Hello, everyone, and welcome to the Vista's Second Quarter twenty twenty five Earnings Call. At this time, all participants are in a listen only mode. After the speakers' presentation, there will be a question and answer session. You will then hear a message advising your hand is raised. To withdraw your question, simply press 11 again. Please note, this event is being recorded. Now it's my pleasure to turn the call over to strategic planning and IRO, Alejandro Chernikov. Please proceed. Thanks. Good morning, everyone. We are happy to welcome you to Vista's second quarter of twenty twenty five results conference call. I am here with Miguel Gallucho, Vista's Chairman and CEO Pablo Vera Pinto, Vista's CFO Juan Garobi, Vista's CTO and Matija Huaesel, Vista's COO. Before we begin, I would like to draw your attention to our cautionary statement on slide two. Please be advised that our remarks today, including the answers to your questions, may include forward looking statements. These forward looking statements are subject to risks and uncertainties that could cause actual results to be materially different from the expectations contemplated by these remarks. Our financial figures are stated in 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 Asosiranonima Bursatile Capital Variables, organized under the laws of Mexico, registered in the Vuelta Mexicana de Valores and the New York Stock Exchange. Our tickers are VISTA in the Vuelta Mexicana de Valores and BIST 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 04/01/2025. Finally, note that as of this webcast, we have moved all definitions which were previously at the bottom of each slide to an appendix at the end of the presentation. I will now turn the call over to Miguel. Thanks, Ale. Good morning, everyone, and welcome to this earnings call. Q2 twenty twenty five 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, Q2 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 $611,000,000 54% above the same quarter of last year. Lifting cost was $4.7 per BOE, 4% above year over year. Capital expenditure was $356,000,000 driven by the ramp up in new well activity during the quarter, both in leased operated block and in La Marghachita. Adjusted EBITDA was $4.00 $5,000,000 an inter annual increase of 40%. Net income was $235,000,000 including $102,000,000 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 $1,400,000,000 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 form a 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, eight in Bajada Del Palo Este, four 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 $12,800,000 per well, representing a saving of $1,400,000 per well or 10%, which will be reflected in our cost of a new well starting in Q3 twenty twenty five. Following inauguration of Old El Val Duplicar Pipeline in March, we eliminated all tracking as of April 1. This led to a $41,000,000 saving compared to Q4 twenty twenty four, substantially improving our margins. Total production was 118,000 BOEs per day, a sequential increase of 46% and inter annual increase of 81%. This reflects the solid execution of our new well campaign as we connected 47 new wells in the last twelve 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. Cash production increased 93% on an interannual basis and 44% on a sequential basis. In Q2 twenty twenty five, total revenues were $611,000,000 50% higher year over year, driven by the strong increase in oil production, which more than offset lower oil prices. Oil export tripled year over year to 5,600,000 barrels for the quarter, boosted by the production growth and acquisition of La Marga 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 oil volumes sold were at export parity prices. Lifting cost 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 tracking as of April 1. This led to a saving of $28,000,000 vis a vis Q1 and $41,000,000 vis a vis Q4 twenty twenty four, the quarter during which tracking volumes peaked. Adjusted EBITDA during the quarter was $4.00 $5,000,000 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 four percentage points and netback remained flat as the elimination of oil tracking offset lower oil prices. During Q2 twenty twenty five, cash flow from operating activities was minus $9,000,000 reflecting income tax payment of $250,000,000 a $59,000,000 increase in working capital and payments for maintenance expansions of $80,000,000 Cash flow used in investing activities was $1,347,000,000 dollars reflecting accrued CapEx of $356,000,000 an increase of $140,000,000 in working capital and the acquisition of Petronas Argentina for $842,000,000 net. The free cash outflow during the quarter was $1,400,000,000 mostly reflecting the upfront payment of Petronas Argentina. Cash flow from financing activities was $770,000,000 reflecting the proceeds from borrowings of $1,379,000,000 dollars and partially offset by the repayment of borrowings of $514,000,000 After quarter end, we have signed three term loans with Locust and International Bank for a total of $500,000,000 to cancel all outstanding maturities in the second half of twenty twenty five and early twenty twenty six. Finally, cash at period end was $154,000,000 Net leverage ratio on a pro form a basis reflecting the Pertronas transaction stood at 1.38 times adjusted EBITDA. Our updated annual guidance reflects that following the acquisition of La Marghachica, we have emerged as a company with larger scale and stronger cash flow generation. Total production in 2025 is forecast between 226,000 BOEs per day. Based on the planned well timings, we forecast between 253,000 BOEs per day for the second semester, which leaves us well positioned for a greater start in 2026. Adjusted EBITDA is forecast between 1,500,000,000.0 and $1,600,000,000 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 $80,000,000 During the second semester, we forecast eight twenty five million to $925,000,000 of adjusted EBITDA or $1,650,000,000 to $1,850,000,000 on an annualized run rate basis. To deliver this plan, we forecast to connect 59 U. S. During the year, of which 34 were connected in the first semester, combining our operating block with our working interest in La Amarga Chica. CapEx in this plan is forecast at $1,200,000,000 for the year. This reflects our new drilling and completion costs and $60,000,000 of saving 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 and 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 on tracking, which expanded adjusted EBITDA margin even though oil prices dropped during the quarter. We have made change to our D and 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 for their outstanding work this quarter. Operator, we can now move to Q Thank you. And it comes from the line of Bruno Montanari with Morgan Stanley. Please proceed. Good morning, everyone. Thanks, Miguel, for the call and for the detail on the guidance. I have one question about La Malaga 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? Thank you very much. Bruno. Thank you very much for your question. Well, let me touch base first probably on the rock. La Maracachica is from the best neighborhood of Vaca Muerta. It's right next to our block, as you know, Baja Del Palo Eti and both Agua Feral. We have studied this area for a long time before we came to Vita and now in Vista. And definitely, we understand that there's geological continuity there. So we have the same rock quality. If you look at the average weather activity, 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 Malaga Chica came in Q1, I will say, with a lower 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 meters, so net of 12 wells for Vista. And the production of large ramp up was 23% from 35,000 barrel oil per day in April to 43,000 barrel of oil per day issued. We have, as you probably 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. 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, it clearly that the fact that we will they are operating, but we are working together, we'll create synergies, and we will create various cost of better productivity, but not only large, I will say also we are compare not the world cost. We are compare what we are doing in the performance, are compare what we are paying for services. We are comparing technology. We are compare how we work with some from one side of the other of defense. We are looking at what we do on the borders and how we can optimize wealth from one side and from the other side. This for sure is going to be in value for both sides. For example, just to give an example, before they were thinking a large to drill 3,000 or 3,200 meter wells. That is not needed as far as we have an agreement of what will happen in the border of the two block. So there are plenty of synergies that basically will improve the performance of the two blocks. Perfect. Thank you very much. Thank you. One moment for our next question, please. And it comes from the line of Alejandro DeMichelis with Jefferies. Please proceed. 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. And also, if you can kind of compare those well costs, say, in Amarga Chica versus what you have in BPO or PPE, please? Well, 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. I would say there are three main verticals that drive our initiative of well cost reduction. The first vertical is technology and innovation. And 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. We pilot 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 Smartest Light, which improve the drilling efficient when we are doing the curve section, basically using a motor and then leaving the rotor receivable just to drill and navigate the horizontal section. This approach have reduced manual integration and resulting time saving of around sixteen 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 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 a specific consumables of service, like gasoline, gasoil, 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 year 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 decide to unbundle the services of the drilling rig into individual contracts. We did few other things that it would take too long for me to explain. And we basically obtain savings to our overall cost. The saving already capture on our drilling and completion costs that are well have take the well cost from $40,200,000 to $12,800,000 So it's a 10% reduction. And you should assume that going forward, we will see more short term reductions and also, which 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. And back to Bruno question, what we saw in La Amarga Chica in terms of where we were both compound when we start to operate, so taking all these 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 Alto. Hope I answered your question, Alain. Yes, that's perfect. Thank you very much. Thank you. One moment for our next question, please. Okay. And it comes from Daniel Guardiola with BTG Pactual. Please proceed. 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 Tetramas, but also due to a deterioration of working capital. And I wanted to ask Miguel, if you could elaborate on the deterioration of your working capital and what we should expect going forward. And also considering the uncertain environment of oil prices, what is the company's mindset in terms of free cash flow generation for 2026 and onwards? Would you feel comfortable operating at negative levels or you're expecting to reach a more neutral level in 2026? Thank you. Thank you, Daniel, for your question. So if you consider the EBITDA generation on the CapEx for the quarter, just to put your question in context, EBITDA is higher by around USD 60,000,000. But 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 the Pepas acquisition, which require $142,000,000 of net outflows. We also have income tax payment of $250,000,000 an increase of $45,000,000 in VAT credit, which both, I would say, should be revert in the coming quarter because when you compare what we're doing quarter over 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 US140 million dollars That was related to a normalization CapEx working capital and $50,000,000 of new cash cost from Latch that was part of was considered as part of the acquisition. Part of this change was also driven by the additional liquidity we have after issuing the international loan, 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 a different condiment to the negotiation that we were having. So 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, 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 onward, but in term of free cash flow, you basically have just seen two things. One, that in 2026, we continue growing. And second, the 2026 and 2026 onward in our model positive is free cash flow outcome. Hope I have answered your question, Daniel. Yes. Thank you, Miguel, for the detailed answer. One moment for our next question, please. And it's from Bruno R. Morim with Goldman Sachs. Please proceed. Thank you for taking my question. Good morning, everybody. So, question is related to the potential growth between now and the end of next year. So considering the maximum capacity that you have in the pipeline systems, what's the maximum production that Vista could deliver by the end of next year? Thank you very much. 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 twenty twenty six numbers. We are planning to hold, and I would take advantage of your question, an Investor Day in Q4 twenty twenty five to provide long term guidance and long term forecast. But based on our transportation capacity, we could produce up to 144,000 barrels per day. That's today. And if we include our share of Vaca Muerta Sur capacity, we can go up to 200,000 barrels per day. Of course, this is mid-twenty seven when PEMOS is it will be delivered. So that is the full capacity that we have in our camp to grow production. Thank you very much. Thank you. I'm moving 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. Thank you, Miguel, Ale and Vista's team. We appreciate the guidance and the company's willingness to slow down operations to preserve the balance sheet. When we look towards the second half of the year, it seems like the global oil markets should be even more oversupplied. The question is, if oil prices move towards the $50 per barrel and stays there for a while, would Vista be willing to slow down growth even further and continue to prioritize the balance sheet? Thank you very much. Thank you, Vicente, for your question. Good question. So 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. If you add up the lifting cost, the steel expensive and the G and 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 rate tax, this one will be assuming a realized price of $6 per barrel. So $20 per barrel is our cash cost base. And that protect 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'll add that we have thirty years concession with no pending capital commitment also add to that flexibility. So this enable us to reduce CapEx burn rate at a very low cost. And we have proved that. I mean, we proved that during the COVID-nineteen pandemic. It was probably the best example of us testing all the way to the limited our agility and capacity to stop and to restart. So if even 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 world 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 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 prices scenario. We know we are going to leave 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. Thank you. One moment for our next question. And it comes from Leonardo Marcones with Bank of America. Please proceed. Hi, good morning everybody. So 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 Bahado de 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 raw market share productivity by working together with YPF there? Thank you very much. Hi, Leo. Thank you for your question. And it's well, I will get a bit technical on this one. And we have basically heard that question before from other analysts on the P30 of La Marghachica. We said La Marghachica 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 it's related that those are worse than others, or we don't think that that was had 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 chop management. And we may have a slightly different strategy than the one that IPF has. But we believe that it's 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 EOR, so the ultimate recovery of the well is more relevant than the Picoid. And on this basis, our model showed that the La Marca Chica is as good as Bajada Del Palo Este. In regard to the second part of your question, yes, we touched base on that on Bruno's 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 that the fact that we have the open 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 spirit from both sides. And I give credit also to the management of YPF on that. We are finding areas of opportunities for most 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. So our discussions are going very well. And there are a few things that we have differences. And we will see what are the best practice 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. Thank you. One moment for our next question. And it's from Kevin McCurdy with Pickering Energy Partners. Please proceed. Hey, good morning. The margin improvement is one of the highlights of the release, which appears structural and related to the Olduvall 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. Thank you for taking my question. Hi, Kevin. Thank you for your question. Yes, we are seeing very good progress. The contractual start in May in all the fronts by line pumping station, storage terminal, also the offshore terminal. We expect the first stage of the project with a capacity of around 550,000 barrel per day should be ready mid-twenty seven. Last week, in term of financing, the team, the full team closed a syndicate five year term loan of $2,000,000,000 at an interest rate of software 5.5. This is obviously a very good news in terms of securing financing of 70% of the project costs. Financing was obtained also from five different international banks, Citi, Deutsche, Itau, JPMorgan, I think Santander was the other one. But for me, it reflects 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. Yeah, now we have to the whole team have to execute. Thank you. Thank you so much. One moment for our next question, please. And it's from Andres Cardona with Citi. Please proceed. Hi. Good morning, everyone. I just have a question about, how much appetite do you have today for potential M and A? And if you and if you can share if the policies are advancing because in the media, we are seeing less headlines about the matter. Thank you. Thanks, Andre, 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 value in term 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 things that are not part of the processes. But you should expect that in term of value accretion for our shareholders and strategic fit, we continue to be as disciplined as we have been so far. Thanks, Andre, for your question. One moment for our next question. And it comes from Taso Vasconcelos with UBS. Please proceed. Hi. Thanks for taking my question here. The discussion we have the most with investors related to this capacity to start generating more solid and stable cash flow. The fact that you didn't actually increase the number of wells to be drilled this year, it is now 59, while before was between 52 to 60. Does it mean you're 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 afterward. So can you please detail the breakdown for this scenario? Could you expect more modest production growth and wells drilling but higher cash generation as from 2026? Thank you. Hi, Tassos. 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 in I mean, talking about 2020 talking about this year, 2025, where we see toward the end of the year a more volatile brand and macro scenario. So basically, we continue to give clear signal for me where we have just set of capital discipline. We have issued new debt following the acquisition of Lama de Gachica. We have increased our level of ratio. The ratio is still super healthy, but we have to calibrate capital spend. So we are 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 ratios. So you should expect that you 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 line toward the second half of the year. Tassos, does that answer your 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 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 onward, with the price scenario of $70.07 $65 you should look at us cash flow positive and continue growing. That has not changed at all. We are so far a growing story and we'll continue being a growth story. Okay, that's clear. Thank you. Appreciate it. Thank you so much. One moment for our next question. And it's from George Gastaut with Latin Securities. Please proceed. 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? Thanks, Jorge, for your question. So look, I mean, our strategy has been from day one with put in place during COVID-nineteen is to gradually increase our export volumes. Something that when you follow the story of it, we have achieved. And today, continue to be the same. Also, I would say credit to the people that manage to pass the base law. And today, they are running the Secretary of Energy. 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 an structural net exporter have gone away. And therefore today is much more seamless to get this per volume when we continue serving the local market. So the scenario that you are basically contracting is a scenario for me, one that we have lived, Paris Criollo, where you have local prices above international oil prices. That we have liquid 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'll 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 or export prices are higher than the local prices. So if that reverse, we will continue with the same percentage or with the same volumes, okay? Percentage are growing because we are producing more and exporting more. So the short answer is no, Jorge. Okay. Thank you. That's very clear. Thank you. One moment for our next question that comes from Oriana Colbold with Balance. Please proceed. Hi. Thanks for taking my question. This is Oriana Colbold with Balance. 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 $250,000,000 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? Thanks, 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 200,000,000 to $300,000,000 and that is included in our free cash flow guidance of this year. So for your model, you should think that way. Thank you. You're welcome. Okay. Thank you so much. One moment for our next question. That comes from Matthias Cataruzzi with ADDAPCA Securities. Hi, Miguel. Can you hear me? Yes, Matthias. I can hear you. Okay. Great. Well, pleasure to meet you guys. 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, I mean the current or what you see at the end of the year, a more volatile market Or will you keep with direct exposure to brands as some investors want? Thank you, Matias. Yes, this question of hedging come several times in the history of Vista. So our operation is, I like to say, natural hedge against lower oil price. Please sketch, mean, the way that we're thinking come 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. The second is the flexibility to reduce CapEx spend because our short cycle CapEx. So we drill a well in fourteen days, fifteen days, and we complete that well in another fifteen, twenty days. And third, the fact that we don't have no capital or regulatory commitment pending differentiate the one that you have in U. S. So given these three drivers, we can protect our balance sheet by reducing CapEx in a lower oil prices scenario. Having said this, I think the financial hedges is not easy to implement in the light of existing capital environment of Argentina, capital control, the previous one. And we said, yes, 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 the sole 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. Thank you. One moment for our next question. That is from Francisco Cascarron with DON Capital. Please proceed. 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 guide for the second semester, let's say 125,000 BOE per day, our calculation is that we need around 50 wells Necho Vista to keep the production flat going forward. And when you take 50 wells and you made a simple math, that equates approximately to $70,000,000,750,000,000 dollars of CapEx. So that is what you should think in a if we ever come to that scenario. I have answered your question, Francisco, I guess. Yes, perfect. Thank you. You're welcome. Thank you so much. And this ends our Q and A session for today. I will pass it back to Miguel for final remarks. Well, gentlemen and ladies, thank you very much for showing and for supporting us and for continue covering Vista. Neither to say that we, the full team of Vista, we are super excited about this acquisition. And also, I mean, we can to see on those numbers on this call this quarter and the quarters to come, the scale that we have take with acquisition of Amarga Chica. So thank you very much for the comments, the coverage and the questions. Have a very good day. Thank you, ladies and gentlemen, and this concludes our program for today. You may all disconnect. Have a great day everyone.