Vista Energy, S.A.B. de C.V. (VIST) Q4 2020 Earnings Report, Transcript and Summary

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

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 four-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.

. Our first question comes from the line of Andres Cardona with Citi.

Alejandro, Pablo. We have three questions. The first one is, when we look at your 2021 guidance, there are four 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 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 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?

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.

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

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?

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.

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

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

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

Congratulations on the results. I have two 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?

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?

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?

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.

Our next question comes from the line of .

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?

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.

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?

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.

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

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.

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

Well, guys, thank you very much for participating. We are truly happy of being here and having taken 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.

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