Vista Energy Q2 2025 Earnings Call Transcript

Quartr
Provided by Quartr
July 11, 2025

Key Takeaways

  • Positive Sentiment: Vista completed the acquisition of a 50% stake in La Amarga Chica, boosting Q2 production by 81% year-over-year to 118,000 BOE/day and making Vista Argentina’s largest independent oil producer and exporter.
  • Positive Sentiment: Operational initiatives cut new well costs by 10% to $12.8 million per well, maintained lifting costs at $4.70/BOE, and slashed selling expenses by 41% after the Old El Valle pipeline expansion.
  • Neutral Sentiment: Q2 revenues reached $611 million (+54% YoY) with adjusted EBITDA of $545 million (+40% YoY) and net income of $235 million; free cash flow was negative $1.4 billion due to the Petronas Argentina acquisition, leaving net leverage at 1.38× pro forma.
  • Positive Sentiment: Updated 2025 guidance forecasts total production of 226,000–253,000 BOE/day, adjusted EBITDA of $1.5–1.6 billion, and $1.2 billion in CapEx, targeting neutral free cash flow in H2 and 16% more production and 70% more EBITDA versus original plan.
  • Neutral Sentiment: With a low cash cost base of ~$20/BOE, short-cycle CapEx and no pending regulatory commitments, Vista can scale activity up or down if Brent moves below $55, supported by $500 million in term loans to address upcoming maturities.
AI Generated. May Contain Errors.
Earnings Conference Call
Vista Energy Q2 2025
00:00 / 00:00

There are 2 speakers on the call.

Operator

Hello everyone and welcome to Vista Energy's second quarter 2025 earnings call. At this time, all participants are in a listen-only mode. After the speaker's presentation, there will be a question and answer session. To participate, you will need to press star 11 on your telephone. You will then hear a message advising your hand is raised. To withdraw your question, simply press star 11 again. Please note this event is being recorded. Now, it's my pleasure to turn the call over to Vista Energy's Strategic Planning and Investor Relations Officer Alejandro Cherñacov. Please proceed.

Speaker 1

Thanks. Good morning everyone. We are happy to welcome you to Vista Energy's second quarter 2025 results conference call. I am here with Miguel Galuccio, Vista Energy's Chairman and CEO, Pablo Vera Pinto, Vista Energy CFO, Juan Garoby, Vista Energy CTO, and Matías Weissel, Vista Energy COO. Before we begin, I would like to draw your attention to a 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 US Dollars and in accordance with International Financial Reporting Standards as IFRS. However, during this conference call we may discuss certain non-IFRS financial measures such as adjusted EBITDA.

Speaker 1

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

Speaker 1

Good morning everyone and welcome to this earnings call. Q2 2025 was transformational for our company as we completed the acquisition of a 50% stake in La Amarga Chica, the second largest oil production block in Vaca Muerta. This transaction has turned Vista Energy into a significantly larger company boosted by this acquisition. Q2 total production was 118,000 boe/d, an increase of 81% year over year. Oil production was 102,000 bbl/d, 79% year over year. Vista Energy 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 $4.70 per boe, 4% above year over year. Capital expenditure was $356 million, driven by the ramp up in new well activity during the quarter both in this operated block and in La Amarga Chica.

Speaker 1

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 $2.30. Free cash outflow in this quarter was $1.4 billion, mostly reflected the upfront cash payment of the Petronas Argentina acquisition. Finally, net leverage ratio at the quarter end was 1.38 times on a pro forma basis, reflecting the new debt raised 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 Este, 4 in Bajada del Palo Oeste, and 12 corresponding to our 50% working interest in La Amarga Chica. We continue to see the results of our strong focus on cost efficiency.

Speaker 1

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 new wells starting in Q3 2025. Following the inauguration of Oldelval Duplicar pipeline in March, we eliminated all trucking as of April 1. This led to a $41 million saving compared to Q4 2024, substantially improving our margins. Total production was 118,000 boe/d, 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.

Speaker 1

As of April 1, oil production was 102.2 thousand bbl/d, 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% 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 interannual basis, mainly driven by the lower international prices during Q2. 100% of all volumes sold were at export parity prices. Lifting cost during Q2 was $4.70 per boe, sequentially flat, reflecting our continued focus on cost control.

Speaker 1

Selling expenses per boe came down 41% quarter over quarter, reflecting the elimination of oil tracking as of April 1. This led to a saving of $28 million vis-à-vis Q1 and $41 million vis-à-vis Q4 2024, the quarter during which tracking 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 tracking offset lower oil prices during Q2 2025. Cash flow from operating activities was minus $9 million, reflecting income tax payment of $250 million, a $59 million increase in working capital, and payments for midstream expansions of $18 million.

Speaker 1

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 three term loans with local and international banks 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 Argentina transaction stood at 1.38 times.

Speaker 1

As in EBITDA, our updated annual guidance reflects that following the acquisition of La Amarga Chica, we have emerged as a company with larger scale and stronger cash flow generation. Total production in 2025 is forecast between 112,000 and 114,000 boe/d. Based on the planned well timings, we forecast between 125,000 and 128,000 boe/d for the second semester, which leaves us well positioned for a greater start in 2026. A SATBA is forecast between $1.5 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 results in a change in adjusted EBITDA of $80 million. During the second semester, we forecast $825 to $925 million of adjusted EBITDA or $1.65 to $1.85 billion on an annualized run rate basis.

Speaker 1

To deliver this plan, we forecast to connect 59 new wells during the year, of which 34 were connected in the first semester. Combining our operating block with our working interest and La Amarga Chica capex in, this plan is forecast at $1.2 billion for the year. These reflect our new drilling and completion cost 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.

Speaker 1

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 Energy. 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 exporter in Argentina. On the operational front, we significantly reduced selling expenses by eliminating oil trucking, which expanded adjusted EBITDA margin.

Speaker 1

Even though oil prices dropped during the quarter, we have made changes 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 and A, I would like to thank everyone at Vista Energy for their outstanding work this quarter. Operator, we can now move to Q and A.

Operator

Thank you so much. As a reminder, to ask a question, press star 11 on your telephone and wait for your name to be announced. To remove yourself, press star 11 again. Thank you, and please stand by for our first question. It comes from the line of Bruno Montanari with Morgan Stanley. Please proceed.

Speaker 1

Good morning, everyone. Thanks, Miguel, for the call and 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. 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? Also, perhaps on the rationale of investing more on that side of the fence compared to adding more wells at BPO? Thank you very much. Thank you very much. Hi Bruno, thank you very much for your question. Let me touch base first. Probably on the rock. La Amarga Chica is in the best neighborhood of Vaca Muerta.

Speaker 1

It's right next to our block, as you know, Bajada del Palo Oeste and Bandurria Sur. We have studied this area for a long time before we came to Vista Energy and now in Vista Energy. Definitely, we understand that there's 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 quarter. In Q2, it has been back to the level that it had in Q4.

Speaker 1

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 were acquiring, 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 wells for Vista Energy, and the production of large ramp up was 23% from 35,000 bbl/d in April to 43,000 bbl/d. As you probably can imagine, we have had 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. We are trying to progressively start to exchange and put some of that conclusion that we have together in actions.

Speaker 1

I would say to be fair for what we see clearly that the fact that they are operating but we are working together will create synergies and we will create various costs of better productivity. Not only large, I will say also we are compared not world cost. We are compared what we are doing in terms of performance. We are comparing what we are paying for services. We are comparing technology. We are comparing how we work with sand from one side of 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. This for sure is going to bring value for both sides. For example, before they were thinking in large to drill 3,000 or 3,200 meter wells.

Speaker 1

That is not needed as far as we have an agreement on what will happen in the border of the two blocks. There are plenty of synergies that basically will improve the performance of the two blocks. Perfect. Thank you very much.

Operator

Thank you. One moment for our next question please. It comes from the line of Alejandro Demichelis with Jefferies. Please proceed.

Speaker 1

Good morning, Vista team. Thank you very much for taking my questions. The question is Miguel, maybe you can double click on how you see these kind of well cost developments and potential further reductions going forward. Also, if you can kind of compare those well costs, say in La Amarga Chica versus what you have in BPO and BPE, please. Thank you Ale for the question. Yes, for sure. I can double click technically on what we are doing because we are putting a lot of focus on well cost today. We think there are three main verticals that drive our initiative of well cost reduction. The first vertical is technology and innovation. I will give you some example of that that I think will give you a picture of what we're doing today. The third example could be the use of wet sand in our operation.

Speaker 1

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 Smart Slide drilling which improves the drilling efficiency when we are doing the curve section, basically using a motor and then leaving the rotary stable just to drill and navigate the horizontal section. This approach can reduce manual integration and result in time saving of around 16 hours per well. Another example is what we are implementing with our frac plan 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 basically is a function of the cost and also to avoid the runaway fracs.

Speaker 1

The fracs that basically are not increasing the area of contact of the reservoir, but they are running away through micro fracture or because they find a fault or because they find a line of micro fracture 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 six 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 arrived to a moment where integration basically was not bringing the amount of value that basically will take our cost performance reduction forward.

Speaker 1

Also, when we were doing comparison in a volatile oil prices scenario with us, we didn't see that the prices of the service were dropping the way they were dropping in the U.S. We basically decide to unbundle the services of the drilling rig into individual contracts. We did few other things that it will take too long for me to explain, and we basically obtain savings to our overall cost. The saving already captured on our drilling and completion costs per well have taken the well cost from $40.2 million to $12.8 million. It's a 10% reduction. You should assume that going forward we will see more short term reductions. You should expect that we'll see also midterm and long term reductions.

Speaker 1

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. Back to Bruno question, what we saw in La Amarga Chica in terms of where we were both compounds when we start to operate. Taking all this out of consideration, we have with YPF similar costs on that block on what happened in La Amarga Chica. What happened in Bajada del Palo Oeste? Hope I answered your question. Ale? Yeah, no, that's perfect. Thank you very much.

Operator

Thank you. One moment for our next question, please. Okay, it comes from Daniel Guardiola with BTG Pactual. Please proceed.

Speaker 1

Thank you very much for the presentation. Good morning, Miguel and Alejandro. My question is on free cash flow. In the second Q, we saw a large negative FCF in part driven by the acquisition of Petronas Argentina, but also due to a deterioration in working capital. I wanted to ask Miguel if you could elaborate on the deterioration of your working capital and what we should expect going forward. 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 are you expecting to reach a more neutral level in 2026? Thank you. Thank you, Daniel, for your question.

Operator

So.

Speaker 1

If you consider the EBITDA generation and the CapEx for the quarter, just to put your question in context, EBITDA is higher by around $60 million. This particular quarter we have a low one-off, as you know, which led to the negative free cash flow that you are pointing out. The most obvious is PEPAS acquisition which required $142 million of net outflow. We also have income tax payment of $250 million, an increase of $45 million in VAT credit, which both I would say should be reverted in the coming quarter. When you compare what we do in quarter with quarter, it's for you clear to expect that part of that is going to be reversed.

Speaker 1

We also have an increase in CapEx working capital of $140 million that was related to a normalization of CapEx working capital and $50 million of new cash code 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 the different condiment to the negotiation that we were having. Basically, based on the update plan that we present today, we are forecasting a neutral free cash flow on the second semester. This is assuming $65 Brent, unrealizable prices of $60.

Speaker 1

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 onward. In terms of free cash flow, you basically have just seen two things. One, that in 2026 we continue growing. Second, that 2026 and 2026 onward in our model is a positive free cash flow outcome. Hope I have answered your question, Daniel. Yeah, thank you, Miguel for the detailed answer.

Operator

One moment for our next question, please. It is from Bruno Amorim with Goldman Sachs. Please proceed.

Speaker 1

Thank you for taking my question. Good morning everybody. My question is related to the potential growth between now and the end of next year. You know, considering the maximum capacity that you have in the pipeline systems, what's the maximum production that Vista could deliver by the end of next year? Thank you very much. Thank you, Bruno. Thank you for the question. It's a good question. We haven't, as I said to Guardiola, we haven't yet communicated 2026 numbers. We are planning to hold, and I will take advantage of your question, an Investor Day in Q4 2025 to provide long term guidance and long term forecast. Based on our transportation capacity, we could produce up to 144,000 barrels of oil per day. That's today. If we include our share of Vaca Muerta Sur capacity, we can go up to 200,000 barrels per day.

Speaker 1

Of course, this is mid-2027 when PEMOS will be delivered. That is the full capacity that we have in our hump to grow production. Thank you very much.

Operator

Thank you for our next question, please. It's from Leonardo Marcondes with Bank of America. Please proceed, please. Oh, he removed himself. Next question, please. One moment. Vicente Falanga from Bradesco BBI. Your line is open.

Speaker 1

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

Speaker 1

If you add up the lifting cost, the expense, and the G&A, this equates roughly to $11 per barrel and increases all the way up to $20 per barrel. If you add to that $11 the royalties and the gross receipts tax, this one will be assuming a realized price of $6 per barrel. $20 per barrel is our cash cost base and that protects us a lot in the low oil price environment. The second is the flexibility in our drilling and completion contracts that not only come from the contract, but come from the fact that we have a very short capital cycle and the fact also, I will add, that we have 30 years concession with no pending capital commitment also adds to that flexibility. This enables us to reduce CapEx burn rate at a very low cost and we have proved that.

Speaker 1

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. If Brent 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 Brent falls consistently below $55, we could probably cut new well CapEx from the plan and grow less and protect our balance sheet almost immediately. Remember also that we can do that gradually, so we don't need to wait until the oil price is $55. Also, I want to highlight that the reverse situation also applies to this. We can easily increase activity in case that we see ourselves in Q4 in a very good price or in a better oil price scenario.

Speaker 1

We know we are going to live 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. Great, that's very helpful. Thank you very much.

Operator

Thank you. One moment for our next question, and it comes from Leonardo Marcondes with Bank of America. Please proceed.

Speaker 1

Hi, good morning everybody. My question is regarding the productivity here. What is the initial production rate? I mean the IP30 that you assume for La Amarga Chica and Bajada del Palo Este 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? Thank you very much. Hi Leo, thank you for your question. I will get a bit technical on this one. We have basically heard that question before from other analysts on the IP30 of La Amarga Chica.

Speaker 1

I would say La Amarga Chica peak oil on average well is slightly lower than our operated block, but we don't think that is related to the rock or we don't think that is worse than 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 comes from usually choke management. We may have a slightly different strategy than the one that YPF has, but we believe that it's not a reflection of the rock. We have a long-term view regarding the reservoir management that focuses on the EOR of the well. For us, EOR, so the ultimate recovery of the well, is more relevant than the peak oil.

Speaker 1

On this basis, our model showed that La Amarga Chica is as good as Bajada del Palo Este. In regard to the second part of your question, yes, we touched base on that Bruno question, and the short answer is YPF people are top notch operators. They are doing a good job in La Amarga Chica. What has changed, as we said, is the fact that we have the opening between the two teams to review a lot of technical processes and details and technology that we use in a very open manner, in a very open fashion. That is the period from both sides. I give credit also to the management of YPF on that.

Speaker 1

We are finding areas of opportunities for both, where 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 Este? 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. That's very clear. Thank you.

Operator

Thank you. One moment for our next question and it's from Kevin MacCurdy with Pickering Energy Partners. Please proceed.

Speaker 1

Hey, good morning. 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 Vaca Muerta Sur 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. Thank you for taking my question. Hi Kevin, thank you for your question. Yeah, 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 per day, to be ready mid-2027. Last week, in terms of financing, the full team closed a syndicated 5-year term loan of $2 billion at an interest rate of SOFR 5.5%.

Speaker 1

This is obviously very good news in terms of securing financing of 70% of the project cost. Financing was obtained also from five different international banks: Citi, Deutsche, Itaú, JPMorgan. I think Santander was the other one. That for me reflects somehow investor confidence in Vaca Muerta and in the whole project of Vaca Muerta as well. I would say good progress and very good news with this financing finally being closed. Now we have to, the whole thing, have to execute. Thank you.

Operator

Thank you so much. One moment for our next question please. It's from Andres Cardona with Citi. Please proceed.

Speaker 1

Hi, good morning everyone. I just have a question about how much appetite do you have today for potential M&A and if you can share if the policies are advancing because in the media we are seeing less headlines about the matter. Thank you. Thank you Andres for your question. Yes, we are always hungry for the right opportunity. We are always looking as part of our strategic approach and we have demonstrated that we are as good at business development as operators. 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.

Speaker 1

The short answer is yes, you will continue to see us active on all the process and sometimes things that are not part of the processes. You should expect in terms of value creation for our shareholders, any strategic fit. We continue to be as disciplined as we have been so far. Thanks Adele, for a question.

Operator

One moment for our next question. It comes from Taso Basconcelos with UBS. Please proceed.

Speaker 1

Hi, thanks for taking my question here. The discussion we have the most with investors is related to Vista Energy 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 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 expectation of pretty much neutral cash flow in the second half of this year, maybe an improvement afterward. Can you please detail the breakdown for this scenario? Could you expect more modest production growth as well as drilling, but higher cash generation as from 2026? Thank you. Thank you very much for your great question.

Speaker 1

First of all, I think for.

Operator

We.

Speaker 1

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 toward the end of the year a more volatile Brent and macro scenario. Basically, we continue to give clear signal for me where we have set of capital disciplines. We have issued new debt following the acquisition. La Amarga Chica, we have increased our leverage ratio. The ratio is still super healthy, but we have to calibrate capital spend so we are free cash flow neutral. We have to calibrate that to be cash flow neutral in the second half of the year. For that, we have to also think that next year we need to start to reduce that ratios. You should expect that you will have a negative free cash flow in Q3 and a positive negative cash flow in Q4.

Speaker 1

That basically will give you a cash flow line toward the second half of the year.

Operator

Tasso, does that answer your question?

Speaker 1

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. For that, that is easy. Also, you can put in account that in Q4 if we don't see that scenario, we could use something that we have done in the past and we can drill some DUC wells, for example. We will look at what is exactly the price scenario. 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. That is the way that you should look at 2025. Now, 2026 onward, with a price scenario of $77.65, you should look at us cash flow positive and continue growing. That has not changed at all.

Speaker 1

We are so far a growing story and we will continue being a growing story. Okay, that's clear. Thank you. Appreciate it.

Operator

Thank you so much. One moment for our next question. It is from George Gasztowtt with Latin Securities. Please proceed.

Speaker 1

Good morning and thank you for taking my question. 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? Thank you for your question. It's a good one. Look, I mean our strategy has been from day one, I would put in place during COVID-19, is to gradually increase our export volumes. Something that when you follow the story of Vista, we have achieved and today continue to be the same. Also, we said credit to the people that manage to pass the base law and today they are running the Secretary of Energy.

Speaker 1

We have seen that a lot of the red tape that was basically making exportation of oil in a country that clearly was in a part to be unstructured and exporter have gone away. Therefore, today is much more seamless to get export volume when we continue serving the local market. The scenario that you are basically contracting is a scenario of, for me, one that we have lived of, Patrice Crioglio, where you have local prices above international oil prices, that we have lived with that for a short while. If that happens, first of all, the answer to your question is no. It's a simple answer. If that happened, what we'll be doing, most of the operators, we will be serving the local market with the same volume that we are seeing the local market today.

Speaker 1

Historically, each operator has served a couple of refineries and we continue doing so even though when the export parity or export prices are higher than the local prices. If that reverse, we will continue with the same potential % with the same volumes. Percentage are growing because we are producing more and exporting more. The short answer is no. Okay, thank you. That's very clear.

Operator

Thank you. One moment for our next question. That comes from Orianna Cobalt with Balance. Please proceed. Hi, thanks for taking my question. This is Diana Cobalt with Balance. I have a question on your free cash flow generation, precisely. How should we think in the tax burden in the upcoming quarters following the $250 million income tax payments that you made this quarter? Are there any remaining cash payment tax payments in the remainder of the year? How should we think of this as a component in your cash buildup in the medium term? Thanks.

Speaker 1

Thank you, Orianna, for the question. 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. That is included in our free cash flow guidance of this year. For your model, you should think that way.

Operator

Thank you.

Speaker 1

You're welcome.

Operator

Thank you so much. One moment. For our next question. That comes from Matías Weissel with Latin Securities.

Speaker 1

Hi, Miguel, can you hear me? Yes, Matías, I can hear you. Okay, great. Pleasure to meet you guys. I want to ask about the recent easings in FX restrictions here in Argentina. Do you see greater flexibility or opportunities to implement a crude oil hedging program, protect cash flows amid the current or what you see at the end of the year, a more volatile market, or will you keep with direct exposure to Brent as some investors want. Thank you, Matías. This question of hedging comes several times in the history of Vista Energy. Our operation is, we like to say, a natural hedge against lower oil price. This hedge, I mean the way that we're thinking, comes from three different drivers. One I mentioned already is the low cash cost I mentioned in a previous question that is around $20 per barrel.

Speaker 1

The second is the flexibility to reduce CapEx spend because our short cycle CapEx, so we drill a well in 14, 15 days and we complete that well in another 15, 20 days. Third, the fact that we don't have any capital or regulatory commitment pending, different to the one that you have in the U.S. Given these three drivers, we can protect our balance sheet by reducing CapEx in a lower oil price scenario. Having said this, I think the financial hedge is not easy to implement in the light of the existing capital environment of Argentina. The capital control, the previous one, and we said yes, today we don't have a path forward and it would be quite expensive for us if we want to basically hedge our production today.

Speaker 1

Every time that we have gone through that discussion or through the thought 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. Okay, great. Thank you so much. You're welcome.

Operator

Thank you. As a reminder, if you do have a question, simply press star one one to get in the queue. One moment for our next question. That is from Francisco Cascaron with Don Capital. Please proceed.

Speaker 1

Hi Miguel, thank you for taking my question. My question is related to the CapEx. How are you looking at your maintenance CapEx moving forward now that you added La Amarga Chica into your portfolio? Yes, thank you Francisco for the question and welcome to this call. Assuming basically a production rate that we have, that we have guided for this second semester, let's say 125 per day. Our calculation is that we need around 50 wells at Vista to keep the production flat going forward. When you take 50 wells and you make a simple math, that equates approximately to $700 million, $750 million of CapEx. That is what you should think if we ever come to that scenario. I have answered your question, Francisco. Yes, perfect. Thank you. You're welcome.

Operator

Thank you so much. This ends our Q and A session for today. I will pass it back to Miguel for final remarks.

Speaker 1

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

Operator

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

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