Vista Energy SAB de CV

BMV:VISTAA

Earnings Call Transcript 2020-Q4

[Operator]

Ladies and gentlemen, thank you for standing by, and welcome to Vista's Fourth Quarter and Full Year 2020 Results Conference Call. [Operator Instructions] It is now my pleasure to introduce Strategic Planning and Investor Relations Officer, Alejandro Cherñacov.

[Alejandro Cherñacov, executive]

Thanks. Good morning, everyone. We are happy to welcome you to Vista's Fourth Quarter and Full Year 2020 Results Conference Call. I am here with Miguel Galuccio, Vista's Chairman and CEO; and with Pablo Vera Pinto, Vista's CFO.

Before we begin, I would like to draw your attention to our cautionary statement on Slide 2. 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 measure can be found in the earnings release that we issued yesterday. Please check our website for further information.

Our company, Vista Oil & Gas, is a sociedad anónima bursátil de capital variable organized under the laws of Mexico, registered in the Bolsa Mexicana de Valores and the New York Stock Exchange. The tickers of our common stock are VISTA in the Mexican Stock Exchange and VIST in the New York Stock Exchange. The ticker of our warrant is VTW408A.

And I will now turn the call the call over to Miguel.

[Miguel Galuccio, executive]

Thanks, Alejandro. Good morning, everyone, and thank you for joining this earnings 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 indicators reflect a V-shaped recovery on the back of a 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 oilfield operations. More than 75% of our staff was working from home by the end of March 2020. In July, we adopted a new protocol to restart drilling, completion and pulling activities. This allow us to tie-in 2 [ 4-well pads ] in Bajada del Palo Oeste, 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 turned this time to a company that is even more resilient to low oil prices environment.

By year-end 2020, our proved reserves increased to 128.1 million barrels of oil equivalent. This implied a reserve replace ratio of 371%, and an increase of 26% vis-à-vis year-end 2019. This result is a clear reflection of the resilience I was mentioning early. 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 landing zone in Bajada del Palo Oeste, with 2 successful wells with 2,400 meter lateral. 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 550 wells.

In 2020, we also maintained a strong focus on sustainability. Our safety metrics continue to improve, having completely reworked safety standards and procedures since we took over this operation less than 3 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 1 standards. Our first sustainability report will be published at the end of April.

After restarting drilling and completion in Q3 2020, we continue to see improvement in our pro forma metrics. Drilling speed in pad 6 was 108% above pad #1, a remarkable learning curve. When we started our shale oil development, drilling a well with 2800-meter lateral would take us more than 35 days. Today, it takes us less than 20 days. The consistent improvement in drilling speed allow us to tie in pad #6, 50 days before the scheduled date, boosting our production exit rate for the year.

During 2020, we captured cost reduction in drilling and completion service rates as well [ tool that are proppant ] and flat drilling costs. In pad #6, drilling cost per lateral foot was down to $472, a 37% improvement compared to pad #1. Similarly, the completion cost for pad #6 was down 45%.

Finally, drilling and completion cost per well was $9.9 million for pad #6, a 43% improvement compared to pad #1.

Additional efficiency was obtained by improving well design. As shown to the right of the slide, we are increasing lateral length and total frac stations. These are key drivers to increase well productivity and to reduce development costs to our target of approximately $8 per BOE. At a $9.9 million cost per well achieved in pad #6, the development costs would actually be below $8 per BOE. We will deep dive into well productivity in the next 2 slides.

The chart on the left shows the production performance of our wells in Bajada del Palo Oeste. Each well shows in gray line. The blue line is the average production of all wells, which is 25% above our type curve, shown in black.

I will give you some additional color on our 2020 performance. 3 wells we landed in La Cocina, corresponding to pad 3 and 4, set Vaca Muerta records for 30-day peak oil. During the second half of 2020, we accelerated drilling and completion activity, and tie-in pad #4 and #5. This boosted our production in Bajada del Palo Oeste to an exit rate of 20,200 BOE per day in December, more than tripling our production year-on-year.

Finally, in the second half of the year, we started our gas lift pilot in pad #1 and #2. The preliminary result of this artificial system, it is a good fit for Vaca Muerta horizontal wells. In the first 2 pads, we achieved production increases of around 20% after conversion to gas lift.

Slide #6 shows the comparison of our wells against peer wells in the Permian and Vaca Muerta basin. I shared a previous version of this chart 1 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 well, 40 of our wells are top quartile, whereas our best [ 8 ] wells rank in the top 10%. The comparison is on normalized basis. Compared to Vaca Muerta wells, in the bottom graph, all our wells fall within the top 25%, whereas our best [ 11 ] wells at top 10%. Vista 2019 wells are shown in purple and 2020 wells are shown in black, highlighting that the productivity of our wells is ranking better year-on-year.

Our audit proved reserve at the end of 2020 stood at 128.1 million BOEs, up from 101.8 million at the end of 2019. Our reserves 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 Oeste. Shale reserves are now 70% of our total group reserves. Our important driver, we are increasing 10% of type well, 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 $93.8 million, despite average realized oil prices that were down 30% with respect to 2019. Cash outflow from investment activities was $156.1 million. 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 recovering, greater price visibility and our new well design will ramp up activity again. We use a second rig to drill an additional pad, and tie it in before year-end. Therefore, in Q4 2020, cash from investing activities was $55.9 million, more than 2x Q2 and Q3, positioning Vista to capture the upside presented by the recovery of realized oil prices.

Cash from financing activities was positive at $25.7 million during 2020 as we successfully raised $100 million in bonds 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 128.1 million BOEs as of December 2020. Total production was 26,600 BOE per day, 9% down year-on-year, impacted by the effect of the COVID-19 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 Bajada del Palo Oeste, 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 prices. Revenues were $274 million, 34% down year-on-year, impacted by the lower production and prices. Lifting costs improved 17% 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 and [ cost ] on permanently lower rate and higher efficiency. Adjusted EBITDA was $96 million for the year, down 44% vis-à-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 million, in line with 2019 and 30% lower than our original 2020 plan guidance. Finally, cash at the end of the period was $203 million, which leaves us in a solid position to fund investing activity 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 2020 metrics are solid, showing progress vis-à-vis prepandemic levels. I will discuss the fourth quarter of 2020 in the following slides.

Production in Q4 2020 was 3,600 BOE per day, a 21% improvement quarter-on-quarter, driven by activity ramp-up in Bajada del Palo Oeste. Oil production increased 31% quarter-on-quarter to 23,100 barrels per day. Revenue were $80 million, increasing 14% vis-à-vis Q3 2020, driven by improvements in production volumes and price. Q4 2020 lifting cost came very solid at $8 per barrel, thanks to our efforts to keep expenditures under control amid production increases due to diluted fixed costs.

Adjusted EBITDA improved 48% sequentially to $36 million for the quarter. More importantly, it is up 1% year-on-year, reaching an adjusted EBITDA margin of 45%. CapEx in Q4 was $97 million for the quarter, driven by the activity ramp up I mentioned earlier. Finally, cash at the end of the period was a solid $203 million with net debt at $330 million. This constitutes a robust starting point to keep developing Bajada del Palo Oeste in 2021.

Moving to Slide 11. Total production is fully recovered from the COVID-19 pandemic impacts, and it is actually up 2% year-on-year. We are back on our profitable growth, but driven by our Bajada del Palo Oeste development. Oil production is 23% up year-on-year and 31% sequentially due to the result of pad #4 and the early tie-in of pad #5. Gas production during the quarter decreased 3% sequentially as we continue to focus our development in Bajada del Palo Oeste, 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. Realized 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 2021, and have obtained very competitive discount to Brent 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 2020 came very solid at $22.6 million, represented a 12% reduction year-on-year. Lifting cost per BOE was $8 per barrel, [ 14 ] below Q4 2019 and [ 19 ] below Q3 2020, driven by the dilution of fixed costs as the production increased and higher cost efficiency.

Adjusted EBITDA was $35.9 million in Q4 2020, 1% above Q4 2019, 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%, improved 10% points sequentially and 8% point year-on-year. This performance was achieved with a realized oil price of $40 per barrel, which is 70% down year-on-year.

Netback or adjusted EBITDA per barrel of Q4 2020 was $12.7 per BOE. We achieved the same netback that in Q4 2019, with an average oil and gas realized price that was $7 lower. This is a clear evidence of Vista's potential for further margin expansion at higher oil prices as we are realizing today.

Cash at the end of Q4 2020 was $203 million. In Q4 2020, cash flow operation was $27 million, a 41% increase quarter-on-quarter, driven by higher adjusted EBITDA generation. Cash from investing activities was $55.9 million, mainly driven by activity ramp-up in Bajada del Palo Oeste, as I explained earlier. Finally, cash flow from financing activities was positive in Q4 2020 as we raised another $20 million in the Argentine capital market in dollar-linked bond with maturity of 32 and 48 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 Bajada del Palo Oeste, we plan to keep drilling and completion at current run rate with 1 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 37,000 and 38,000 BOE per day, a 40% improvement year-on-year. We want pad to be tie-in each quarter. We forecast sequential growth in all quarters, and an exit rate about 40,000 BOE per day. Our plan reflects a lifting cost at, at least, $8 per BOE for the year. We are expecting a slight sequential increase in Q1 2021 due to a ramp-up in pooling activity, but all quarters 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 million, 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 could grow $8 million.

We are planning capital expenditure for 2021 to be in line with adjusted EBITDA at $275 million 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 2021.

I will now recap on the main points of today's presentation. We continue to deliver world-class well productivity in our Bajada 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 2020 boosted our production, setting the stage for continued growth in 2021.

Our rebased 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 lifts Q4 2020 margins above Q4 2019 levels, when oil prices were 70% higher and proved our resilience to lower oil price scenarios in the future. We maintained a solid balance sheet with over $200 million in cash at the end of 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 million. We expect adjusted EBITDA margin above 50% with realized oil prices at $45 per barrel.

Before we move to Q&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&A.

[Operator]

[Operator Instructions] Our first question comes from the line of Andres Cardona with Citi.

[Andres Cardona, analyst]

Alejandro, Pablo. We have 3 questions. The first one is, when we look at your 2021 guidance, there are 4 pads that you are targeting to drill. The question is, what is the strategy there? Are you targeting to derisk the new zones that you test with pad #5 and #6? 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 2021, and in 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?

[Miguel Galuccio, executive]

Andres, thank you for your question, good to talk to you. Look just starting with the first question relating to our strategy of development for 2021. Well, I mean, between end of 2020 and the campaign that we are going to tackle, we are tackling in 2021. We are not planning to derisk new zones vertically. It means where we have proven carbonate in pad 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 gives 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 some of the pads, yes, have been placed in a position where geographically, we can say that we are sort of derisking our area. Pad #6 went all the way to the east. Pad #5 was all the way to the north. And therefore, yes, that somehow is helping us to derisk the area. Now pad 6, 7, 8 and 9, 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 focus on that, focus on the guidance, focus on the financial results. So that is pretty much the strategy. So you will see those pads 6, 7, 8 and 9 are basically the core of the core of what we have in Bajada del Palo Oeste.

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 2020 Q4 with realized prices of $40. And one thing is important for us to understand in Argentina is the dynamic of pricing. We have 2 source of revenues, one coming from our local refineries and one coming from our export. Export is agreement of factor, it's something that we close ahead of a quarter or sometimes ahead of a few months of production. Therefore, in Q1, we've been living with the prices of export 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. But basically, just to be fair, it goes both ways. When Brent prices come up, we don't see that price on the refineries as 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 reduction in Argentina ever. So for Q1, I think we should expect prices -- average realized prices close to our guidance, okay? It will be slightly above, but it's going to be close to our guidance.

For Q2, yes, realized oil 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 [ above $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 regard lifting costs. Our lifting cost for our unconventional -- first of all, I don't know if we can -- I mean, we can split lifting cost between conventional, unconventional. 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 tasks. And 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 this operation with $17, with no production coming from unconventional. So we plan that lifting costs probably to continue going a bit further down as we increase the percentage of our unconventional production. It dilute the feed cost that we have for the whole lifting. So we can separate lifting costs from conventional, unconventional. 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 costs decreasing.

[Operator]

Our next question comes from the line of Alejandro Demichelis with Nau Securities.

[Alejandro Demichelis, analyst]

Yes. A couple of questions, please. Could you give us some kind of guidance how you see the drilling and completion costs evolving on your unconventional, [ probably ] 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?

[Miguel Galuccio, executive]

Thank you, Alejandro, for your question. So drilling and competition costs and development costs overall have come up -- come down a bit since -- with their operation, more than a bit, probably a lot. And that has been based basically in performance. When I mean performance, it's 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 that 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 the scheme that we call One Team, 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 side with the similar -- with the same scheme for service companies and our people in order to create that main team spirit.

Drilling cost per well, as you see in Slide #4, has come down from our first pad 1 from $17.4 million to $9.9 million. And we believe we have room to continue reducing as we said, probably, I would say, another 1 million for sure. Main source of cost reduction could be, for example, sand. Sand is something that we continue developing. We are thinking in developing our own source. We are investing CapEx in doing that this year. And also we are looking another modification and the process, a few things that have been tested somewhere else that we believe could also bring further cost reduction in terms of logistic, how we mobilize the sand. So the short answer for you is, yes, we believe we could continue reducing the drilling costs, probably not at the speed that we've been doing so far, but there's still room to improve there.

In terms of CapEx, what 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 lower room and we are quite 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 ] 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, a very 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 a 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 the new price scenario or a better price scenario, to be able to increase the activity if it require.

[Alejandro Demichelis, analyst]

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

[Miguel Galuccio, executive]

I will -- for your model, we consider 1 more pad in Q4, an additional pad, pad #10.

[Operator]

Our next question comes from the line of Marcelo Gumiero with Crédit Suisse.

[Marcelo Gumiero, analyst]

Congratulations on the results. I have 2 questions for today. First one, could you provide us kind of a CapEx breakdown. I mean how much is unconventional, how much is conventional? And if Plan Gas 4 is probably impacting? And how much does it impact? And still on the CapEx side, is there any, I mean, restriction regarding the capital restriction from the Central Bank?

And maybe a second topic. I mean, in some more general way, where should we expect, I mean, Vista productions going to in the next few years, I would say?

[Miguel Galuccio, executive]

Thank you, Marcelo, a very good question. So for the CapEx breakdown, so we are reporting in the guidance, $275 million, from which the majority is for Vaca Muerta unconventional drilling, the 16 well drilled and the 16 completions. So you have there probably around $220 million of unconventional Capex. Then you have a small portion for conventional, around $25 million. You have $40 million in Mexico. You have less than $10 million on a sand initiative related to the previous question of Andres -- Alejandro, and that's it. You have others to complete the $275 million, but that is mainly the breakdown. So most of the investment is related to Vaca Muerta development, Bajada del Palo, to be more precise. And there, you have also -- you have a split between drilling and completion. You have investment in facilities, and you have investment in other studies. So that is the bulk of our investment.

Your next question was related to?

[Marcelo Gumiero, analyst]

Maybe just a follow-up, a quick follow-up on the previous questions. I mean is there any impact of Plan Gas 4 on the CapEx? I mean, how much would be the CapEx if there was not Plan Gas 4?

[Miguel Galuccio, executive]

Okay. So in Plan Gas, I mean, we are not drilling for gas. So all the gas that we get is associated regard to our oil development. The Plan Gas have -- give us an additional pricing that is around $1 per million of BTU. So that is all what we get from Plan Gas. We participate in the Plan Gas because we saw that upside. But we have not changed at all our development plan or our strategy in development due to that. Because our main margins, our main business and the nature of our resources is oil focused.

I mean your next question, I think is a very good question. It's related to how we see Vista going forward in terms of development and pricing. So if you take what we have go through in 2020 and probably late 2019, I think the main achievement of Vista teams has been the restructure of our cost base based in 2 main elements, I think, operation -- 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 a better margin than we had a year ago with $5 less in price, $40. A margin of 45% -- margins of the EBITDA. So that has been the main achievement.

In 2021, on the back of that restructuring and also higher prices and stronger demand, we -- what we are doing is returning to profitable growth. And we are returning to profitable growth with a minimum operational unit of 1 rig and 1 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 returning based on that efficiency that we create with the same crew, with the same rig, with the same frac fleet, with the same scheme 2 years ago.

Going forward -- going on 2022 and onwards, we continue seeing growth even with this minimum operational unit that we mentioned, 1 rig and 1 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 cost and the development cost of Vista. And then if the context plays right for us 2022 onward, now the decision is what we're going to do with the company that have free cash flow generation and very good numbers. I hope I have answered your question.

[Operator]

Our next question comes from the line of [ Ezekiel ] Fernandez with [ Valence ].

[Unknown Analyst]

Thank you for the materials and congratulations on the recent performance of the new wells. I have 3 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 expect to see higher crude prices before this really becomes something?

[Miguel Galuccio, executive]

Yes. Thank you for the question. Look, I think, as I mentioned before during the presentation, I think you start with, as we said, today, refineries are paying [ above $50 ] per barrel. So that is [ above $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 they're in 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 volumes that can be export. So our realized prices now is a bucket of local crude prices and a portion of pricing that comes from our export.

Back to the local prices, we have seen in the past that in order to manage that inertia, they are -- and I've been through 2 periods where the industry basically get together and agree how to transition that pricing. We have never seen 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 and of people getting together. We have not yet participated of any of this conversation. But in the past, more than conversations, I think they've been a dynamic to get into this export parity that, again, it does not in Argentina come to the pump and to the refinery prices immediately when we see an increase on international crude oil prices.

[Unknown Analyst]

That's great. 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 where do you think you will need to go?

[Miguel Galuccio, executive]

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 will be continue growing, adding more rigs and continue growing. Since we have the reserve base to do that, we mentioned that with the 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, it's a scenario that we can go on, generating cash without adding much more CapEx in additional facilities. That means our facilities, we handle around 50,000 barrel oil per day with no issues, with just very small incremental CapEx.

If we really want to go to 2 rigs, 3 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.

[Unknown Analyst]

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

[Miguel Galuccio, executive]

We always look to M&A. It's, for us, a continuous exercise that we do, just to -- just probably to keep agile and to keep looking and even to compare with 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 economics 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're always looking. We have looked at it. It proved that 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 Bajada del Palo Oeste, in Vaca Muerta. And this is where we're going to be concentrated in the next 2 years. We also see value in being a pure play, a very focused player, doing what we do.

[Operator]

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

[Miguel Galuccio, executive]

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 costs 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.

[Operator]

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