Vista Energyb De Cv Aktie

Good day and thank you for standing by. Welcome to the Vista's First Quarter 2026 Earnings Webcast Conference Call. [Operator Instructions] Please be advised that today's call is being recorded.

I would now like to hand it over to our first speaker, Alejandro Chernacov, Vista's Strategic Planning and Investor Relations Officer. Please go ahead.

Thanks. Good morning, everyone. We are happy to welcome you to Vista's First Quarter 2026 Results Conference Call. I am here with Miguel Galuccio, Vista's Chairman and CEO; Pablo Vera Pinto, Vista's CFO; Juan Garoby, Vista's CTO; and Matias Weissel, 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 the 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 conference 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 VIST in the New York Stock Exchange.

I will now turn the call over to Miguel.

Thanks, Ale. Good morning, and welcome to this earnings call. During the first quarter of 2026, we made solid progress in our annual work program on the back of a robust new well productivity. Total production was 135,000 BOEs per day, up 67% year-over-year. Oil production was 117,000 barrels per day, an increase of 68% compared vis-a-vis the previous year. Total revenues during the quarter were $694 million, 58% above the same quarter of last year. Lifting cost was $4.3 per BOE, 8% below year-over-year.

Capital expenditure was $391 million, driven by a strong progress in new well activity during the quarter. Adjusted EBITDA was $451 million, an interannual increase of 64%. Net income was $108 million, leading to earnings per share of $1 during the quarter. Free cash flow was minus $341 million, impacted by $331 million of nonrecurring items, of which $206 million corresponded to the initiation of VEISA operation on a delivered basis. Without these nonrecurring items, free cash flow in the quarter would have been almost neutral. Finally, our net leverage ratio at quarter-end was 1.7x adjusted EBITDA. During Q1, 2026, we tied in 23 wells -- 12 in Bajada del Palo Oeste, 4 in Bajada del Palo Este, and 7 net wells in La Amarga Chica.

This represents very good progress compared to our guidance of 80 to 90 wells for the full year. Solid well productivity of the tie-in wells drove a material production increase from 127,400 BOEs per day in January to 143,200 BOEs per day in March. Total production during Q1 averaged 134.7 BOEs per day. This represents an interannual increase of 67%, reflecting organic growth and our larger scale after the acquisition of La Amarga Chica. Oil production was 116,700 barrels per day, 68% higher year-over-year. Gas production increased 62% on an interannual basis. In Q1 2026, total revenues were $694 million, 58% above the previous year, driven by a solid increase in oil production, which more than offset lower oil prices.

Oil exports more than doubled year-over-year, reaching 7.2 million barrels in the quarter, representing 67% of our total sales volume. Realized oil price in Q1 was $60.1 per barrel on average, down 12% on an interannual basis, and up 2% on a sequential basis, in both cases driven by Brent. We sold 100% of oil volumes at export parity prices, both domestically and internationally. Higher oil prices owing to war in the Middle East had a minor impact on Q1 revenues, as we had mostly locked in March prices when the conflict started in February 28. We expect higher oil prices to significantly boost adjusted EBITDA and free cash flow during Q2 2026 and onwards.

In Q1 (sic) [ Q4 ], lifting cost was $4.3 per BOE, 8% below the same quarter of last year, reflecting our low-cost asset base and fixed-cost dilution as we continue to gain scale. Selling expenses were $3.8 per BOE, down 41% on an interannual basis, mainly driven by the elimination of oil trucking as of the end of Q1 2025.

Adjusted EBITDA during the quarter was $451 million, 64% higher interannually, mainly driven by the consolidation of 50% working interest in La Amarga Chica and organic production growth in our core development hub, which more than offset lower oil prices. On a sequential basis, adjusted EBITDA increased 2%, driven by higher realized oil prices. Adjusted EBITDA margin was 65%, up 3 percentage points compared to the same quarter of last year, driven by lower export duties, selling expenses, and lifting costs, which offset lower oil prices.

In Q1 2026, cash flow from operating activities was $86 million, mostly impacted by 2 one-off negative items. First, a working capital impact of $206 million as a consequence of ramping up our trading operation, which moved a large part of our export from FOB to delivered basis and at a higher Brent price. Second, an outflow of $46 million corresponding to a tax payment in Mexico, which has been booked in previous quarters. Cash flow used in investing activities was $427 million, reflecting accrued CapEx of $391 million, a decrease in CapEx-related working capital of $53 million, and the $80 million deposit related to the Equinor acquisition.

As a result, free cash flow was minus $341 million during the quarter. Net of the working capital, one-off impacts, and the Equinor deposit, recurring free cash flow was minus $10 million during the quarter. These impacts were expected and do not change our positive free cash flow forecast for the year, excluding payment to Equinor. Additionally, as we will show in the following slide, free cash flow is forecast to be materially higher than our original expectations.

Cash flow from financing activities were $118 million, driven by proceeds from borrowings for $590 million, partially offset by the repayment of borrowings for $130 million and the interest payments of $27 million. Finally, our cash position remains very strong, standing at $615 million at the end of the quarter. Our net leverage ratio stood at 1.7x adjusted EBITDA.

Today, we are updating our annual guidance to reflect the impact of robust production performance, as well as a more constructive view of oil prices. Based on the solid progress of our new well campaign, with 23 tie-ins to date, and robust productivity, we are increasing our full year production guidance from 140,000 to 143,000 BOEs per day, more than 1 million barrels of oil equivalent for the year. Importantly, our CapEx guidance remains unchanged. We forecast to spend between $1.5 billion and $1.6 billion of CapEx in 2026. Considering the current oil price volatility, we are showing different scenarios for Q2 through Q4, $75, $85, and $95 Brent. Based on this new production and oil price assumptions, we are forecasting a material increase in our financial metrics.

In the $85 per barrel scenario, our adjusted EBITDA guidance increased to $2.6 billion, an improvement of $700 million from our previous guidance. Assuming $95 Brent for Q2 through Q4, adjusted EBITDA will be $2.9 billion. And at $75 Brent, it will be $2.3 billion. Our 2026 free cash flow guidance increased to $700 million, assuming our base case of $85 Brent in Q2 through Q4. This is $0.5 billion more than in the original guidance. Assuming $75 for the same period, free cash flow for the year will be $400 million, whereas at $95, it will be $1 billion of free cash flow for the year.

This updated guidance does not reflect the closing of Equinor Argentina acquisition. Last week, we completed all the conditions precedent to close the transaction. We expect closing to occur in early May, and guidance will be updated probably after. On a preliminary basis, after consolidating the acquired assets, we forecast 2026 adjusted EBITDA guidance to increase to $3 billion, assuming $85 Brent for Q2 to Q4.

To conclude this call, and before we move to Q&A, I will make some closing remarks. Solid execution of our annual work program delivered material production growth during the quarter. Based on our production performance and a more constructive view on oil prices, we have updated our 2026 guidance, which now reflects more production as well as a material improvement to adjusted EBITDA and free cash flow projections. Our new scale, following the execution of 2 important M&A transactions that add up to our 70,000 BOEs per day, place us in an excellent position to benefit from this positive oil pricing cycle. We expect a significant boost to adjusted EBITDA and free cash flow as of Q2 2026. This additional cash generation will allow us to strengthen our balance sheet by significantly reducing our leverage ratios during 2026, emerging from this price cycle as a strong and more flexible company.

Before we move to Q&A, I would like to thank all our employees for their hard work during the quarter. Operator, we can now move to Q&A.

[Operator Instructions] Our first question will come from the line of Leonardo Marcondes from Bank of America.

So my question here is regarding the revision of the guidance for production. Could you walk us through the main drivers behind the increase in this year's production guidance? Given that CapEx remains unchanged, what is effectively enabling this uplift? Should we attribute it mainly due to better-than-expected well productivity?

Leonardo, thanks for the question. Yes. Look, I think there's 2 things. One, and the more important, is that we feel super confident due to the results of the 23 wells that we connected in Q1. All of them have very robust productivity. So we decided, basically, that we will up [ 2026 ] as you saw from 140 to 143 barrels of oil equivalent per day, that basically adds 1 million barrels during 2026. If you go and try to understand a bit the quarter breakdown, I think you have to expect that Q2 will be around the production level that we are recording now in March, and then progressively, you see increases in Q3 and in Q4 that will lead us to a total of 143,000 barrels of oil per day average for the year. And as I mentioned in the presentation, this does not include the consolidation of Equinor assets. Thanks for the question.

Our next question will come from the line of Guilherme Martins from Goldman Sachs.

I have a quick one on capital allocation. I understood you guys have maintained your CapEx guidance for the year despite the scenario of higher oil prices since your last Investor Day last year, right? Having said this, what should we think in terms of capital allocation this year? Miguel, you mentioned the company could use this additional cash flow from higher oil prices to pay down debt, right? What is the target net debt to EBITDA we should think of?

Thank you, Guilherme, for the question. The answer is in line with what you mentioned. We should -- you should go back and we should go back to the capital allocation framework that we've been basically commenting for the last few years. We used our balance sheet to close 70,000 barrels of oil per day in acquisitions when you take in consideration the acquisition of Petronas and Equinor.

Now that we enter in a higher oil price scenario and that we almost doubled the production in the last year, we believe that we should deleverage using that momentum that we are living and regain financial flexibility, the one that we had prior to the acquisition. That means for us going back to around the 1x net leverage ratio we said by year-end.

Additionally, we said on Tuesday, we announced that the shareholders approved the extension of the share buyback plan for $150 million for 2026. So you also should assume that we will use the cash during this year to complete that acquisition of the buyback. So that is pretty much how you should think of the year. So you're correct, our priority now will be deleveraging.

And our next question will come from the line of Bruno Montanari from Morgan Stanley.

I wanted to explore a little bit more the pricing situation, Miguel. You mentioned that you were unable to capture the full benefits in the first quarter because you closed the prices ahead of the March rally. So can you comment on what you have been able to secure now in the beginning of Q2? And if there is any commercial strategy change that could allow you to capture more spot prices without eventually fixing the prices 1 month ahead?

Thank you, Bruno, for the question. A lot of noise in the line, but I think I managed to catch the question. So first, I would like to say that we are not changing our commercial strategy. You are going to see that we capture 100% of the high oil prices starting in Q2. There is always part of the oil sales, as you know, of the next month, which have locked-in in advance. We've been doing that for many years. The rationale has always been working capital management.

As we said in the presentation, we sold essentially all the March volume before the conflict in the Middle East started, and the price of such a sale was locked in previous to the event. As of today, less than 1/3 of Q2 production is priced at an average price of around $90 Brent, while the rest of the production will continue to price at the current and future price levels. So summarizing, for that, we are exposed to full Brent volatility for the rest of the volume that we have not yet closed. So basically, no change in the strategy and also no change in the practice of locking in 1 month ahead that we are selling.

Thank you. And our next question will come from the line of Daniel Guardiola from BTG Pactual.

I have a question on cost inflation, especially considering the current environment of high oil prices. I wanted to ask if you've seen any early signs of service cost inflation in rigs, frac crews, logistics, sand, et cetera. And how should we think about the balance going forward between pricing tailwinds and potential cost pressure? And to what extent do you believe your efficiency gains can somehow offset this potential inflation? So that would be my question.

Thanks, Daniel, for the question. A very good question. So first of all, probably the best thing for me to say and to clarify is that we have not had any tariff change, okay? And we will not allow any tariff change. Now the existing contracts, some of them, I would say many of them, are just using gasoline prices. So we are seeing some tariff adjustment on those cases, we could consider inflation. We are also seeing some impact on the peso component due to the flat FX.

Now saying all that, and as you mentioned, we have a very solid cost reduction plan in place. So the project that we are executing will allow us to offset most of those effects, so we are on track, and we are basically confirming our guidance of $11.7 million for drilling and completion cost per well, and also the $4.3 that we mentioned in terms of lifting costs. So we are super confident. Yes, we are seeing some pressure or adjustment on the contract due to the price of gasoline, but the plan that we have in place will allow us to offset that small impact.

And our next question will come from the line of Alejandro Demichelis from Jefferies.

Miguel, you just talked about your hedging strategy and how you're dealing with the commercial part. Maybe you can talk about how the new trading vehicle should be operating, how much risk it should be taking, and how can that continue to improve your commercial cost?

Thank you, Ale, for the question. Yes. So first, the reason why we created a trading company, the main reason, and we explained it before, is to access to new markets. But basically, we generate more demand from the Medanito oil, and also we create some additional margins since we are selling our own oil on delivering basis. As we said, when we look at what we have done, we are achieving both. We are reaching new markets. And as an example, Malaysia, Australia, Thailand, Singapore, that we didn't reach before, we are reaching now. And we are also capturing additional margins on the 25 million barrels that VEISA expects to trade during 2026. So we are not a trading company. So VEISA's goal is not to take any trading risk.

That they only take position to cover the volume that we sold, and usually also only for the following month until the oil is delivered. So I mean, I think it's super important to clarify because we did VEISA for that reason. And we should not look at VEISA as a trading company. And, of course, I mean, the 2 objectives that we put us in line of the creation of VEISA, we are achieving it.

And our next question will come from the line of Henrique da Cunha from JPMorgan.

We have a question on working capital. Could you provide more color on the impact it had on free cash flow in the quarter? Specifically, in the report, you mentioned around $200 million related to VEISA, which was not included in our estimates here. So could you elaborate on the contract effects from VEISA, and what should we expect going forward?

Yes, Henrique, of course, happy to elaborate on that. So basically, the ramp-up of VEISA operations generate 2 one-offs, as we explained. One is related to the fact that VEISA sold most of its production on a delivered basis instead of FOB that was what we were doing before, which is -- that is what we were doing with all the trading companies that we were using before the creation of VEISA. This extended the revenue collection cycle by the transit of the ship.

So let me give you an example. An oil vessel that takes around [ 25 days ] to go from Puerto Rosales to West Coast in U.S. Also now we are seeing more demand from the Asian buyers, but also will take that transit time -- much more time, I would say, probably 40 days of transit time. And that is basically the change that we have, from what we did before and what we have today. This is the first one-off.

The second effect is related to VEISA's short-term [ hedge ] will consist of buying physical oil from Vista Argentina and selling a forward contract at the same price to lock in that revenue. So for example, in the month of March, with significant price volatility, our EBITDA reflects the realization of price of $60, but the invoice to be collected by VEISA reflects the market price that was between $90 and $100, leading to an increase in working capital. So those are the 2 effects that we have. One is related to the realization of the price and the short hedge that VEISA takes every time it sells. And the other one is the change of us that today we are selling on delivered basis instead of FOB that we were doing before. I hope that answers your question, Henrique.

Our next question comes from the line of Tasso Vasconcellos from UBS.

Miguel, you already mentioned a little bit about your pricing, the discount on premium to Brent prices, Medanito and so on. But can you also comment on that agreement that you had with the local refineries in Argentina in terms of setting some kind of limit on pricing when oil prices are too high, but also some kind of protection when it moves to lower [ intermediate ] periods, that's good for us to understand how we should think about this agreement looking forward.

Tasso, thank you very much for the question. So first, probably prices in the domestic market continue to fully reflect export parity. And I think that is super important to understand. There was no agreement to fix prices. Now what we did was to discuss an agreement to mitigate the financial impact of rising crude oil prices resulting from the conflict that we have in Middle East. So that agreement was that the buyer will recognize full export parity, but paying up to $95 to $100 Brent for April and May. So any positive difference between the price that they paid and the international market price will be deferred and paid no later than July 31.

This agreement does not have any material impact on our cash flow, as you know, and is only applied to 1/3 of our local sales, equivalent to 15,000 barrels of oil per day, or around 10% of our total sales. The rest of the volume continue to be priced and paid at export parity. So that is what we did. I think it was very smart. It took the consensus of very few people. And again, we continue receiving and reflecting full export parity in the local market.

And our next question will come from the line of Andres Cardona from Citi.

The province of [indiscernible] is considering doing a new round of some 15 blocks, from what I see, on the Neuquén. Could you share your thoughts about this opportunity, timing, if the assets are located in a relatively core acreage or it's more type of frontier? Any color that you could share is appreciated.

Thank you, Andres. Yes, I think, look, I mean, very good timing of the province to put this out. We are always going to look into anything that is on the basin that we can participate. Nevertheless, when you look at what basically they are offering, I would say there's a lot of border of the basin and gas, okay? As you know, our strategy is very concentrated in oil. There could be some oil block that we will look at it. But very early to tell you if we will do anything. But we believe a very good initiative from the province.

Miguel, do these blocks have the same royalties scheme, or are they introducing any incremental rate?

Could you repeat, sorry?

Yes, if the new blocks may have the same royalties rate that the traditional shale acreage as in [ Vaca Muerta ].

Yes, Andres, I understand it's the same, okay? And to be honest, I cannot give you detail. We will look how the process evolves, but there should not be any change on the scheme.

Our next question will come from the line of Michael Furrow from Pickering Energy Partners.

Look, we were just hoping to get a quick update regarding the Equinor deal. I know it's still a bit early for the company to issue pro forma guidance until that deal closes in early May. But what do you see as a good run rate for annual net turn-in lines on the Bandurria Sur assets? And what could the associated CapEx look like?

Yes, Michael, thank you for the question. So as we mentioned, we now received the pending approval that we have from the Chilean antitrust authorities. So all conditions precedent basically have been met, and we are planning to close this deal early May. Regarding the CapEx, it will be around $200 million. And also assuming that the deal closes in May, the consolidation will be as of 1st of May. The assets are producing around 20,000 barrels of oil per day at Vista working interest. And I think there could be a little upside on this in the coming quarter. With that production assumption, you should assume that we will generate around $3 billion of EBITDA.

And our next question will come from the line of George Gasztowtt from Latin Securities.

Clearly it's a very volatile environment, but I was wondering if you could comment on the Medanito discount to Brent. Are you seeing that move a lot? And how should we think about the differential in Q2 and beyond?

Yes. Thank you for the question, and we're happy with this one. So yes, we have seen significantly stronger Medanito differentials. This is driven by the supply tightness of Asia and this is also contributing to the higher realization price that you saw in Q2. We saw a lower volatility in the last month from basically minus $3/bbl prior to the Middle East event to a range of plus $6/bbl to $9/bbl that was more recently. We believe that this trend will continue depending on how the oil market dynamic unfolds. There's still a lot of uncertainty there. But I will say you should assume that we will continue selling on a premium price, at least for the near future.

And our next question will come from the line of Ignacio Sabelle from Itaú BBA.

Congrats on the results. I would like to understand how the new scope of the RIGI benefits you. What are the plans? Are there any blocks developments that could be targeted here? And maybe understand what are the time frames? When are you going to submit any projects? And also, until when can you submit any projects?

Yes. Thank you, Ignacio, for the question. Yes, we are currently preparing the documentation to apply for RIGI for 2 of our future development blocks. One is Águila Mora and the other one is Bandurria Norte. After closing the Equinor deal, we will have also a better understanding of Bajada del Toro, which we believe also could apply to the RIGI. But the application of that in particular has to be submitted by this operator, the YPF. But we are quite confident that also that one will apply.

Regarding your second question on timing, we plan to submit the documentation by the end of Q2. The Minister of Energy then has to analyze all the information before the approval. Based on what we've seen is happening with other companies that have asked for the RIGI, that will take probably a few months. I would like to add that the impact of RIGI is very positive. For what we saw on the valuation that the 2 blocks that we present, it creates fiscal incentives and also it moves us to accelerate the CapEx of investment in those blocks that otherwise will be at the tail of our plan. So very good initiative for the government on this one. And it will help to bring that block from the north a bit closer in our plan.

And our next question will come from the line of Oriana Covault from Balanz.

I have a quick one regarding the nonoperated assets. Specifically, how do you see the contribution from these areas, specifically La Amarga Chica evolving through the year?

Thank you, Oriana, for the question. Yes, look, La Amarga Chica is performing quite well. When we acquired the block, if you remember, we were producing around 38,000 barrels of oil per day. This is Vista's working interest. And in Q1, we produced around [ 48,000 ] barrels of oil per day, so a 25% increase. For the rest of the year, as we said, we are expecting a flattish forecast or even a slight growth, okay? But, yes, happy with the acquisition, happy with the performance, happy with the relationship that we have today with YPF at the operational level. Everything is working pretty well.

And our next question will come from the line of Matías Cattaruzzi from AdCap.

My question is as follows. How would the 2026 EBITDA and free cash flow guidance look at Brent of $105 or $115 per barrel in the new guidance framework?

Thank you, Matias. I like this question. So I think as a rule of thumb, the way we look at it, if you consider that every $10 increase between Q2 and Q4, you have to think that we will capture around $275 million of EBITDA and $250 million of free cash flow. So back to your numbers, we show early $95 Brent for Q2 to Q4. EBITDA will be estimated around $2.9 billion in 2026. And at $105, that same EBITDA will be $3.2 billion, and at $115 Brent, it will be almost $3.5 billion. In the case of free cash flow, a $95 Brent scenario, the free cash flow will be around $1 billion for the full year. And at $105, $1.25 billion, and at $115, $1.5 billion of free cash flow during the year.

Thank you. I'm not showing any further questions at this time. I will now turn the call back over to Miguel for any closing remarks.

So guys, thank you very much for the participation, for the good questions. Very positive about what is coming up. We are starting the year from the operational point of view and the production point of view on good grounds, and very confident for Q3 and Q4. This should be an excellent year for us. Thank you very much for the continued support, and have a good day.

Thank you for your participation in today's conference. This does conclude the program. You may now disconnect. Everyone, have a great day.

Good day, and thank you for standing by. Welcome to the Vista's Fourth Quarter and Full Year 2025 Earnings Webcast 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, Vista's Strategic Planning and Investor Relations Officer. Please go ahead.

Thanks. Good morning, everyone. We are happy to welcome you to Vista's Fourth Quarter and Full Year 2025 Results Conference Call. I am here with Miguel Galuccio, Vista's Chairman and CEO; Pablo Vera Pinto, Vista's CFO; Juan Garoby, Vista's CTO; and Matias Weissel, 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 the 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 conference call, we may discuss certain non-IFRS financial measures such as adjusted EBITDA and adjusted net income. Reconciliations of these measures with 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 Anonima 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. 2025 was a year of many achievements for Vista, marked by the substantial value creation for our shareholders through growth in our core development, significant well cost savings and accretive M&A.

The acquisition of 50% stake in La Amarga Chica marked a major milestone in our successful growth journey, turning Vista into the largest independent oil producer of Argentina. We also held our third Investor Day, during which we unveiled an updated strategic plan targeting to produce more than 200,000 BOEs per day by end of the decade.

Today, we will be going over our Q4 results and a summary of the highlights of the full year. During the fourth quarter of 2025, we continue to deliver robust production growth on the back of new well tie-ins and strong productivity in Bajada del Palo Oeste, Aguada Federal and La Amarga Chica. Total production was 135,000 BOEs per day, an increase of 59% year-over-year and 7% quarter-over-quarter. Oil production was 118,000 barrels per day, an interannual increase of 61% and 8% sequentially.

Total revenues during the quarter were $689 million, 46% above the same quarter of the last year and 2% below the previous quarter, driven by lower oil prices. Lifting cost was $4.1 per BOE, 12% below year-over-year and 8% below vis-a-vis Q3. Capital expenditure was $355 million, driven by new well activity during the quarter.

Adjusted EBITDA was $444 million, an interannual increase of 62% Net income was $86 million, leading to earnings per share of $0.8 during the quarter. Free cash flow was $76 million, driven by strong cash flow of operations. And finally, our net leverage ratio at year-end was 1.5x on a pro forma basis, flat quarter-on-quarter.

Total production during Q4 was 135,400 BOEs per day. As in the previous quarter, we record a solid 7% growth on a sequential basis, driven by robust well productivity and 16 net tie-ins during the quarter, 9 in Bajada del Palo Oeste, 3 in Bajada del Palo Oeste, and 4 corresponding to our 50% share in Amarga Chica.

On an interannual basis, production growth was 59%, reflecting our larger scale after the acquisition of La Amarga Chica, combined with organic growth. Oil production was 118,300 barrels per day, 8% above Q3 and 61% higher year-over-year. Gas production increased 45% on an interannual basis.

In Q4 2025, total revenues were $689 million, 46% higher than the previous year, driven by a robust increase in oil production, which more than offset lower oil prices. Oil exports doubled year-over-year, reaching 7.1 million barrels in Q4 2025, representing 64% of our total sales volume.

Realized oil price was $58.9 per barrel on average, down 12% on interannual basis and 9% on a sequential basis in both cases, driven by lower oil prices. During Q4, again, we sold 100% of oil volumes at export parity prices, both domestically and internationally.

In Q4, lifting cost was $4.1 per BOE, 12% below the same quarter of last year and 8% below the previous quarter, reflecting our low-cost asset base and fixed cost dilution as we continue to gain scale. Selling expenses were $4.2 per BOE, down 48% on an interannual basis, driven by the elimination of oil tracking as of the end of Q1.

Adjusted EBITDA during the quarter was $444 million, 62% higher interannually, mainly driven by the consolidation of 50% working interest in La Amarga Chica and organic production growth in our core development hub, which more than offset lower oil prices. On a sequential basis, adjusted EBITDA declined 6% as lower oil and natural gas prices offset production growth. Adjusted EBITDA margin was 64%, up 8 percentage points compared to the same quarter of last year as the decrease in selling expenses offset lower oil prices. Similarly, netback was $35.6 per BOE, up 2% on an interannual basis.

During Q4 2025, cash flow from operating activities was very robust at $435 million even after income tax payment of $32 million and an increase in working capital of $16 million. Cash flow used in investing activities was $360 million, reflecting accrued CapEx of $355 million and a decrease in CapEx relating working capital of $16 million. As a result, free cash flow was positive at $76 million during the quarter and $47 million during the second semester. Hence, we achieved our positive free cash flow guidance for the second half of 2025.

Cash flow from financing activities was $143 million, driven by proceeds from borrowings for $618 million, partially offset by the repayment of borrowings for $368 million and interest payment of $75 million. Finally, our position remains very strong, standing at $538 million at year-end. Our net leverage ratio on a pro forma basis, reflecting the Petronas Argentina transaction stood at 1.5x adjusted EBITDA, flat vis-a-vis the previous quarter.

The fourth quarter of 2025 marks the completion of an outstanding year at Vista, and these are some of our key achievements. Combining the successful derisk of the structural area in Bajada del Palo Oeste with the acquisition of a 50% working interest in La Amarga Chica, we enlarged our well inventory to more than 1,600 wells.

P1 reserve increased by 57% year-over-year to 588 million BOEs, with strong additions both on the organic and inorganic side, leading to a reserve replacement ratio of 605%. Our organic reserves replacement ratio stood at 260%. We tie-in 74 wells during the year, up from 50 in 2024, reflecting the CapEx acceleration in our strong portfolio of short-cycle, high-return wells in the oil window of Vaca Muerta. This boost total production to over 115,000 barrels of oil per day, 66% above 2024. Our solid operational performance was also reflected by the cost reduction with 3% lifting cost savings and 15% D&C cost savings compared to 2024.

Operational excellence remains one of our top priorities. In 2025, our total recordable incident rate remained below 1 for the sixth consecutive year. By investing mainly in decarbonization process in our facilities, we reduced Scope 1 and Scope 2 greenhouse gas emissions intensity by 23% to 6.8 kilos of CO2 equivalent per BOE. This placed Vista's operation within the first decile at the global level.

We continue to invest in nature-based solutions in Argentina to develop our own carbon credits. We have made progress in 2025 to ensure that in 2026, we will have enough credit to balance the Scope 1 and Scope 2 emissions of our operated oil and gas production.

Finally, in 2025, we continue delivering a strong financial performance. Adjusted EBITDA grew 46% compared to the previous year, reaching $1.6 billion. Earnings per share amounted to $7 and ROC was 29%. Finally, we executed a share buyback program of $50 million, buying 1.2 million shares at an average price of $41.2 per share, a significant discount relative to current prices.

Our 2025 performance leaves us well poised to continue our growth trajectory in 2026. Total production at 115,000 BOEs per day was above the 112,000 to 114,000 guidance range. Production during the second semester was also above guidance, 131,000 BOEs per day compared to the guidance of 125,000 to 128,000.

Adjusted EBITDA was $1.6 billion and stood at the top end of the range we guided at midyear. We also met the adjusted EBITDA guidance for the second semester, recording $0.92 billion or an equivalent of $1.83 billion on an annualized basis.

Lifting costs at $4.4 per BOE mark an over delivery with respect of our $4.5 guidance. We were also very efficient with the use of the capital by delivering 74 wells tie-ins with $1.3 billion of CapEx. We outperformed the original guidance of 59 tie-ins with $1.2 billion. Importantly, the delivery of 2025 full year results, in particular, the momentum achieved in the fourth quarter leave us very well placed to deliver on 2026 guidance. As a reminder, this guidance includes 140,000 BOEs per day of total production, reflecting 80 to 90 well tie-ins, $1.5 billion to $1.6 billion of CapEx and $1.9 billion of adjusted EBITDA, assuming Brent at $65 per barrel on average.

Early this month, we announced an agreement to acquire Equinor's assets in Vaca Muerta. This constitutes a highly accretive transaction for our shareholders as reflected by the implied EV to EBITDA and EV per flowing barrel metrics compared to Vista's market value. The acquired asset will enhance our portfolio by adding more than 27,000 net acreage, which currently produce around 22,000 barrels of oil per day and generate positive free cash flow. Importantly, the blocks have production growth potential as they add 244 net wells to our drilling inventory.

As shown on the map, the new blocks are next to our existing blocks, which creates many opportunities for synergies in the subsurface characterization, surface facilities, meeting capacity, crews scheduling and oilfield services contracting.

As disclosed in our filings, the agreement is subject to 2 conditions present. The first one was already achieved last week, we were informed that Shell has waived its right of first refusal over Bandurria Sur. Regarding the second one, we have already filed the relevant documents with the Chilean antitrust authority on February 11. Based on the timeline of this process, we expect the transaction to close around mid-May.

To conclude this call and before we move to Q&A, I will make some closing remarks. Q4 marked the completion of a transformational year for the company, during which we gained significant scale and delivered on an annual guidance across all key metrics.

During 2025, we record robust operational performance, increasing total production, P1 reserve and expanding well inventory. We achieved material lifting costs and selling cost savings that improve our margins, offsetting lower oil prices. We also captured significant D&C cost reductions through the commercial supply chain and technological innovation. This strong operational performance, combined with the acquisition of 50% working interest in La Amarga Chica led to superior profitable growth during the year, materially expanding adjusted EBITDA and earnings per share.

More recently, we continue to demonstrate our unique ability to execute accretive M&A, gaining further scale, enhancing portfolio debt and long-term cash flow generation through the acquisition of participation in Bandurria Sur and Bajo del Toro, 2 premium assets in Vaca Muerta.

Before we move to Q&A, I would like to express my gratitude to our staff for having delivered another remarkable year for our company. I am also thankful to our shareholders for their continued support.

Operator, we can now move to Q&A.

[Operator Instructions] Our first question will come from the line of Walter Chiarvesio from Santander.

Yes. Can you hear me?

Yes, we hear well, Walter.

Perfect. Congratulations for such moving year for the company. My question is regarding the acquisition of Bandurria Sur. What are the next steps in terms of -- especially in terms of CapEx reallocation, if there is any? I see that the numbers of wells for the year remain the same. But if you think that there will be some CapEx reallocation? And what is the situation regarding facilities with the new situation of the company and the acquisition of all the blocks in 2025?

Thank you, Walter, for your question. So the main milestone, so starting with your first part of the question, the next step, the main milestone, which was a share rights of refusal was already clear. We are now going through the Chilean antitrust process that was filed on February, jointly with Equinor. So the relevant documents are already in the Fiscalia Nacional Economica. So based on all that presence, we believe we should be closing during Q2.

Related to capital allocation and the Equinor acquisition. Going to the Equinor deal, we are currently focused on the process of closing the deal and it's for us a bit premature to comment anything related to the new plan. But in terms, general principles that we assuming $65 Brent, the CapEx plan for the existing asset is not affected by the new assets. That means we will continue having the plan as we have. And the acquisition that we have done will be self-funded by the EBITDA and CapEx generation of the asset that we have acquired.

You asked also another question related to the facilities. So we don't see any issues with the facilities in the acquisition of Bandurria Sur. We have plenty of facilities there. We have -- they have a spare capacity. Also, we have a spare capacity. Different will be for the development of Bajo del Toro, where it's very close to one of assets there, Aguila Mora, but that will require new facilities.

As far as we know, Duplicar Norte is ongoing. So one option that we have is to tap into that pipeline that is being -- I think it's being linked by other companies, Pluspetrol, CVX, and Tecpetrol. So that could be an option, but that will not happen in the next year and even in the next few years.

Our next question comes from the line of Bruno Montanari from Morgan Stanley.

My question is also about capital allocation, but more on a broad perspective. So the company is generating cash, and we believe that, that cash generation should increase substantially in 2026 and beyond. So can you help us how to think about options such as accelerating drilling activity in case oil prices increase or pursuing acquisitions around your existing acreage and/or distributing cash back to shareholders? So how do you think about using that incremental cash that will be generated in the coming years?

Thank you for your question. The actual operation is running between 4 and 5 rigs from now to 2028. And we have an inventory life of 15 years. So we think we are close to the optimum activity level relative to the size of the asset that we have. If you will see the oil price go above assumptions in our plan, you could see that we add some wells to the plan, but I wouldn't expect that we will have anything that is completely material change compared to what we have in the plan today towards 2028.

Most of the cash that we will generate will be allocated through our capital allocation framework that we presented in Investor Day, that is: buyback and dividends, M&A, and debt reduction. How we are going to split between the three, I mean, we would like to maintain that flexibility based on the options that we have at the moment. But this is basically what we plan to do with the cash. Thanks for your question, Bruno.

Our next question comes from the line of Alejandro Demichelis from Jefferies.

Miguel, you mentioned the very sharp decrease in drilling and completion costs that you have achieved, and that has been great. Could you please kind of comment where do you see kind of drilling and completion costs right now? Where do you think that those could end up, say, over the next few quarters? And also, are you seeing also similar kind of decreases in your non-operated acreage?

Thank you, Ale, for your question. And yes, we are -- one of the things and one of the initiatives that we are very proud of is the reduction of D&C costs, where we are putting a lot of effort and a lot of innovation. So we made very good progress during the second semester. We fully implemented the use of bulk wet sand as well as our property frac real-time monitoring tool, streaming the completion short. We talk about that tool a little bit during our Investor Day.

On the contractual side, we renegotiated our contract with our major provider and rebundled the drilling services. All that led to an important savings. In all, this initiative led to a D&C cost of $12.1 million per well in the second half of 2025 in Bajada del Palo Oeste. This taking consideration a normalized well of 2,800 meters with 47 frac stages.

We are currently working on other cost reduction projects. Last week, we start operating the sand washing plant that we moved from Bajada del Palo Oeste, sourced from our new mine in basin. This new mine is 100 kilometers from our operation. So it's probably the closest one to any operation in Vaca Muerta today. With that, we plan to save some logistic costs for the entire core development hub.

We are also working on the rebundling of completion services. We are testing new pump technology that can replace diesel for natural gas. And also, we are testing new casing design that reduce the steel cost. This project will drive 2026 and 2027 well cost savings. We are on track to deliver $11.7 million per well this year and $11.3 million in 2027. And my personal opinion that we can go further down on that target if all these come into place.

Our next question will come from the line of Andres Cardona from Citi.

Congratulations on the good set of results. And my question has to do with the recent inclusion of the upstream business to the regime and how it could change the development plan of the cluster of Bajo del Toro and Aguila Mora?

Thank you, Andres, for the question. So first, probably to put that question in context, I will talk a bit about the rig. So the new rig scheme consists of incorporating basically upstream projects during the lay buses, upstream were not part of the scope of the rig. In our view, this is a very positive change in regulation and clear conditions to accelerate investment and grow on the basin.

Under the terms outlined by the decree, there is a minimum investment commitment of $600 million, of which 40% needs to be spent on the first 2 years. Also there's a ratio between cash from operation and total CapEx. The benefit that the rig bring include accelerated amortization, a decrease in corporate tax from 35% to 25%, 0 export taxes after the third year and being able to keep partially export proceeds abroad also after the third years.

So we are analyzing the scheme in detail. But based on our preliminary analysis, we believe that that could be applicable to some of our developed block, as you mentioned, one in Bandurria Norte, the other one could be Aguila Mora, and eventually also can be applied to Bajo del Toro. So very good initiative from the government, very welcomed by us and by the industry.

Our next question comes from the line of Milene Carvalho from JPMorgan.

After all those questions on the strategic deals, I would like to go back a little bit on the operational side. So this quarter, Vista reported record low lifting costs. Can you explain a little bit further what were the efficiency measures that have been supporting results besides all the cost dilutions with the production growth? And again, you're very well positioned for the guidance in 2026, but what can we expect as trend for the coming quarters?

Milene, thanks for your question, and thanks for being back to operations. So during Q4, we captured some savings related to well services. As in previous quarter, we continue to capture savings as we increase production, which dilutes fixed costs, and we have seen that effect for many years since we run the operation in Vista. This led to a lifting cost of $4.1 that you pointed out during the quarter. In my view, that number based on what I said before, is an exceptional number.

For 2026, our plan shows a lifting cost that will continue with the trend of basically reducing. We guide 2026 for a lifting cost of $4.4, that is 2% below 2026. In Q1, we see lifting costs that probably we expect that lifting cost will probably go sequentially upward, which is typically what happened at the start of the year with some costs moving from Q4 last year to Q1 this year. And also, usually, in the first quarter, we have some one-off maintenance projects that are allocated to lifting costs. But what you should expect is the $4.4 that we have guided that is 2% below 2026.

Our next question comes from the line of Bruno Amorim from Goldman Sachs.

So my question is a follow-up on the 2026 guidance, which you have reconfirmed. Can you provide us with your expectations for the evolution during the year for production, EBITDA and free cash flow, please?

Bruno, good question, and I hope you're doing well. So the 2026 plan includes a pickup in D&C activity with 80 to 90 tie-ins during the year. We plan 20 to 22 well in tie-in during the Q1, of which 10 were put on production in January with very good productivity reading so far. This will lead to production rate of 132,000 barrels of oil per day in February. We are all placed for March, and estimate a very good pickup, surpassing the 140,000 barrel oil per day for March. So we believe in Q1 will be flattish or slightly below Q4, but with a very good momentum entering Q2.

In Q2, we expect a substantial sequential growth, then relatively flat again in Q3 and another very nice and good step in Q4. We reiterate our guidance of 140,000 barrels per day for 2026. And of course, this does not include the Equinor acquisition that will come into place later on when it's closed.

In terms of EBITDA, we have reiterated our guidance of $1.9 billion of adjusted EBITDA for 2026. And as a reminder, this also excludes the effect of Equinor transaction. Q1, you should expect that we will be flattish or maybe slightly lower than Q4 on adjusted EBITDA. Then should increase that steadily in the coming quarter, and we expect to reach an annualized run rate of around $2 billion in Q4, assuming, of course, a Brent of $65.

In terms of free cash flow, free cash flow turned positive, in line with the strategic plan of 2026. This new phase of the company combines, as we mentioned in Investor Day, growth and free cash flow generation. In 2026, total free cash flow will be around $150 million to $200 million, a $65 Brent. Always, I mean, we should expect that free cash flow could be affected by working capital variation, tax payment that can negatively impact in some quarters, but also you should expect a negative free cash flow in Q1, turning into positive in Q2 and onward. So that gives you maybe a quarterly picture of what we think will happen in 2026.

Next question comes from the line of Daniel Guardiola from BTG Pactual.

My question is on the acquisition of the assets of Equinor in Argentina. And I wanted to know, Miguel, if you could provide us more color on the type curves and productivity you're seeing in Bandurria Sur and Bajo Toro. And also during the presentation, you mentioned that there is material upside potential in Bajo Toro. So it would be great to hear if you could share with us what is the potential growth opportunity that you're seeing in both assets.

Okay. Yes. Thank you, Daniel, for the question. Maybe starting with the first part. Well type curve, I think, for Bandurria Sur, very similar to the ones that we have present of our asset. It's a neighbor asset. We didn't -- we evaluate it and we don't expect anything different. On Bajo del Toro, you should wait for us because it's probably too early to comment on that.

Then related to the second part of your question, based on the information that we have and the analysis that we have done so far, and this is a very preliminary view, our stake of these assets is currently 22,000 barrels oil per day. And we think we can double that by 2030, driven by the growth in Bajo del Toro once we move Bajo del Toro to full development plan. So we will probably see a couple of years with a small growth and free cash flow generation, followed by the growth of Bajo del Toro.

As our working capital interest in Bandurria Sur, we produced approximately 19,000 barrels of oil per day in Q4, an increase to 20,000 in January. Based on the inventory side, 106 wells are allocated to our working interest and the field can continue producing on the current rates until probably 2030. So also in Bandurria Sur, we see some growth potential.

In Bajo del Toro, today, they are producing around 2,000 barrels oil per day, and that is pretty much the same that we saw in January at our working interest. So this block for us present significant upside based on the inventory, and we're still analyzing the scenario to go to full development. But that will happen during the next 3 years. And based on the question that we have before, also, we will have to think about infrastructure, evacuation infrastructure there.

Our next question comes from the line of Kevin MacCurdy from Pickering Energy Partners.

We've noticed a meaningful progress in the country backdrop along with increased attention on Argentina and the basin overall. Is Vista seeing an expansion in oilfield service vendors or equipment entering the country? And if so, would you expect this to translate into further improvement in drilling and completion costs?

Kevin, thank you. Very good question. Yes, the short answer is yes. We are seeing a lot of interest from service companies to come down to Argentina based on the increase of activities, as you mentioned also, based on the normalization of the macro and the ability to have more cross-border freedom in terms of repatriating dividends and proceeds. And I will say that is interest.

Now one thing that we are seeing is most of the companies that are today in the country are adding capacity. And also that is helping today, as you saw in the presentation on the reduction of the D&C cost. Also, we continue evolving in terms of innovation and practices that are changing. We are a clear example of that, where you can see, for example, on the completion side, a lot of integration between sand, delivering the sand, the logistics, wet sand project, and now probably demanding the completion services to have better numbers and better rates on services.

There are many -- we have seen or we have inquired many service companies that are today working in the Permian, looking in what they can do in Argentina. I hope I answered your question.

Miguel, look forward to seeing you at our conference in a few weeks.

Super. Looking forward, Kevin.

Our next question will come from the line of Nicolas Barros from Bank of America.

Just one question here. So we saw that your trading arms started operations this quarter, right? So just interested to see if you could provide more color on Vista, right, and your expectations on how it can help you to unlock more value in the company.

Thank you, Nicolas. Yes, that was a great initiative. I visit them a few weeks ago. The creation of Vista is part of our export-oriented strategy. Oil exports have increased significantly on the past years. During 2025, we export 22 million barrels of oil. That is an increase of 10% vis-a-vis 2024, that generate $1.4 billion of export revenues. So -- and according when you look at our plans, we plan to double that in 2028.

So Vista is a fully owned subsidiary. The rationale behind moving into the trading business is to improve our market reach. Higher volume mean that we need to develop more clients in different markets. And we believe that selling cargoes on delivered basis will allow us to be more competitive. So it's very preliminary to comment on margin. We believe it will not be very material to the results of the entire company.

So having our own trading units add flexibility to our short-term hedging program, allowing us to hedge all sales on a short-term basis and basically to manage the cash flow on a quarterly basis. So we are not planning today to make any hedge on long term. But short term, we believe we will have a benefit having Vista.

Our next question comes from the line of George Gasztowtt from Latin Securities.

You mentioned earlier free cash flow expectations at around $150 million to $200 million this year. Prices have started the year a little bit above your Investor Day assumption of $65 Brent. And I was wondering how you're thinking about capital deployment and the capital deployment framework you also mentioned in the current price context.

Thank you, George, for your question. So I mean, we said that we are very happy with the Brent prices on Q1 this year. It was not expected. And I think this -- we believe is mainly based on the volatility that we see in the market related to geopolitical issues. I think it's very early to change our plan for the entire year. So of course, we will watch what happened with oil price. But I don't think that it will affect any short-term decision.

Regarding the long term, it's related to the question that Bruno said. I mean, we have our capital allocation framework and anything that we can do in reducing debt, buybacks, dividends of M&A acquisition, cash in hand will be helpful to be more aggressive or aggressive, depending how we build up that cash during the years to come.

Our next question comes from the line of Joao Barichello from UBS.

I have only a very quick one from my side. So regarding the acquisition of Bajo del Toro and Bandurria Sur, the company stated that the transaction will be financed by a combination of both cash and bank finance. So could you provide an update on this financing plan? What are the expectations for the breakdown of cash and banking finance funds? That's it from my side.

Thank you, Joao, for your question. Yes, I mean, the initial $387 million cash payment will be funded 100% with debt, and we plan to keep the cash balance stable at Vista. Pablo and Ale have agreed with the 3 top-tier banks, a bridge loan of $300 million of acquisition financing, which should be used and will be used and should be enough to cover our initial cash payment. So again, I mean, we'll do something with that later on, but it will not affect our balance sheet today and our plan in CapEx that we have for the year.

Our next question will come from the line of Oriana Covault from Balanz.

Congratulations on the solid results for the quarter. Just perhaps going into -- directly into potential shareholder returns in the more constructive pricing scenario, what are the alternatives you have in place for 2026? And namely, do you have any thoughts to renew and/or extend the buyback program this year?

Oriana, thank you for your question. So in August, we executed the $50 million buyback plan that was approved by the shareholder meeting in April last year. We purchased 1.2 million shares at $41.2 per share. So we are considering the current share price -- considering the current share price, we are super happy with the outcome of that buyback plan. We plan to request an extension of the program in the upcoming shareholder meeting that is coming now in April. And we believe it will be larger in size than the one that we plan for 2025.

Our next question will come from the line of Francisco Cascaron from DON Capital.

Given that you announced a CapEx of $1.5 billion to $1.6 billion annually between 2026 and 2028, what is your maintenance CapEx expectation in the foreseeable future?

Francisco, thanks for your question. Using 100,000 barrels per day of production as a reference, you need around $700 million to $750 million of CapEx to keep production flat going forward. And assuming that by the end of the year, we will be around 150,000 barrels per day. This, of course, is including Equinor asset.

We will need around 60 wells to keep production flat. So that will equate around $850 million CapEx to keep production flat. So you should take more or less those numbers.

Our next question will come from the line of Matias Cattaruzzi from Adcap Securities.

How could you characterize Vista's relationship with YPF today after the La Amarga Chica acquisition, and now the Equinor deal where YPF is also an operator?

Matias, thanks for your question. The short answer is the relationship with YPF is great. We have very high hope after the acquisition of Petronas asset on how the relationship will be put in place and will evolve. And to be honest with you, it turned out even better than we expect. It's working very well at all levels.

I would say that the top, the strategies are aligned. Both companies want to continue and that make the relationship very easy because we have the same target. The technical teams are working side by side. And that for me is the more important part. We see them sharing geological information, collaborating meeting. But more importantly, there has been synergies that have been captured, sharing all treatment capacity that have led to save CapEx, sharing well services, enabling the company to optimize headcount, discussing artificial lift strategies that will help to improve the long-term productivity of the well and reduce lifting costs.

So all in all, I would say it's a great relationship. And that, of course, that was the fact that give us confidence also to execute the Equinor deal. That was something that we took in consideration at the time that we made the decision.

I'm not showing any further questions at this time. I would now like to turn it back over to Miguel for any closing remarks.

So ladies and gentlemen, thank you very much once again for the support, a very good quarter, and we are pretty much on track to deliver our guidance in 2026, a very good start of the year. Thank you, everybody.

Thank you for your participation in today's conference. This does conclude the program. You may now disconnect. Everyone, have a great day.

Good morning, and welcome to Vista's 2025 Investor Day. Today's call is being recorded. [Operator Instructions] This event is hosted by Vista's executive team and attended by sell-side analysts on site. [Operator Instructions] I would now like to turn the conference call over to Vista's Co-Founder, Strategic Planning and Investor Relations Officer, Mr. Alejandro Chernacov. Sir, please go ahead.

Good morning, everyone. And thank you for joining us. We are pleased to welcome you to Vista's 2025 Investor Day, our third since we started operations back in 2018. Today, we will update you on Vista's progress since our last Investor Day, explaining how we have set the stage for our next phase of profitable growth and present our new 2026 to 2028 targets.

Before we begin, let me remind you that today's presentations and our responses during the Q&A session may include forward-looking statements subject to risks and uncertainties that may cause actual results to differ materially. All financial figures are in U.S. dollars and in accordance with IFRS. We may also reference non-IFRS metrics such as adjusted EBITDA.

Reconciliation of historical figures are available in our public filings. During today's presentations, we will refer to previous targets as those set in our 2024 to 2026 plan disclosed as you may remember, during our 2023 Investor Day. We will refer to new targets as those introduced for the 2026 to 2028 period and our 2030 vision.

Please refer to Slide 2 for the full text of our safe harbor statement. We will begin our presentation with Miguel Galuccio, Founder, Chairman of the Board and CEO, who will open the event by showcasing how Vista has scaled its leadership in Vaca Muerta and how our unique playbook delivers profitable growth with industry-leading total shareholder returns. Next, Juan Garoby, Co-Founder and CTO; and Matias Weissel, our COO, will provide a deep dive into how Vista is leveraging innovation at scale and new technologies to double down on efficient growth. They will also provide an updated production forecast through 2028.

Following that, Pablo Vera Pinto, Co-Founder and CFO; and myself will walk you through our updated financial outlook. We will present how Vista's export-driven business model, disciplined capital allocation and cost leadership translate into strong EBITDA and free cash flow growth, a strengthened balance sheet and robust shareholder returns. To close, Miguel will outline our 2030 vision, which reflects a company with higher scale, continued growth and global competitiveness.

Before we begin, a few housekeeping items. We expect today's presentation to last around 40 minutes, followed by Q&A. If you are joining virtually, you'll be able to ask questions via chat at the end. A replay and the presentation deck will be shortly on vistaenergy.com. With this, I'll now hand the presentation over to Miguel.

Good morning, and welcome to Vista's 2025 Investor Day. Two years ago, when we meet for our last Investor Day, we discussed how in just 5 years since inception, we have built the company we envisioned when we founded Vista, a leading efficient, high-growth and profitable oil producer with a clear purpose and a world-class team capable of delivering exceptional results. We also said that Vista was ready to accelerate growth and strengthen its leadership in Vaca Muerta.

Today, I am proud to say we overdelivered it. Since 2021, we have tripled production and quadrupled adjusted EBITDA. We are now entering a new phase of growth, one that builds on what we have achieved, taking Vista to the next level with a larger scale. Our next phase is self-funded and is set to deliver more profitable growth and industry-leading margins. This will generate an increasing amount of free cash flow.

By 2028, we plan to increase production to 180,000 barrels of oil equivalent per day and an adjusted EBITDA to $2.8 billion, 75% above our guidance for 2025. During this period, we forecast our ROCE to remain above 20%, a level that puts Vista among the highest return E&P company globally.

So where do we see ourselves 5 years from now? By 2030, we expect to be generating $1.5 billion of free cash flow per year. We have the assets, the capabilities and the committed team to become a cash-generating machine ready to deliver sustainable long-term value. That is what scaling success look like for Vista. I will now provide you with more detail on how this strategy translates into more growth and higher efficiency.

Let's start with a quick recap of our growth story. Since our Investor Day in 2021, we tripled in size with total production growing from 39,000 to 114,000 barrels of oil equivalent per day in 2025. We quadrupled adjusted EBITDA from $380 million in 2021 to approximately $1.6 billion in 2025. We are now the largest independent oil producer in Argentina and have also become the largest oil exporter in the country.

The strength of our business model is clearly reflected in our numbers. Vista has consistently outperformed peers across efficiency, profitability and shareholder returns. At $40 per barrel, our netback reflects a profitable, low-cost operation and provide resilience to lower oil prices. Our average ROCE since 2021 was 31%, reflecting the successful execution of our capital allocation framework. And since 2021, our share price has compounded at 73% per year, one of the strongest performances in the global E&P space.

This combination of operational excellence and disciplined capital allocation is what sets Vista apart. It's not only about growing fast, it is about growing profitably, generating cash and delivering tangible value to our shareholders. We have done the work to derisk Vista's next phase of growth, and we are now ready to raise the bar again.

We derisked and acquired new acreage. We now have more than 1,650 wells in our ready-to-drill inventory, an addition of 500 wells since our last Investor Day. Of this, more than 1,300 or 80% are yet to be drilled. We secured drilling and completion equipment as well as treatment, transportation and export capacity. We now have 4 drilling rigs and 2 frac sets under contracts and operation, doubling 2023 operating capabilities.

We also doubled oil treatment capacity and triple contracted pipeline capacity. We tripled export volumes, which now represents 62% of oil production, 10 percentage points above 2023. We are fully funded to deliver double-digit growth. We are now free cash flow positive and issue a long-term financial debt, which provides us with substantial financial flexibility. We have consolidated one of the most experienced committed management team in the region. We have a unique culture based on fundamentality and full alignment of incentives. In short, we have built an outstanding company ready to grow profitably into the next decade.

Now let's take a step back and look at the big picture with the global energy context. In today's fast-evolving energy landscape, one thing is clear, demand for oil is not going away anytime soon. On the contrary, we expect oil demand to continue growing for several years before reaching a plateau. This growth will be mainly driven by economic development in the emerging markets, where energy demand per capita is still 4x to 5x lower than in the developed world. At the same time, under investment in oil exploration and development over the past decade leads us to have a contracted view on mid- and long-term oil prices.

Finally, evolving geopolitical dynamics are leading to higher volatility in commodity markets and an increased need for reliable and affordable energy. We believe the winners in the next decade will be the low-cost, short-cycle, reliable energy producers, and that is where exactly Vista stands.

We have the playbook to thrive in this context, and it's based on 3 pillars. First, a large, high-quality, short-cycle and low-cost asset base with a total unit cost of approximately $11 per barrel and 1,300 wells yet to be drilled, each with a payback of only 2 years. Second, a strong culture driven by a team that is relentless to achieve results, committed to people and guided by innovation and agility. And third, a solid total shareholder return strategy, supported by a disciplined capital allocation framework that has delivered a 73% share price CAGR since 2021.

This playbook has proven to work, and now we are ready to apply it on a larger scale. We are now entering in another phase of profitable growth to continue delivering superior shareholder returns. By 2028, we expect production to reach 180,000 barrels of oil equivalent per day, a 58% increase from 114,000 in 2025.

Adjusted EBITDA is projected to grow by 75% from around $1.6 billion in 2025 to $2.8 billion in 2028. This growth will generate around $1.5 billion of cumulative free cash flow between 2026 and 2028, providing us with the flexibility to return cash to shareholders, deliver and pursue accretive M&A opportunities when they arise. In short, our growth is profitable and our balance sheet is strong, future-proofing shareholder returns. Operational excellence and sustainability remain at the core of everything we do.

Since our last Investor Day, we have made very good progress in reducing carbon emission intensity, developing carbon credits through our nature-based solution projects, maintaining a strong safety track record and proactively engaging with the local communities. Gabriela Prete, our operational excellent manager, will share a brief update of these topics from a unique location in Argentina.

Thank you, Miguel. Since day one, we have worked hard to build a company of high standard that is fit for the future. Safety is the bedrock of our organization. We operate with the highest oil and gas industry standards in accordance with established international best practices. Our strong and consistent safety track record is a consequence of stringent evidence to procedures, tailored training and close supplier engagement.

Our goal is to maintain our total recordable incident rate below 1, in line with the industry's best practices. We have achieved this target over the last 5 years. The focused execution of our emissions reduction strategy has allowed us to achieve a greenhouse gas emissions intensity in our oil and gas operations including Scope 1 and 2 of only 7.5 kilograms of CO2 equivalent per BOE in 2025. This ranks us among the first decile worldwide and more than 75% below the global average.

This was achieved by investing in highly efficient projects which allows us to maintain a very competitive lifting cost. Some examples include, the installation of paper recovery units, the construction of a gas pipeline linking Aguada Federal with Bajada del Palo Oeste, the electrification of new gas compression units and the use of cost competitive renewable energy across our oil fields.

I am standing here in Rolón Cué, our flagship NBS project, surrounded by millions of trees that didn't exist just 3 years ago. This is a clear testimony of our positive contribution to the environment. Here, Aike, a Vista subsidiary, has developed an NBS project that combines native and exotic trees. Aike manages 13 nature-based projects spanning 43,000 hectares across 7 provinces in Argentina. Since 2022, Aike planted around 5 million trees in afforestation projects, achieving average growth rates comparable to leading international projects.

Argentina's natural endowment allows Aike to generate low-cost, high-quality carbon credit. We have sized our NBS project so that the carbon credit generated by Aike, match the size of Vista's residual hard-to-await emissions in 2026. Vista takes a proactive approach to engagement with local communities. Since 2021, we contributed almost $5 million to voluntary social programs focused on education, employment and biodiversity. We have partnered with more than 10 NGOs across the country to implement these initiatives. Our highest standards make our operations more resilient and strengthen our license to operate. I will now hand it over to Matias, who will continue with the presentation.

Good morning, everyone. Together with Juan, we'll walk you through Vista's production growth strategy, focusing on operational excellence, efficiency and growth. Since our last Investor Day, Vista has continued to scale at an exceptional pace. Production more than doubled since 2023, reaching 114,000 barrels of oil equivalent per day in 2025.

Our [indiscernible] reserves grew by 60% to a total of 519 million barrels of oil equivalent at the end of 2024 on a pro forma basis. This growth was driven by both strong organic development and the successful integration of the 50% stake acquired in La Amarga Chica. Our focus on productivity is demonstrated by outstanding well performance.

When we compare Vista's wells across Vaca Muerta, our productivity consistently exceeds that of peers, reflecting the quality of our assets, our best-in-class operating capabilities. In the first 6 months of production, the average Vista wells delivers approximately 200,000 barrels of oil normalized to 2,800 meter lateral length. That is 24% above the Vaca Muerta average and 48% above the Permian average.

After 12 months, the trend remains the same. With a cumulative production of 330,000 barrels of oil, the average Vista well produces around 22% more than the Vaca Muerta average and around 72% more than the Permian average, also on a normalized basis.

This consistent outperformance gives us the confidence that our model is both repeatable and scalable as we continue expanding development across our acreage. Our standard investment unit is a 4-well pad, which has a 120-day time to market, including drilling, completion and tie-in. With a payback period of only 2 years, the short-cycle models gives us a distinct competitive advantage in a volatile environment.

Vista's long-term growth is supported by its large, high-quality short-cycle well inventory. Our inventory has increased by 500 wells since 2023, driven by: first, the acquisition of 50% La Amarga Chica, neighboring our core development hub; and second, the successful pilot recently completed in a new development area within Bajada del Palo Oeste, expanding our core development inventory. Today, we have around 1,300 wells yet to be drilled, providing an inventory of at least 10 years with breakeven prices of $45 per barrel.

Looking ahead, we plan to continue derisking our acreage and see additional inventory upside from untested landing zones within our existing blocks. Juan will now deep dive into how we have successfully implemented technology and innovation to extend our well inventory, improve efficiency and reduce costs.

Good morning. I am very excited to share the successful results of the pilot project in the center of Bajada del Palo Oeste, an area partially covered by structural faults. We confirmed the technical feasibility of drilling and completing wells in between faults, a concept we were the first to test in Vaca Muerta. This is yet another example of our innovative and pioneering approach to developing the play.

The wells have 2,800 meters of lateral length and an average of 48 stimulation stages and are showing very good productivity. After 45 days, they produced on average 55,000 barrels of oil, in line with the average Bajada del Palo Oeste well. Based on these results, we have added 180 new wells to our inventory in Bajada del Palo Oeste, Coirón Amargo Norte and Bajada del Palo Oeste.

Growing our inventory is only part of the story. Another key driver of our competitiveness is how efficiently we develop it. As we continue expanding our drilling runway, we're also focused on further reducing well cost. In 2024, our average drilling and completion cost was $14.2 million per well.

Today, our D&C cost has been reduced to $12.3 million. By the end of 2026, we expect to reach $11.7 million per well and $11 million by the end of 2028. These gains come from innovating and adopting new technology and optimizing processes. For example, we recently adopted bulk transportation of wet sand, eliminating sun drying costs and reducing sand logistic costs. We implemented an innovative real-time simulation process that enhances well completions and lowers completion cost. We also deployed new remotely operated directional drilling technology to further reduce costs.

Finally, we introduced new contracting practices by, for example, de-bundling drilling services and renegotiating certain key contracts, achieving additional cost savings. These combined efforts have made Vista one of the lowest cost operators in Vaca Muerta. We never stopped innovating. Over the coming months, we will implement new cost reduction initiatives such as moving our sand washing plant to our core hub to further reduce sand logistic costs. We have recently adopted bulk wet sand transportation, which has already resulted in a cost reduction of around $200,000 per well.

During 2026, we plan to relocate our sand plant to our core development hub and source sand from nearby sand mines. By doing so, we expect to significantly reduce transport distances, lowering both sand transportation cost and our footprint. Once fully executed, we expect this project to reduce sand cost by an additional $400,000 per well, bringing total savings to approximately $600,000 per well.

I will now deep dive into an example of how our thorough understanding of the subsurface allowed us to implement a real-time completion optimization process aimed to reduce cost and improve productivity. We have introduced real-time monitoring capabilities using in-house proprietary AI tools, which allow us to monitor how stresses build up during the hydraulic stimulation process and adjust completion strategy accordingly. This innovative practice helps reduce the probability of runaway fracs, improve frac hit identification, characterization and decision-making to mitigate impact on parent wells.

This novel technology was implemented earlier this year and has already improved key operation metrics. We reduced lost completion stages to less than 1%. We cut on average runaway frac stage per well, and we generated average savings of $150,000 per well. Looking ahead, we have a portfolio of productivity-enhancing technologies that will be tested in the coming years, such as Huff 'n Puff, surfactant injection and the acquisition of a new 3D seismic that should eliminate parts of the field looking for buckets of productivity that have not been identified to the moment.

Building on our strong foundations, our solid operational expertise, large asset base, low unit costs and unique culture, we are ready to pursue a new phase of profitable growth. We plan to tie in between 80 and 90 wells per year between 2026 and 2028, requiring $1.5 billion to $1.6 billion of CapEx per year. All the capacity needed to execute this plan, drilling, completion, crews, treatment, transportation and export is already secured.

This plan will increase production from 114,000 BOEs per day today to 140,000 in 2026, 160,000 in 2027 and 180,000 BOEs per day by 2028. That represents an increase of almost 60% in 3 years, implying a CAGR of 16%. With that, I hand it over to Paolo and Ale, who will take you through how this operational performance translates into financial strength and superior total shareholder returns.

Thank you, Matias. Good morning, everyone. Over the next few minutes, Ale and I will present how our profitable growth plan translates into strong financial metrics that enable us to continue delivering industry-leading total shareholder returns while maintaining a robust balance sheet. Our business model is export-driven.

Virtually, all incremental barrels we produce will be sold into international markets. Exports improve the quality of our revenues, diversifying commercial risk and providing a strong currency hedge. Our total revenues are expected to grow by 72% from about $2.5 billion in 2025 to $3 billion in 2026 and $4.3 billion by 2028. We plan to double export revenues from $1.5 billion in 2025 to $3.2 billion by 2028.

This means that by 2028, around 3/4 of Vista's total revenues will come from oil exports, up from 60% today. Our oil exports will reach destinations across the world, including North and South America, Europe, Asia and Australia. Our cost base remains among the most competitive in the sector globally, ensuring resilience in low oil price environments while maintaining significant upside exposure to higher oil prices.

By combining low lifting cost, efficient transportation through pipelines and a lean organization, we plan to maintain unit costs at $11 per barrel. With Brent between $60 and $70, our netback ranges from $38 to $46 per barrel. Even at $50 Brent, we still generate a healthy netback of $29 with an upside potential of reaching $54 per barrel in a scenario of Brent at $80.

To maintain production at 130,000 BOEs per day, our expected Q4 2025 production rate, we need to invest the equivalent of $15 per barrel. After deducting this maintenance CapEx and financial interest plus income tax, our free cash flow to equity ranges between $13 and $19 per barrel in a scenario of Brent in the range of $60 to $70. I will now give the floor to Ale, who will walk you through our financial projections.

Thank you, Pablo. Our growth plan is expected to deliver solid financial results. Adjusted EBITDA is projected to grow from $1.6 billion in 2025 to $1.9 billion in 2026 and $2.8 billion in 2028. This is an increase of 75%, which implies a 21% CAGR over the next 3 years.

During the same period, our adjusted EBITDA margin will remain around 65%. Our average ROCE over that period is forecast to be well above 20%, keeping Vista's return on capital among the industry's top quartile. We plan to deliver double-digit growth while generating substantial free cash flow, too. Between 2026 and 2028, we expect to generate cumulative free cash flow of $1.5 billion.

This financial strength gives us the flexibility to return cash to shareholders, reduce gross debt and pursue synergetic business development opportunities. High profitability and strong cash flow generation will continue to strengthen our balance sheet. We expect to deliver self-funded growth while organically reducing net leverage. Gross debt currently stands at about $2.9 billion with an average maturity of 4.5 years and an average interest rate of 6.7%. We have a sound debt maturity profile with annual debt repayments representing an average of only 15% of annual adjusted EBITDA over the next 3 years.

Looking ahead, we expect gross debt to remain broadly stable, while the net leverage ratio declines organically from 1.5x today to below 1x by 2028, mainly driven by the continued growth of our adjusted EBITDA. Our business plan is designed to deliver value across all different oil price cycles, supported by our low-cost base, capital discipline and operational and contractual flexibility.

In our base case, we expect to generate $1.5 billion of free cash flow between 2026 and 2028, assuming Brent at $65 in 2026 and $70 thereafter. In a downside scenario, with Brent $10 below our current base assumption, we can still deliver the same self-funded production growth, still generating $0.5 billion of free cash flow.

In an upside scenario, with Brent $10 above the base case assumption, free cash flow rises to $2.5 billion over the same period. That means $1 million more. This resilience, combined with our ability to rapidly adjust our activity to market conditions has been and will continue to be a cornerstone of Vista's success.

Our capital allocation priorities, which have delivered solid total shareholder returns since 2021 remain firmly in place. Our focus is simple and remains unchanged, generate cash, maintain financial discipline and allocate capital where it creates the most value. We will efficiently deploy net cash generation to return cash to shareholders, initially prioritizing share buybacks. We may also use cash to reduce gross debt, accelerating deleveraging and further strengthening our balance sheet.

Finally, and in line with our proven track record of generating value through business development, we will continue evaluating selective synergistic M&A opportunities focused on the oil window of Vaca Muerta. This disciplined approach will allow us to maximize total shareholder returns while maintaining financial flexibility. Miguel will now briefly close with our 2030 vision.

Thank you, Pablo. As we look ahead, our 2030 vision is clear. Our plan is to deliver double-digit production growth over the next 5 years. As I said before, we have the playbook, and we will continue to apply it at a larger scale. By the end of the decade, we expect to produce over 200,000 barrels of oil equivalent per day, 33% above the forecast we shared during our 2023 Investor Day. This production growth is forecast to generate an increasing amount of free cash flow driven by our highly efficient operating model.

As we continue to scale and reduce costs, we expect to deliver strong returns on capital. This allows us to envision a company that by 2030, assuming a mid-commodity cycle Brent of $70 per barrel is projected to generate a recurring free cash flow of around $1.5 billion per annum.

Before we move to Q&A, let me summarize today's key messages. In this presentation, you have seen how we have materially transformed Vista, scaling our production, strengthening profitability and becoming a leading independent player in Vaca Muerta. Our growth is built on efficiency and capital discipline, designed to deliver value across all price cycles.

Importantly, it's fully aligned with the global energy market dynamic. We have derisked the next phase of growth, expanding our well inventory and securing drilling and completion equipment, crews, pipeline and export infrastructure while maintaining financial flexibility to keep growing profitably. Our updated plan drives double-digit annual EBITDA growth, and we will continue delivering industry-leading total shareholder return.

Vista is still a young company. Yet in just 7 years, we have become the benchmark of performance in Vaca Muerta and one of the most profitable independent E&P companies in the America. We have the assets, the team, the culture to keep creating value for our shareholders for Vaca Muerta and for Argentina. Thank you for your continued trust and support and for showing us in this next phase of growth. I will now move to Q&A.

[Operator Instructions] First question from Alejandro Demichelis from Jefferies.

Miguel, one quick question. It has been a tremendous journey since the 4 of you put the company together only a few years ago. Now, you're entering a new phase of growth. Maybe you can talk about the culture, what's the secret sauce that you have here to deliver on this next phase, please?

Thank you, Alejandro. Good question to the heart. I will set talented people and company culture. At the end of the day, companies are run by people. And we have extraordinary people in a culture that empower them to deliver extraordinary results. And they have been delivering results that have beaten market expectation, shareholder expectation and sometimes their own expectations.

I also like to say that Vista is a company run by their owners. Between 30% and 40% of our employees hold and have received Vista shares. Remuneration of the leaders that you will meet tomorrow have a component of 40% of Vista shares and the C-suite, 75% of their compensation is Vista shares. That gives an extraordinary incentive to deliver results fully aligned with our shareholders.

Today, we discuss a lot about operational excellence. Operational excellence for us is a blend of competency, talent, processes, technology and innovation. And that is in the heart of everything that we do. When we drill a well, we think about operational excellence, when we complete a well, when we close an M&A transaction, when we develop an export market, when we manage risk above and below surface, we think on operational excellence.

Also, we have an entrepreneurial mentality. We like to keep things lean. That’s why despite of this enormous growth that we have during the last 7 years, we have maintained our organization extremely lean. We have set a rule to ourselves that between a tool pusher that is today drilling in Vaca Muerta and myself, we cannot have more than 4 layers. That ensure us that the decision-making process is still simple and still fast.

We have born as a start-up. And when you look at Vista today, you have the size of the corporation. But we remain thinking as a startup. That's why innovation is in everything that we do. We have a team fully dedicated to innovation. It is run by Juan today, wear the hat of CTO, and you will met [indiscernible] that is leading that front in the field.

And innovation is key for us to basically to be ahead. I have taken most of the calls -- all the calls during the quarter review. And today, during the Investor Day, I plan to give the floor to the people that have built the company with me that are escorting me today, the C-suite that is sitting here. And tomorrow also, we will give you full exposure to the people that we have in the field.

And back to your question and back to my fair answers, this talent of people is what make us a company that is different and managed to deliver the results that we have delivered so far. Thank you very much for the question.

So the next question from Claude Rivera from Santander.

First question is, what were the key factors behind the decision to accelerate drilling and increase well count? And what led you to set this specific number of wells at the right level of activity?

Super. Well, I will let that question to be answered by Pablo and Matias, both part of your question.

Perfect. Thank you, Claudia. I would say that the primary driver -- I can even say the only driver is to drive enterprise value. In our case, more production growth is more value growth, right? Every well we drill adds value to Vista. The wells we're drilling next year have an IRR of between 40% and 60%. And if you look at our track record of return on capital employed, it's above 30% for the last 5 years.

It's going to be well above 20% for the next 5 years, and that's almost double our cost of capital, right? So it makes a lot of sense to go to this higher level of CapEx. Obviously, there are certain considerations to not go too aggressively into production growth mode, and that has mainly to do with maintaining a strong balance sheet. We have been free cash flow positive in Q4.

We are going to deliver a Q4 that's free cash flow positive. And we've set a rule to be free cash flow positive during 2026. And that puts sort of a financial limit to the pace of growth. And then there are obviously other operational consideration when it comes to defining what's the optimal level, and I'll let Matias comment on that.

Thank you, Pablo. Yes, when you design the field, we are fully focused on the core development hub. So this rig count of 4 rigs in operated areas has a sense that this drive we will build and design development in corridors. So 1 of -- each of those rigs are going to drill in each of their corridors, talking about Bajada del Palo South corridor, North corridor and also BPE.

And to add to that, we have already all the capacity contracted in terms of internal capacity of treatment, also transport, we have the crews. And also La Amarga Chica happens the same. You have 3 triangles and each of triangle, we are going -- YPF is going to operate with 1 rig. So somehow, we have designed from the subsurface to the surface the way we want to develop the field, and that's really combined with the business point of view that Pablo just answered.

The next question is from Leonardo Marcondes from Bank of America.

So my question is how sensitive is your business plan to oil prices? I mean, what is the price range that your plan remains untouched, right, from both upper and bottom of the range, right? And another key point to understand is, is it free cash flow driven?

I mean, if oil prices average, I don't know, $90 or $80 per barrel over the next years, would you consider accelerate the drilling plan in order to maintain the free cash flow indicated in your guidance, also observing the infrastructure potential bottleneck there, right?

Thank you, Leonardo. I will leave this question to Alejandro.

You, Miguel. I mean let's start with sensitivities. I mean, if we think of the plan, I think we're going to be generating $7.2 billion of EBITDA in the next 3 years. If you move prices $10 up or $10 down, it's approximately $1.2 billion of difference. So it will be $8.4 billion or $6 billion, if you see it on an EBITDA number. Then if you relate this a bit more to free cash flow, I think we covered that in the presentation, $10 less, and that's why I want to use this number, takes that $1.5 billion that we're going to be generating in the next 3 years to $0.5 billion.

So you're still going to be growing at the same pace, targeting those 180,000 or those 200,000 barrels per day in 2030 by generating $0.5 billion of free cash flow over the next 3 years. So what I would say there is that those $65 or $70 that we're seeing from '27 onwards, lowering them by $10 will still give you a position where $55 next year or $65 or $60 going forward, you're still going to be delivering the same amount of growth.

So on the lower side, I would say, at those levels, it will continue the same way. If it goes a little bit below that, we'll see how we play with the CapEx. And of course, see how much CapEx actually costs in a lower price environment. Now let's see on the other side, as you said, I mean, let's say, prices go to $80 or $90. The way we plan the development, and I think Matias just covered part of that. This is what we plan to do in terms of production.

We might accelerate a bit here or there, but it really will go around the production that we are actually targeting today. So that additional cash flow, if we actually have a positive year or a positive part of the cycle, we will probably use to either delever the company. It's a good time to delever sometimes when you actually have a higher price of oil or a peak and also in other ways to return more cash to shareholders.

Next question comes from Thiago Casqueiro from Morgan Stanley.

My question is related to drilling and completion costs. Given the $11.7 million for year-end '26 and then $11 into '28, where do you currently see the comparable figures for Permian? And also, do you see a site to your numbers here? But in other words, do you see further room to reduce this number or even accelerate the reduction through 2028?

Good question. Thiago. I will pass it to Juan.

Thank you, Thiago. Okay. So -- as far as our comparison to Permian, besides the difference in scale where in Permian, you have more than 500 rigs drilling. And in Vaca Muerta, you have less than 40. Besides the capital cost in one country and the other, there are some specific technical differences between Permian and Vaca Muerta. I'll get a bit technical on this, but in Vaca Muerta is the confined stress is much higher than in Permian, and that makes the rock more difficult to be drilled.

Also in Vaca Muerta, we need one additional casing strength to isolate areas or formations of different pressure regimes. And we use equipment and techniques for managed pressure drilling that is not something that is used in Permian. Also, the cost of labor here in Argentina is higher, and we expect that to be partially at least tackled with the reform, the labor reform that is sent to the Congress in December. So there are some specific differences between Vaca Muerta and Permian.

As far as going below $11 million, we have put together a team, as Miguel said, that is fully focused on well cost. And we're reviewing everything. We're reviewing all the cost structure. We're reviewing contracts, and we're renegotiating contracts. We're reviewing processes, and we are analyzing and testing new technologies. With that, we have a portfolio of opportunities that will take us to this $11 million number.

But there are some other opportunities and some other technologies that are being analyzed at the moment and will be tested probably in the future that may help us go further down. For instance, integration as vertical integration as we did with the sand plant production and logistics, going further on that may help us on reducing our well cost even further.

Next question from Tasso Vasconcellos from UBS.

It's been very interesting to follow the story from Vista to hear and great to see the outlook ahead. My question, I think, is more on the industry side because on the business plan, you mentioned your expectations to have a Brent at $65 next year and probably moving to $70 in the upcoming years.

And when we look at these prices, it's not consensual. It could move lower to $50 or inventory higher to $70 or inventory even higher to that, right? So I think it would be great to hear from you, maybe to Miguel this one, what your viewing in the industry? What gives you confidence that Brent will be closer to the $70 1 or 2 years from now and not closer to the $50?

Thank you, Tasso, for your question. I will take this one. We are very contracted and positive on $70 that we have planned from '27 onwards, mainly because 2 or 3 things. The first one is we believe the supply-demand balance going forward is going to be driven by the undeveloped countries that today are consuming 4x or 5x less energy than the developed country.

And we believe, okay, due to the fact that the E&P industry have not invested in exploration during the last 20 years, that balance, it will play a positive balance to having to sustain a price that is about $70. Geopolitically, we can guess anything, okay? But I think we will continue being experience of being in a volatile war. And for me, that if you take what we have on positive and negative, I believe it's going to play in favor of having higher oil prices and lower oil prices and anything can happen in the middle.

Saying all that, we are always prepared for the downside case, okay? And as I have explained many times before, we have built the business based on having a portfolio of ready-to-drill wells that are basically fast to deploy, but also fast to stop. And we proved that during the COVID-19. We have flexible contracts with our service providers. We drilled a well in 13, 14 days, and we completed a well in another 12 days.

So for us, a pad of 4 well is almost a month, 1.5 months. It's easy to start and easy to stop. Today, we have a cash flow positive operation. So we are not super leveraged. And also, we have a very good margin. When you look at our netback today are between $40 and $50. So we have room. So I said we can go probably down to 60% without changing our plan. And if it will go to 50%, we will have to adjust our plan and go back if it just happen for a period of time.

Next question comes from Vicente Falanga from Bradesco.

Congratulations on this great event. My question is, clearly, you're going to have excess cash to shareholders on your plan. In terms of remuneration, would you rather do buybacks? Or would you rather pay cash dividends? And also, if you can provide us an update on the Petronas shares?

Super. I will pass to Pablo this question.

Perfect. Thank you, Vicente. So as you see in the presentation, our free cash flow progresses over time, right? Initially, it's around $200 million, and it grows to $500 million, $700 million, $800 million and more than $1 billion in 5 years, right? So we think it's a bit too early in that cycle to define a fixed dividend policy.

So I would say next year, the next 12, 18 months for sure, share buybacks will be a priority over dividends, in particular, our understanding of the stock price being at a discount to what the target prices of essentially all of you is and what we believe is the fair market value of that stock, right? So we'll prioritize that. In terms of Petronas, a few days back, we received a communication from Petronas that they have successfully disposed of all the shares. So they have all been 3.7 million shares have been placed in the market.

Next question comes from [indiscernible] from JP Morgan.

Congrats on the very constructive plan presented today. I wanted to explore a little bit more on the drilling plan. So Matias was mentioning that we had unlocked 180 new wells, right? And we have the plan of drilling 80 to 90 wells per year. So could you explain a little bit on how the tie-ins will be developed? And if you can explain also the Coirón Amargo Norte that is one region that has not been drilled. What are your expectations towards that?

Thank you, Milan. I'm going to take that one. It's a good one. Just to understand our plan in the next 3 years is to be focused on the core development hub. So the first year, taking into consideration, for example, 2026, we'll be drilling 85 wells. Those 85 wells are coming from our operated assets. That's mostly 60 wells, mainly focused on what we call core development hub. When we call core development hub, it's all Bajada del Palo Oeste and Este and also that we are going to operate with 4 rigs.

To add to that sum, we need to add the La Amarga Chica that are 25 wells at a working interest. So if you add the 60 with 25 with 85 wells. And that's going to somehow what's going to happen in 2026. Then we have the upside of the pilots. We're going to be piloting Águila Mora and Coirón Amargo Norte, but that's going to happen in between 2027 and 2028.

Specifically related to Coirón Amargo Norte, we have a planned pilot for 2 wells. I assume that's going to be at the end of 2027. What is interesting, what happened in this block is a 22,000 square -- 22,000 acres block. It's all the [indiscernible] activity that happened at the north in Bajada Palo Oeste, also in different kind of activities, Shells and Pan American, they had really good results.

So it's encouraging for us to put a pilot early there. And another advantage that has the block is pretty easy to link with the infrastructure of Bajada del Palo. So we're very confident on that pilot of Coirón Amargo Norte.

Next question from Andres Cardona from Citi.

It has been an amazing journey since 2017 when you did the IPO as a SPAC and now showing these ambitious targets. And my question is about the 2030 free cash flow. If you can help us to break down the assumptions behind that number.

Ale, do you want to take this one?

Sure. Yes, I mean, when you think about 2030, we were envisioning a production of a little bit over 200,000 barrels per day. So that's what you should think of. Remember, prices of around $70 Brent. That's what we were targeting. That should mean that revenues probably are around $5 billion if you actually do a number.

Then if we subtract export taxes, royalties and selling expenses, lifting costs and G&A, you're probably seeing an EBITDA of anywhere between $3.3 billion to $3.5 billion probably, around that. Then if you take out the CapEx and the income tax, that would probably take around $1.8 billion, and that's how you get more or less to the $1.5 billion of free cash flow for 2030.

So next to come from Bruno from Goldman Sachs.

My question is on the productivity of the wells that you're going to drill in the next few years. It seems that your guidance for production implies a decline in productivity per well in the next few years. Can you confirm if that's the case? And if so, why? And what's the pace of decline that you expect going forward?

Thank you, Bruno. Well, I have the luxury to pass it to Matias today, this question.

Yes, I take it. That's a good one, Bruno. Of course, you have seen the presentation. We're really proud of the results we have got. We have the best results in productivity of the wells of Vaca Muerta and benchmark to Permian Basin and also that. So having said that, perhaps it's hard to find just one type curve for the inventory that we have. But what I can say is in every single well that we're going to put on production since now, it's -- you are going to find perhaps IP rates 30 days, that's going to be between 1,300 BOEs per day to 1,900 BOEs per day.

And in terms of total recovery, it should be between 1.2 million and 1.8 million BOEs cumulative production in all the years. What's important to mention is as far as we are continuing developing the assets, perhaps we're going to find some maturities and some interferences. As Juan mentioned in the presentation, we are building some technologies and approaches in order to mitigate those interferences.

All that is already involved in our model, and we're very confident we're going to gain some advantages of upside for those kind of technologies. And on top of that, we have plenty of inventory, as I mentioned in the presentation, and we also see upside in inventory related to new technologies and some enhanced recovery technologies, too.

I will add, Bruno, to what Matias said that because when we get this question, usually, people have the mindset of Permian. And I think there's one thing that set us completely apart of Permian and it's the way that we develop our blocks.

In Permian, you have leases and you have to put leases together in order to have an operational plan that allow you to have continuity for your rigs. And those leases are not based on reservoir management and not based on what you have in the subsurface. We here have concessions for 35 years.

So we can plan the way that we want to develop our fields in the more rational reservoir management way of doing it. And I think that is a huge advantage that many people don't realize that we have in terms of regulation compared with U.S. that affect and goes exactly to your question.

Next question comes from Michael Furrow from Pickering.

Just a good follow-up to the previous comments. Look, Vista has done a great job driving down well costs, improving well level economics. It seems like you found an optimal frac stage spacing, but one of the items that we've noticed is that lateral lengths have been pretty consistent. From the perspective of U.S. shale, one of the largest value creators we've seen over the last few years is extending lateral lengths to levels that the industry thought was not possible.

So it seems like whatever operator in the Vaca Muerta that makes this breakthrough will be a real strategic advantage. So my question is, does your 5-year plan contemplate extending of lateral lengths? And if not, could you maybe speak about what some of the operational and geologic limitations are that would prevent you from doing so?

Good question, Michael. I will -- I think the best person to answer this one is Juan.

Thank you, Michael. Okay. So we are -- today, we're reporting and standardizing in 2,800 meters wells that is for reporting purposes in order to be able to compare one campaign over the other. Now, we are actually extending the lateral length of the wells. The average for 2025 will be 3,100 meters, and we have drilled wells over 3,600 meters. In La Amarga Chica, for instance, we're drilling wells over 4,000 meters. So what is the limit? The limit is the technology and how much it takes to clean the well after fracturing it. And so as long as we can clean it, we will extend it as much as we can.

Now then as Miguel said, there are some limitations on the concession because of the shape of the concession and because of some structural limitations or wells that you have already drilled and that limits you from going further and further. So although we will continue to report and to normalize to 2,800 meters, it does not mean that we're drilling just 2,800 meters. We are drilling the longer lateral that we can depending on the specific area that we are drilling.

Next question comes from George from Latin Securities.

My question has been touched on through various other questions. But you've guided today an impressive production trajectory over the next 5 years. I was wondering when you think about potentially accelerating that trajectory, how are you viewing the potential to acquire more midstream capacity if that potential exists?

Pablo, do you want to take that one?

Thank you, George. So the pipeline capacity is not a limiting factor to our plan, right? If you go through what we have today, we have 111,000 barrels of capacity in OldelVal, including the Duplicar project that is fully online. We have 33,000 barrels of capacity per day going to Chile, right? So that can accommodate, obviously, our growth in 2026 and part of early 2027. And then we have a 10% stake in Vaca and VMOS, the new pipeline that is being constructed is at an advancement rate of around 33%. The pipeline is already 50% constructed. So it's going pretty, pretty well.

That would add around 50,000 barrels net to us, which is more than enough to deliver on our 2030 vision of 200,000 barrels of oil equivalent, 85%, 90% of that is barrels of oil, right? So we don't see a limitation in our plan. There are several flexibilities built into the system. One is OldelVal can use friction reduction agents, which adds like 10% capacity. OTC to Chile can use that as well. The VMOS pipeline can be expanded from the targeted 550,000 barrels of oil transportation per day to 700,000 with very simple additions, pumping stations and so on.

So let's say, if we and other players in the basin get more aggressive and want to grow even further, we think that the system can accommodate it, right? And then there's trucking capacity. Remember, we built like 37,000 barrels of trucking capacity a couple of years ago. It was instrumental in that initial phase to grow and now use all those barrels -- fill those barrels in the Duplicar system. And those are available, right? So if it happens that we all grow together much faster than anticipated, there will be place in the system.

Next we can come from Juan Muñoz from BTG Pactual.

This is regarding the export tax and considering the high amount of volumes that you export right now and you plan to increase this share, what are the chances of the export tax to be removed? And if it is the case, I know you have calculated the impact that it will have in your EBITDA.

I will take that one. So that been -- first of all, I mean, what is our export tax? Our export tax today is 8% at $60 per barrel and below $45 is 0, functional in the middle, linear in the middle. And this is what we have probably for the last 5 years, as we said. Before that, we have 12%.

That discussion -- the current discussion of the government of reducing export tax, but nothing that we can count on today to put in a plan, okay? Of course, we will welcome anything that make Vaca Muerta more competitive. It makes a lot of sense for the country to promote Vaca Muerta because as you see, as many people said here, we have just 40 rigs compared with 450 that U.S. have. So plenty of room to accelerate and to grow. but nothing yet that we can really consider to put in the plan.

So next question comes from Ignacio Sabelle from Itau.

My question is on capital allocation. Given the higher cash generation going forward, how should we think of capital allocation if capital controls at the end narrow the ability to pay dividends? And well, what should change?

Ale, do you want to take this one?

Sure. Ignacio, -- we've seen probably in the last 2 years, a positive trend in terms of lifting of capital controls, starting beginning of last year when we were able to repay 100% of the debt. I think that plus a better macro allowed most of the companies that are public to access international debt market. So we've seen a very positive trend started at that time.

In the meantime, there was another change to Vista probably when we acquired La Amarga Chica, which gave us access to Decree 929, which allows us to lift dollars from the exports that we do. We've been doing almost $15 million per month during 2025.

That should -- that's around $180 million for the year. And actually, if you do the math going forward, you'll see that probably in the next 3 years, based on Decree 929, there's like $1 billion linked to potentially lifting 20% to 40% of the exports that we actually do from La Amarga Chica.

So that is one way that we've seen very positive reaction from this government, where both on the debt side and honoring the Decree 929 allowed us to have access to at least $1 billion, let's say, in the next 3 years if you actually think of what we're going to be producing. So that's one way when you match to the $1.5 billion that we're generating if we wanted to have fully available dollars.

That will give us possibilities to either do share buybacks to put eventually in a longer-term dividend policy and eventually, of course, delever. So those are the things we can do with that. Now the one thing to also take is that we're seeing a very positive trend, and let's see how things evolve. If the macro continues going well, I think we're going to probably not necessarily be in that situation, and we probably fully decide what we do with the cash flow.

Next question comes from Matías from Adcap.

First of all, thank you for this event. And also thank you for the past 3 years of growth for shareholders. It's a promising company. The future seems promising as well and also for over delivering in the past Investor Days. My question goes on the regard of drilling and completion unit cost per well. Can you break down the cost per well? Do you include ground leveling, testing and others? Or it's just the drilling and competition?

Thank you, Matias, for your comment, first of all, and I will have Juan to answer that question.

Thank you, Matias. Okay. So when we report well cost, we're always talking about drilling and completion. And we do that because it is the standard KPI for the industry. If we were to compare against other peers in the industry, other public companies that report the D&C cost, we report exactly the same.

So basically, when we say D&C or well cost, we're talking about drilling and completion. And our well cost, the split is probably 60% is completion and 40% is drilling. Now if you want to add up all the well construction well pad construction facilities and well tie-in and testing, then you need to add probably 10% to 15% to that well cost.

Next question from Oriana from Balanz.

Congratulations on the program presented today. I have a broader question based on the macroeconomic backdrop. And just thinking under a more favorable political landscape, could you see a revival of the potential hydrocarbon law conversation going there? And what are, in your view, the key initiatives needed for like a promotion -- continued promotion of the sector?

Thank you, Oriana. I will take this one. So first of all, just to put this -- your question in context, I think since we started developing Vaca Muerta in 2012, we have come a long way. And many of the interventions that we have had from governments have been always positive since I believe Vaca Muerta, everybody realizes part of the solution.

During the current administration,[indiscernible], I think -- and we think introduced a very positive change because for the last 2, 3 years, we have become a country that we are a structural net exporter. And therefore, there was room to free up the exportation of barrel of oil.

And they have eliminated the [indiscernible] that were somehow making the exportation much more cumbersome for no reason. Then I think stabilizing the macro economy of the country and having access to capital market is probably one of the biggest things that this current government is doing and can do for Vaca Muerta.

And the other thing that we said as a big subject, and we've been discussing this today here is to gain competitiveness. We know that we have a different on CapEx well cost, particularly with U.S. of around 40%. Part of that come from economy of scale. They have 450 rigs. We have 40 rigs. But there are other parts that come from regulation, taxes and so on.

And anything that we can do to become more competitive clearly will translate in more production in more exports and more proceeds for the country and more shops for our people. So I believe there is room there for a win-win situation. And there's a lot of discussion going on around that. Again, nothing that we can build today in our plan.

Next question comes from Francisco from DON Capital.

Congratulations on great perfections. My question will be that assuming the same CapEx that you showed on the presentation previously, at what level of Brent price will you be free cash flow neutral?

All right. Pablo, do you want to take it?

Sure. So we're planning for 3, 4 years of relatively flat CapEx, $1.5 billion, $1.6 billion per year, and our free cash flow grows every year, driven by EBITDA growth, right? So next year, our free cash flow would be neutral if Brent is slightly below $60, call it, probably $58, $59.

But that breakeven gets significantly lower in the outer years, right? So by 2028, that Brent breakeven would probably be around close to $45, call it, $46, $47, right? And something in between for '27 call it, around $50, right? And I think that's evidence of the competitiveness of our capital program.

Next question from Santiago from [indiscernible].

My question is regarding lifting cost. How do you see projection for next years? And if there is a technical limit?

Super Santiago, I will pass this one to Matias.

I take that. Thank you, Santiago, for your question. That wasn't included in the presentation. So you know that lifting cost for us is somehow the flagship of efficiency. Somehow, I may say we're reaching the point of the technical limit and that technical limit should be around $4 per BOE.

And the most important thing here is that we have derisked all the uncertainties. So we have deployed full gas lift in our wells. So more or less around the 200 wells that we have flowing, 160 wells has gas lift. So we know exactly what is the densification of the chemicals, the manpower in the field, how to manage with technology and not going to just supervise each well. So you should consider that we are going to have around between $4 per BOE to $4.5 during the next 3 years.

Thank you, Matias. We have -- we had a lot of questions really from the chat, but a lot of them were already covered. So I have 2 here that I would like to read. One comes from [indiscernible] says, can you give more color about a share buyback program to take advantage of any opportunistic and flexible opportunities that the market may provide?

The first thing is that we have already used the share buyback program that we had during 2025. It was $50 million. We already executed that. To have a buyback -- to have a new share buyback program, we need to go back to shareholder meeting. We have to present full year results.

And with those results, we ask for shareholder approval to put a new plan in place. So this is what we're going to do in April this year, next year, we're going to present a new plan for share buyback to be approved during the shareholder meeting. So that's what you should expect.

And the second question is from Daniel Guardiola from BTG. In terms of growth, are you considering inorganic growth opportunities in your production targets for 2028 and 2030? In case you're not, how do you envision M&A fitting your business model? And can you share with us what kind of opportunities would you be interesting to pursue? Probably, Pablo, do you want to take that one?

Sure. I'll take it. Thank you, Daniel. 100% of the growth in our plan is organic, right? So we've only included wells that have been derisked and that are in our inventory today.

M&A, however, is, I would say, part of our DNA, right? Vista has started to exist on the basis of M&A transactions. We have grown on the basis of M&A. We've closed a very important M&A transaction that gave us a lot more scale earlier this year.

But going forward, we don't have the imperative. We don't have the need to do an M&A transaction. However, to the extent a transaction brings in value to Vista and by value, we mean it's synergetic. It's focused in what we do. So we would only be looking at the oil window of Vaca Muerta in Argentina.

If something fits that profile, we will take a look at it. And the mandate will be for that transaction to add value dollars per share to our stock price. We don't need more scale just for the sake of scale, and we don't need to do M&A just for the sake of doing it, right? So we'll be, I would say, extremely selective as we have been until now. That's it.

Well, thank you very much. First of all, thank you for coming here, and we are all looking forward to spend a few more days with you in the field and later here in Buenos Aires.

I would like to take the opportunity also to thank our shareholders, to thank our employees and people in Vista that have taken us all the way up here. We are super excited about the new plan. It's a new phase of growth for us. And from tomorrow on, we will focus on delivering on the promise as we always do. So thank you very much, and have a good rest of the day.

Thank you for attending today's presentation. You may now disconnect.

Good day, and thank you for standing by. Welcome to the Vista's Third Quarter 2025 Earnings Webcast 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, Vista's Strategic Planning and Investor Relations Officer. Please go ahead.

Thanks. Good morning, everyone. We are happy to welcome you to Vista's Third Quarter of 2025 Results Conference Call. I'm here with Miguel Galuccio, Vista's Chairman and CEO; Pablo Vera Pinto, Vista's CFO; Juan Garoby, Vista's CTO; and Matias Weissel, Vista's COO.

Before we begin, I would like to draw your attention to our cautionary statements 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 the 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 conference call, we may discuss certain non-IFRS financial measures such as adjusted EBITDA and adjusted net income.

Reconciliation of these measures to the closest IFRS measures can be found in the earnings release that we issued yesterday. So please check our website for further information. Our company is sociedad anónima bursátil de capital variable organized under the laws of Mexico, registered with the Bolsa Mexicana de Valores and the New York Stock Exchange. Our tickers are VISTA 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, and welcome to this earnings call. During the third quarter of 2025, we recorded a strong performance across key operational and financial metrics, especially on a sequential basis, driven by strong productivity in new well tie-ins in Bajada del Palo Oeste and La Amarga Chica. Total production was 127,000 BOEs per day, an increase of 74% year-over-year and 7% quarter-on-quarter. Oil production was 110,000 barrels per day, an interannual increase of 73% and 7% sequentially.

Total revenues during the quarter were $706 million, 53% above the same quarter of last year and 16% above the previous quarter. Lifting cost was $4.4 per BOE, 6% below year-over-year. Capital expenditure was $351 million, driven by new well activity during the quarter. Adjusted EBITDA was $472 million, an interannual increase of 52% and a sequential increase of 70%. Adjusted net income during the quarter was $155 million. Net income was $315 million, reflecting a nonrecurring gain of $288 million from the Petronas Argentina acquisition.

Earnings per share was $3 and adjusted earnings per share was $1.5. Free cash flow in this quarter was almost neutral at minus $29 million, driven by higher adjusted EBITDA and a decrease in working capital. Finally, our net leverage ratio at quarter end was 1.5x on a pro forma basis.

During Q3, we connected 24 wells, 11 in Bajada del Palo Oeste, 4 in Aguada Federal, and 9 corresponding to our 50% working interest in La Amarga Chica. We recorded solid productivity in the latest well tie-ins, which boosted Q3 production by 7% compared to the previous quarter. Based on robust well performance, improvement in our oil realization prices and financial flexibility award by the $500 million term loan closed in July.

We have decided to accelerate new well activity in Q4. We are now planning between 12 and 16 tie-ins in the next quarter, leading to between 70 and 74 connections for the year. We are seeing Q4 production about 130,000 BOEs per day, which leaves us on track to over deliver on production guidance for the year and the second semester.

Total production in Q3 was 126,800 BOEs per day, an interannual increase of 74%. Oil production was 109,700 barrels per day, 73% above year-over-year. On a sequential basis, both oil and total production increased 7%, reflecting solid execution of our drilling campaign and robust well productivity during Q3, especially in Bajada del Palo Oeste and La Amarga Chica. Bajada del Palo Oeste also drawn production in our operated block, which increased 50% compared to a year ago and 6% compared to the previous quarter. Gas production increased 87% on an interannual basis and 9% on a sequential basis.

In Q3 2025, total revenues were $706 million, 53% above Q3 2024, driven by a strong increase in oil production, which more than offset lower oil prices. On a sequential basis, total revenues increased 16%, driven by 7% increase in total production and 4% higher oil prices. Oil exports increased 84% year-over-year to 6.3 million barrels for the quarter. Realized oil prices were $64.6 per barrel on average, down 5% on interannual basis and up 4% on a sequential basis, in both cases driven by international prices.

We captured higher Brent prices and lower discounts, which were around $1 per barrel during the quarter. During Q3, 100% of oil volumes were sold at export parity prices. In Q3, lifting cost was $4.4 per BOE, 6% lower compared to both the previous quarter and the same quarter of last year. This reflects our continuous focus on efficiency. Selling expenses per BOE were down 24% on an interannual basis, driven by the elimination of oil trucking services as of the start of the last quarter.

Adjusted EBITDA during the quarter was $472 million, 52% higher on interannual basis, mainly driven by production growth, explained by the 15% in our operated production and the consolidation of 50% of La Amarga Chica. Compared to the previous quarter, adjusted EBITDA increased 17%, mainly driven by oil production growth. Adjusted EBITDA margin was 67%, up 2 percentage points compared to the same quarter of last year as production growth and the elimination of oil trucking offset lower oil prices.

Netback was $40.5 per BOE, up 8% on a sequential basis. During Q3 2025, cash flow from operating activities was $304 million, reflecting income tax payments of $179 million, partially offset by a decrease in working capital of $43 million. Cash flow used in investing activities was $333 million, reflecting accrued CapEx of $351 million partially offset by a decrease in CapEx-related working capital of $17 million.

Free cash flow during the quarter was minus $29 million, reflecting higher adjusted EBITDA that drove cash from operations and a decrease of $59 million in working capital. Cash flow from financing activities was $195 million, driven by proceeds from borrowings of $500 million, partially offset by the repayment of borrowings' capital of $193 million and the repurchase of shares of $50 million. Finally, cash at period end was $320 million, our net leverage ratio on a pro forma basis reflecting the Petronas Argentina transaction stood at 1.5x adjusted EBITDA.

To conclude this call and before we move to Q&A, I will make some closing remarks. During Q3, we recorded a robust well productivity in new well tie-ins, reflecting our high-quality asset base and peer-leading operating performance. This led to a material increase in adjusted EBITDA, both in a sequential and interannual basis, driven by production growth and continued focus on cost control.

Q3 production was well within guidance range for the second semester. Production growth in the fourth quarter on the back of solid productivity and more investment in our profitable ready-to-drill inventory leaves us on track to potentially over-deliver on our guidance. I remind you that we will be hosting our third Investor Day on November 12. During this virtual event, we will present an updated strategic plan, focusing on profitable growth, cost efficiency and cash generation.

Before we move to Q&A, I would like to thank everyone at Vista for delivering a remarkable quarter. Operator, we can now move to Q&A.

[Operator Instructions] Our first question comes from the line of Rodolfo Angele from JPMorgan.

Thanks for the time to discuss the numbers presented yesterday. I'm sure we would like -- looking forward to the investor event where you're going to revise the strategic numbers. But for the time being, I think my question to you is on price realization. The numbers were pretty good. And compared to our expectations here, one of the positive surprises came from a realization of prices pretty solid versus Brent. So can you expand a little bit on what drove this? And what should we expect for the coming quarters? That's it for me.

Rodolfo, thank you very much for your question. It's a good one. There are basically 2 factors driving this good realization prices. With our spot export via the Atlantic, we have some flexibility regarding when we trigger the Brent price. This can potentially usually help us to capture some Brent price slightly above what you can see as a quarterly average. In Q3, the Brent averaged around [indiscernible], but the trigger Brent that we use to price the cargo was on average $1 higher. Also, the average discount of Brent was around $1 per barrel during Q3.

So this is explained by 3 main factors. The first one is the high oil demand that we saw from West Coast U.S. due to seasonal factor. The other one was the very good demand that we have for Medanito. And the last factor was the lower availability of other type of crude oil that usually compete with us like [indiscernible] crude. So that mainly explains why we have some good realization pricing during the Q3.

Our next question comes from the line of Leonardo Marcondes from Bank of America.

So my question is regarding the drilling completion and tie-in of the wells since September's figures beat the market expectations, right? So I would like to know if you could provide some color on the rationale of this significant increase in well tie-ins now, right? And also some color on what can we expect from this team for the remainder of the year? I mean, should you keep the rhythm on October, November, December?

Leonardo, thank you very much for the question. And I will explain and give you a bit of context on the rationale on the increase of well tie-ins. So I mean, as a recap, in April, we took on a bridge loan to finance the Petronas Argentina acquisition, as you know. In May, we successfully tapped to the international market and issued a bond of $500 million to take out the bridge loan. And also in July, a $500 million term loan to refinance all our short-term maturities, and that basically give us or regain full financial flexibility.

We also consolidate the new assets. We saw very good productivity and production growth, even, I would say, better than our original expectation. And on the top of this, now there is less bearish consensus regarding the oil price. So in summary, due to all these factors, we decide -- we saw that we are aware in a position that we were more comfortable to basically accelerate CapEx.

Regarding Q4, the short answer to your question is yes. You will see pretty much, I would say, 11 to 14 wells. And regarding '26, you have to bear with me, I mean we have in a few weeks at our Investor Day in November 12, and I will probably wait to give you a full view of what we're going to do in 2026 and onwards.

Our next question comes from the line of Bruno Amorim from Goldman Sachs.

I have a follow-up question on the production outlook. It seems that you ended third quarter on a strong tone. So what does it mean for the fourth quarter, given you just mentioned you're going to continue to drill and tie-in a significant number of wells into the fourth quarter. Can you elaborate on where do your current expectations stand versus your guidance for the remainder of the year?

Bruno. Yes, you can expect that the production for Q4 to be about the 130,000 barrels oil per day that we guide. As always, you will see the typical up and downs that we see month-over-month. As you know, the natural rhythm of how we tie-in the wells sometimes it's not quarterly, but it's changing month-by-month. But on average, Q4 will be similar to September. So this implies that we will likely be above guidance for the year.

The guidance was between 112,000 and 114,000 barrels oil per day. And also [indiscernible] we will be about the guidance for the second semester, which was between 125,000 and 128,000 barrels oil per day. So yes, you can you can probably look at Q4 about 130,000.

Our next question comes from the line of Alejandro Demichelis from Jefferies.

Congratulations on the quarter. Miguel, one quick question. Could you please indicate how you're seeing the evolution of drilling and completion costs over the next few quarters? We have seen a bit of volatility on the FX. We have seen kind of inflation kind of going up a little bit. So just some kind of direction on how you see those costs go on, please?

[Operator Instructions]

Congratulations on the quarter. Miguel, one quick question. Could you please indicate how you're seeing the evolution of cost of drilling and completion costs over the next few quarters given the volatility on the FX, inflation and so on.

Yes, Ale here again. I mean we listened the first one, but thanks for the question. So we announced, I was saying in Q2 that our cost of the well was around $12.8 million. This is drilling and completion cost for well with a lateral length of approximately 2,800 meters and 47 stages. Today, we are slightly below this number and we are seeing very good results from the initiatives that also we announced last quarter that we will implement it. We are currently working on further initiatives on the same 2 verticals that were contracts and technology, so -- which basically, we believe and we feel very strongly that will lead to further savings.

So the idea is to comment and to give a lot of color and more color because we have very good news coming on that front on the Investor Day. So I hope you take that answer now, and we will give you more detail when we see you in the [ field ] on November 12.

Our next question comes from the line of Thiago Casqueiro from Morgan Stanley.

Congratulations on the results. My question here is regarding La Amarga Chica. It's been about 6 months since you acquired the stake in the assets. So looking back on this initial learning period, what would you say are the key challenges and opportunities you have identified in the assets so far?

Thiago, thanks for the question. Look, I mean, we have a very open and contractive relationship with YPF, I will say, at all levels. At my level, CEO and at the level of Matias in the field and everybody. You imagine they have been for many years, co-worker of us. So very good relationship, very good collaboration. We are collaborating in many fronts. First, I would say, sharing technical learnings. We regard ourselves as lead operator. We have learned a lot. YPF has a very extense experience in unconventional. So the sharing of practices has been very rich.

Second, in opportunities on services and also in infrastructure, very collaborative and very open discussion also in those both fronts. The performance of the production and the cost efficiency this quarter was very good, I have to say, very good. So we are now focusing and discussing the 2026 [indiscernible] and the budget for that. But overall, it's going very well.

Our next question comes from the line of [ Matteo Tosti ] from Citi.

Congratulations on results as well. I was wondering while you may comment on M&A. I mean I remember last quarter, you touched on this, and we -- you said maybe there was still appetite for M&A. And has this appetite continued? Is something that has maybe weighed down a bit? What can you comment on this?

Matteos, well, the short answer is the appetite is intact. So we have a proven track record, as I said before, creating value through M&A. So we are not only good operators, we have been very good M&A wise all the way up to here. And the best example of that probably the Petronas acquisition earlier this year. So that is part of our strategic approach as Vista.

So given also that we are increasing our scale and our cash profile going forward, we will continue assessing opportunities. The only thing I will say that you have to take in consideration that we have a very high value in terms of value accretion and also in terms of strategic fit. But yes, the short answer is the appetite to M&A is intact for us, and we will continue looking to opportunities as they come.

If I may add a quick follow-up. Are there any open processes today, maybe the opportunities to engage with other companies? Are there any open process, any assets available that you're looking into? Or has the temperature cooled on that front, too?

No, I don't think -- I mean, as we said in a formal process, I don't see any formal process that we are participating. We are having, yes, several discussions as always we have. As you know, the interest in Argentina have renewed a lot during the last few -- during the last year. And also, we see new players coming into the country, I would say, exploring opportunities. So yes, we are maintaining discussion with all of them. But I will not say that we are participating in any formal process at the moment.

Our next question comes from the line of Tasso Vasconcellos from UBS.

Great. Miguel, maybe a follow-up question on the discussion on CapEx and production levels. If Vista were to only maintain current level of production is stable without much growth, what would be the level of CapEx required? And in this same sense here, what would be the maintenance CapEx to maintain production stable closer to 150,000 barrels a day. That's my question.

Thank you, Tasso for the question. Yes, these are numbers that usually when we simulate our plans, we look into. I will say using 100,000 barrel per day of production as a reference, we will need around $700 million of CapEx to keep the production flat going forward. And that will imply probably between 50 and 55 wells. If we in [indiscernible] of 130,000 with 150,000 barrel per day, then I think that we should add one rounding the CapEx around $800 million and then the number of wells would be between 55 and 60 wells. So that will be around numbers. Of course, that could change also depend of the context now.

Our next question comes from the line of Michael Furrow from Pickering Energy Partners.

So there's been a lot of attention on the upcoming midterm election. And for good reason, the outcome could have meaningful implications to the country. Now that said, the Vaca Muerta is an extremely valuable natural resource, and it seems to us that regardless of the outcome, this resource will continue to be developed. So I was hoping that you could maybe take some time to discuss your thoughts on the matter and if you see any outcomes from this weekend's election that would have a material impact on Vista's operations.

Thank you, Michael, for the question. It's a recurring question and a good question. In short, the elections do not change our plan. We've been growing Vista from the scratch to where we are today, participating in 4 different administrations. And even before that, most of us came back to the country in 2012. And as we said, we were part of making Argentina a structural net exporter today and being part of the solution of the country. So the fact that we are holding an Investor Day 2 weeks after the elections is a full reflection of what we feel about the business.

Our business model is solid, is dollarized, and we are increasing as we grow the amount of sales to the export market. So also, we said that we have secured the funding to continue growing, and we will discuss that in November 12. And we don't have any large financial debt maturity in the coming years. We also have secured the services, the rigs, the completions, the frac set with flexible contracts going forward.

So no, Michael, I don't think, I mean, the elections will affect multiples and other things or the perception of Argentina, but will not affect Vaca Muerta. It doesn't affect our ability to continue growing and to execute our plan.

That's great. I appreciate such a comprehensive answer.

Our next question comes from the line of George Gasztowtt from Latin Securities.

Brent has remained pretty volatile again this quarter. And I was wondering what your EBITDA sensitivity to oil prices was now in 4Q.

Thanks, for the question. Yes, there is a sensitivity. Using 130,000 barrel oil per day production as a reference, you should think that for every dollar per barrel of changing in realized oil prices, the adjusted EBITDA in the fourth quarter will change approximately between USD 8 million and USD 9 million. That's more or less will be the impact.

Our next question comes from the line of Juan Jose Munoz from BTG.

Regarding La Amarga Chica, could you provide more color about the production of the 3Q? I understand that you finished on a strong note and also regarding the outlook that you have for La Amarga Chica in the last quarter of the year.

Thank you, Juan Jose, for the question. So in La Amarga Chica, let me do a bit of a recap of La Amarga Chica. In La Amarga Chica, we connect around 18 wells. And we have 50% of that work [indiscernible], so YPF connect 18. This well correspond to 4 parts, Pad 120, Pad 67, and these Pads, if I'm not mistaken, in the south triangle of the block and also the Pad 105 and the PAD 83 that are in the center of the block. All the 4 pads are producing above budget.

The well performance of La Amarga Chica was good and the production was for Q2, 38.7 and they took it from 38.7 to 43.5 in Q3. So very good performance for Q3. And we are expecting -- I cannot give you a number, but we are expecting a very strong performance also in Q4. So I hope that gives you a feeling of how we are looking at La Amarga Chica.

Our next question comes from the line of Francisco Cascarón from DON Capital.

My question is what caused the decline in operated production during the first 2 months of the quarter? And if you are looking to accelerate that production going forward like we saw in September?

Thank you, Francisco. So yes, we saw a very good productivity in the wells that we connect during the quarter, specifically Bajada del Palo Oeste where we connect 11 wells that correspond to 3 different pads. Bajada del Palo 35 was connected in July, has 5 wells of around 3,400 meters in lateral length and 57 completion stages on average. Then we connect Bajada del Palo Oeste 36 that has 4 wells, lateral of 3,300 meters. On average, I think, around 50 stages.

And then we -- that was -- the last one was connected in August. And then we connect Bajada del Palo Oeste 37 that has only 2 wells, 2,800 meters length and 48 stages on average that was connected in September. So what you're seeing is the solid productivity of this 11 wells is the result of the boost production that you saw from Bajada del Palo Oeste that went from 56,400 barrels of oil per day in Q2 to 60,200 barrels oil per day in Q3. So that are the pads that somehow result in the boosted production. You will see that also continuing in Q4.

Our next question comes from the line of Matías Cattaruzzi from Adcap Securities.

Miguel and Alejandro, my question goes on the regard of CapEx guidance. Given the current activity levels and the pulse of -- the pace of well tie-ins, do you see a possibility of this year CapEx ending above the $1.2 billion guidance closer to $1.3 billion or over that number as recent trends in activity suggest?

Matias, yes, thanks for the question. Yes, I mean, we guide 59 wells, and we will be end up drilling between 70 and 74 wells. So you should add 11 to 15 wells to our original guidance. Of course, that will involve more CapEx or some additional CapEx. So you should think that [indiscernible] $1.2 billion. So you should think that we will end up between $1.2 billion and $1.3 billion for total CapEx for the year and Q4, a little over $300 million. So that is how you should look to the actual CapEx numbers.

Thank you. At this time, I would now like to turn the conference back over to Miguel Galuccio for closing remarks.

Well, thank you very much, everybody, for the participation. Of course, we are super happy with the quarter, a fantastic quarter for us. And I'm looking forward to see you all on November 12 in Argentina. Thank you very much, and have a good day.

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

Hello, everyone, and welcome to the Vista's Second Quarter 2025 Earnings Call. [Operator Instructions] Please note, this event is being recorded.

Now it's my pleasure to turn the call over to Vista's Strategic Planning and IRO, Alejandro Chernacov. Please proceed.

Thanks. Good morning, everyone. We are happy to welcome you to Vista's Second Quarter of 2025 Results Conference Call. I am here with Miguel Galuccio, Vista's Chairman and CEO; and Pablo Vera Pinto, Vista's CFO; Juan Garoby, Vista's CTO; and Matias Weissel, 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 the 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 conference call, we may discuss certain non-IFRS financial measures such as adjusted EBITDA. 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 sociedad anónima bursátil de capital variable organized under the laws of Mexico, registered in Bolsa Mexicana de Valores and the New York Stock Exchange. Our tickers are VISTA in the Bolsa Mexicana de Valores and VIST in the New York Stock Exchange.

As explained in our earnings release yesterday afternoon, please be advised that the operating and financial metrics shown in this presentation reflect the effects of consolidating the acquisition of Petronas Argentina as of April 1, 2025. Finally, note that as of this webcast, we have moved all definitions, which were previously at the bottom of each slide to an appendix at the end of the presentation.

I will now turn the call over to Miguel.

Thanks, Ale. Good morning, everyone, and welcome to this earnings call. Q2 2025 was transformational for our company as we completed the acquisition of 50% stake in La Amarga Chica, the second largest oil production block in Vaca Muerta. This transaction has turned Vista into a significantly larger company. Boosted by this acquisition total production was 118,000 boes per day, an increase of 81% year-over-year. Oil production was 102,000 barrels per day, 79% year-over-year. Vista is now the largest independent oil producer and the largest oil exporter in Argentina.

Total revenues during the quarter were $611 million, 54% above the same quarter of last year. Lifting cost was $4.7 per boe, 4% above year-over-year. Capital expenditure was $356 million, driven by the ramp-up in new well activity during the quarter, both in Vista operated block and in La Amarga Chica.

Adjusted EBITDA was $405 million, an interannual increase of 40%. Net income was $235 million, including $102 million related to one-off mainly related to the Petronas Argentina acquisition. Earnings per share were $2.3. Free cash flow outflow in this quarter was $1.4 billion, mostly reflecting the upfront cash payment of the Petronas Argentina acquisition.

Finally, net leverage ratio at the quarter end was 1.38x on a pro forma basis, reflecting the new debt raise to finance this cash payment.

During Q2, we made solid progress on the operational front. New well activity picked up sequentially with 24 wells connected during the quarter, 8 in Bajada del Palo Oeste, 4 for in Bajada del Palo Este, and 12 corresponding to our 50% working interest in La Amarga Chica.

We continue to see the result of our strong focus on cost efficiency. We made decisive progress in reducing new well costs, capturing savings through innovation and efficiency, changes to our contract strategy and contract renegotiations for specific consumables and services. This has led to a new drilling and completion cost of $12.8 million per well, representing a saving of $1.4 million per well or 10%, which will be reflected in our cost of a new well starting in Q3 2025.

Following inauguration of Oldelval Duplicar pipeline in March we eliminated all tracking as of April 1. This led to a $41 million saving compared to Q4 2024, substantially improving our margins.

Total production was 118,000 boes per day, a sequential increase of 46% and interannual increase of 81%. This reflects the solid execution of our new well campaign, as we connected 47 new wells in the last 12 months and the consolidation of La Amarga Chica production as of April 1.

Oil production was 102,200 barrels of oil per day, 79% above year-over-year and 47% above Q1. Gas production increased 93% on an interannual basis, and 44% on a sequential basis.

In Q2 2025, total revenues were $611 million, 50% (sic) [ 54% ] higher year-over-year, driven by the strong increase in oil production which more than offset lower oil prices. Oil exports tripled year-over-year to 5.6 million barrels for the quarter, boosted by the production growth and the acquisition of La Amarga Chica. Realized oil price was $62.2 per barrel on average, down 13% on an interannual basis, mainly driven by the lower international prices. During Q2, 100% of oil volumes sold were at export parity prices.

Lifting costs during Q2 was $4.7 per boe sequentially flat, reflecting our continued focus on cost control. Selling expenses per boe came down 41% quarter-over-quarter, reflecting the elimination of oil trucking as of April 1. This led to a saving of $28 million vis-a-vis Q1 and $41 million vis-a-vis Q4 2024. The quarter during which trucking volumes peaked.

Adjusted EBITDA during the quarter was $405 million, 40% higher on an interannual basis, driven by the production increase in our operating blocks and the consolidation of 50% working interest in La Amarga Chica. On a sequential basis, adjusted EBITDA margin increased 4 percentage points, and netback remained flat as the elimination of oil trucking offset lower oil prices.

During Q2 2025, cash flow from operating activities was minus $9 million, reflecting income tax payment of $215 million, a $59 million increase in working capital and payments for midstream expansions of $18 million. Cash flow used in investing activities was $1,347 million, reflecting accrued CapEx of $356 million, an increase of $140 million in working capital and the acquisition of Petronas Argentina for $842 million net.

The free cash outflow during the quarter was $1.4 billion, mostly reflecting the upfront payment of Petronas Argentina. Cash flow from financing activities was $770 million, reflecting the proceeds from borrowings of $1,379 million and partially offset by the repayment of borrowings of $514 million. After quarter end, we have signed 3 term loans with local and international bank for a total of $500 million to cancel all outstanding maturities in the second half of 2025 and early 2026.

Finally, cash at period end was $154 million. Net leverage ratio on a pro forma basis reflecting the Petronas transaction stood at 1.38x adjusted EBITDA.

Our updated annual guidance reflects that following the acquisition of La Amarga Chica, we have emerged as a company with larger scale and a stronger cash flow generation. Total production in 2025 is forecast between 112,000 and 114,000 boes per day. Based on the planned well tie-ins, we forecast between 125,000 and 128,000 boes per day for the second semester, which leaves us with well positioned for a greater start in 2026.

Adjusted EBITDA forecast between $1.5 billion and $1.6 billion for the year, assuming $65 Brent for the second semester, equivalent to $60 per barrel of realized price, a change in $5 per barrel of realized oil price in the second half of the year result in a change in adjusted EBITDA of $80 million. During the second semester, we forecast $825 million to $925 million of adjusted EBITDA or $1.65 billion to $1.85 billion on an annualized run rate basis.

To deliver this plan, we forecast to connect 59 new wells during the year, of which 34 wells connected in the first semester combining our operating block with our working interest in La Amarga Chica. CapEx in this plan is forecast at $1.2 billion for the year. This reflects our new drilling and completion costs and $60 million of savings in facilities compared to the original 2025 guidance.

Our new 2025 plan represents an improvement to the original plan. At $60 realized oil price, we are forecasting a neutral free cash flow during the second half of the year, composed of negative free cash flow in Q3 and positive free cash flow in Q4, evidencing a strong capital discipline in the context of high oil price volatility.

Compared to the original guidance for the year, we are now forecasting to deliver 16% more production and 70% more adjusted EBITDA at $65 Brent, while maintaining the same CapEx level. The projected growth for 2025 compared to 2024 is 62% for production and 41% for adjusted EBITDA.

To conclude this call and before we move to Q&A, I would like to make some closing remarks. This has been a transformational quarter for Vista the acquisition of 50% working interest in La Amarga Chica materially boosted production and adjusted EBITDA. Our company has emerged as the largest independent oil producer and the largest oil exporting in Argentina.

On the operational front, we significantly reduced selling expenses by eliminating oil trucking, which expanded adjusted EBITDA margin even though oil prices dropped during the quarter. We have made a change to our D&C contracting model, capturing savings through innovation and renegotiating rates with service providers leading to a 10% lower well cost, capturing significant value through a highly competitive development cost.

Finally, the revised annual guidance following the acquisition of La Amarga Chica implies material production and adjusted EBITDA growth while significantly improving our free cash flow profile. Before we move to Q&A, I would like to thank everyone at Vista for their outstanding work this quarter.

Operator, we can now move to Q&A.

[Operator Instructions] And it comes from the line of Bruno Montanari with Morgan Stanley.

Thanks for the detail on the guidance. I have one question about La Amarga Chica. Based on the available data, it seems that the well costs are a bit higher than those at BPO, while the EURs are a bit lower. So could you shed some light on why those differences exist? And if you could somehow contribute to improve the performance of those wells, even if you do not operate the area. And also perhaps on the rationale of investing more on that side of the fence compared to adding more wells at BPO.

Bruno, thank you very much for your question. Well, let me touch base first probably on the rock. La Amarga Chica is on the west neighborhood of Vaca Muerta. It's right next to our block, as you know, Bajada del Palo Oeste [indiscernible]. We have studied this area for a long time before we came to Vista and now in Vista. And definitely, we understand that there is geological continuity there. So we have the same rock quality. If you look at the average well productivity, the performance of La Amarga Chica is very robust. It's comparable 100% to the block that we operate.

From the production standpoint, now when we look at what we have and what was delivered for Q1 and Q2, La Amarga Chica came in Q1, as we said with a lower growth quarter, but in Q2 it has been back to the level that we had in Q4. And for us, that reflects the quality of what we forecast, the quality of the rock that we saw, and that is confirming basically what we acquired in PEPASA.

If we focus, particularly in Q2, we saw a very solid ramp-up driven by 24 wells connected at 100% working interest, so net of 12 well for Vista. And the production of large ramp-up was 23% from 35,000 barrels of oil per day in April to 43,000 barrels of oil per day in June.

We have, as you probably can imagine, we have several discussions with YPF. We are working very well with them. We have exchanged a lot of technical information that has been valuable for us and valuable for them. And we are trying to progressively start to exchange and put some of that conclusion that we have together in actions.

So I would say, to be fair, for what we see, clearly that the fact that we will -- they are operating, but we are working together will create synergies, and we will create various costs of better productivity, but not only in large, I will say also Bajada del Palo Oeste, we are compare not well cost. We are compared what we are doing in term of performance, we are compared what we are paying for services. We are compare core technology, we are compare how we work with some from one side or the other of the fence. We are looking at what we do on the borders and how we can optimize well from one side, and from the other side, is for sure, is going to bring value for both sides, before -- for example, just to give you an example, before we were -- they were thinking enlarge, to drill 3,000 or 3,200 meter wells. That is not needed as far as we have an agreement on what will happen in the border of the 2 blocks. So there are plenty of synergies that basically will improve the performance of the 2 blocks.

One moment for our next question, please. And it comes from the line of Alejandro Demichelis with Jefferies.

The question is, Miguel, maybe you can double-click on how you see this kind of well cost developments and potential further reductions going forward? And also, if you can kind of compare those well costs in La Amarga Chica versus what you have in BPO or BPE, please?

Thank you, Ale for the question. Yes, for sure, I can double-click technically on what we are doing because we are putting a lot of focus on well costs today. I would say there are 3 main verticals that drive our initiative of well cost reduction.

The first vertical is technology and innovation. And I will give you some examples of that, that I think will give you a picture of what we're doing today. The first example would be the use of wet sand in our operation. We piloted that technology last year. And now we have taken the decision to roll out the use of wet sand for the full operation. That will bring a lot of savings, immediate savings and future savings.

We recently introduced a technology that is called a [indiscernible] with improved drilling efficiency when we are doing the curve section, basically using a motor and then leaving the rotary steerable just to drill and navigate the horizontal section. This approach has reduced manual integration and result in time saving of around 16 hours per well.

Another example is what we are implementing with our frac plan and real-time monitoring system. We modify our pumping schedule on the fly from the remote operation center in order to optimize the frac size that have basically is a function -- is a direct function of the cost and also to avoid the runway fracs, the fracs that basically are not increasing the area of contact of the reservoir, but they are running away through microfracture or because they find a fall or because they find a line of microfracture to a different well.

The second driver is cost reduction through negotiation of specific consumables of service, like gasoline, gas oil, water transfer services, drilling fluids and others.

The third driver is related to the change of our contract strategy. We've been reviewing for the last 6 years, our contract strategy and our contract strategy has been very useful for us starting up and running Vista all the way to here.

Now we are right to a moment where integration basically was not bringing the amount of value that basically will take our cost performance reduction forward. Also, when we were doing comparison in a volatile oil prices scenario with U.S., we didn't saw that the prices of the service were dropping the way they were dropping in U.S. So we basically decided to unbundle the services of the drilling rig into individual contracts. We did a few other things that it will take too long for me to explain, and we basically obtained savings to our overall costs.

The savings already captured on our drilling and completion cost per well have taken the well cost from $40.2 million to $12.8 million, so it's a 10% reduction. And you should assume that going forward, we will see more short-term reductions and also you should expect that we'll see also midterm and long-term reductions. Some of them are not related to contract renegotiation but are more related to the innovation and technology changes that are coming from the changes that we are doing in the process.

I'm back to Bruno question. What we saw in La Amarga Chica in terms of where we were both -- when we start to operate, so taking all this out of consideration. We have with YPF similar costs on that block on what happened in La Amarga Chica and what happened in Bajada del Palo Oeste.

I hope I answered your question, Ale?

Yes. That's Perfect.

One moment for our next question, please. And it comes from Daniel Guardiola with BTG Pactual.

Miguel and Alejandro. My question is on free cash flow. And in the second Q, we saw a large negative FCF in part driven by the acquisition of Petronas, but also due to a deterioration in working capital. And I wanted to ask, Miguel, if you could elaborate on the deterioration of your working capital and what we should expect going forward? And also considering the uncertain environment of oil prices, what is the company's mindset in terms of free cash flow generation for 2026 and onwards? Would you feel comfortable operating at negative levels or you're expecting to reach a more neutral level in 2026?

Thank you, Daniel, for your question. So if you consider the EBITDA generation and the CapEx for the quarter, just to put your question in context, EBITDA is higher by around USD 60 million. But this particular quarter, we have a lot of one-off, as you know, which led to the negative free cash flow that you are pointing out. The most obvious is PEPASA acquisition, which required $842 million of net outflow.

We also have income tax payment of $215 million, an increase of $45 million in VAT credit which both, I would say, should be reverted in the coming quarter because when you compare what we're doing for a good quarter, it's for you clear to expect that part of that is going to be reversed. We also have an increase in CapEx, working capital of USD 140 million. That was related to a normalization of CapEx working capital, and $50 million of new cash cost from LACh that was considered as part of the acquisition.

Part of this change was also driven by the additional liquidity we have after issuing the international bond, where at the same time that we were negotiating new tariffs with our service provider. We decide to use part of the cash to cancel some of the basically services and DSO that we have in hand in order to also put different condiment to the negotiation that we were having.

So basically, based on the updated plan that we present today, we are forecasting a neutral free cash flow on the second semester. This is assuming $65 Brent unrealized oil prices of $60. This will be composed of a negative free cash flow in Q3 and a positive cash flow in Q4.

We are not giving guidance of 2026 onwards, but in terms of free cash flow, you basically have to assume 2 things: one that in 2026 will continue growing; and second, that 2026 and 2026 onward in our model is a positive free cash flow outcome. I hope I have answered your question, Daniel.

Yes. Thank you, Miguel, for the detailed answer.

One moment for our next question, please. And it is from Bruno Amorim with Goldman Sachs.

So my question is related to the potential growth between now and the end of next year. So considering the maximum capacity that you have in the pipeline systems, what's the maximum production that Vista could deliver by the end of next year?

Thank you, Bruno. Thank you for the question. It's a good question. So we haven't, as I said, to Guardiola, we haven't yet communicated 2026 numbers. We are planning to hold, and I will take the advantage of your question, an Investor Day in Q4 2025 to provide long-term guidance and long-term forecast. But based on our transportation capacity, we could produce up to 144,000 barrels of oil per day. That's today. And if we include our share of Vaca Muerta Sur capacity, we can go up to 200,000 barrels of oil per day. Of course, this is mid-'27 when VMOS is -- it will be delivered. So that is the full capacity that we have in our hand to grow production.

One moment for our next question, please. It's from Leonardo Marcondes with Bank of America. He removed himself.

Next question, please, one moment. Vicente Falanga from Bradesco BBI.

Thank you, Miguel, Ale and Vista's team. We appreciate the guidance and the company's willingness to slow down operations to preserve the balance sheet. When we look towards the second half of the year, it seems like the global oil markets should be even more oversupplied. The question is, if oil prices move towards the $50 per barrel and stays there for a while, would Vista be willing to slow down growth even further and continue to prioritize the balance sheet?

Thank you, Vicente, for your question. Good question. So we have 2 drivers to protect us from lower prices. I would say the first one is our low cash cost base. Let me expand a bit on that one. If you add up the lifting cost, the expenses and the G&A, this equates roughly to $11 per barrel and increase all the way up to $20 per barrel, if you add to that $11, the royalties and the gross tax, this one will be assuming a realized price of $60 per barrel. So $20 per barrel is our cash cost base. And that protects us a lot on the low oil price environment.

The second is the flexibility in our drilling and completion contracts that not only come from the contract come from the fact that we have a very short capital cycle. And the fact also that we have 30 years concession with no pending capital commitment also add to that flexibility. So this enabled us to reduce CapEx burn rate at a very low cost. And we have proved that. I mean, we proved that during the COVID-19 pandemic. It was probably the best example of us testing all the way to the limit our agility and capacity to stop and to restart. So if we then -- were to fall consistently, we have the full flexibility to protect our balance sheet by reducing activity.

Now just to take one potential scenario, let's say that the Brent fall consistently below $55. We could probably cut new well CapEx from the plan and grow less and protect our balance sheet almost immediately. And remember also that we can do that gradually. So we don't need to wait until the oil price is $55.

And I also want to highlight that the reverse situation also applies to this. We can easily increase activity in case that we see our sale in Q4 in a very good price -- or in a better oil price scenario. We know we are going to lead volatility, and we have decided to be prepared for both scenarios, the low case scenario and also a more positive scenario that we are facing today.

One moment for our next question. And it comes from Leonardo Marcondes with Bank of America.

So my question is regarding the productivity here. What is the initial production rate, I mean, the IP-30 that you assume for La Amarga Chica, Bajada del Palo Oeste in your guidance. And I'm not sure if I heard correctly the answer for Bruno's question. Do you see any further room to improve La Amarga Chica productivity by working together with YPF there?

Leo, thank you for your question. I will get a bit technical on this one. And we have basically heard that question before from other analysts on the IP-30 of La Amarga Chica. And I would say, La Amarga Chica peak oil on average well is slightly lower than our operated block. But we don't think that it's related to the rock, or we don't think that's related to [indiscernible] other or we don't think that, that well has been operated in a fashion that is different to ours. We believe that each operator has different strategies to manage peak oil. And basically, that come from usually choke management. And we may have a slightly different strategy than the one that YPF has. But we believe that this is not a reflection of the rock.

So we have a long-term view regarding the reservoir management that focus in the EUR of the well. For us, EUR, so the ultimate recovery of the well is more relevant than the peak oil. And on this basis, our model showed that the La Amarga Chica is as good as Bajada del Palo Oeste.

In regard to the second part of your question, yes, we touched base on that on Bruno question. And the short answer is, YPF people are top-notch operators, and they are doing a good job in La Amarga Chica. What has changed, as we said, is that the fact that we have the opening between the 2 teams to review a lot of technical processes and details and technology that we use in a very open manner and in a very open fashion that, that is the spirit from both sides. And I give credit also to the management of YPF on that.

We are finding areas of opportunities for both where we -- probably you will see that from that discussion, we will apply some of those in La Amarga Chica and why not also in Bajada del Palo Oeste. So that discussions are going very well. And there are a few things that we have differences, and we will see what are the best practices to be applied. Ego aside, at the end of the day, we both are to generate value to our shareholders.

One moment for our next question, and it's from Kevin MacCurdy with Pickering Energy Partners.

The margin improvement is one of the highlights of the release, which appears structural and related to the Oldelval expansion fully online. I believe the next midstream update for Vista is the VMOS pipeline. I was wondering if you could give an update on the progress of that project and if there's any key milestones that we should be looking for.

Kevin, thank you for your question. Yes, we are seeing very good progress. The contractual start in May in all the fronts, pipeline, pumping station, storage terminal, also the offshore terminal. We expect the first stage of the project with a capacity of around 550,000 barrels of oil per day to be ready mid-'27.

Last week, in terms of financing, the team -- the full team closed a syndicated 5-year term loan of $2 billion at an interest rate of SOFR 5.5%. This is obviously a very good news in terms of securing financing of 70% of the project cost. Financing was obtained also from 5 different international banks, Citi, Deutsche, Itau, JPMorgan, I think Santander was the other one. But for me, reflect somehow investor confidence in Vaca Muerta and in the old project of Vaca Muerta as well. So I would say, good progress and very good news with this financing finally being closed. Yes, now we have to -- the whole team have to execute.

One moment for our next question, please. And is from Andres Cardona with Citi.

I just have a question about how much appetite do you have today for potential M&A? And if you can share if the process are advancing because in the media, we are seeing less headlines about the matter.

Thank you, Andres, for your question. Yes, we are always hungry for the right opportunity. So we are always looking as part of our strategic approach. And we have demonstrated that we are as good business development as operators. So I think given the increase of scale and our cash flow profile, we will actively continue assessing opportunities.

I would say the only difference is that we have set a high bar in terms of value accretion and also a strategic fit. So the short answer is yes, you will continue to see us active on all the process and sometimes on things that are not part of the processes. But you should expect that in terms of value accretion for our shareholders and in strategic fit, we continue to be as disciplined as we have been so far. Thanks Andres, for your questions.

One moment for our next question, and it comes from Tasso Vasconcellos with UBS.

The discussion we have the most with investors related to Vista capacity to start generating more solid and stable cash flow. The fact that you didn't actually increase the number of wells to be true this year, it is now 59 while before, it was between 52 to 60. Does it mean you are already seeking to reduce the growth speed and start generating more cash flow as from now? I know we already discussed this a little bit in the previous questions. You mentioned the expectation of pretty much neutral cash flow in the second half of this year, maybe an improvement afterwards. So can you please detail the breakdown of this scenario? Could you expect more modest production growth and wells drilling, but higher cash generation as from 2026?

Tasso, thank you very much for your question. First of all, I think for -- we basically -- we continue -- we want to maintain a strong balance sheet. And I mean talking about 2020 -- talking about this year, 2025, where we see it towards the end of the year, a more volatile Brent and macro scenario. So basically, we continue to give a clear signal for me what we have just said of capital discipline.

We have issued new debt following the acquisition of La Amarga Chica. We have increased our leverage ratio. The ratio is still super healthy, but we have to calibrate capital spend. So we were free cash flow neutral. So we have to calibrate that to be cash flow neutral in the second half of the year. And for that, we have to also think that next year, we need to start to reduce that ratio. So you should expect that we will have a negative free cash flow in Q3 and a positive negative cash flow in Q4 that basically will give you the cash flow neutral line towards the second half of the year.

Tasso does that answer your question?

Give me a second. We are prepared for a potential ramp-up of activity in the case that in Q4, we see a better scenario of oil prices. And for that, that is easy. Also you can put in account that in Q4, if we don't see that the scenario, also we could use something that we have done in the past, and we can drill some dug wells, for example.

So we will look at what is exactly the price scenario, and we will not be shy of modifying what we are presenting today if we have to do it because the context is more positive or more negative. And that is the way that you should look at 2025. Now 2026 onwards, with the price scenario of $70 -- $65, you should look at as cash flow positive and continue growing. That has not changed at all. We are so far a growing story, and we will continue being a growth story.

One moment for our next question. And it is from George Gasztowtt with Latin Securities.

I was wondering how much flexibility Vista has to take advantage of stronger local pricing? Specifically, is there room to sell more barrels into the local market if the premium over export parity holds?

Thanks for your question. It's a good one. So look, I mean, our strategy has been from day 1, as I said, and put in place during COVID-19 is to gradually increase our export volumes, something that when you follow a story of Vista, we have achieved. And today continue to be in the same. Also we said credit to the people that managed to pass the Bases Law. And today, they are running the Secretary of Energy, we have seen that the lot of the red tape that was basically making exportation of oil in a country that clearly was in a path to be a structural net exporter have gone away. And therefore, today is much more seamless to get export volume when we continue serving the local market.

So the scenario that you are basically constructive -- contracting is a scenario of, for me, one that we have lived, [indiscernible], where you have local prices above international oil prices that we have lived with that for a short while. So if it does happen -- first of all, the answer to your question is no. It's a simple answer.

If it does happen, what we will be doing most of the operators, we will be serving the local market with the same volume that we are seeing in the local market today. Historically, each operator has served a couple of refineries, and we continue doing so. Even though when the export parity, export prices are higher than the local prices. So if that reverse, we will continue with the same percentage -- with the same volumes, okay? Percentage are growing because we are producing more and exporting more. So the short answer is no, George.

One moment for our next question that comes from Oriana Covault with Balanz.

This is Oriana Covault with Balanz. I have a question on your free cash flow generation precisely. And how should we think in the tax burden in the upcoming quarters? Following the $215 million income tax payments that you made this quarter, are there any remaining cash payment -- tax payments in the remainder of the year? And how should we think of this as a component in your cash buildup in the medium term?

Thank you, Oriana, for the question. So going forward, I think you should think of 35% income tax. Specifically, more specific for this year, we still have pending cash outflow that are related to advanced tax payment of approximately $200 million to $300 million, and that is included in our free cash flow guidance of this year. So for your model, you should think that way.

One moment for our next question. That comes from Matías Cattaruzzi with Adcap Securities.

Miguel, can you hear me?

Yes, Matías, I can hear you.

Okay. Great. I want to ask about the recent easing in FX restrictions here in Argentina. Do you see a greater flexibility or opportunities to implement crude oil hedging program, protect cash flows amid the current or what you see at the end of the year, a more volatile market? Or will you keep with direct exposure to Brent as some investors want?

Thank you, Matías. Yes, this question of hedging come several times in the history of Vista. So our operation is, I would like to say, natural hedge against lower oil price. This hedge, I mean the way that we thinking come from 3 different drivers. One, I mentioned already is the low cash cost, I mentioned that in a previous question that is around $20 per barrel. The second is the flexibility to reduce CapEx spend because our short-cycle CapEx. So we drill a well in 14 days, 15 days, and we complete that well in another 15, 20 days. And third, the fact that we don't have, no capital or regulatory commitment pending different to the one that you have in U.S. So given these 3 drivers, we can protect our balance sheet by reducing CapEx in a lower oil price scenario.

Having said this, I think the financial hedges is not easy to implement in the light of existing capital environment of Argentina, the capital control, the previous one, and we said yet today, we don't have a path forward. And it will be quite expensive for us if we want to basically hedge our production today. So every time that we have go through that discussion, or through this whole process, or even we have engaged in an exercise of hedge, the outcome has been that it never makes sense for us to implement it.

[Operator Instructions] One moment for our next question, that is from Francisco Cascarón with DON Capital.

Miguel. My question is related to the CapEx. How are you looking at your maintenance CapEx moving forward? Now that you added the La Amarga Chica into your portfolio?

Yes. Thank you, Francisco for the question, and welcome to this call. Assuming basically a production rate that we have for -- we have guided for the second semester, let's say, 125,000 boe per day. Our calculation is that we need around 50 wells net to Vista to keep the production flat going forward. And when you take 50 wells and you made a simple math, that equates approximately to $700 million, $750 million of CapEx. So that is what you should think in if we ever come to that scenario. I have answered your question, Francisco, I guess?

Yes. Perfect.

And this ends our Q&A session for today. I will pass it back to Miguel for final remarks.

Well, gentlemen and ladies, thank you very much for joining and for supporting us and for continued covering Vista. Needless to say that we -- the full team of Vista, we are super excited about this acquisition and also -- I mean, to see on those numbers on this call, this quarter and the quarters to come, the scale that we have to take with the acquisition of La Amarga Chica. So thank you very much for the comments, the coverage, and the questions. Have a very good day.

Thank you, ladies and gentlemen, and this concludes our program for today. You may all disconnect. Have a great day, everyone.