Vista Energy - Earnings Call - Q4 2020

Transcript

Speaker 0

Ladies and gentlemen, thank you for standing by, and welcome to Vista's Fourth Quarter and Full Year twenty twenty Results Conference Call. At this time, all participants are in a listen only mode. After the speaker presentation, there will be a question and answer session. It is now my pleasure to introduce strategic planning and investor relations officer, Alejandro Chernikov.

Speaker 1

Good morning, everyone. We are happy to welcome you to Vista's Fourth Quarter and Full Year twenty twenty Results Conference Call. I am here with Miguel Gallucho, Vista's Chairman and CEO and with Pablo Ella Pinto, Vista's CFO. Before we begin, I would like to draw your attention to our cautionary statement on Slide two. Please be advised that our remarks today, including the answers to your questions, may include forward looking statements.

These forward looking statements are subject to risks and uncertainties that could cause actual results to be materially different from expectations contemplated by these remarks. Our financial figures are stated in U. S. Dollars and in accordance with International Financial Reporting Standards, IFRS. However, during this call, we may discuss certain non IFRS financial measures such as adjusted EBITDA.

Reconciliations of these measures to the closest IFRS measures can be found in the earnings release that we issued yesterday. Please check our website for further information. Our company, Vista Oil and Gas, de Socirano, Mabustatile de Capitala Ariable, organized under the laws of Mexico, which is in the Bolsa Mexicana de Valores and the New York Stock Exchange. The ticker of our common stock are Vista in the Mexican Stock Exchange and BIST in the New York Stock Exchange. The figure of our warrants is BTW408A.

I will now turn the call over to Miguel.

Speaker 2

Thanks, Alejandro. Good morning, everyone, and thank you for joining this earning call. The year 2020 presented us multiple challenges, and I'm proud to say we are up to the task. The presentation I will share with you today shows how most of our key indicator reflect a V shaped recovery on the back of an structurally lower development and operating cost. In short, I believe we have emerged stronger from the crisis.

Our response to COVID pandemic has been firm, first and foremost, by protecting our staff and ensuring business continuity. We quickly established a health protocol for essential oil field operations. More than 75% of our staff was working from home by the March 2020. In July, we adopted a new protocol to restart drilling, completion and pulling activities. This allow us to tie in two four well paths in Baja del Palo Este, boosting our production that reached 35,000 BOE per day by year end.

Our continued focus on efficiency gave way to solid results. During 2020, we redesigned our type well based on increased productivity and cost reductions. This has led to unexpected development cost of approximately $8 per BOE. We also lowered our operating cost base by renegotiating more than 20 key oilfield services contracts. This led to a reduction in lifting costs to $8 per BOE in Q4.

Therefore, we turn this time to a company that is even more resilient to low oil prices environment. By year end 2020, our proved reserves increased to 128,100,000 barrels of oil equivalent. This imply a reserve replace ratio of 371% and an increase of 26% vis a vis year end 2019. This result is a clear reflection of the resilience I was mentioning earlier. We increased reserve even though for 2020 we used $42 per barrel of realized oil price compared with $56 per barrel in 2019 to run reserve economics.

We also increased our well inventory by derisking the lower carbonate line in zone in Baja del Palo Verde with two successful wells with 2,400 meter laterals. Solid well productivity proved the lower carbonate as an economic play, enabling us to add 150 wells to our drill inventory, which now totals an estimated of five fifty wells. In 2020, we also maintained a strong focus for sustainability. Our safety metrics continue to improve, having completely reworked safety standards and procedures since we took over this operation less than three years ago. Our total recordable incident rate for 2020 was 0.38, down from 1.25 in 2019, which was already in line with international Tier one standards.

Our first sustainability report will be published at the April. After restarting drilling and completion in Q3 twenty twenty, we continue to see improvement in our performance metrics. Drilling speed in Pad 6 was 108% above pad number one, a remarkable learning curve. When we started our shale oil development, drilling a well with 2,800 meter lateral would take us more than thirty five days. Today it takes us less than twenty days.

The consistent improvement in drilling speed allow us to tie in path number six, sixty days before the scheduled date boosting our production exit rate for the year. During 2020, we captured cost reduction in drilling and completion service rate as well as tubular, propane and flat sewing costs. In Part six, drilling cost per lateral foot was down to $472 a 37% improvement compared to Part one. Similarly, the completion cost for part number six was down 45%. Finally, drilling and completion cost per well was $9,900,000 per part number six, a 43% improvement compared to part number one.

Additional efficiency was obtained by an improving well design. As shown to the right of the slide, we are increasing lateral length and total frac stages. These are key drivers to increase well productivity and to reduce development costs to our target of approximately $8 per BOE. At the $9,900,000 cost per well achieved in part number six, the development cost would actually be below $8 per BOE. We will deep dive into well productivity in the next two slides.

The chart on the left shows the production performance of our wells in Bajada Del Palo Este. Each well shows in gray line. The blue line is the average production of all wells, which is 25% above our type curve, showing black. I will give you some additional color on our twenty twenty performance. Three wells we landed in La Cocina corresponding to pad three and four set Vaca Muerta records for thirty day peak oil.

During the 2020, we accelerated drilling and completion activity and tie in pad number four and number five. This boosted our production in Bajada Del Palo Este to an exceed rate of 20,200 BOE per day in December more than tripping our production year on year. Finally, in the second half of the year, we started our gas lift pilot in pad number one and number two. The preliminary result of this artificial lift system, it is a good fit for Vaca Muerta horizontal wells. In the first two parts, we achieved production increases of around 20% after conversion to gas lift.

Slide six shows the comparison of our wells against peer wells in the Permian and Vaca Muerta Basins. I shared a previous version of this chart one year ago and the message is the same. Our ability to deliver world class productivity is still intact. In the top graph compared to the Permian wells, 40 of our wells are top quartile whereas our best eight wells ranked in the top 10%. This comparison is on normalized basis.

Compared to Vaca Muerta wells in the bottom graph, all our wells fall within the top 25%, whereas our base 11 wells are top 10%. Vista twenty nineteen wells are shown in purple and twenty twenty wells are shown in black, highlighting that the productivity of our wells is ranking better year on year. Our audit proved reserves at the 2020 stood at 128,100,000 BOEs, up from 101.8 at the 2019. Our reserve replacement ratio was 371% in total and 512% for oil. Net additions were mainly driven by the incorporation of 30 new well locations in Bajada Del Palo Este.

Shared reserves are now 70% of our total proved reserves. As important driver, we are increasing 10% of tight wells EUR and lower lifting costs. Such improvement more than offset a 25% decrease in realized oil prices. During 2020, we maintained a solid cash position in a very challenging macroeconomic environment. Our cash flow from operating activities was solid at $93,800,000 despite average realized oil prices that were down 30% with respect to 2019.

Cash outflow from investment activities was $156,100,000 During Q2, we stopped all drilling and completion activities in response to the sharp contraction in oil demand. We took advantage of the flexibility embedded in our contract to reduce our CapEx run rate. In August, with demand recovery, greater prices visibility and our new well design, we ramped up activity again. We used a second rig to drill an additional pad and tie it in before year end. Therefore, in Q4 twenty twenty, cash from investing activities was $55,900,000 more than 2x Q2 and Q3, positioning Vista to capture the upside presented by the recovery of redized oil prices.

Cash from financial activities was positive at $25,700,000 during 2020 and we successfully raised $100,000,000 in bond in the Argentine capital market at a single digit. I will now go through a summary of our main metrics for the year. Proof reserves were up 26 year on year with 128,100,000 BOEs as of December 2020. Total production was 26,006 BOE per day, 9% down year on year impacted by the effect of the COVID-nineteen on crude oil demand during Q2. Oil production stood at 18,300 barrels per day, up 0.4% from 2019, driven by the ramp up of activity in Q3 and Q4 in Baja del Palo Verde, which has more than 90% of oil production.

Realized oil prices were $37.2 per barrel on average for the year, 30% below 2019 as the reduction of oil demand caused a contraction in international oil price. Revenues were $274,000,000 34% down year on year impacted by the lower production and prices. Listing costs improved 70% to $9 per BOE, down from $10.8 in 2019. During Q2, we set up a specific task force to renegotiate more than 20 key oilfield service contracts to rebase our cost structure with savings incurred on permanently lower rate and higher efficiency. Adjusted EBITDA was $96,000,000 for the year, down 44% vis a vis 2019, but showing a strong sequential recovery during the year as you can see in the chart on the right.

CapEx for the year was $224,000,000 in line with 2019 and thirty percent lower than our original 2020 plan guidance. Finally, cash at the end of the period was $2.00 $3,000,000 which leaves us in a solid position to fund investing activities during 2021. In sum, 2020 was a challenging year, but we have successfully weathered the storm. Key metrics have a V shaped recovery, including total production and adjusted EBITDA as shown on the right. Q4 twenty twenty metrics are solid, showing progress vis a vis pre pandemic levels.

I will discuss the 2020 in the following slides. Production in Q4 twenty twenty was 30,600 BOE per day, a 21% improvement quarter on quarter driven by activity ramp up in Baja del Palo Verde. Oil production increased 31% quarter on quarter to 23,100 barrels per day. Revenue were $18,000,000 increasing 14% vis a vis Q3 twenty twenty driven by improvements in production volumes and price. Q4 twenty twenty lifting costs came very solid at $8 per barrel, thanks to our effort to keep expenditures under control amid production increases due to diluted fixed costs.

Adjusted EBITDA improved 48% sequentially to $36,000,000 for the quarter. More importantly, it is up 1% year on year reaching an adjusted EBITDA margin of 45%. CapEx in Q4 was $97,000,000 for the quarter driven by the activity ramp up I mentioned earlier. Finally, cash at the end of the period was a solid $2.00 $3,000,000 with net debt at $330,000,000 This constitutes a robust starting point to keep developing Bajada del Palo Verde in 2021. Moving to Slide 11, total production is fully recovered from the COVID-nineteen pandemic impact, and it is actually up 2% year on year.

We are back on our profitable growth path driven by our Baja del Palo Alto development. Oil production is 23% up year on year and 31 sequentially due to the result of Part four and the early tie in of Part five. Gas production during the quarter decreased 3% sequentially as we continue to focus our development in Baja del Palo Este, which is a light oil asset with associated gas production. Revenues for the quarter increased 14% with respect to Q3, mainly driven by higher crude oil production. Paradise oil price was essentially flat quarter on quarter, but is still down year on year, impacted by 27% decline in Brent.

We have partially offset this effect through our commercial effort to reduce the discount to Brent of our oil. Therefore, realized oil prices were only 70% down year on year. In Q4, we continue our marketing efforts to export crude oil. Approximately 20% of our revenue came from export market in the quarter. We plan to continue this strategy in Q1 twenty twenty one and have obtained very competitive discounts to brand in our latest tender at around $2 per barrel.

Gas prices were down 27% year on year impacted by softer demand in industrial segment severely affected by the quarantine measures. Lifting cost for Q4 twenty twenty came very solid at $22,600,000 represented a 12% reduction year on year. Disting cost per BOE was $8 per barrel, 14 below Q4 twenty nineteen and nineteen below Q3 twenty twenty, driven by the dilution of fixed costs as the production increased and higher cost efficiency. Adjusted EBITDA was $35,900,000 in Q4 twenty twenty, 1% above Q4 twenty nineteen, a solid evidence of V shaped recovery. Adjusted EBITDA was boosted by higher revenues and flat lifting costs leading to a 48% expansion quarter on quarter.

Adjusted EBITDA margin was 45% improving 10% points sequentially and 8% points year on year. This performance was achieved with a realized oil price of $40 per barrel, which is 70% down year on year. Net back or adjusted EBITDA per barrel of Q4 twenty twenty was $12.7 per BOE. We achieved the same netback that in Q4 twenty nineteen with an average oil and gas realized price that was $7 lower. This is a clear evidence of Vista potential for further margin expansion at higher oil prices as we are realizing today.

Cash at the end of Q4 twenty twenty was $2.00 $3,000,000 In Q4 twenty twenty, cash from operation was $27,000,000 a 41% increase quarter on quarter driven by higher adjusted EBITDA generation. Cash from investing activities was $55,900,000 mainly driven by activities ramp up in Baja del Palo Verde, as I explained earlier. Finally, cash flow from financing activity was positive in Q4 twenty twenty as we raised another $20,000,000 in the Argentine capital market in dollar linked bond with maturity of thirty two and forty eight months. I will now present our guidance for 2021, which is quite exciting considering the challenge in 2020 we went through. In terms of activities in Baja del Palo Este, we plan to keep drilling and completion at current run rate with one drilling rig operation in our core acreage.

We expect to tie in 16 shale oil wells during the year for a total of 36 producing wells by year end. Our production guidance for 2021 is between 37,038 BOE per day, a 40% improvement year on year. With one part to be tied in each quarter, we forecast sequential growth in all quarter and exceed the rate above 40,000 BOE per day. Our plan reflects a lifting cost at least $8 per BOE for the year. We are expecting a slight sequential increase in Q1 twenty twenty one due to a ramp up in pooling activity, but all quarter will show a reduction year on year with a total annual reduction of at least 12% compared to 2020.

We are targeting adjusted EBITDA at $275,000,000 tripling our 2020 adjusted EBITDA based on a conservative $45 per barrel realized oil price. For every dollar added to realized oil price, adjusted EBITDA would grow $8,000,000 We are planning capital expenditure for 2021 to be in line with adjusted EBITDA at $275,000,000 at our conservative oil price scenario. Finally, we plan to maintain gross debt at current levels to achieve a quick normalization of our leverage ratios by Q3 twenty twenty one. I will now recap on the main points of today's presentation. We continue to deliver world class well productivity in our Baja Del Palo core acreage.

Our average well is performing 25% of our vista type curve and 70% of our well ranked in Vaca Muerta top 10%. The ramp up of activity in Q4 twenty twenty boosted our production, setting the state for continued growth in 2021. Our rebate cost structure led to a lifting cost of $8 per BOE in Q4 and an adjusted EBITDA margin of 45% at $40 per barrel. This leaves Q4 twenty twenty margins above Q4 twenty nineteen levels when oil prices were 70% higher and prove our resilience to lower oil price scenarios in the future. We maintain a solid balance sheet with over $200,000,000 in cash at the 2020 fully prepared to face our 2021 CapEx plan.

For 2021, we expect solid growth metrics with production increasing 40% year on year and adjusted EBITDA tripling to $275,000,000 We expect adjusted EBITDA margin above 50% with realized oil prices at $45 per barrel. Before we move to Q and A section, I would like to thank our investors for their continued support and all the team at Vista for their passion and hard work during a very challenging year. We will now move to Q and A.

Speaker 0

Thank you. And our first question comes from the line of Andres Sirdone with Citi.

Speaker 3

Hi, good morning everyone. Alejandro, Pablo, I have three questions. The first one is when we look at your 2021 guidance there are four parts that you are targeting to drill. The question is what is the strategy there? Are you targeting to the risk the new zones that you test with part number five and number six?

Or are you targeting to test new areas in the block? The second question has to do with oil prices. How do you expect to see the realization prices in 2020 particular in the first quarter? How should we think about that given the restrictions in the local market? And the second and the last question has to do with the lifting cost.

It's an impressive reduction of 20% quarter on quarter and a very solid guidance for next year at similar levels. But what I would like to understand is, can you split it between unconventional production and conventional production? The lifting, how does it look for each of them? Thanks.

Speaker 2

Hi, Andre. Thank you for your question. Good to talk to you. Look, just starting with the first question related to our strategy of development for 2021. Well, I mean between 2020 and the campaign that we are going to tackle or we are tackling in 2021, we are not planning to derisk new zones vertically.

It means what we have proven carbonate in Pipe 4 is I mean we are amazed with the result of the carbonate, but we don't have a plan to develop further wells on the carbonate in 2021. I don't want to say that that is not going to change, but that is not the plan at the moment. Of course, that give us optionality and optionality that we did not have a few months ago. And again, we are following closely the production of those wells that should then continue performing quite about our type curve. Now, sign of the path, yes, have been placed in a position where geographically we can say that we are sort of derisking our area.

Pad number six was all the way to the East. Part number five was all the way to the North. And therefore, yes, that somehow is helping us to delete the area. Now, Pac six, seven, eight and nine that is what we have ahead in 2021 are all in the core acreage of Vaca Muerta. So we are drilling for production really and 2021 is focused on that, focused on the guidance, focused on the financial results.

So that is pretty much the strategy. So you will see those parts six, seven, eight and nine are basically the core of the core of what we have in Bajada del Palo Este. In terms of pricing, you have seen we are giving we are basically running our numbers on our plan for 2021 with $45 per barrel guidance. We finished twenty twenty Q4 with realized prices of $40 one thing is important for us to understand in Argentina is the dynamic of pricing. We have two source of revenues, one coming from our local refineries and one coming from our exports.

Exports is agreement of exports is something that close ahead of a quarter or sometime ahead of few months of production. Therefore, in Q1, we've been leading with the prices effect for that we closed in December and November. And for the refinery pricing or price of the pump, there's a dynamic of inertia in Argentina that basically just to be fair goes both ways. When Brent prices come up, we don't see price on the refineries asset immediately neither in the pump. And when Brent come down also we don't see it basically we have never seen a pump reduction in Argentina price pump in Argentina ever.

So for Q1, I think we should expect prices average realized prices close to our guidance, okay? It could be slightly above, but it's going to be close to our guidance. For Q2, yes, realized prices I believe will be quite above guidance for us for whatever I mentioned before. If you want our local refinery pricing today that we are seeing without mentioning any names are about $50 per barrel. Okay.

So I guess that gives you kind of a sense of where we are pricing wise today, where we were, where we're going to be in Q1 and where we expect to be in Q2. The last question is regarding lifting costs. Our lifting costs for our unconventional first of all, I don't know if we can mean we can split lifting cost between conventional and conventional, but we look at the lifting cost of unconventional as an incremental lifting cost because somehow we are using the platform that we have in the conventional in terms of facilities, some of the people that tackle some of the task and so on. So I would say that our lifting cost for unconventional is probably close to $4 per barrel. And today we are having $8 and we started operation with 17 with no production coming from unconventional.

So we plan that lifting cost probably to continue going a bit further down as we increase the percentage of our unconventional production. It dilutes the fixed cost that we have for the whole lifting. So we can prepare lifting cost from conventional and conventional. I don't think that is going to be a true exercise. But clearly as we add unconventional production at $4 per barrel of lifting cost, we will see our total lifting cost decreasing.

Speaker 3

Thank you guys and congratulations again.

Speaker 2

Thank you, Andres.

Speaker 0

Thank you. And our next question comes from the line of Alejandro Dimichelis with NAU Securities.

Speaker 4

Yes, morning gentlemen. A couple of questions please. Could you please give us some kind of guidance how you see the drilling and completion cost evolving on your unconventional, but only now that you're going to be focusing on the core? That's the first question. And then the second question is, Miguel, I understand what you're saying in terms of pricing dynamics in Argentina.

But if prices remain high, can we see CapEx going up much more than what you're guiding now?

Speaker 2

Thank you, Alejandro, for your question. The premium completion cost and development cost overall have come down a bit since we start operation more than a bit, probably a lot. And that has been based basically in performance. What I mean performance is drilling a split completion strategy and also basically the renegotiation and the rebasing that we did with all the contracts during pandemic, but also before pandemic. And I don't know if you recall, but the way that we contracted our main service companies, mainly drilling rigs and services is based on something that we are very proud of that is a scheme that we call OneTEAM where we not only pay for services, we also pay for performance.

And the performance is measured as a common performance of us and the service company. So even we reward people at the rig site with a similar with the same scheme for service companies and our people in order to create that 19% speed. Drilling cost per well as you see in Slide number four has come down from our first batch from $17,400,000 to $9,900,000 And we believe we have room to continue reducing, I will say, probably I will say another $1,000,000 for sure. Main source of cost reduction could be for example sand. Sand is something that we continue developing.

We are thinking and developing our own source. We are investing CapEx in doing that this year. And also we are looking another modification on the process, a few things that have been tested somewhere else that we believe could also bring further cost reduction in terms of logistic and how we mobilize the sun. So the short answer for you is yes, We believe we could continue reducing the drilling cost, probably not at the speed that we've been doing so far, but there's still room to improve there. In terms of CapEx, we basically express as a guidance is what we call a drill to fill plan.

And we have no plan to change that, but we have a plan to look at where we are in Q4. So if in Q4 prices or realized prices to be more precise show us that we have a lot of room and we are quiet about of our plan and our plan is a very aggressive plan. So it has to be an understanding situation in terms of pricing or performance. We have been in an option in our team and in our plan to probably increase activity toward Q4. You have to remember that one of the things that we did during the pandemic and was for me bold movement was we commit to them key service companies with long term contracts, but building in that a lot of flexibility.

So we have a frac fleet contracted for few years. We have drilling rig contracted for a few years with flexibility in our contract to start and to stop. And today with that flexibility, we basically are commanding the speed and the performance and the timing of our wells. We are sharing those contracts with other companies in order to reduce the cost where those equipments are not dedicated to us. But at the same time, we command that because we own those contracts.

So that was a move also that is helping us in Q4 if we want really to take advantage of a new pricing scenario or a better pricing scenario to be able to increase the activity if required.

Speaker 4

Okay. Thank you. And just to follow-up, when you talked about the increase in activity, can we see a second rig coming into the block?

Speaker 2

I will for your model, I will consider one more pad in Q4, an additional pad, pad number 10.

Speaker 4

Okay. That's fantastic. Thank you very much, Miguel.

Speaker 2

You're welcome.

Speaker 0

Thank you. And our next question comes from the line of Marcel Gimmerio with Credit Suisse.

Speaker 5

Hi, good morning everyone. Good morning Miguel. Thanks for taking the questions and congratulations on the results. I have two questions for today. First one, could you provide us a kind of a CapEx breakdown?

I mean, how much is unconventional? How much is conventional? And if planned gas four is probably impacting and how much does it impact? And still on the CapEx side, is there any restriction regarding the capital restriction from the Central Bank? And maybe a second topic, I mean, some more general way, where should we expect Vista productions going to in the next few years, I would say?

Thank you for taking the questions.

Speaker 2

Thank you, Marcelo, and very good question. So for the CapEx breakdown, so we are reporting in the guidance $275,000,000 from which the majority is for Vaca Muerta unconventional drilling, the 16 well drilled and the 16 completions. So you have there probably around 20,000,000 of unconventional CapEx. Then you have a small portion for conventional around $25,000,000 You have $40,000,000 in Mexico. You have less than $10,000,000 on a fund initiative related to the previous question of Andres, Alejandro.

That is you have others to complete the $275,000,000 but that is mainly the breakdown. So most of the investment is related to Vaca Muerta development, Baja Del Palo to be more precise. And there you have also you have a split between drilling and completion. You have investment in facilities. You have investment in other studies.

So that is the bulk of our investment. Your next question was related to

Speaker 5

Maybe just a follow-up, a quick follow-up on the previous questions. I mean, there any impact of planned gas for on the CapEx? I mean, how much would be the CapEx if there wasn't planned gas for?

Speaker 2

Plant gas, I mean, we are not drilling for gas. So all the gas that we get is associated gas to our oil development. The plant gas has give us an additional pricing that is around $1 per million of Btu. So that is all what we get from Plan Gas. We participated Plan Gas because we saw that upside, but we have not changed at all our development plan or our strategy and development due to that because our main margins, our main business and the nature of our resources is all focused.

I mean, next question, I think it's a very good question is relative how we see Vista going forward in terms of development and pricing. So if

Speaker 0

you

Speaker 2

take what we have go through in 2020 and probably late twenty nineteen, I think the main achievement of Vista teams has been the restructure of our cost base based in two main elements. I think operational efficiencies and also reservoir performance. The fact that today we have a total development cost where it is and the lifting cost where it is put us as I mentioned in the presentation in a position to have better margin than we have a year ago with $5 less in price, 40, a margin of 45% margins of EBITDA. So that has been the main achievement. In 2021, on the back of the restructuring and also higher prices and stronger demand, what we are doing is returning to profitable growth.

And we are returning to profitable growth with a minimum operational union of one rig and one frac fleet. In a moment that everybody is fighting for rigs and fighting for frac fleet in Argentina, we have that secure and not only secure, I mean we are return in based on that efficiency that we create with the same crew, with the same rig, with the same frac fleet, with the same scheme two years ago. Going forward, going on 2022 and onwards, we continue seeing growth even with this minimum operational unit that we mentioned, one rig and one frac fleet. But in a scenario that with that growth and with that minimum commitment, we are going to be a company that we are going to be creating free cash flow. So we are going to be generating free cash flow.

The other The next decision for us to make in 2022 and onward is what we are going to do with that free cash. And this we have different ideas, different scenarios and of course it's going to depend on the context. But 2021, I mean 2021, we are going to really harvest everything that we have done in terms of restructuring the lifting costs and the development costs of Vista. And then if the context plays right for us 2022 onward, now the decision is what we're going to do with a company that has free cash flow generation and very good numbers. I hope I have answered your question.

Speaker 5

Yes, very clear. Thank you very much.

Speaker 0

Thank you. And our next question comes from the line of Ezekiel Fernandez with Valens.

Speaker 6

Good morning to everybody. Thank you for the materials and congratulations on the recent performance of the new Wells. I have three questions. I would like to go one by one if you don't mind. The first one is related to what we have seen in the media or in the press talks about certain industry players in conversations, refineries and crude producers in conversations regarding an internal crude price.

Would you comment, please, if this is something that it's really moving forward or maybe we should, you know, expect to see higher crude prices before this really becomes something?

Speaker 2

Yeah. Hello, Sergio. Thank you for the question. Look, think as I mentioned before during the presentation, I think to start with, I will set today refineries paying about $50 per barrel. So that is about $50 per barrel.

This is where we are today. As I mentioned before, we have an inertia in Argentina and I have been through this cycle before. And that inertia means that what we see in international crude prices when the rain increase, we don't capture that immediately in the local market. The difference between what I have lived before and today is that we have additional volume that can be export. So our realized prices now is a basket of local crude prices and a portion of pricing that come from our exports.

Back to the local prices, we have seen in the past that in order to manage that inertia there been and I've been through two periods where the industry basically get together and agree how to transition that pricing. What I've never seen is the industry not to fight for export parity or even to fight for something that is between export parity and import parity. So how we get to export parity it will be basically the dynamic of the market or an agreement between producers, operators and refineries in order to get there. So I'm not surprised that there are rumors on the press of people getting together. We have not yet participated of any of these conversations.

But in the past, more than conversations, I think they've been a dynamic to get into this airport parity. But again, it does not in Argentina come to the PAM and to the refinery prices immediately when we see an increase on international crude oil prices.

Speaker 6

That's great. Thank you. And my second question is related to facilities. Hopefully, this year, you're going to be getting close to 40,000 barrels equivalent barrels per day in production. Hopefully, we will see more growth in 2022, 2023.

So where is your limit now in terms of treatment capacity and

Speaker 4

where do you

Speaker 2

think you will need to go? Yes, look, it's a good question. As I mentioned before, I think 2022, 2023, we'll have a company that will be generating cash and we will be in a situation where we can decide what we do with that. And of course, one option is will be continue growing, adding more rigs and continue growing since we have the reserve rate to do that. We mentioned that just with addition of the Carbonate we have probably north of 500 locations to be drilled.

So the question will be what is the pace? In our plan, in terms of facilities this scenario that we have today that is what we call drill to fill is in a scenario that we can go on generating cash without adding much more CapEx in additional facilities. That mean our facilities we handle around 50,000 barrel per day with no issues, which is just very small incremental CapEx. If we really want to go to two rigs, three rigs and accelerate that development, we will have to plan for additional CapEx in terms of facilities, mainly batteries and stations and some probably refinery treatment plants.

Speaker 6

Great. And finally, are you looking into M and A or not really right now?

Speaker 2

We always look to M and A. It's for us a continuous exercise that we do just probably to keep a shot and to keep looking and even to compare what we have. The reality is it's very difficult to find an opportunity that match the quality of the resources that we have and the quality of the economy that we have. And also we are very pragmatic. We know that we are very good at what we do.

And one element of that is the focus that we have. So saying that, yes, we are always looking What we have looked at it, it proved to never get even close to what we have in hand. So just to give you a short answer, today the focus is where we are in Baja del Palo Este, in Vaca Muerta and this is where we're going to be concentrated in the next two years. We also see value in being a pure play, a very focused player doing

Speaker 4

what we do.

Speaker 2

That's great.

Speaker 6

Thank you very much.

Speaker 0

Thank you. And I'm showing no further questions. So with that, I'll turn the call back over to management for any closing remarks.

Speaker 2

Well, guys, thank you very much for participating. We are truly happy of being here and having take the pandemic as an opportunity, revising our cost and really very excited of tackling 2021 with a growth plan. So thank you for your support. Thank you for your participation and have a good day.

Speaker 0

Ladies and gentlemen, thank you for participating in today's conference. This does conclude the program and you may now disconnect.