Vista Energy S.A.B. de C.V. American Depositary Shares, each representing one series A share, with no par value

Good day, and thank you for standing by. Welcome to VISTA's third quarter 2024 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 11 on your telephone. You will then hear an automated message advising your hand is raised. To withdraw your question, please press star 1-1 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 Chernekov, 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 Galucho, VISTAS Chairman and CEO, Pablo Verapinto, VISTAS CFO, and Juan Garobi, VISTAS 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 US 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 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 BISC 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 Baca Muerta. Total production was 72.8 thousand DOEs 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 costs was $4.7 per DOE, 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 EBDA was $310 million, 37% above year-over-year, driven by robust revenue growth and lower lifting costs per VOE. Adjusted net income was $53 million, implying a quarterly adjusted EPS of $0.6 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 dry growth. Net leverage ratio at quarter end was a solid 0.65 times adjusted EBDA. I will now deep dive into our main operational financial metrics of the quarter. Total production during the quarter was 72.8 thousand BOH 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 tight 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 12 months compared to the 31 during 2023. Oil production was 63.5 thousand 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 streams coming from our Vaca Muerta shale oil wells. During the third quarter of 2024, we continue to make solid progress in the execution of our Orano Agro Program. We connected three paths during Q3, two in Bajada del Palo Este and one in Bajada del Palo Este for the total of 12 new wells. We completed an additional path in Bajada del Palo Este 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 digit in Q4 to 85,000 BOEs per day. We also reiterated our guidance of 68,000 to 70,000 VOEs 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 strong production growth. Realized oil prices were $68.4 per barrel on average, up 1% on interannual 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 tracking 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 the international market driven by the production growth. We exported 3.5 million barrels of oil during the quarter, 57% above the previous year. Additionally, 1 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 VOE of $4.7 million. On a unique 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 VOE 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 previewing. On a sequential basis, adjusted EVA increased by 8%. Noteworthy is the fact that on LTM basis, adjusted EVA has surpassed $1.1 billion. Adjusted EVDA margin was 65% during the quarter. The softer interannual print reflect a temporary increase in tracking expenses. During Q3, we tracked 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 unbalanced payments for administering expansions 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 $74 million negative, 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 BOEs per day on average in Q4. This will imply more than a 50% increase year-over-year in that quarter. Additionally, we secure oil minitring capacity of 124,000 barrels of oil per day by year-end in 2025. And finally, We secure a third lean rig and a second frag set under term contracts, 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 barrel holes per day, implying an interannual production growth of more than 40%. This plan is based on 52 to 60 new wells during the year and $1.1 to $1.3 billion of CAPEC. This excludes potential investments in Bacamorte-Azul oil pipeline and export terminals. We forecast an adjusted EBDA 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 brand of $75 to $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 investors 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 here today. 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 VDA. 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 CAPEC 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 focused to yield more than 40% growth in production and adjusted EVDA 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 11 on your telephone and wait for your name to be announced. To withdraw your question, please press star 11 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, Valucho. Thank you, Ali. Thank you, Juan. My question is the following. Avista 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 topics. Can we assume that you're drilling longer laterals with more frac stages? And if yes, what is the expected rate? 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.

So, yes, you're right. I mean, when you look at the total gap in Q3 was $369 million compared with 346 in Q2 with similar numbers of wells tying. When you look at the breakdown, 280 million were drilling and completion in Q3. compared with Q2 or 267. And as you pointed out, the main different gap came from the lateral length of our horizontal wells. So we drill, yes, longer laterals between 3,300, 200 meter compared with 2,800 meter. Cost of those wells go from 14.5 in the 2,800 to a range of 16 to 17, and depending on the length, it is 3,000, 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 a 2,200 to 50 to 55 in a 3,000 or 3,000 plus lateral length. The decision of this is super based on subsurface, so it's subsurface driven. And of course, EURs of this wealth 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, NPVY payoffs. So that's the main reason of what you have seen, the $20 million or $23 million of 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 in the line of Tasso 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.

Thank Tasso for your question. It's a very good question. So maybe the best way to look at this is we look at 2024. When you look at 2024, we will end up tying in between 50 and 54 wealth. And that execution It 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 have been drilling with three drilling rigs full year. And one frag set, full year. And then we use an exposed frag set, I believe, twice a year. So with that, we will achieve between 50, maybe 54 tie-ins. When you look at what we got for 2025, we got between 52 and 60 new tie-ins, three during the week. And the main difference is that we will have access to a full frag set for the full year. So when you talk about potential, really, what this track set give us is the full potential to go beyond this 52 or 60 well tie-in. It's worth to notice here that if you want to add another drilling rig, a four 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 It's not difficult. Getting a new FRAC feed, having that optionality ready in the country at 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 got. So that FRAC set, back to your question, is really what gives us flexibility, optionality, and potential.

Thank you. 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 to 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 means that we will have an exit 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 the 44 that we already have, plus the 31 that we will add. Vaca Muerta Norte in Chile and Otaza, it will be 12,000. So that gives you 87,000. And we have big capacity, tracking capacity for 30,000 barrels 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 spare capacity in Old El Val. I mean, beyond the 31,000 that we will use and we have access to, for me, when you look at the capacity that's 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 barrels per day on tracking, 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 goes to the line of Marina Mertens from Latin Securities.

Hi, good morning. Thanks for taking my questions. So in the third quarter, rent prices declined and local prices remained quite stable. So the gap between domestic and international prices narrow 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 parties 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 real life price of our exports with $78 per barrel, it was 60.8. And when you see the prices of local in Q3, it was 68. So very similar. We feel that we should not see a change in that dynamic going forward. 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 reglamentation of this new law will support that conversion between local pricing to international prices. we believe that same demand will continue to flow. 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 cell process of action. 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 that I cannot answer, but I will try to do my best to give you some color. So first of all, Yes, we continue to engage in Exxon. As I said, the previous quarter was a competitive process that we were keen to participate in 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, it will be welcome. If not, I will move on and we have enough acreage in our hands to continue with the development of our plans, our future plans. Exxon assets are good assets. I mean, that's why we are there. It gives us probably beyond. I mean, we have today 200,000 acres. As you know, we have around 1,300 well locations 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 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 road plan. Having a development hub in the north will add something to Vista. Hope I give you some color. 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.

Thanks for picking my question here. Well, 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? So my question is, when do you guys expect to explore or try to develop the middle carbonate land zone of BPO, the lower carbonate of BPO in Aguada Federal, and also the organic land zone of BPE? 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 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 take 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. What this slide in the corporate presentation does show is the area distribution of all those zones. For example, when you look at BP, the organic is not present in the full block. So they are beside testing the productivity of the zone. In some of those fields, we need to test where those zones really are and where are the borders. And 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 Acamorta with Permian, this is one of the main things that set us apart. And for many of them, is one of the things that may think that Vaca Muerta, even though today has better productivity than Permian, has 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, we will have an opportunity, some of those zones, but we will not come with a plan of how to develop those zones in a different way uh in 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 goes to the line of Ignacio Saber from Itao BBA.

Hi, everyone. Good morning. Congratulations on the results and on the updates. My question was about mid-trade 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 comes to additional capacity, I mean, the first thing that we are working on and we expect to have is all Del Valle 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 mass 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 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 barrels per day. So that is where 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 all the value expansion that we expect to have in Q1 next year.

Sure.

Thanks, Alex. 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 about 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.

Tracking. Let me look at the number. In terms of volume tracking, we will finish Q3 with a total volume of around 12,000.3 barrel holes per day. When you look at Going forward, we are forecasting for Q4. Of course, it's an increase, but we will increase volumes, but Old Elba will not be online. So we are thinking that we will be tracking around 23,000 barrels per day average in Q4. Of course, that number will come down in Q1 2025, depending on when exactly Old Elba comes into line. But I mean, you could expect that Q1 will be between the middle of what we did in Q3 and Q4 in terms of tracking.

Thank you, Miguel.

You're welcome, Andres. Thank you. One moment for our next question. Our next question comes from the line of Henri 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 expectation like in drivers going forward? How should the company manage this increase?

Thank you, Enrique, for your question. Yes, I mean, lifting costs increased a few cents during Q3. And that basically increased the continued investment that we are doing in gathering, processing, in compression, in 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 TK United is CAPEX, we also have to accommodate OPEX somehow. So we continue with our guidance, $4.5 per barrel for the year in terms 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 the number going forward, and we see room for even improving that 4.5 that we have. So no concern on the lifting costs, Ron.

Okay. Thank you.

You're welcome.

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

Good morning, Mr. Tim. Congratulations on your three 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, Mattia. 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 $2 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. 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. I would like to understand a bit better your guidance for 2025 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 124,000 barrels a day of capacity for at least half of the year. 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... Yeah, definitely. I mean, as you pointed out, we will have a difference to what we experienced in 2023. We will go to 2025, most likely having, most likely we will have spare capacity, even striking or spare capacity in all the value expansion, the capacity will be there. The other thing that we have and that we have proved this year, and we will continue proving, 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 had 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 gives 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 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 brings, 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.

Great. Thank you.

You're welcome. Thank you. I would now like to turn the conference back to Miguel Galucho for closing remarks.

Well, thank you very much, guys, for the support, for the question, 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 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.