Good day, and thank you for standing by. Welcome to Vista's Third Quarter 2024 Earnings Webcast and Conference Call. [Operator Instructions] Please be advised that today's conference is being recorded. I would now like to hand the conference over to your speaker today, Alejandro Chernacov. Please go ahead.

Thanks. Good morning, everyone. We are happy to welcome you to Vista's third quarter of 2024 results conference call. I am here with Miguel Galuccio, Vista's Chairman and CEO; Pablo Vera Pinto, Vista's CFO; and Juan Garoby, Vista's COO. 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 and adjusted net income. 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 is, Vista Sociedad Anonima Bursatil De Capital Variable organized under the laws of Mexico, registered in the Bolsa Mexicana de Valores and the New York Stock Exchange. Our tickers are VISTAA in the Bolsa Mexicana de Valores and VIST in the New York Stock Exchange. I will now turn the call over to Miguel.

Thanks, Ale. Good morning, everyone, and welcome to this earnings call. The third quarter of 2024 was marked by strong operational and financial performance, driven by new well activity in our development hub in Vaca Muerta. Total production was 72,800 BOEs per day, an increase of 47% year-over-year and 12% quarter-over-quarter. Oil production was 63,500 barrels per day, 53% above the same quarter of last year and 11% up compared to the previous quarter. Total revenues during the quarter were $462 million, a 53% increase compared to the same quarter of last year. Lifting cost was $4.7 per BOE, 2% down year-over-year. Capital expenditure was $369 million, mainly driven by 12 new wells drilled and 15 wells completed during the quarter plus $63 million in development facilities. Adjusted EBITDA was $310 million, 37% above year-over-year, driven by robust revenue growth and lower lifting cost per BOE. Adjusted net income was $53 million, implying a quarterly adjusted EPS of $0.60 per share. Free-cash flow was $74 million, negative during the quarter, driven by higher cash in investing activities, as we ramp-up capital expenditure in our development to drive growth. Net leverage ratio at quarter end was a solid 0.65 times adjusted EBITDA. I will now deep dive into our main operational and financial metrics of the quarter. Total production during the quarter was 72,800 BOEs per day, our highest quarter ever. On a sequential basis, production growth was 12%, driven by the connection of 23 new wells between May and September. We continue to see solid productivity with new wells performing in line with our type curve. Total production was 47% higher on an interannual basis, reflecting the ramp-up of our new well activity. We tied in 51 new wells during the last 12 months compared to the 31 during 2023.…

[Operator Instructions] Our first question comes from the line of Vicente Falanga from Bradesco BBI.

Hi. Good morning, everyone. Thank you, Galuccio. Thank you, Ale. Thank you, Juan. My question is the following. Vista had a similar level of well drillings and completions in the third quarter versus the second quarter of 2024, but we saw quite a sharp rise in the CapEx. Can we assume that you're drilling longer laterals with more frac stages, and if yes, what is the expected peak production for these kind of wells that you drilled in the third quarter versus the ones that you were drilling before? Thank you very much.

Pardon me, speakers, please check your mute button. You might be muted on your side.

Hi, Vicente. Can you listen me now?

Yes, yes.

All right. So yes, you're right. I mean, when you look at the total CapEx in Q3 was the $369 million compared with $346 million in Q2 with similar numbers of wells tie-in. When you look at the breakdown, EUR280 million were drilling and completion in Q3 compared with Q2 of $267 million. And as you pointed out, the main difference in CapEx came from the lateral length of our horizontal wells. So we drilled yes, longer laterals, between 3,300 -- 3,200 meters compared with 2,800 meter. Cost of those wells go from 14.5 in the 2,800 meter to a range of 16 to 17 and dependent of the length, if it's 3,000 meters, 3,200 meters. And the main difference doesn't come from the drilling itself. It comes from the number of stages of completion. We usually move from 47 in the 2,800 meters to 50 to 55 in a 3,000 meters or 3,000 meters plus lateral length. The decision of this is a super based on subsurface. So it's subsurface driven. And of course, EORs of these wells are different. We moved from 1.5 million barrel of total EOR to around probably 1.8 million. So that is the main difference. And yes, I mean, when you look at NPV-wise, every time that we have a chance to go a bit longer on a lateral NPV pay-off. So that's the main reason of what you have seen the $20 million or $23 million CapEx difference between drilling and completion between Q3 and Q2.

Great. That's very clear. Thank you very much.

You're welcome.

Thank you. One moment for our next question. Our next question comes from the line of Tasso Vasconcellos with UBS.

Hi, Miguel. Hi, everyone. Thanks for taking my question here. Miguel, you said that the company delivered 51 new wells in the past 12 months and that's actually prior to the full usage of the new equipment set. And the guidance ahead is a little bit above that figures, but I think the question is, what would be the full potential looking ahead in terms of how many wells can the company deliver, maybe on a best case scenario? And what would be the main bottlenecks and the main risks for such accelerated development plan? That's my question. Thank you.

Thanks, Tasso, for your question. It's a very good question. So, maybe the best way to look at this is if we look at 2024. When you look at 2024, we will end up tying in between 50 wells and 54 wells with and that execution of will be done with three drilling rigs for the full year. Independently that -- we are replacing one rig with now a rig that has arrived, that is a new drilling rig. When you look at -- we have been drilling with three drilling rigs full year and one frac set full year. And then we use an export frac set, I believe, twice a year. So with that, we will achieve between 50 tie-ins, maybe 54 tie-ins. When you look at what we guide for 2025, we guide between 52 new tie-ins and 60 new tie-ins, three drilling rig, and the main difference is that we will have access to a full frac set for the full year. So, when you're talking about potential, really what this frac set give us is the full potential to go beyond this 52 wells or 60 wells tie-ins. As well to notice here that if we want to add another drilling rig, a fourth drilling rig because the conditions are there or the context allow us to do so, getting a new rig in the country or getting access to a rig within the country is not difficult. Getting a new frac fleet, having that optionality, ready in the country any moment, that is what is difficult, and is what we will have in hand, in case we want to go further to the safety of 52 wells that we have guided. So, that frac set, back to your question, is really what give us flexibility, optionality, and potential.

Thank you.

That's clear. Thank you.

Thank you. One moment for our next question. Our next question comes from the line of Bruno Montanari from Morgan Stanley.

Good morning, Miguel, Ali, and team. Thanks for taking my question. So, when we think about your secured evacuation capacity, which I believe you mentioned 124,000 barrels per day into next year. Can you give us a sense of how we should expect your production to evolve quarterly into 2025, and perhaps getting closer to that level of around 120,000 barrels per day? Thank you very much.

Hi, Bruno, and thanks for your question. Yes, we will finish this year with an average of 85,000 barrels of oil per day in Q4, and we are guiding for 2025 95,000 to 100,000. So, I mean it's a super incremental increase as we outlined in our presentation, 40% increase in production, 40% increase in EBITDA. When you -- if we want to basically finish between 95,000 and 100,000 for next year, that mean that we will have an exit rate in 2025 above 100,000 barrels of oil per day for sure. We will have evacuation capacity in 2025 for 124,000 barrels of oil per day. That will be composed of 75,000 Oldelval, 44,000 that we already have, plus the 31,000 that we will add. Vaca Muerta North, I mean, Chile and OTASA, it will be 12,000, so that gives you 87,000. And we have big capacity -- trucking capacity for 30,000 barrels of oil per day. So that makes our 124,000 total capacity that we have in hand for 2025. The reality, I believe, there's going to be a spare capacity in Oldelval. I mean beyond the 31,000 that we have -- that we will use and we have access to, and for me, when you look at the capacity that is going to be put in place in Q1, they most likely would prefer capacity. So, even though we talk about 35,000, 37,000 barrels of oil per day in trucking, I think it's unlikely that we will use that full capacity in 2025.

That's clear. Thank you.

Thank you. One moment for our next question. Our next question comes from the line of Marina Mertens from Latin Securities.

Hi, good morning. Thanks for taking my questions. So in the third quarter, Brent prices declined and local prices remained quite stable. So, the gap between domestic and international prices narrowed significantly. How do you foresee these dynamics evolving, and in particular, what is your outlook for the price of the local barrel compared to export prices in the upcoming quarters?

Yes, you're right. I mean, when you look at Brent prices, Q2 was around $85, Q3 $78, and we are thinking that Q4 would be in similar range to what we have in Q3. When you do the realized price of our export with 78,000 -- $78 per barrel, it was $60.8. And when you look at -- when you see the prices of local in Q3, was $68, so very similar. We feel that we should see -- we should not see a change in that dynamic going-forward. Now, we will look at the same dynamic and that is based in the new law, that call for no pricing intervention. So, we are optimistic that the reglementation of this new law will support that conversion between local pricing to international prices. So, we believe that same demand will continue in Q4. We don't see a major change.

Okay. Thank you very much.

Thank you. One moment for our next question. Our next question comes from the line of Daniel Guardiola from BTG Pactual.

Hi, good morning, Miguel and Alejandro. First of all, congrats for the results. I would like to touch on inorganic growth. And in that sense, I wanted to know if you could share with us an update on the sale process of Exxon. My understanding according to local media is that this process is now a three-horse race and I wanted to know if you are in this race or if you decided to opt out. And if you're is still in this race, Miguel, I would like to know if you can share with us what are the main merits you have identified from Exxon's assets in Argentina.

Hi, Daniel. Thank you for a question that I cannot answer, but I will try to do my best to give you some color. So first of all, yes, we continue engage in Exxon that -- as I said, the previous quarter was a competitive process that we were keen in participating and we continue to be in the race. And of course, as I said also in the last quarter, we will do whatever makes business sense. And if it comes to us, I mean, it will be welcomed. If it's not, life will move on, and we have enough acreage in our hands to continue with the development of our plans -- our future plan. Exxon assets are good assets, I mean, that's why are there. It gives us probably beyond. I mean we have today 200,000 acreage. And as you know, we have around 1,300 well location from which we have drilled 120, 130 of those, but also we have assets in the North, and that will probably allow us to create a new development hub in the North with more materiality to the one that we have today. So that is probably the strategic view beyond -- behind that. Now, again, I mean, it's building optionality for the future. We have enough upside in our own portfolio today to continue with our overall plan. Having a development hub in the North will add something to Vista. Hope I give you some color and I cannot say much more than that.

No, that's very good. Thank you, Miguel.

You're welcome, Daniel.

Thank you. One moment for our next question. Our next question comes from the line of Leonardo Marcondes from Bank of America.

Well, hi, everyone, and thanks for taking my question here. Well, there is a very interesting exhibit in our corporate presentation that I would like to explore a little more. Corporate presentation, okay, not the one from this quarter. On the Slide 11, there is an exhibit showcasing potential upside for different lending zones in different blocks, right? The message I get from this exhibit is that, there could be an upside in terms of well inventory, right? So my question is, when do you guys expect to explore or try to develop the Middle Carbonate landing zone of BPO, the Lower Carbonate of BPO in Aguada Federal, and also the Organic landing zone of BPE? Any color here or -- on your expectation would be great. Thank you.

Leonardo, thank you for the technical question. I would like to have my Chief Geologist next to me now to answer properly, but I will do my best. So, yes, as you pointed out, we have been testing different zones in different fields. So in BPO, for example, we test the Lower Carbonate. We have not tested yet the Middle Carbonate. In Aguada Federal, we tested the Middle Carbonate. In BPE, we have presence of Organic. So also -- I mean, it's something that we will test or we have some upside for the future. What this slide in the corporate presentation doesn't show is the area distribution of all those zones. For example, when you look at BPE, the Organic is not present in the full block. So they are -- besides testing the productivity of this zone, in some of those field, we need to test where those zones are -- really are and where are the borders. And as you -- as we see in the corporate presentation, we have started to test those zones little by little. And this -- what you just pointed out -- I mean, when you talk to independent American companies and very technical people that compare the rock of Vaca Muerta with Permian, this is one of the main thing that set us apart. And for many of them, it's one of the things that may think that Vaca Muerta, even though today have better productivity than Permian, have even more upside potential. Now saying all that, 2025 for us continues to be a year of full development. So, you will see that we will test when we have an opportunity sign of those zones, but we will not come with a plan on how to develop those zones in a different way in the next year. But yes, as you pointed out, we will continue assessing those zones because we believe that that will add a future reserve to our future development.

Thank you. Very clear.

Thank you. One moment for our next question. Our next question comes from the line of Ignacio Sabelle from Itau BBA.

Hi, everyone. Good morning. Congratulations on the results and on the updates. My question was about midstream capacity, but maybe could you give us any color on the long-term contracted capacity? I mean, 2030 goals are above the current capacity, and I would like to understand a bit better this. Thanks.

Okay, Ignacio. Thank you for your question. So, when coming to additional capacity, I mean, the first thing is that we are working on and we expect to have is Oldelval expansion. So, we expect that full capacity of the Vista share to be in place between February and April of 2025. This will be additional 31,000 barrels of oil per day. More long term is Vaca Muerta Sur. This is a process with YPF and other upstream producing of the basin, where we are actively participating with equity in that concept, or in the building of that pipeline. Today, we are working in the commercial and financing shareholders' agreement of how that will come into place. I think a lot of work has been done in that front, and we are confident that this project will take place. We have not yet defined our working interest on that one. But I think -- I mean, I can probably say that it will not be less than 10% for the Stage 1 and the Stage 1 full capacity, you have to think is around 400,000 barrels of oil per day. So, that is what we are working, and we are looking, and we are engaging in long-term capacity. But for now, of course, our eyes are in the ball and the ball is Oldelval expansion that we expect to have in Q1 next year.

Sure. Thanks.

Thank you. One moment for our next question. Our next question comes from the line of Andres Cardona from Citi.

Hi, good morning, Miguel, Pablo, Ale. Congratulations on the results. I have a more short-term question on the trucking activity for the fourth quarter. If you have any estimate guidance that you can provide, it would be very helpful. Thank you.

Hi, Andres. Trucking, so -- yes, look -- let me look at the number. So in term of volume, trucking, we will finish Q3 with a total volume of around [12,300] barrels of oil per day. When you look at going forward, what we are forecasting for Q4, of course, it's an increase, but we will increase volumes, but Oldelval will not be online. So we are thinking that we will trucking around 23,000 barrel oil per day average in Q4. Of course, that number will come down in Q1 2025, depending on when exactly Oldelval come into line. But -- I mean, you could expect that Q1 will be between the middle of what we did in Q3 and Q4 in term of trucking.

Thank you, Miguel.

You're welcome, Andres.

Thank you. One moment for our next question. Our next question comes from the line of Henrique Cunha from JPMorgan.

Hi, thank you. A lot of my questions were already asked, so a more basic one here. Lifting costs increased in the quarter despite the relevant production ramp-up. So, what is the expectations like and drivers going forward? How should the company manage this increase?

Yes. Thank you, Henrique, for your question. Yes, I mean, lifting costs increased few cents during Q3 and that basically increase is the continued investment that we are doing in gathering and processing, in compression, in power generator -- power generation to accommodate the production growth, and the future production growth. So now -- when coming to accommodate production grow and future production grow, even though the main [indiscernible] is CapEx, we also have to accommodate OpEx somehow. So, we continue with our guidance of $4.5 per barrel for the year in term of the average lifting cost for 2024 and going forward, with the increase of production and having lifting costs, a main component of fixed costs, I mean, we are very positive with that number going forward, and we see room for even improving that $4.5 that we have. So, no concern on the lifting cost front.

Okay. Thank you.

You're welcome.

Thank you. One moment for our next question. Our next question comes from the line of Matias Cattaruzzi from AdCap Securities.

Good morning, Vista team. Congratulations on Q3 numbers and the updated guidance. My question goes in the line of recent oil price volatility. Is the company considering implementing a hedging strategy for realized oil prices if regulation allows it, or how would you manage this in the future? Thanks.

Hi, Matias. Thanks for the question. Yes, first of all, as you know, I mean, regulation does not allow today to have a hedging policy or a hedging program since we cannot access to roll out for hedging. We see ourselves as a low-cost operator and we are very unleveraged, with no mature debt maturity in front of us. So, we like to think that our investors today can hedge themselves more efficiently than we can do in the current conditions. So, again, I mean, we don't have a hedging program. It's very unlikely that we will have in the next few years a hedging program. If the conditions change at some point of time and that makes sense, I mean, we will do something, but it's not something that we have today in our plan and we are looking at.

All right. Thank you so much.

Thank you. One moment for our next question. Our next question comes from the line of Alejandro Demichelis from Jefferies.

Yes, good morning guys. Thank you very much for taking my question. Actually, I would like to understand a bit better your guidance for 2025 on how much flexibility you have in that. So you said, Miguel, that you should have the Oldelval expansion there by April. So, that means you should have like 124,000 barrels a day of capacity for at least half of the year. And so, if there is any spare capacity in the pipeline, how quickly can you access that, and do you have enough flexibility in your work program to further expand your production?

Well, thanks, Ale. I mean, yes, definitely. I mean, as you pointed out, we will have different to what we experienced in 2023, we will go to 2025, most likely having -- not most likely, we will have a spare capacity, even trucking or spare capacity in Oldelval expansion, the capacity will be there. The other thing that we have and that we have proved this year and we will continue growing, I think, going into Q4 is the ability that we have to ramp up and execute. I mean, we are today quietly discuss it, the increase of production that we just have in Q3, but that has been an amazing achievement and something that we have proved to ourselves that we are capable to do. And I think that is another very important point. Going forward also, we will have a second frac set in hand. And as I said before, that give us optionality to grow because when the opportunity comes, you have to have the tools to make it happen and this second frac set is very important. If we want to go beyond what we have guided in 2025, we will need probably an additional drilling rig, a fourth drilling rig. Now saying all that, that will all depend on the context, that the 2025 green particularly pricing of oil internationally. So, if we -- the price is better or equal to the one that we plan, yes, we have flexibility to grow. We said that in the next three years, we will have generated around $1 billion of cash. We are using this cash this year partially to boost that growth, and 2025 we will do exactly the same thing. But of course, the context has to be there. So price of oil will play a role and for that, we have the rest.

That's great. Thank you.

You're welcome.

Thank you. I would now like to turn the conference back to Miguel Galuccio for closing remarks.

Well, thank you very much guys for the support, for the questions, for the continuous interest in Vista. And again, I would like to thank you, the people in the field that have made that quarter possible. This plan internally called Moonshot for us. It reflects or shows how difficult we thought was to go through this ramp up of production. So all credit to them. Thank you very much and have a very good day.

This concludes today's conference call. Thank you for participating. You may now disconnect.