maranhão. We really liked the area. It was good surprise to all of us, so we keep on trying to mitigate any opportunities that we consider to lower the risk to our portfolio or to anticipate our revenue. We will really keep our eyes open. Despite everything that's happening to Brazil for the moment, the project we have in mind are quite sizable, a lot of upfront, a lot of cash. This is what the media shows. These areas are really good. So today we continue to see, and we've seen a couple of them, that make no sense to us, others were outside our financial feasibility be it short or long-term. We need some comfortable cash. And once opportunities come up we'll benefit from them. In the short term, despite the sale of Block BM-S-8, our intention is to be part of the game, of the presalt game. We want to be present to presalt. It really matches our long-term view. In terms of having a list of assets which provides good impact to our revenues and also bring in a lot of visibility and long-term operational visibility presalt also brings and is also top quality oil and this oil certainly has a lot to do with Enauta's goals. And it's also within the gas chain for the future. That's part of our intention. We believe that the energy required for transition. So we're going for it. And we are very interested within our possibilities and we are watching this very carefully and considering what we can do in the 6 bidding round and also the 16th for concessions. So within our possibilities if we find the right partners we'll share our strategy, then we can be included in these bidding processes.

[Unknown Analyst]

That's clear. Thank you very much. If I may, just one follow-up question about Atlanta. This $480,000 that you mentioned, this increase is only based on the FPSO contract. So my question is if we see oil prices increasing given that the chartering of the FPSO is linked to oil price, should we see a higher lifting cost? I don't know if it's clear, but that's my question.

[Unknown Executive]

Absolutely. There is a correlation with oil price, oil price is increasing. But there are 2 effects here. So you're right. If oil prices continue to increase with our current agreement, but there are some limits to it. But still what we see is that there is an effect which for us has been quite beneficial, a lot more beneficial for us than for the company that is leasing the FPSO to us because given the low sulfur content in Atlanta oil, this has a leveraging effect. A higher oil price is good for us. It helps us. And it is a difference that we're starting to see regarding oil price or the Brent oil price. The Brent oil price discount fell given the quality of the oil. And this tends to maintain. We actually -- we would like to have this decrease even more. With the new regulation for the bunker oil, the IMO, it's going to reduce from 3.5% sulfur to 0.5%. And our oil has less than 0.5% sulfur. So our oil will be in more demand. So we can definitely expect an increase in the fixed rate given the share that they can have above a certain value for the Brent. But there are -- so there are 2 factors here. And I mentioned there might be a reduction in the discount. And obviously the cost per barrel will drop given the increased production. Increased production will be higher, will be greater than the increase in the rate associated with the higher oil Brent -- Brent oil price.

[Operator]

Next question from Mr. Luiz Carvalho with UBS.

[Luiz Carvalho, analyst]

I have 2 questions. In your release you mentioned that the third well has been drilled and is now in the process of being completed and you expect oil flowing in the third quarter. Can you be more precise? Can you give us more visibility regarding the production of the third well? I just want to understand, you see, in terms of what we should monitor, in terms of timing. And my second question, yesterday in Petrobras' presentation to my surprise they showed one single slide about deepwater in Sergipe basin confirming the extended well test in Moita Bonita. I think that they've had about 6 discoveries. And in this region there's an FPSO allocated in their business plan ending in 2023. So I would like to understand from you, when do you expect a unitization process? When could this begin? Or have you started dealing with or discussing this with Petrobras?

[Unknown Executive]

Okay, Luiz, I understood you want to know when -- what will be the productivity of Atlanta well. The third well should start producing in late May, early June. There's some factors there. For example, today we have the completion of the well and there was a shutdown due to the vessel condition. So we want to have a ramp up, Luiz. You see, today Atlanta has 12,100 barrels. We expect the well will be producing -- let me give you a ballpark figure, potential number, 10,000 to 11,000 barrels. So Atlanta would start from 12,000 and would increase to 22,000 barrels a day. But we want to do this ramp up very slowly, maintaining the frequency of the pumps for the well increasing after 1 week and preparing a plan before 2020. And once production at this well is stabilized and the plant is stabilized then we will shutdown the first initial well that we will do the work over in to exchange the well inside -- or the pump inside the well. So we want to have this ramp-up looking at the well and also looking the change in the level of production at the production plant. And I think that only then we will know the accurate potential of this third well. And of course, we have to look at porosity, saturation, permeability, already given by the logging. But in terms of a production, we'll have a dynamic production. So I could tell you perhaps then within 15 days once production starts, perhaps in the first week of June at the latest we'll have a pretty good idea of how much or what is the potential of the well. That could give us an idea of what the other 2 initial wells could produce once we exchange the pumps inside the well in terms of productivity, okay? And I know you're knowledgeable, so I'm going to turn the floor to Mendes now who can speak about the consequences of this very important discovery by Petrobras and regarding the areas that we have in Sergipe.

[Jose Milton Mendes, executive]

Hello, Luiz, this is Mendes speaking. Yes indeed, this was good news from Petrobras regarding the discovery in Sergipe-Alagoas basin. We mentioned another appraisal well in the region of Moita Bonita, confirming the potential of this area. In this important discovery by Petrobras. Petrobras also commented with the press some initial values regarding a discovery Poco Verde. This is data that we have not access to until now. No information not only about the first FPSO but Petrobras considering the possibility of a second FPSO in Sergipe area. So these are very, very good news. And I'm happy about that. We have some blocks in Sergipe-Alagoas basin, so we are very satisfied because we are in the region which is proven to be very promising. And regarding interpretation, it's a little prematurely. We're in the process of interpreting the data. We have to prioritize the areas where we should start drilling. So we cannot talk about the unitization at this point. This is a little too soon.

[Operator]

Our next question comes from Andre Hachem with Itaú BBA.

[Andre Hachem, analyst]

Lincoln, I have basically 2 questions regarding Atlanta. The first is about the oil realization price from Atlanta. We mentioned that we would have a much higher discount, about $11. Some people mentioned $15. And we have seen a much lower discount, something close to $7, $8. So I would like to understand the dynamics there. What about the realization of Atlanta oil? Can you elaborate? And my second question is a follow-up of the first question, regarding lifting cost, regarding production cost at Atlanta. We have seen in the release that the production cost has been way below than the $410,000 informed. Could you give us more color regarding why this number is so much lower and how recurring is this level looking forward? Thank you.

[Paula da Costa Corte-Real, executive]

This is Paula speaking. Indeed, as we start selling Atlanta oil we saw discounts that were lower than initially forecast. We had talked about $18, $20 discount. But as the oil started being sold, for the benefit of the project we started seeing much lower discounts. These discounts are still at the level of $13, sometimes reaching $15, that depends on the offtake. And this is not just a discount. When we talk about a discount, it's not a discount which is oil quality related. The discount includes the price paid by the refinery. There's a discount because this is heavier oil. But it includes logistics costs that make up this amount of this value. And the choice for best alternative is based on the company's strategy to expand the market to make our oil more well-known because this will favor the project in the future, particularly when we have a higher production.

[Andre Hachem, analyst]

And what would be the net back for the company, including value given quality of the oil and logistics costs for this quarter?

[Paula da Costa Corte-Real, executive]

Yes, we are talking about a discount of around $13. Our expectation, as Lincoln mentioned, is that this discount will be further reduced in the future. First, because as we increase the volume of production, logistics costs tend to drop in terms of amount per barrel. Some logistics costs -- in some logistics costs there will be a gain. And also because of the regulation in the sulfur content requirement for bunker oil. And Atlanta oil will benefit from that because it is heavier oil but with very, very low sulfur content which is quite rare. And we believe that this will expand the market and improve the discount. But in this quarter, on a reported basis we are talking about $13 discount, which is what we have been informing the market. As for cost, we have verified, as I mentioned in my answer to Rodrigo, we have seen lower costs than the $410,000. We had an impact because of logistics what we were estimating, the cost has been lower. So some contracts that we have standing by with some redundancies. Well we have used those less than that we had initially forecast. It's hard to say whether this reduction will continue until year-end when we are going to have a change in level to $480,000. So we prefer to maintain our expectation at $410,000. But yes, indeed we have seen in this quarter specifically, I don't know if you remember, but in the end of last year we had a delay damage clause with Teekay because of the chartering agreement for the FPSO. And the amount recorded in the balance sheet is in dollars. And in this quarter, specifically we had a foreign exchange accounting effect which reduced this cost a little. So in addition to lower logistics costs in this quarter specifically, we had a daily cost in dollar that was lower. Our functional currency is reals, the BRL. So but we get the effect of the foreign exchange in the balance sheet and on the results of the company. So in this quarter we had a foreign exchange variation impact that reduced the cost a little more. And that's why we think that looking forward we should work with $410,000 a day until we increase the level to $480,000.

[Andre Hachem, analyst]

How big is this effect?

[Paula da Costa Corte-Real, executive]

I did not understand the question.

[Andre Hachem, analyst]

How big was this nonrecurring foreign exchange gain?

[Paula da Costa Corte-Real, executive]

It's actually, it's a combined effect, foreign exchange and logistics. Net of these two effects, I think that we would be closer to the previous average, the previous average lifting cost per day. In this quarter, more specifically, we have these two nonrecurring impacts.

[Operator]

The next question is from Christian Audi with Santander.

[Christian Audi, analyst]

I would just like to clarify 2 points. Lincoln, coming back to the use of capital topic, how would you consider M&A opportunities, dividend payout or spend more in exploration CapEx? How do you rank these three elements considering the company's position today? The second question is just a follow-up question. In the beginning you talked about downtime. For the second, third and fourth quarter, do you have any scheduled maintenance that will be more significant or shutdown that might have impact more significantly in your results?

[Lincoln Rumenos Guardado, executive]

Hi, Christian, Lincoln speaking. Thank you for your question. It's a pleasure having you with us. With regards to this rank, let me tell what it is, what is our adequate ranking. Naturally we have a dividend program and it will keep on being active BRL 0.15 per share and it's still applicable. However, we also expect, as we increase our revenue and income, we expect to change this dividend payout method via or through a program. That's what we are always fighting for. In the current scenario our cash position and some of the actions in disposal, divestment, BM-S-8, the [ GP ] which also brought us some cash relief and more predictability of capital allocation, this all led us to consider the dividend payout, the special dividend payouts last year and in the current year. That's not a general rule and it's not our intention, except there is no other kind of impediment. So we can, number one, continue to consider any possibility of having an asset in early production or on production. What we have in mind today, well, it's very challenging right now because we have things that are shallow waters or onshore or mature assets at the end of life. I'm not saying they are bad, but it's not along the company's lines or assets whose size are beyond our financial capacity. Let me mention a couple of them like Tartaruga Verde, Marlin, et cetera, which undoubtedly prevented us from joining. But that diversification of revenue origin and source is always on our radar, are the areas that could not reverse the picture and these constraints, either because they have liabilities like abandonment that might heavily impair the company's status. So we haven't come to a solution yet. But this diversification of revenue is one of our priorities. But it's not easy to find a good match considering the market constraints and the market with new cycles and very high barrel conditions even though they are still very attractive. Secondly, what about the [indiscernible]. As a big effect we have our improved portfolio in terms of risk reduction. And we don't deny, we search for having some new composition of any possible stake that is compatible to our size. It might be in the area of the blocks that are in the offer in the sharing system or in the concession system. What we see today, and based on the attractiveness generated, we would like to have a secondary stake, 20% tops, but which would allow us to consider in the future our future CapEx. So these rounds even though they are our second priority they are more visible, because they have multiple entry points that are very clear and straightforward, particularly when we consider presalt and not only bidding. So we have a minimum, it is open along. So it allows us to have a more strong calculation. And we also consider some kind of dividend provided the first assumptions or both assumptions and these are the assumptions for investments, our commitments and we have a couple of these assumptions in the midterm or starting '20 or '21 provided they are all met. Whenever that happens, we might consider naturally some kind of dividend payout. Always bear it in mind that's a policy set by our board and also by the controlling shareholders. But there is no doubt it's part of the policy. We don't want to turn extraordinary dividend payout into a policy. But whenever we did it we always took into account future investments. And this strategy to try to improve even further our mid to long-term portfolio considering that production assets of average size offshore, for instance, they are rare. What we find more commonly are better outlook particularly for Petrobras not only moving away from some marginal assets for them but at the same time monetize things with a considerable size considering the strategy proposed. Unfortunately that was not a perfect match with our possibilities, okay?

[Operator]

[Operator Instructions] This concludes the question-and-answer session. Would like to give the floor back to Mr. Lincoln Guardado for the closing remarks.

[Lincoln Rumenos Guardado, executive]

Well, my friends, thank you very much for joining us in this call for questions. I have to recognize that we are very, very happy with our results and with the fact that we are able to increase our production with immediate effects on our cash flow, now having more visibility regarding future exploration drilling that can increase our reserves. And at the same time, we're thinking about our shareholders with a significant payout of dividends, again causing no trouble whatsoever in our forecast of capital allocation in the short to midterm. Of course, in the future we'll need more capital, meaning the most likely we are going to have a lot more to develop. I'd like to thank you again. I would like to say that we are very, very satisfied with the results that we obtained, particularly operating results. And we expect that in the second quarter we'll be back reaffirming our belief in terms of an increased production from Atlanta. Thank you very much.

[Operator]

This concludes Enauta's conference call for today. We would like to thank all of you. And have a good day.