Edited Transcript of QGEP3.SA earnings conference call or presentation 12-Mar-20 2:00pm GMT

Another impact of — from this price war is related to the indebtedness level of U.S. shale producers. Here, it is also important to highlight that Enauta has one of the lowest leverage levels in the industry, and that we ended the year with a net cash position placing us in a more comfortable position facing these events. That said, we will move on with the quarterly results presentation, and we can talk more about these impacts in the Q&A.

Please go to Slide 4 for the highlights for the period. The quarter and the year were periods with a combination of positive factors, such as increased production, competitive oil barrel prices, higher gas demand and lower lifting costs, which led to a significant increase in our operating revenue and overall financial results. Atlanta Field had 2 main highlights in the quarter. Total production since first oil reached 10 million barrels of oil produced at the field, positioning us as the 6th largest oil and gas producer in Brazil at the end of 2019. And we began the pricing process for the implementation of Atlanta’s Full Development System, considering 1 FPSO with a capacity of 50,000 barrels of oil per day, and drilling of up to 9 additional wells.

Regarding the Sergipe-Alagoas Basin, the consortium continues to evaluate seismic data on the first 6 blocks acquired. And processing of the final data should be completed by the end of the first half of 2020. 2 of the 3 recently acquired blocks are already covered by the seismic. The grand schedule considers drilling of 1 well in early 2021.

Let’s go to Atlanta Field highlights on Slide 5. We reached the average daily production of 28,500 barrels, up from 22,100 barrels per day in Q3 ’19 and 12,400 barrels per day in the fourth quarter of 2018 when we operated only 2 wells. Average operating efficiency of the FPSO was 98.9% compared to 98.2% in Q3 ’19. And we had 0 nonfatal days lost incidents. In the fourth quarter, we continued to see a reduction in the oil discount compared to Brent, which ended the year at $8 to $11 per barrel and continues to narrow.

In January, we already had our first offtake that traded at a premium to Brent, including logistics costs. We believe this is mainly due to the enactment of IMO 2020, which reduced the limit of sulfur content in bunker fuel. As you know, sulfur content of the oil produced at Atlanta is one of the lowest in the market, which gives Enauta the edge from both a commercial and environmental standpoint, since the other option, which is installing vessel cleaning systems is not allowed in all countries due to the disposal of waste water into the ocean.

Another highlight in Atlanta, we see stable average lifting cost in Q4 ’19 at $16.6 per barrel per day compared to $16.5 in Q3 ’19. This already takes into account the higher fees agreed upon in the original agreement following the first 18 months of reduced fees. This should be the average level maintained over the course of 2020.

On Slide 6, we have Manati Field highlights. Average daily gas production at Manati reached 4.5 million cubic meters in Q4 ’19, an increase over the prior quarter due to the increase in gas demand starting August after thermal power plants resumed operations. For the year, average daily gas production stood at 3.6 million cubic meters, below our projections.

Please note that the take-or-pay contract obligation is 3.8 million cubic meters per day, which determined the amount to be paid by Petrobras in 2019 regardless of the demand. In 2020, our financial compensation forecast corresponds to an average daily gas production of 2.8 million cubic meters with a margin of approximately plus or minus 10%.

Moving on to the financial highlights on Slide 7, please. You can see that our revenues grew 28% quarter-on-quarter and 39% year-on-year. One of the main highlights was the increase in production at Atlanta Field, which in Q4 ’19, contributed 68% of total revenue. The 60% revenue increase over Q4 ’18 was mainly due to the increase of 133% in production sold in the period, the foreign exchange appreciation of 8% and the lower discount in oil compared to the Brent of 38%.

Looking at the year 2019, net revenue from Atlanta Field accounted for 64% of the total, an increase of 145% from 2018, mainly due to the substantial increase in the field’s production. Manati Field accounted for 32% of total revenue in Q4 ’19. Despite the 6% year-over-year decrease in production, total revenue grew slightly by 2% from Q4 ’18 due to the annual adjustment of gas sale prices. For the year, Manati revenue dropped 20% due to lower production, which went from an average 4.9 million cubic meters to 3.6 million cubic meters, reflecting the natural decline of the field.

On Slide 8, we have the breakdown of costs. Before talking — taking a look at the figures, it is important to mention that the impact of IFRS 16 on the income statement reduced operating costs and increased depreciation and financial expenses, benefiting the company’s EBITDA and EBITDAX. In the balance sheet, a new line was added to assets with a corresponding offset in current and noncurrent liabilities under leasing.

In the fourth quarter of 2019, operating costs reached BRL 226 million, 24% higher than in the fourth quarter of 2018. The adoption of IFRS 16 led to an increase of BRL 13.3 million in operating costs in the period, including the effect of increased depreciation of BRL 46 million. Manati’s operating costs increased 65% higher than the same period of 2018. The adoption of IFRS 16 increased operating costs in BRL 17 million, including BRL 146 million depreciation effect.

Operating cost in Manati were 28% lower than 2018, reflecting lower costs related to royalties, payment of special payments, research and development and reduction of depreciation, lower — to lower production in the period. It did not offset an increase of 117% of Atlanta’s operating costs directly related to the growth in production and the effects on IFRS 16 and nonrecurring costs associated with the workovers of the first 2 wells, amounting to BRL 68.2 million.

On Slide 9, we have general and administrative expenses and exploration expenses. During the year, general and administrative expenses experienced a downward trend due to higher operating efficiency. In Q4 2019, as a percentage of revenue, G&A expenses were 110 basis points lower than a year ago, reaching 5.8%. For the year, G&A expenses were 11% lower than in 2018. As a percentage of total revenue, G&A expenses in 2019 accounted for 4.1% compared to 6.4% in 2018, a decrease of 230 basis points. Exploration expenses were BRL 22.5 million in Q4 2019 compared to BRL 9 million in Q4 2018, mainly due to studies for environmental drilling licensing and cost of acquisition and seismic processing for the blocks of the Sergipe-Alagoas Basin.

For the full year 2019, this cost amounted to BRL 82 million compared to BRL 54 million in 2018, mainly due to the provisioning in the third quarter of 2019, reflecting a fine in the amount of BRL 27 million for failing to comply with the amount established in the concession agreement Block BM-CAL-5. The operator informed us that they are waiting for the conclusion of the administrative proceeding and will possibly sign a consent decree. The increase in expenses also includes expenditures of $800,000 related to the return of the Oliva Field, and other cost of seismic processing and environmental license studies for drilling activities in the Sergipe-Alagoas blocks.

On Slide 10, you can see our profitability measured by EBITDAX and net income. In the fourth quarter of 2019, EBITDAX amounted to BRL 260 million, an increase of 63% from Q4 2018. The positive impact from the adoption of IFRS 16 was BRL 60 million. Note that in Q4 2018, EBITDAX benefited from BRL 46 million under the supplier agreement in the Atlanta Field’s FPSO. Excluding these effects, EBITDAX in Q4 2019 was BRL 200 million, 76% higher than the BRL 114 million recorded in Q4 2018 due to an increase of 50% in our operating results. Adjusted EBITDAX margin reached [18]% compared to 38% in 2018, an expansion of 37 basis points. In the year, EBITDAX was BRL 670 million, growing 18% vis-à-vis the same period of the last year. Please note that both periods were impacted by nonrecurring amounts.

EBITDAX in 2018 benefited from BRL 46 million under our supply agreement of Atlanta, like I said. And BRL 148 million referring to the first installment of the sale of Block BM-S-8. In 2019, workovers in Atlanta Field wells had an impact of BRL 68 million, which for the calculation of EBITDAX, were offset by BRL 60 million related to IFRS 16. Excluding these effects, EBITDAX in 2019 would have been BRL 685 million compared to an EBITDAX of BRL 351 million in 2018. EBITDAX margin was 62% compared to 48% in 2018, an expansion of 138 basis points.

Net income in the fourth quarter of 2019, BRL 102 million compared to BRL 125 million in Q4 2018, reflecting the higher operating results, offset by higher exploration expenses and lower financial results. The increase in amortization mainly reflects the start-up of the Atlanta Field, which completed its first full year of operation in 2019. In the year, net income amounted to BRL 215 million, a reduction of 49% vis-à-vis 2018 because in 2019, it benefited from gains from the sale of Block BM-S-8.

On Slide 11, we talk about cash and indebtedness. We ended the year with cash and cash equivalents of BRL 1.7 billion, 11.6% lower than the cash balance recorded at the end of 2018, reflecting a payment of BRL 500 million in dividends in May 2019. As for indebtedness, we ended the year with a total debt of BRL 252 million compared to BRL 290 million in the same period of the prior year. As a result of payments to FINEP starting September 2016, and payments to BNB starting October 2019. We further reduced our leverage during the year, demonstrating financial strength particularly important in volatile markets such as we are seeing today.

On Slide 12, CapEx. You can see our realized CapEx in 2019 and a breakdown of investments projected for 2020 and 2021. We ended 2019, having invested $50 million, which was below our budget of $63 million, of which $38 million or 76% was allocated to the Atlanta Field. Of this total, nearly BRL 2 million was the amount spent in Q4 2019, 100% allocated to the Atlanta Field. For 2020, total expected CapEx will reduce to $46 million due to the postponement of equipment acquisition for the Full Development System in the Atlanta Field for 2021. We currently estimate investment of $14 million in the Atlanta Field and $20 million in blocks located into Sergipe-Alagoas Basin.

For 2021, the company estimates total CapEx of $150 million, of which $85 million will be allocated to the Atlanta Field. This estimate reflects costs associated with the early acquisition of equipment required for the field’s production under the Full Development System, which is in the pricing phase. $48 million will be allocated to Sergipe-Alagoas for the start of drilling at the basin. Please bear in mind that we currently do not foresee any additional changes to our CapEx estimates for 2020, 2021, in light of the recent market events, but we’re keeping our eyes open to how it unfolds.

Enauta continues to grow and expand. Pursuing the path for energy in Brazil, we are proud to have produced 10 million barrels of oil in Atlanta with 0 nonfatal days loss incidents and over 98% operating efficiency. This is a very important milestone for us, demonstrating the success of our strategy in the field. We have been monitoring the success of exploration in the Guyana and Suriname, where prospects with material volumes of oil resources have been identified. For this reason, we remain confident in the potential of the Sergipe-Alagoas Basin due to the progress of exploratory interpretation.

We also made progress in governance, and currently have one of the highest diversity levels in the industry with a total of 42% women employees and 35% women in management, and these figures make us very proud. In light of the last bids and the government’s repositioning regarding economic conditions for the bids, especially for pre-salt, the company is reviewing its outlook regarding a possible entry in the pre-salt area and/or timely acquisitions.

I finish my presentation here, and we are now available to take your questions.

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Questions and Answers

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Operator [1]

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(Operator Instructions) Our first question comes from Gabriel Barra with UBS.

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Gabriel Barra, UBS Investment Bank, Research Division – Associate Analyst [2]

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I have 2 questions. The first is, and please correct me if I’m wrong. In 2018, I think Lincoln or Danilo mentioned that oil at $40 would start the Full Development System with a narrow return. I know that this is for the long term. The short-term is not influenced by that. But we know that everybody is thinking that in the oil and gas market. Has anything changed regarding the breakeven for the Full Development System today? What would be the breakeven for the project? Do you have a different number? And if oil prices remain low, and if you think you’re not at the right level, would you have a plan B for Atlanta? My second question has to do with Petrojarl and the EPS. You said that after 18 months, the charter rate would go back to the original price. And I think you mentioned something similar to what you have said before. With the Brent oil price dropping, would this value stay at the same level? Or should we expect a daily rate that would be lower, considering something around $30 per barrel along 2020?

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Paula Vasconcelos da Costa Corte-Real, Enauta Participações S.A. – CFO, IR Officer & Executive Board Member [3]

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Gabriel, thank you for the questions. Regarding Full Development System at Atlanta, as I mentioned in the presentation, that we are in the pricing phase. In the first half of the year, we’ll be collecting the prices. And this will help us gauge our breakeven in our operating costs and even the CapEx for the field. And so we are at the pricing phase with the market now.

To date, we don’t have any relevant information that would change the estimates that we had back in 2018. What brings us a certain comfort is exactly what you mentioned, and we have to look at the long-term curve.

I believe that the market will recover its prices. And even when the price was higher or lower, we always look at the long-term converging at a rate of $50 to $60 per barrel. Of course, this varies a little up and down. Right now, we are living a moment of volatility, and we are monitoring the trends, but we’re at a phase, at a pricing phase, which is fundamental for the next steps at Atlanta. And we’re taking everything into account, including the design of the field, the number of wells and so on and so forth, we benefit from operating information we collected from the field. We’ll be collecting the prices in a more volatile market moment, and we’ll see the impact of that on the operating costs and CapEx for the field.

But so far, as I mentioned, we are paying attention to everything that is happening, of course, the whole world is. It wouldn’t be different in an oil and gas company. So we are paying attention to everything, but we haven’t reviewed our CapEx, and we haven’t reviewed the strategy of the company. Your second question had to do with operating cost of Petrojarl. We continue to work with that level of $500,000. If you ask me, if there will be any reduction because of Brent price, yes, there is a reduction in the daily rate according to Brent price. Of course, it’s less representative than the impact on revenue. Actually, I would prefer the cost of $500,000 per day, but it can have perhaps a 10% reduction or a little less. But our estimates remain of around $500,000 per day, and there might be some slight variations according to Brent price.

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Operator [4]

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Next question from [Paula Picardo] with Condor Insider.

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Unidentified Analyst, [5]

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Congratulations on the presentation. I would like to ask regarding the price oil. What is the long-term impact, in your opinion, particularly regarding dividend payout? Do you envision a possible increase in dividend payout anytime soon?

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Paula Vasconcelos da Costa Corte-Real, Enauta Participações S.A. – CFO, IR Officer & Executive Board Member [6]

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[Paula], regarding dividend payout in the future, we have a dividend payout policy approved by the company. And this policy was approved in 2015. And this is a $0.15, about $40 million approximately per year. In the last 3 years, we had approval of supplementary — in the last 2 years, actually, we had the approval of supplementary dividend payout. In this year, it is in our proposal, and this will be deliberated during the Annual Shareholders’ Meeting, considering BRL 300 million worth of supplementary or extraordinary dividend payout. For the coming years, what we have to date, at the moment, is the company policy, $0.15 per share. But of course, dividend amounts always depend on the variation of capital allocation of the company, of surplus of cash, investment commitments. So this is a discussion that happens every year. So what we have approved today is our dividend payout policy.

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Operator [7]

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(Operator Instructions) Our next question comes from Guilherme Levy with Morgan Stanley.

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Guilherme Levy, Morgan Stanley, Research Division – Research Associate [8]

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Actually I have 2 questions. I would like to understand this additional well that will be drilled at Atlanta Field in early 2021. That would be the first one in the Full Development System. And you mentioned that it could also be a backup for water injection in the Early Production System. Could you comment on what you expect in terms of increased water production? And my second question, if you could comment on this new project of gas storage at Manati Field?

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Paula Vasconcelos da Costa Corte-Real, Enauta Participações S.A. – CFO, IR Officer & Executive Board Member [9]

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Guilherme, thank you for the questions. I will turn the floor to Danilo.

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Danilo Oliveira, Enauta Participações S.A. – Chief Production Officer & Executive Board Member [10]

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Guilherme, the fourth well, well the consortium decided about a year ago to acquire all of the necessary equipment, and to schedule, in principle, drilling for early 2021. And the explanation for that is simple. Atlanta Field has a water reservoir, which is responsible for the maintenance of pressure at the field. In other words, it is what pushes oil out. And we have a simulator, which indicates when the water will surface. But we are not sure of that until water actually surfaces. So we are prepared to drill this well in the first half of 2021, if it is necessary. We have 3 producing wells already. One of them already shows presence of water, which is good because it confirms water movement pressurizing oil for production maintenance. Today, this BSW is below 1% in 30,000 barrels a day. This accounts for 300 barrels. So it’s low, still low, but we have to monitor this.

Petrojarl has the capacity to treat water of about 6,000 barrels, which makes us have a production capacity of up to 6,000 barrels of water, up to 20% of BSW. So we are comfortable with that. And this fourth well is being considered in case we do have water. But all of that will have to be decided by the consortium in terms of approval and confirmation of drilling in 2021.

Regarding your second question, Manati gas storage. The Manati reservoir is extremely adequate for this kind of work. We are now at the moment when we have surplus supply of gas considering the demand. So the market see the development of a gas storage reservoir with good eyes. We have the necessary facilities. We can easily connect the field with the Bahia regasification terminal, and we have a plant, all belonging to the consortium, and which is perfectly adapted to this purpose. So we are conducting the studies, economic feasibility studies, and we are discussing with the company — with the companies of the consortium to make a decision to convert Manati into a gas storage field in late 2021, early 2022, if everything goes well.

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Guilherme Levy, Morgan Stanley, Research Division – Research Associate [11]

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Excellent. But just to confirm, I’m a little bit in doubt here. In the additional well at Atlanta, this would be another producing well, so that when the production at the third initial wells start declining. I remember that you wouldn’t have injection wells in this project, right?

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Danilo Oliveira, Enauta Participações S.A. – Chief Production Officer & Executive Board Member [12]

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Yes. This is correct. Atlanta will not have injector wells. The fourth well is — will happen in case one of the wells reaches a water volume that when comparing with a new well, the new well would give us a higher oil productivity, than this well will be replaced by the fourth well. It is a backup well to replace a well that might start producing more water than we would produce of oil in the new well.

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Operator [13]

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The next question is via webcast. Fábio Machado with Multinvest Capital.

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Fábio Machado;Multinvest Capital;Analyst, [14]

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With regards to the discount of Atlanta oil, this range between $8 to $11, is it on a nominal basis? Or does it vary according percentage-wise to the Brent oil price? And what about the cost of production in Atlanta in a Brent scenario at $35. What is the daily cost since it ranges according to the Brent oil price?

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Danilo Oliveira, Enauta Participações S.A. – Chief Production Officer & Executive Board Member [15]

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Brent discount is nominal. There is no percentage when it comes to Brent. It is a flat fixed amount, which is according to the water quality for Brent. And also logistics costs required to have the oil in the refinery.

As for the oil quality, like Paula said, we are in an upward trend. We already showed shipment with a premium vis-à-vis Brent. And this already takes into account logistics cost and the final cost is already Brent plus. And no percentage, it’s a nominal cost.

Regarding the reduction of operating costs in Atlanta, Paula already said, there is really a drop in Petrojarl daily rate, which is the only decrease in the cost that is possible. And it will be approximately 10% tops of our current operating costs. My estimate is that will be more related to 5% of the cost because it’s only on top of Petrojarl daily rate, all the remaining costs do not — or another factor to a reduction in Brent price.

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Operator [16]

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The next question is from [Vinicius].

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Unidentified Analyst, [17]

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When it comes to Sergipe-Alagoas Basin, is it possible to find oil in the same amount found by other companies in Suriname and Guyana?

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Jose Milton Mendes, Enauta Participações S.A. – Exploration Superintendent [18]

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What we are trying to get in our exploration box and not only Sergipe, but all exploration blocks of Enauta’s portfolio Foz, PAMA, Ceará, Camamu, Espírito Santo, always have in mind the same oil system that has proved to be right in Sergipe-Alagoas. So we do like to compare our assets compared to what we said. So we have something is more distal vis-à-vis where Petrobras has 6 significant discoveries, and you are expected to be commercially disclosed by the end of the year. So this is part of the same diesel oil reservoir system of an offshore sedimentary basin. So the prospects that we mapped in the area of our blocks are distal to the model found by Petrobras in more proximal blocks of the basin. So naturally, if we are searching for prospects that are economically feasible and 3,000 square meter of water, we have to think about how to map several prospects with possible material reserves that may bring economic discoveries, our prospect, not only Sergipe, but also Foz, PAMA, Camamu, Espírito Santo.

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Operator [19]

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The next question is from Leonardo Marcondes with Itaú BBA.

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Leonardo Marcondes, Itaú Corretora de Valores S.A., Research Division – Research Analyst [20]

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Now that the FPSO of Atlanta Full Development System is already at 50,000 barrels per day, could you give us more color on the price range — daily price range? I’m asking because I believe the market has, as a proxy, a platform of 70,000 barrels per day and Petrobras also did it for the modeling project.

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Danilo Oliveira, Enauta Participações S.A. – Chief Production Officer & Executive Board Member [21]

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Leonardo, unfortunately, that’s a question that we shouldn’t answer. Right now, we are in the middle of the bid process, and we cannot set any estimated price for the platform. We have to wait until companies bring this price to us. We have our internal assessments, and we cannot set any values to the market yet. For the moment, all we can say is that we are going to market, but how much we’ll get at the end of the day, we just have to wait and see.

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Operator [22]

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Next question, also from the webcast, by [Sérgio Simon].

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Unidentified Analyst, [23]

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It is well-known to all that the amount of production is 100% negotiated with Shell. What about the price per barrel given this crisis? Is there any stop clause? Anything that can ensure, say, a minimum price? A reduction in oil prices will be absorbed by Enauta?

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Paula Vasconcelos da Costa Corte-Real, Enauta Participações S.A. – CFO, IR Officer & Executive Board Member [24]

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Sérgio, well, regarding the Shell contract, we don’t have any stop mechanism — any protection mechanism for Brent oil price. Shell works as a trader for the company. In other words, it sells our oil and looks for the best alternative to sell the product, but we are always subject to Brent price variations.

What we have internally is a market risk management policy, and we incorporate some hedging mechanisms or some protection mechanisms to cope with volatility of commodity prices. For the foreseeable future, we have a higher hedging percentage then for the long term. And that provides us protection exactly in case of a steep abrupt short-term volatility.

Of course, our business is, by definition, exposed to oil prices in the long run. So our hedging position today for this first half of the year, we have between 30% and 35% of our production already hedged with some put options for the oil at prices clearly higher than the current market prices, around $57 per barrel.

Now when we look at the whole 2020, we have about 25% of our production hedged. So as I mentioned, our hedging position is more concentrated in shorter periods of time than in the long-term because we mentioned that in the long run, we envision a rally in oil prices. So that is our protection mechanism. It is our internal policy. This is not included in the Shell contract — the Shell trading contract.

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Operator [25]

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Next question, from Pedro de Marco, Reach Capital also on the webcast platform.

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Pedro De Marco;Reach Capital;Analyst, [26]

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If you could revisit the hedging policy for the oil. And is there any change in the bidding of the Full Development System in terms of FPSO with a lower capacity? And this oil barrel price, most likely, there will be a reduction in the market — in the oil and gas market. So do you expect a reduction in the daily rates of the FPSO?

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Paula Vasconcelos da Costa Corte-Real, Enauta Participações S.A. – CFO, IR Officer & Executive Board Member [27]

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Well, regarding the hedging policy, I believe I have answered in the previous question. So I’ll turn the floor to Danilo, to speak about the FPSO.

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Danilo Oliveira, Enauta Participações S.A. – Chief Production Officer & Executive Board Member [28]

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There was a change compared to the original Full Development System that we have submitted to the agency. It was a system of 12 wells with an FPSO of 70,000 barrels. Today, we have an indication that the oil prices will be, for a long time, between $50 and $70. And not at a level of $80 per barrel, which was the level that we had when we designed the original FDS, Full Development System. So we reduced the capacity of the FPSO to 50,000 barrels per day. And the Full Development System will include 8 wells and 4 optional wells for the future.

This reduction from 70,000 to 50,000 will give us a maintenance of a certain level of oil and a reduction in the initial CapEx because we will not be drilling all of the additional wells at the same time.

Our plan is to drill initially 5 wells. We’ll connect them to the 3 original ones that we have. So in total, 8 wells for an FPSO with a 50,000 barrel per day capacity.

Now why 50,000 since the current 3 wells produced 30,000? Because we work with an average for the wells. We have 1 well producing 14,000, another producing 11,000 and another one which produces 5,000 barrels per day. And of course, the 5 additional wells were behaving the same way. Some might produce 5,000, others might produce 10,000.

The current producing wells, for sure by 2023, will not be producing at the same level as they are now. And that’s why we’re calculating that we’ll need 50,000 barrels so as to maintain — we’ll be able to maintain this level of 50,000 barrels a day for a longer period of time as we’re doing today with the 3 wells.

Petrojarl can only receive 30,000. We have the ability to produce a little more. And that is why the guidance for this year is, in practice, almost a 30,000 barrels per day for the full year, which is not normal for the field’s production. If I produce at my maximum capacity every month, there will be a reduction.

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Operator [29]

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Next question coming from webcast from [Vinicius].

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Unidentified Analyst, [30]

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Could you better explain the reduction of reserves — proven reserves at 19%?

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Danilo Oliveira, Enauta Participações S.A. – Chief Production Officer & Executive Board Member [31]

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Okay. This has to do with the previous question. If you think about an FPSO of 70,000 barrels per day and 12 producing wells, the production curve, at first, is way higher and delivers an oil volume that is included, so to speak, in the reserve. When you start at 50,000 barrels, the curve only goes down. So the oil I produce in the curve with FPSO at 50,000, the recovered oil is less compared to the volume in a curve that starts at 70,000. However, from the economical standpoint, in terms of NPV, the FPSO of 50,000 at 8 wells makes more sense to the consortium.

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Operator [32]

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(Operator Instructions) This concludes the Q&A session. I would like to give the floor back to Ms. Paula Costa Corte-Real for the closing remarks.

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Paula Vasconcelos da Costa Corte-Real, Enauta Participações S.A. – CFO, IR Officer & Executive Board Member [33]

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Well, in the first place, I would like to thank everyone for participating in this very challenging moment for the market. So I’d like to thank everyone for participating. I think that the questions were very constructive, so that we could explain the main points. And again, I’d like to say that the company remains available through our Investor Relations department. If you have any further questions, if you need any further clarification, we are available.

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Operator [34]

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That does conclude Enauta’s conference call for today. Thank you very much for your participation, and have a good day.

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