Good day, and thank you for standing by. Welcome to Vista's third quarter two thousand and twenty-four earnings webcast and conference call. At this time, all participants are in a listen-only mode. After the speaker's presentation, there will be a question and answer session. To ask a question during the session, you will need to press star one one on your telephone. You will then hear an automated message advising your hand is raised. To withdraw your question, please press star one one again. Please be advised that today's conference is being recorded. I would now like to hand the conference over to your speaker today, Alejandro. Please go ahead. Thanks. Good morning, everyone. We are happy to welcome you to Vista's third quarter of two thousand and twenty-four 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 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 and adjusted net income. 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 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. Our tickers are VISTA in the Bolsa Mexicana de Valores and V-I-S-T 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 72.8 thousand BOEs per day, an increase of 47% year over year and 12% quarter over quarter. Oil production was 63.5 thousand 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 costs per BOE. Adjusted net income was $53 million, implying a quarterly adjusted EPS of $0.6 per share. Free cash flow was -$74 million 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 BOE 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 interannual basis, reflecting the ramp-up of our new well activity, as we tie in 51 new wells during the last twelve months compared to the 31 during 2023. Oil production was 63,500 barrels per day, implying an interannual growth of 53% and a sequential growth of 11%. Natural gas production increased 16% year over year and 12% quarter over quarter. Growth was driven by associated gas stream coming from our Vaca Muerta shale oil wells. During the third quarter of twenty twenty-four, we continued to make solid progress in the execution of our annual work program. We connected three pads during Q3, two in Bajada del Palo Oeste and one in Bajada del Palo Oeste, for the total of 12 new wells. We completed an additional pad in Bajada del Palo Oeste in late September, which led to the tie-in of three wells earlier this month. We therefore connected 40 new wells year to date, leaving us on track to deliver on our activity guidance, which is between 50 and 54 new wells for the year. Based on the execution of our new well activity plan, our model shows that production is forecast to expand again by double digits in Q4 to 85,000 BOEs per day. We also reiterated our guidance of 68-70,000 BOEs per day on average for the full year, noting that we will likely be on the upper end of this range. In Q3 2024, total revenues were boosted to $462 million, a 53% increase year over year, and 70% above the previous quarter, driven by a strong production growth. Realized oil prices were $68.4 per barrel on average, up 1% on inter-annual basis, and on a sequential basis, oil prices were 5% lower, driven by softer international prices. Domestic realization prices were $67.8 per barrel, net of trucking costs and including volume sold at export parity. Export realization prices were $68.9 per barrel. During Q3, we continued to execute our export-oriented strategy with an increase in amount of oil sold in international market, driven by the production growth. We exported 3.5 million barrels of oil during the quarter, 57% above the previous year. Additionally, one million barrels of oil were sold in the domestic market at export parity prices. Therefore, combining the sales to international buyers and domestic buyers paying export parity, 72% of our total oil sales were sold at export parity prices. Lifting cost was $31.6 million during the quarter, implying a lifting cost per BOE of $4.7. On a unit cost basis, our lifting costs were down 2% inter-annually, reflecting dilution of fixed costs as we continue to ramp up production. This effect was partially offset by the inflation in U.S. dollars. In a sequential basis, lifting costs per BOE increased 5%. This was driven by higher costs in gathering, processing, gas compression, and power generation to accommodate current production and future growth. Based on our annual work program, our model shows we are on track to deliver on our guidance of $4.5 per barrel for the year. Adjusted EBITDA during the quarter was $310 million, a solid increase of 37% year over year, mainly driven by a strong production growth amid stable oil prices and lifting cost per BOE. On a sequential basis, Adjusted EBITDA increased by 8%. Noteworthy is the fact that on LTM basis, Adjusted EBITDA has surpassed $1.1 billion. Adjusted EBITDA margin was 65% during the quarter. The softer inter-annual print reflect a temporary increase in trucking expenses. During Q3, we trucked 12,000 barrels of oil per day for a total cost of $23 million, of which $16 million were allocated to selling expenses in our income statement and $7 million were deducted from our revenue line. During the third quarter, we continued with CapEx acceleration to support production ramp-up. Operating activities cash flow was $255 million, reflecting an increase in working capital of $52 million and advanced payments for the midstream expansion of $20 million. Cash flow used in investing activities was $329 million, reflecting accrued CapEx of $369 million, partially offset by a $42 million decrease in CapEx-related working capital. Cash flow from financing activities reflect proceeds from borrowing of $143 million, the repurchase of shares for $50 million, and the repayment of borrowings for $74 million. As a result, free cash flow during the quarter was negative $74 million, and cash at period end was $256 million. Net leverage ratio stood at a very healthy 0.65 times Adjusted EBITDA at quarter end. During 2024, we have achieved three very significant milestones to deliver on our profitable growth plan. Firstly, we have accelerated growth in 2024, ramping up new well activities and leading to a forecast of 85,000 BOE per day on average in Q4. This will imply more than a 50% increase year over year in that quarter. Additionally, we secure our midstream capacity of 124,000 barrels of oil per day by year-end in 2025. And finally, we secure a third drilling rig and a second frac set under a term contract, which give us capacity to grow further during 2025. Based on these milestones, we are updating our 2025 guidance. We forecast total production between 95,000 and 100,000 barrels of oil per day, implying an inter-annual production growth of more than 40%. This plan is based on 52-60 new wells during the year, and $1.1-$1.3 billion of CapEx. This excludes potential investment in Vaca Muerta Sur oil pipeline and export terminal. We forecast an Adjusted EBITDA of between $1.5 and $1.65 billion, also implying an interannual growth of more than 40%. Our realized oil price assumption is between $67 and $72 per barrel, implying a Brent of $75-$80 per barrel. This plan is in line with capital allocation priorities disclosed in our last investor day. Based on the depth of our short cycle, high return well inventory, we are accelerating our profitable growth plan. We continue to assess the impact that this updated guidance will have on our 2026 forecast. As a result, we are withdrawing our 2026 guidance, and we are working on a new long-term plan to be presented to our investor during 2025. I will now summarize the key takeaways of today's presentation. During Q3 2024, we recorded strong operational and financial performance. We continue to deliver growth with industry-leading return on capital. Growth was driven by the sharp execution of our annual work program. We have connected 12 wells in the quarter and 40 wells year to date. Alongside with solid well productivity, this has boosted production, revenues and net profit. Based on solid progress during the quarter, I can confirm we are well on track to deliver on our 2024 guidance for activity, production, lifting costs, and adjusted EBITDA. During Q3, we have also made focus on return to shareholders. We executed the second tranche of our share buyback plan for $50 million. This adds up to $100 million of buyback during the year. Finally, based on our CapEx acceleration during the year and having secured additional capacity in drilling, completion, and oil export infrastructure to continue our growth, we have updated our 2025 guidance. Our plan is forecast to yield more than 40% growth in production and adjusted EBITDA compared to 2024. Before we move to Q&A, I would like to thank our shareholders for their continued support and congratulate the entire Vista team for their outstanding performance. Operator, please open the line for Q&A. Thank you. As a reminder, to ask a question, please press star one one on your telephone and wait for your name to be announced. To withdraw your question, please press star one one again. Please stand by while we compile the Q&A roster. Our first question comes from the line of Vicente Falanga from Bradesco BBI. Hi, good morning, everyone. Thank you, Venutro. Thank you, Ali. 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 two thousand and twenty-four, but we saw, you know, quite a sharp rise in the CapEx. Can we assume that you're drilling longer laterals with more frack stages? And if yes, you know, 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, you're right. I mean, when you look at the total CapEx in Q3 was $369 million, compared with $346 million in Q2, with similar numbers of well tie-in. When you look at the breakdown, $280 million were drilling and completion in Q3, compared with Q2 or $267 million. And as you pointed out, the main difference in CapEx came from the lateral length of our horizontal wells. So we drill, yes, longer laterals between 3,300 and 3,200 meters, compared with 2,800 meters. Cost of those wells go from 14.5 in the 2,800 to a range of 16-17, and depending on the length, it is 3,000-3,200 meters. 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 to 50- 55 in a 3,000 or 3,000+ lateral length. The decision of this is super based on subsurface, so it's subsurface driven. And of course, EURs of these wells are different. We moved from 1.5 million barrels of total EUR to around probably 1.8. 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 the lateral, NPV payoff. So that's, that's the main reason of what you have seen, the $20 million or $23 million CapEx difference between drilling and completion and 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 on the line of Taso Vasconcelos 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, Taso, 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 and 54 wells. And that execution will be done with three drilling rigs for the full year, independently, we are replacing one rig with now a rig that has arrived that is a new drilling rig. When you look at we, we have been drilling with three drilling rig full year, and one frac set full year. And then we use a spot frac set, I believe twice a year. So with that, we will achieve between 50, maybe 54, tie-ins. When you look at what we guide for twenty twenty-five, we guide between 52 and 60 new tie-ins, 3 drilling rig, and the main difference is that we will have access to a full frac set for the full year. So when you talk about potential, really what this frac set give us is the full potential to go beyond this 52 or 60 well tie-in. If we notice here that if you want to add another drilling rig, a fourth drilling rig, because the conditions are there, 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 farther to the 60 or 52 wells that we have guided. So that frac set, back to your question, is really what gives 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, Ale, 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 thank you for your question. Yeah, we will finish this year with an average of 85,000 barrels per day in Q4, and we are guiding for 2025, 95-100. 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 and 100 for next year, that mean that we will have an execute rate in 2025, about 100,000 barrels per day for sure. We will have evacuation capacity in 2025 for 124,000 barrels per day. That will be composed of 75,000 on Oldelval, 44 that we already have, plus the 31 that we will add. Vaca Muerta Norte in Chile and Otasa, it will be 12,000, so that give you 87,000. And we have big capacity, trucking capacity for 30,000 barrel per day. So that make 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, for me, when you look at the capacity that are going to be put in place in Q1, they most likely will be spare capacity. So, even though we talk about 35,000-37,000 barrel 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 parities 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 per barrel, it was $60.8. And when you see the prices of local in Q3 was $68, so very similar. We feel that 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 calls for no pricing intervention. So we are optimistic that the regulation of this new law will support that conversion between local pricings to international prices. So we believe that same dynamic 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 want 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're in this race or if you decided to opt out, and if you're 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 I cannot answer, but I will try to do my best to give you some color. So first of all, yes, we continue engaged in ExxonMobil. That, as I said, the previous quarter was a competitive process that we were keen in participate, and we continue to be in the race. Of course, as I said, also in the last quarter, we will do whatever make business sense. If it come to us, I mean, it will be welcome. If not, life move on, and we have enough acreage in our hands to continue with the development of our plans, our future plan. ExxonMobil assets are good assets. I mean, that why we are, we are there. It give us probably beyond. I mean, we have today 200,000 acreage. 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, if building optionality for the future is we have enough upside in our own portfolio today to continue with our overall plan. Having a development hub in the north, yeah, it 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. Hi, everyone. Thanks for taking my question here. There's 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's an exhibit showcasing potential upside for different landing 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? 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 and Agua Federal, and also the organic landing zone of BP. Any color here or on your expectation would be great. Thank you. Hi, Leonardo. Thank you for the technical question. I would love 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 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 Agua Federal, we test the middle carbonate. In BPE, we have presence of organic. So also, I mean, it's something that we will test, so we have some upside for the future. But this slide in the corporate presentation, does it show 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 fields, we need to test where those zones really are, and where are the borders. As we see in the corporate presentation, we have started to test those zones little by little. 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 things that set us apart. For many of them, is 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, twenty twenty-five for us continue to be a year of full development. So you will see that we will test, when we have an opportunity, some of those zones, but we will not come with a plan of how to develop those zone 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 Zabaleta from Itau BBA. Hi, everyone. Good morning. Congratulations on the results and on the updates. Now, 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 it come to additional capacity, I mean, the first things that we are working on and we expect to have is all the Oldelval expansion. So we expect that full capacity of the Vista share to be in place between February and April of twenty twenty-five. These are, 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 producers 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, financial, 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 one. And the stage one full capacity, you have to think it's around 400,000 barrel per day. So, that is what we are working, and we are looking, and we are engaging in the, in long-term capacity. But, for now, of course, our eyes are on the, in the ball, and the ball is, all the value expansion that we expect to have in Q1 next year. Sure. Thanks. Have a nice one. 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, Alejandro. Congratulations on the results. I have a more short-term question. The trucking activity for the fourth quarter, if you have any estimate guidance that you can provide, would be very helpful. Thank you. Hi, Andres. Trucking, so yeah, look at, let me look at the number. So in terms of volume trucking, we will finish Q3 with a total volume of around 12,000.3 barrels of oil per day. When you look at going forward, what we are forecasting for Q4, of course, is an increase, but we will increase volumes, but all the volume will not be online. So we are thinking that we will be trucking around 23,000 barrels of oil per day, average in Q4. Of course, that number will come down in Q1 2025, depending on when exactly all the volume comes online. But, I mean, you could expect that Q1 will be between the middle of what we did in Q3 and Q4, in terms 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 JP Morgan. 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, how should the company manage this, the increase? Yeah. Thank you, Henri, for your question. Yes, I mean, lifting costs increased a few cents during Q3. And that basically increase is the continued investment that we are doing in gathering, processing, in compression, in power generator, power generation, to accommodate the production growth and the future production growth. So, when it comes to accommodate production growth and future production growth, even though the main thing you need is CapEx, we also have to accommodate OpEx somehow. So we continue with our guidance of $4.5 per barrel for the year in terms of the average lifting cost for 2024. Going forward, with increase of production and having lifting costs a main component of free costs, I mean, we are very positive with the 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 Cataruzzi 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 hedging program since we cannot access to dollar for hedging. We see ourselves as a low-cost operator, and we are very unleveraged. We don't measure the 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, well, 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 twenty twenty-five and how much flexibility you have in that. So you said, Miguel, that you should have your global expansion there by April, so that means you should have- ... like hundred and twenty-four thousand barrels a day of capacity for at least half of the year. So if, 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? Thanks, Ale. I mean, yeah, 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, or most likely, we will have a spare capacity. Even striking or spare capacity in all the well 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 discussing the increase of production that we just have in Q3, but that has been amazing achievement and something that we have proved to ourselves that we are capable to do. 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 come, 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 guide in 2025, we will need probably an additional drilling rig, a four drilling rig. Now, saying all that, that will all depend on the context that 2025 bring, particularly pricings of oil internationally, so if 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 have to be there. So price of oil will play a role, and for that, we have the rest. Great. Thank you. You're welcome. Thank you. I would now like to turn the conference back to Miguel Galuccio for closing remarks. Thank you very much, guys, for the support, for the question, for the continuous interest in Vista. 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 reflect or shows how difficult we saw 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.