VIST

Be advised that today's call is being recorded. I would now like to hand it over to our first speaker, Alejandro Cherñacov. This is 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 CFO, Juan Garoby, Vista CTO, and Matías Weissel, Vista COO. Before we begin, I would like to draw your attention to our cautionary statement on slide two. Please be advised that our remarks today, including the answers to your questions, may include forward-looking statements. These forward-looking statements are subject to risks and uncertainties that could cause actual results to be materially different from the expectations contemplated by these remarks. Our financial figures are stated in USD 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% vis-à-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. CapEx 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 -$341 million, impacted by $331 million of non-recurring items, of which $206 million corresponded to the initiation of basic operation on a delivery basis. Without these non-recurring items, free cash flow in the quarter would have been almost neutral. 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 Oeste, and seven net wells in La Amarga Chica. This represent very good progress compared to our guidance of 80-90 wells for the full year.

Solid well productivity of the tying 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 134,700 BOEs per day. This represent 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 $394 million, 58% above the previous year, driven by a solid increase in oil production, which more than offset lower oil prices.

Oil export 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 interannual basis and up 2% on a sequential basis, in both cases driven by Brent. We sold 100% of oil volumes at a export parity prices, both domestically and internationally. Higher oil prices owing to war in Middle East has a minor impact in Q1 revenues, as we have 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 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 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 two 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 use 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 -$341 million during the quarter. Net of the working capital, one-off impacts, and the Equinor deposit recurring free cash flow was -$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. 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 contracted view of oil prices.

Based on the solid progress of our new well campaign, with 23 tie-in to date and robust productivity, we are increasing our full-year production guidance from 140,000-143,000 BOEs per day, more than 1 million barrels of oil equivalent for the year. Importantly, our CapEx guidance remain unchanged. We forecast to spend between $1.5 billion-$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 best case of $85 Brent in Q2 through Q4. This is $500 million more than 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 condition precedent to close the transaction. We expect closing to occur in early May, and guidance will be updated promptly after.

On a preliminary basis, after consolidating the acquired asset, 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 contracted 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 two 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.

Thank you. As a reminder, to ask a question, you will need to press star one one on your telephone and wait for a name to be announced. To withdraw your question, please press star one one again. Please stand by while we compile the Q&A roster. One moment for our first question. Our first question will come from the line of Leonardo Marcondes from Bank of America. Your line is open.

Hi, everyone. Thank you for picking my questions. 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? Thank you very much.

Hi, Leonardo. Thanks for the question. I think there's two things. One, the more important is that we feel super confident due to the results of the 23 wells that we connect in Q1. All of them have very robust productivity. We decide basically that we will up the 66, as you saw, from 140-143 barrels of oil equivalent per day. That basically add 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. Then progressively, you see increases in Q3 and in Q4. That will lead us to a total of 143,000 barrels per day average for the year.

As I mentioned in the presentation, this does not include the consolidation of Equinor assets. Thanks for the question.

Thank you.

One moment for our next question. Our next question comes from the line of Guilherme Martins from Goldman Sachs. Your line is open.

Thank you. Thank you for taking my question. 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 EBITDA we should think of? Thank you.

Thank you, Guilherme, for the question. The answer is in line what you mentioned. 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 use 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 double the production in the last year, we believe that we should delever us using that momentum that we are living and regain financial flexibility, the one that we have prior to the acquisition.

That mean for us, going back to around the 1 net debt leverage ratio, I will set 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. You also should assume that we will use the cash during this year to complete that acquisition of the buyback. That is pretty much how you should think of the year. You're correct. I mean, our priority now will be delivering.

Understood. Thank you.

You're welcome.

Our next question will come from the line of Bruno Montanari from Morgan Stanley. Your line is open.

Good afternoon, everyone. Thanks for taking my question. 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. Can you comment on what you have been able to secure now in the beginning of Q2? If there is any Commercial strategy change that could allow you to capture more spot prices without eventually fixing the prices one month ahead. Thank you very much.

Yeah. Thank you for the question. A lot of noise in the line, but I think I managed to catch the question. First, I just said that we are not changing our commercial strategy. You are going to see that we capture 100% of the higher prices starting in Q2. There is always part of those sales, as you know, of the next month, which have locked in in advance. We've been doing that for many years. The rationale is always been working capital management. As we said in the presentation, we sold essentially all the March volume before the conflict in Middle East started, and the price of such a sale was locked in previous to the event, you know.

As of today, less than a third 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. Summarizing, I mean, for that, we are exposed to full Brent volatility for the rest of the volume that we have not yet closed. Basically no change in the strategy and also not change in the practice of locking in one month ahead that we are selling.

Very clear. Thank you very much.

You're very welcome.

Thank you. Our next question will come from the line of Daniel Guardiola from BTG Pactual. Your line is open.

Hi. Good morning, Miguel and team, and thanks for the presentation. I have a question on cost inflation, especially considering the current environment of higher prices. I wanted to ask if you're seeing any early signs of service cost inflation in rigs, crackers, logistics, sand, et cetera. How should we think about the balance going forward between pricing tailwinds and potential cost pressure? To what extent you believe your efficiency gains can somehow offset this potential inflation? That would be my question.

Thanks, Daniel, for the question. A very good question. First of all, probably the best thing for me to say and to clarify that we have not have any tariff change. Okay. We will not allow any tariff change. The existing contract, as are some of them, I would say many of them, are adjust using gasoline prices. We are seeing some tariff adjustment on those cases that we could consider inflation. We are also seeing some impact on the peso component due to the flood effects. Saying all that, and as you mentioned, we have a very solid cost reduction plan in place. The projects that we are executing will allow us to offset most of those effect.

We are on track, and we are basically confirming our guidance of $11.7 million for drilling and completion cost per well, and also $4.3 that we mentioned in terms of lifting costs. 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.

Thank you, Miguel.

Very welcome.

Thank you. Our next question will come from the line of Alejandro Demichelis from Jefferies. Your line is open.

Yes. Good morning. Thank you very much for taking my question. 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 kind of, you know, continue to improve your commercial cost.

Thank you, Ale, for the question. Yes, first, the reason that why we create a trading company, the main reason, and we explained it before, is to access to new market. Basically, we generate more demand from the Medanito oil and also, we create 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 it now. We are also capturing additional margins on the 25 million barrels that Vista expect to trade during 2026. We are not a trading company.

Basic goal is not to take any trading risk. They only take position to cover the volume that we sold, and usually also, only for the following month until the oil is delivered. I mean, I think it's super important to clarify because we did BEHSA for that reason, and we should not look at BEHSA as a trading company. Of course, I mean, the two objectives that we put as in line of the creation of BEHSA, we are achieving it.

That's very clear. Thank you.

You're welcome.

Thank you. Our next question will come from the line of Enrique Kuna from JPMorgan. Your line is open.

Hi, hi. Good morning. Thanks for taking up our question here. We have a question on working capital. Could you provide more color on the impact if it had on free cash flow in the quarter? Specifically in the report, you mentioned around $200 million related to BEHSA, which was not included in our estimates here. Could you elaborate on the contract effects from BEHSA and what should we expect going forward?

Yes, Enrique, of course. I mean, happy to elaborate on that. Basically, the ramp-up of base operations generate two one-offs, as we explained. One is related to the fact that BEHSA sold most of its production on a delivery basis instead of FOB. That was what we were doing before, which is, that is what we were doing with all the trading company that we were using before the creation of BEHSA. This extended the revenue collection cycle by the transit of the ship. Just let me give you an example. An old vessel that take around 20 to go from Puerto Rosales to West Coast in U.S. Also now we are seeing more demand from the Asian buyers, will take that transit time much more time. I would say probably 40 days of transit time.

That is basically the change that we have, what we did before, what we have today. This is the first one-off. The second effect is related to BEHSA short-term we consist on buying physical oil from Vista Argentina and selling a forward contract at the same price to lock in that revenue. For example, in the month of March, with significant price volatility at whatever that reflect the realization of price of $60, but the invoice to be collected by BEHSA reflect the market price that was between $90 and $100, leading to an increase in working capital. That are the two effects that we have. One is related to the realization of the price and the short hedge that BEHSA take every time they sell.

The other one is the change of us that today we are selling on delivery basis instead of FOB that we were doing before. Hope that answer your question, Enrique.

Thank you.

Thank you. Our next question come from the line of Tasso Vasconcellos from UBS. Your line is open.

Hi, Miguel. Hi, Ale. Miguel, you already mentioned a little bit about your pricing on the discount or premium to Brent prices, Medanito and so on. 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 in determined periods? That's more for us to understand how we should think about this agreement looking forward. Thank you.

Hi, Tasso. Thank you very much for the question. First, probably prices in the domestic market continued to fully reflect a poor parity. I think that is super important to understand. There was no agreement to fix prices. What we did was to discuss an agreement to mitigate the financial impact of raising crude oil prices resulting from the conflict that we have in Middle East. That agreement was that the buyer will recognize full export parity, but paying up to $95-$100 Brent for April and May. Any positive difference between the price that they paid and the international market price will be deferred and paid no later than July 31st.

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

That's very clear. Thank you, Miguel.

Thank you. Our next question will come from the line of Andres Cardona from Citi. Your line is open.

Hi, good morning, Miguel and team. The province of Buenos Aires, the governor Kicillof is considering to do a new round of some 15 blocks, [per what I see on the million]. Could you share your thoughts about this opportunity, timing, if the assets are located in a relatively core acreage, so it is more type of frontier. Any color that you could share, it is appreciated.

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

Miguel, do these blocks have the same royalty 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. Regalía.

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

Thank you. One moment for our next question. Our next question will come from the line of Michael Furrow from Pickering Energy Partners. Your line is open.

Hello, and thanks for taking our question. 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. What do you see as a good run rate for annual net turning lines on the Bandurria Sur assets, and what could the associated CapEx look like?

Yeah, Michael, thank you for the question. As we mentioned, we now received pending approval that we have from the Chilean antitrust authorities. All conditions present basically has been met, and we are planning to close this deal early May. Regarding the CapEx, it will be around $200 million. Also assuming that the deal close early May, the consolidation will be as May 1. The asset are producing around 20,000 barrel per day at Vista working interest. I think there could be a little upside on this on the coming quarter. With that production assumption, you should assume that we will generate around $3 billion of EBITDA.

Great. Thank you.

You're welcome.

Our next question will come from the line of George Gasztowtt from Latin Securities. Your line is open.

Good afternoon, Miguel, and thank you for taking my question. Clearly it's a very volatile oil environment, but I was wondering if you could comment on the Medanito discount to Brent. Are you seeing that move a lot? How should we think about the differential in 2Q and beyond?

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

Thank you. Very clear.

Thank you, George.

Our next question will come from the line of Ignacio Sabelle from Itaú BBA. Your line is open.

Yes. Hi, everyone. Congratulations on the results, and thanks for taking my question. 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? Maybe understand what are the time frames, when are you going to submit any project? Also until when can you submit any projects? Thanks.

Yes. Thank you, Ignacio, for the question. Yes, we are currently prepare the documentation to apply for RIGI for two our future development blocks. One is Aguada Mora and the other one is Bandurria Norte. After closing the Equinor deal, we will have also better understanding of Cien Toro, which we believe also could apply to the RIGI, the application of that in particular have to be submitted by his operator at the YPF. 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 have to analyze all the information before the approval. Based on what we've seen is happening with others, 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 evaluation that the two block that we present, it creates fiscal incentives and also it move us to accelerate the CapEx of investment in those blocks that otherwise would be at the tail of our plan. Very good initiative for the government on this one. It will help to bring that block from the north a bit closer in our plan.

Awesome. Thanks. Very clear.

Thank you. Our next question will come from line of Oriana Covault from Balanz. Your line's open.

Hi. Thanks for taking the question. I have a quick one regarding the non-operated assets. Specifically, how do you see the contribution from these areas within La Amarga Chica evolving through the year? Thank you.

Thank you, Oriana Covault, for the question. Look, La Amarga Chica is performing quite well. When we acquire the block, if you remember, we were producing around 38,000 barrel oil per day. This is Vista working interest. In Q1 we produce around 48 barrel of oil per day. A 25% increase. For the rest of the year, as we said, we are expecting a flattish forecast or even on a slightly growth. Okay? Yes, happy with the acquisition, happy with the performance, happy with the relationship that we have today with YPF, the operational level. Everything is working pretty well.

Thank you.

You're welcome.

Thank you. Our next question will come from line, Matías Cattaruzzi from Adcap. Your line is open.

Hello. Good day, Miguel and management team. My question is as follows: How would the 2026 EBITDA and free cash flow guidance look at a Brent of $105 or $115 per barrel in the new guidance framework?

Thank you, Matías. I like this question. I mean, the way you got 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. Back to your numbers. I mean, we show early $95 Brent for Q2-Q4. EBITDA will be estimated around $2.9 billion in 2026. At $105, that same EBITDA will be $3.2 billion. 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 $105, $1.25 billion, and at $115, $1.5 billion of free cash flow during the year. Thank you for the question.

Thanks to you.

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

Guys, thank you very much for the participation, for the good question. Very positive about what is coming up. We are starting the year from the operational point of view and the production point of view in good grounds. Very confident for Q3, Q4, and Q4. It 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.