Vista Energy, S.A.B. de C.V. ($VISTAA)

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.