Vista Energy, S.A.B. de C.V. (NYSE:VIST) Q2 2025 Earnings Call Transcript

Vista Energy, S.A.B. de C.V. (NYSE:VIST) Q2 2025 Earnings Call Transcript July 11, 2025

Operator: 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.

Alejandro Chernacov: 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.

Miguel Matias Galuccio: 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.

Q&A Session

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

Bruno Montanari: 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.

Miguel Matias Galuccio: 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.

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

Alejandro Anibal Demichelis: 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?

Miguel Matias Galuccio: 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?

Alejandro Anibal Demichelis: Yes. That’s Perfect.

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

Daniel Guardiola: 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?

Miguel Matias Galuccio: 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.

Daniel Guardiola: Yes. Thank you, Miguel, for the detailed answer.

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

Bruno Amorim: 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?

Miguel Matias Galuccio: 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.

Operator: 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.

Vicente Falanga Neto: 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?

Miguel Matias Galuccio: 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.

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

Leonardo Marcondes: 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?

Miguel Matias Galuccio: 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.

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

Kevin Moreland MacCurdy:

Pickering Energy Partners Insights: 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.

Miguel Matias Galuccio: 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.

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

Andres Felipe Cardona Gómez: 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.

Miguel Matias Galuccio: 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.

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

Tasso Sousa Vasconcellos: 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?

Miguel Matias Galuccio: 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.

Operator: Tasso does that answer your question?

Miguel Matias Galuccio: 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.

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

George Gasztowtt: 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?

Miguel Matias Galuccio: 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.

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

Oriana Covault: 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?

Miguel Matias Galuccio: 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.

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

Matías Cattaruzzi: Miguel, can you hear me?

Miguel Matias Galuccio: Yes, Matías, I can hear you.

Matías Cattaruzzi: 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?

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

Francisco Javier Cascarón: 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?

Miguel Matias Galuccio: 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?

Francisco Javier Cascarón: Yes. Perfect.

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

Miguel Matias Galuccio: 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.

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