Thank you for standing by. My name is Danica, and I will be your conference operator today. At this time, I would like to welcome everyone to the YPF First Quarter 2025 earnings webcast presentation. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question-and-answer session. If you would like to ask a question during this time, simply press star followed by the number one on your telephone keypad. If you would like to withdraw your question, press star one again. Thank you. I would now like to turn the call over to Margarita Chun, YPF's Investor Relations Manager. Please go ahead. Good morning, ladies and gentlemen. This is Margarita Chun, YPF IR Manager. Thank you for joining us today in our First Quarter 2025 earnings call. Today's presentation will be conducted by our Chairman and CEO, Mr. Horacio Marín, and our CFO, Mr. Federico Barroetaveña. During the presentation, we will go through the main aspects and events that explain the quarter results, and then we will open the floor for Q&A session together with our management. Before we begin, please consider our cautionary statement on slide two. Our remarks today and answers to our questions may include forward-looking statements, which are subject to risk and uncertainties that could cause actual results to be materially different from the expectations contemplated by these remarks. Our financial figures are stated in accordance with IFRS, but during the presentation, we might discuss some non-IFRS measures, such as adjusted EBITDA. Finally, according to the relevant fact released last December, as from 2025, the new business structure of YPF is in place. The main changes are as follows. First, we split gas and power segments into two segments: LNG and integrated gas, and new energies. Second, we renamed the downstream segment as midstream and downstream, and third, we relocated our midstream gas business that used to be in the gas and power segment to the midstream and downstream segment. You can find further details on the backup slide of this presentation. I will now turn the call over to Horacio. Please go ahead. Thank you, Margarita, and good morning, everyone. Let me begin today's presentation with the main highlights of the quarter. First, we recorded a strong level of adjusted EBITDA of $1.24 billion, marking a significant sequential growth of 48%. This increase reflects the initial benefit and increasing profitability resulting from the initial disbursement in mature fields, in accordance with the first two pillars of the 4x4 Plan. In addition, we report improved refining and marketing margins, where our strategic efforts have played a crucial role in this performance to align our price to international parities and enhance our operational efficiency metrics. Let me also highlight that without the negative contribution of our mature fields, our proxy adjusted EBITDA during this quarter would have been roughly $1.35 billion. Interannually, adjusted EBITDA remained stable, as the robust growth in our shale operation and higher local field prices of Q1 this year was offset by the extraordinary low OpEx in Q1 last year after the discrete devaluation of December 2023, but partially softened by lower value on inventory due to this devaluation. In terms of shale oil, we produced 31% more than Q1 last year, now representing 55% of our total oil production. This outstanding growth was boosted by record drilling performance achieved, especially in March. First, we record the fastest unconventional drilling speed of 551 m per day in our Chañar block for an oil well with 2,573 m of lateral length in 10 days. Second, in the same month, we drilled the deepest unconventional oil well of 7,828 m with a useful lateral length of 4,501 m in the La Amarga Chica block at a speed of 353 m per day. In both cases, our real-time intelligence center contributed to efficiently design the roadmap and casing processes and mitigate vibrations. In downstream business, in Q1, we reached a record-high refining utilization of 94%, even with a higher technical capacity of 338,000 barrels per day. Moreover, at the beginning of this month, we inaugurated our first real-time intelligence center for the downstream segment in the La Plata refinery. This center is designated to facilitate data-driven decision-making in real time, with a focus on profitability and maximizing the output value for every barrel of oil processed, while optimizing resource utilization. We plan to replicate this center in the other two refineries of YPF, as well as in logistics and commercialization throughout this year and into 2026. Additionally, by the end of April, we signed an MoU with Globant to accelerate our digital transformation, implementing artificial intelligence that learns and evolves, incrementally making complex decisions by using algorithms that are supervised by our experts, so that we can optimize efficiency across the whole supply chain. Regarding our LNG projects, last week, Southern Energy, also known as SESA, obtained FID approval for the 20-year Bareboat Charter Agreement for 2.45 MTPA floating LNG, Hilli, which is expected to be operational in 2027. With respect to Hilli, a few weeks ago, the SPV already obtained a three-year export permit from the Secretary of Energy for a maximum daily volume of 10.4 million cu m per day, as from July the 4th of 2027. Moreover, the Rio Negro Province approved the environmental impact assessment. Additionally, a few days ago, the Secretary of Energy approved the RIGI for a total capacity range between 1.5 and 2.2 million tons per year of LNG, depending on the availability of gas. In addition, SESA also signed a 20-year Bareboat Charter Agreement for 3.5 million tons per year Floating LNG MKII, subject to FID approval, which is estimated to be no later than July 31st. If approved, it is expected to be operational in 2028. This second vessel allows the construction of a 100% dedicated gas pipeline from Vaca Muerta to the San Matías Gulf in the province of Rio Negro, available during the whole year instead of using existing pipeline idle capacity during the off-peak season. To supply natural gas for the Floating LNG Hilli and MKII, SESA signed a 20-year gas supply agreement with main gas producer of Argentina, including YPF, through its subsidiary, Sur Inversiones Energéticas. Our equity stake in SESA is 25%, while our commitment of gas production is 27.5%. On the other hand, in mid-April, we signed an MoU with Eni, the strategic partner for the Argentine LNG 3, to analyze the development of upstream transportation and gas liquefaction facility through two floating LNG using 6 MTPA each for a total of 12 million tons per year. Considering all this advance and the project development agreement signed last December, we show our strategic partner for the Argentine LNG 2, with a capacity of 10 million tons per year, it allows us to reach almost 30 million tons per year of the Argentine LNG project, which was defined when YPF launched its 4x5 Plan in March last year. Moving to our quarterly results, we reported revenues of $4.61 billion in Q1, reflecting a 3% sequentially decline, mainly explained by lower seasonal local demand of diesel oil and fertilizers, and reduced oil export volume as we increased the vertical integration with our La Plata refinery. This effect was partially offset by higher local fuel prices and peak seasonal demand of natural gas from power plants. Interannually, revenues grew by 7%, mainly boosted by shale activity, including increased oil exports. Improvement in tariffs from Metrogas and a slightly higher local fuel price and our agro business sale also played a role in enhancing our Q revenues. Nevertheless, revenues were partially offset by discontinuation of shale fuel sales from our Chile subsidiary. Q1 adjusted EBITDA amount of $1.24 billion, increasing by 48% sequentially, primarily driven by increased prices of fuels and other refined products, driven by higher Brent as well as OpEx savings related to the partial sale of mature fields, in addition to higher value inventories and processing level in our refineries to accumulate stock of our incoming program maintenance. On the other hand, EBITDA was negatively impacted by slightly higher costs of oil purchases to third parties. Interannually, adjusted EBITDA remained flat as the strong shale production was counterbalanced by the exceptional low OpEx record last year as a result of the December 2023 devaluation. This last effect was partially offset by lower value of inventories due to the same devaluation. Also, Q1 last year was affected by lower availability of crude oil and adverse weather conditions that affect La Plata refinery, while Q1 this year recorded strong processing level to accumulate stock before the next maintenance stoppage, as mentioned before. Let me remark once more that without mature fields, our proxy adjusted EBITDA would have been $1.35 billion. In the incoming quarters, we expected to continue reducing this impact and deliver even stronger EBITDA to achieve guidance of the year with range from $5.2 billion-$5.5 billion, considering an annual average Brent of $72.5 per barrel. Q1 net result was a loss of $10 million compared to a loss of $284 million in Q4 last year, mainly explained by higher adjusted EBITDA and lower one-off costs related to mature fields, partially offset by income tax charges from subsidies and higher negative financial results driven by lower gains for the holding of financial instruments and higher net interest expenses. On the other hand, Q4 last year accrued positive income tax driven by lower future tax payables. Interannually, net result declined significantly compared to a gain of $657 million, primarily explained by one-off costs related to mature fields in Q1 this year, in addition to higher depreciation and amortization due to increased unconventional activities, while during Q1 last year, we accrued positive income tax driven by lower future tax payables. As highlighted earlier, mature fields also impacted our net results. Without mature fields, our proxy net result would have been a gain of $428 million. In terms of investment, in Q1, we deployed $1.21 billion, and 75% was allocated to unconventional assets. Also, this level of CapEx is fully in line with our guidance for the year, ranging from between $5 billion and $5.2 billion. Sequentially, Q1 CapEx declined by 8%, mainly because during Q4, we recorded higher CapEx in downstream related to revamping works and seasonality, partially offset by higher sale activities. Interannually, CapEx increased 4%, mainly boosted by shale operations. On the financial side, we reported a negative free cash flow of $957 million in Q1. Although adjusted EBITDA was similar to the deployment of our CapEx, Q1 was mainly affected by $336 million of negative impact from mature fields' net of proceeds. Moreover, Q1 free cash flow was impacted by $211 million of net disbursement, mainly for the acquisition of Sierra Chata at 54.45% of stake, that is a shale gas block in Vaca Muerta. As a result, our net debt rose to $8.3 billion, reaching a net leverage ratio of 1.8 times. We expected to reach, after disbursing our mature fields, returning to 1.5 and 1.6 times level by year-end, considering an annual average Brent of $72.5 per barrel. Focusing on the upstream segment, Q1 total hydrocarbon production increased by approximately 5%, both on a sequential and interannual basis, reaching 552,000 barrels of oil equivalent per day, primarily boosted by shale contribution, which now accounts for an outstanding level of 58% of the total output. On the other hand, mature field output reduced by 11% versus the previous quarter, mainly due to the effect of already divested block, recording 97,000 barrels of oil equivalent per day and represented 18% of the total. Crude oil production amounted to 270,000 barrels per day in Q1, recording an interannual increase of 6%, mainly driven by shale expansion, which effectively offset reduction in conventional oil, especially mature fields. Notably, shale oil production grew an impressive 31% year- over- year, underscoring our strategy focus in our Pillar One and in line with our 2025 annual target of over 165,000 barrels per day. As a result of the production ramp-up, our oil export, mainly to Chile, grew by 34% interannually, reaching 36,000 barrels per day and representing 13% of our oil production. Sequentially, oil export reduced by 11%, underscoring our vertical integration with our refineries. Beyond crude oil, natural gas production in Q1 increased by 9% sequentially, delivering more than 37 million cu m per day, mainly due to higher seasonal demand from power plants. NGL's production amounted to 47,000 barrels per day, returning to normal levels thanks to the reactivation of Mega's facilities after maintenance. In Q1, total lifting costs reached $15.3 per barrel of oil equivalent, a sequential 12% reduction, mostly driven by the completion of disbursement of certain mature fields. If we exclude this mature field, our proxy lifting cost of Q1 would have been below $9 per barrel of oil equivalent. Considering that we continue reducing our exposure to mature fields, our best estimate for 2025 average lifting costs would be $12 per barrel of oil equivalent. Zooming in our core shale blocks, lifting costs was $4.6 per barrel of oil equivalent on a gross basis. Regarding prices in the upstream segment, crude oil prices recovered 3% sequentially, averaging almost $68 per barrel. Despite Brent volatility during the quarter, local pricing environment was more gradual. On the natural gas side, price stood at a similar level of $3 per million BTU, mostly derived from the off-peak season price of plant gas. Now, walking through the performance of our shale activities, we continue focusing on operational efficiency in our oil blocks, in line with the production target set for the year. In that sense, we accelerated the activity by drilling 51 horizontal wells on the gross basis, most of them in operating blocks, delivering a 16% increase compared to the same period last year. Our net working interest percentage also grew to 65%. This performance is in line with our estimated number of wells to be drilled during the year 2025, which amounts to 190 operating and 15 not operating shale oil wells on a gross basis, where net working interest should be around 55%. In terms of completion and tying of wells, we also accelerated activities in our operating blocks, completing 53 and tying in 47 horizontal wells on a gross basis, recording an increase of 83% and 21%, respectively, when comparing to Q1 last year. Once again, we successfully set a new record high shale oil production, delivering 147,000 barrels per day in Q1, which is more than 50% growth compared to 2023 annual average production. This production level indicates a positive start for the year to reach the 2025 target of 165,000 barrels per day. 76% of the total shale output came from our core hub oil blocks: Loma Campana, La Amarga Chica, Bandurria Sur, and Aguada del Chañar. Moreover, it's important to highlight that sequential growth was driven by the contribution from La Angostura Sur 1, a block located in the south half of Vaca Muerta, which has shown outstanding productivity. In terms of efficiency, with our unconventional operation on the drilling side, we reached an average speed of 304 meters per day in our core hub blocks. Despite beginning the year with the drilling speed at a level below our expectation in certain wells in Aguada del Chañar block, in March, we recovered successfully drilling the faster unconventional well in the same block as mentioned before. Expecting further improvements, we are confident of achieving the annual target of 360 m per day. On the fracking side, we recorded 235 stages per set per month in our unconventional operation, a strong performance in line with the target of the year of 260 stages per set per month. Moving on to our downstream segment, during Q1, we continued adjusting local fuel prices to fully converge with international parities while preserving our leading market share. As a result, local fuel prices, measured in dollars, were up 2% versus the previous quarter and 1% up versus the same period last year, while the gap with import parities stood in positive territory at 1% in Q1 compared to 3% in Q4 and - 7% in Q1 last year. Moreover, let me mention that, driven by the international price downward trend, we reduced local fuel prices by an average of 4% as from this month. Regarding fuel sales volume, it decreased by 5% sequentially to 3.4 million cu m, but below the contraction of the competition. The main decrease came from diesel, which was affected by lower seasonal demand. Let me mention that since the second fortnight of April, diesel demand started to grow again. Also, it's worth noting that despite price normalization, our market share remained at a historical level of 56% in Q1, while growing our refinery and marketing margins by 28% sequentially to $14.3 per barrel, boosted by our OpEx efficiency measures. In terms of efficiency, we continue moving forward with our plan to improve our downstream margins and become a world-class refining player. In that sense, during Q1, we implemented more than 100 initiatives that allow us to capture efficiency for more than $70 million, such as energy consumption, steam and gas recovery optimization, as well as service contract rearrangement and shutdown maintenance cost reduction. Lastly, regarding refining utilization, we processed 318,000 barrels per day in Q1, expanding 5% sequentially and recording a strong refinery utilization rate of 94%, boosted by the better performance of La Plata Refinery during Q1, which was affected by the maintenance shutdown in Q4. Also, let me clarify once more that the higher processing level enables us to accumulate inventory or refine products before the incoming maintenance stoppage. Interannually, processing level increased by 6%. Now, let me share the progress so far in terms of the midstream oil expansions. Regarding the existing oil pipeline expansion and the Duplicar Plus project, it was successfully completed in early April, increasing its transportation capacity from 330,000 barrels per day by the end of December to 540,000 barrels per day today. Let me highlight that the original capacity Oldelval before the execution of this project was roughly 225,000 barrels per day. Therefore, Oldelval more than doubled its capacity in close to two years, contributing significantly to the evacuation of the shale oil from Vaca Muerta. YPF's shipping stake in Oldelval is roughly 25%. YPF will use this expansion to transport our shale oil to our La Plata refinery, optimizing our vertical integration. Regarding the VMOS Vaca Muerta Oil Sur, the new 100% oil export dedicated pipeline that started construction in the beginning of this year, the SPV was already started receiving the pipes and started the construction work in the pipeline routes and the trench excavation. Moreover, it received initial steel plates for initial tank assembly at the export terminal, where we are now working on ground movements and civil works. The operational progress of this project is roughly 4.5% by the end of March. Now, I will turn the call over to Federico. Thank you, Horacio. Switching to the financials, let us start with the cash flow evolution. In Q1, we posted a negative free cash flow of $957 million. Although adjusted EBITDA was consistent with the deployment of our CapEx, the quarter was significantly impacted by the performance of the mature fields. Specifically, these fields resulted in an adjusted EBITDA loss of $106 million and a one-off cash flow loss of $230 million net of proceeds. Additionally, we disbursed a net amount of $211 million in M&A activity, primarily for the acquisition of Sierra Chata, and provided contributions and prepayments to our affiliates for $102 million, mostly to VMOS and Oldelval. Considering also the negative working capital, mainly due to lower sales accrual in addition to the regular debt service, we added approximately $1 billion of new net debt, including the reduction of our cash and equivalent position by 18%. In terms of financing, as mentioned during the last call, in January, we issued a nine-year unsecured international bond for $1.1 billion at a yield of 8.5. The proceeds were mainly directed to refinance $757 million of the 2025 notes maturing in July and acquire 54% of the Sierra Chata block. Regarding the 2025 notes, we executed a cash tender offer, prepaying $315 million in January, and exercised the make-whole call option for the remaining balance in February to complete the refinancing. In addition, we have also been active in the local bond market. We issued two Dollar MEP local bonds in February, one for $140 million with a two-year tenor at 6.25% and $60 million bill with a six-month tenor and 3.5%. After the quarter, we also issued a $204 million linked bond in April and, more recently, in May, another $140 million hard dollar bond, the first one with a 15-month tenor at 3.95% and the second one with a two-year tenor at 7%. For the remaining nine months of 2025, the company faces around $800 million, consisting of 71% of local maturity and only 29% international. Also, as mentioned in the last call, as a consequence of the recent sovereign rating upgrade, lower country risk and a better outlook during Q1, two global rating agencies raised YPF trade ratings. Moody's upgraded from Caa3 to Caa1 with a stable outlook, while S&P upgraded from CCC to B-. On the liquidity front, in line with the free cash flow and debt issuance, our cash and short-term investment decreased by 18% versus previous quarter to $1.2 billion, while our net debt increased amounting to $8.3 billion. Consequently, our net leverage ratio also increased from 1.6x to 1.8x, as anticipated during our investor day last month. Once we fully divest mature fields, we estimate to end the year with a net leverage ratio of 1.5x or 1.6x, considering an annual average Brent of $72.5 per barrel. So, with this, we conclude our presentation and open the floor for questions. Thank you. At this time, I'd like to remind everyone, in order to ask a question, press star, then the number one on your telephone keypad. Your first question comes from the line of Daniel Guardiola with BTG. Your line is now open. Hi, good morning. Actually, it's Daniel Guardiola. But thank you, Horacio and Federico, for the presentation. Before we dive in, I just want to take a moment and wish you, Horacio, a very happy birthday. Congrats. And I hope the market gets the chance to give you a decent present today. Looking at the questions, my first question is on how resilient the company is amid the current uncertain and bearish environment of prices. I wanted to know, Horacio and Federico, if you could please share with us what is the current Brent break-even level in terms of EBITDA and cash flow that the company currently has? My second question will be also in the same line, but just to better understand, what is the required CapEx that you need to keep your current production stable, especially considering that right now the bulk of your production is shale oil and shale gas and the declining rates are very steep? Those are my two questions. Thank you. Okay. Thank you very much. Because you tell me happy birthday, I answer the second question, okay? Not, I would say no, okay? Okay. For the first question, if you see the, I think this is slide 37, if my memory is not bad, because now I am old man of 62 years old. Remember for all the market, I'm two years more than Federico. So Federico is 60, okay? If you go to that slide, you can see that every $10 of reduction as an average in all the year, all the year for the sensitivity is in order of $900 million, okay? That is the answer. If I take Brent of 60, our EBITDA would be 4.4. That is everything I explained that in New York. That is the, I think it's the first. The second one is in the order of $2 billion, okay? To maintain our production. But we are going to grow, okay? Thank you, Horacio. Okay. All right. Our next question comes from Alejandro Demichelis. Please go ahead. Yes. Good morning. Alejandro Demichelis here from Jefferies. Horacio, Federico, one question, please, as a bit of a follow-up. So in the current oil price scenario that we are seeing, when you were in New York, you talked about some flexibility on your plan. What is your latest thinking in terms of how you're seeing CapEx, activity levels, and also the risk that some of these disposals that you have been doing may not complete because some of your buyers may actually have some trouble financing those? Okay. First, I would like to say that if we have to change our program, we will change, okay? But never, never I will take a decision in panic, okay? And also, there is a lot of volatility, sorry, in the price. Go up, go down, go up, go down. And if there is one news that is positive, you can get back, okay? So we wait. If we need to stop, we will stop. But it's not the moment today, okay, to do that. And another thing is that we have the CapEx to do when the price is down. It's a very good news for you, for investors, because I can reduce the price of the unit cost because service company when it goes down, they go down the price and I can reduce the investment. And when they go back, we make much more money. But we will wait. I think now it's not, for me, the market is not stabilized to say that that is the new number, the new price, that it will be steady, okay? Okay. Okay. Thank you. All right. Our next question comes from Leonardo Marcondes with Bank of America. Please go ahead. Hi, everyone. Horacio, Federico, Margarita. Thanks for picking my questions here. I have two. My first one is related to the divestment of the mature assets. In this quarter, we saw an impact of around $230 million on the cash flow related to the mature assets, right? So I was wondering if you could provide more color on this impact and also if we could expect a further impact related to the divestments of the assets that are yet to be divested, right? My second question is regarding the LNG projects. I mean, could you walk us through the necessary steps for the final investment decision for the LNG projects that are more advanced? And by more advanced, I mean the Southern Energy JV, right? Because there's still another vessel to be brought, if I'm not mistaken. And also the project with Shell because you already have the off-takers and so on, right? What are the necessary steps for the FID of this project? Thank you very much. Okay. The first question, what I can tell you that in the we are very proud of what we did in the mature fields. Today, with the lower price, you have to be proud of us also because we made YPF to be very good at low price, okay? Regarding the mature fields, yesterday was a decree of the province of Santa Cruz. We think that in a couple of months, we are finishing all going out from Santa Cruz. The same is in we are working hard for Tierra del Fuego, what is a small one. The others that we have are we are in the last, last, last stage. I think we are going to be out during this year. I would say Q3 is our purpose because of all the delay that you need for signing all the documents and following all the law for the different provinces. Regarding if you have to spend more on this basement, we think that it could be some in materials, but not a lot. We have almost all done, okay? There will be compared with all the process; it's marginal what we spend on that, okay? The second question, you asked about the LNG project. For the SESA, what is the first I call Argentina 1 LNG, that is the one that we made with SESA, with the one that we signed the FID for the first ship May the 1st. For the second, we have to sign the FID before the end of July. The second, what is Argentina LNG 2, what is with Shell. I don't know if you remember, but we are in the process today for bidding the fifth. And after FID could be, I would say, end of next year or so. I cannot exactly tell you when because it depends. We are going to receive the bidding process in a few days for the fifth, and after we can have a better date. And with the Argentine 3, what is with Eni, the purpose that we have both companies is to sign FID by the end of the year. That is our goal. But things can change while you are working and see what is happening in the world, okay? That's very clear. Thank you very much for the answers. Thank you for the question. All right. Our next question comes from George Gasztowtt with Latin Securities. Please go ahead. Hi, good morning, and thank you for taking my question. Following the gasoline price cut in May, what is your fuel pricing strategy for the rest of the year? As a most competitively priced provider, do you expect to capture additional market share? And did this drive a quarterly improvement in market share? Okay. The price strategy that we have is saying that any company can have around the world in a free market. It's as simple as that. So what I saw, I was in the United States last week it was on Sunday and Monday for some meetings, and I saw the price of gasoline goes up. So that is our strategy. It's no different than that. So I cannot answer more than that, okay? It's import price, price of oil, taxes, price of biofuel that we have to buy, and the exchange rate of Argentina. Thank you. Okay. All right. Our next question comes from Andres Cardona with Citigroup. Please go ahead. Hi, good morning, everyone. I have two questions. The first one is about the update you provided about Vaca Muerta Sur. I noticed you are moving forward the 550,000 barrels that originally was scheduled for the third quarter 2027 to the first half of the year. But the slide you are showing us today, there is no mention to the 180,000 barrels addition by the fourth quarter 2026. Are you still targeting that first stage by the end of the next year? And the second one is media is reporting that the Southern Energy is negotiating already the gas pipeline with an international company. Do you know the size of the pipeline investment and the technical characteristics? And why not to go with an open process? Thank you. Okay. The COD of VMOS is affected and is in line with what we say, but the first is 4Q between end of Q3 or 4Q 2026. That is for 180, and for 550 is in the first, I would say, end of. I can say end of quarter two of 2027. As I would say at the beginning, there is no delay. There is no delay. We are working very hard on that. For sure, we are going to put a lot of effort to reduce if we can, okay? You are talking about the CapEx in the gas pipeline. Okay. You are right. We are talking with an international company. Why not do an optional open process? Because if we can have a company that is a good price for all the partners, that is a tariff, it's a good deal for the project. And we ask for a tariff that works for everybody. And we think that if that happens, it will be an excellent news for all our companies, all the partners. So that there is a period on that. And if that finishes and we don't agree with the tariff, we are making an optional open process, as you say. Exactly as you say, okay? Thank you. Our next question comes from Guilherme Martins with Goldman Sachs. Please go ahead. Hey, everyone. Thanks for having my questions. I have three quick ones. The first one is a follow-up on the divestment of natural fuels. I understand roughly 11 blocks were already fully divested, right? I would like to get a sense on terms of production contribution from those blocks. And my second question is still on the divestment of natural fuels. Correct me if I'm wrong, but you mentioned you are expecting to bring leverage down as you divest from those legacy fuels. I would like to understand if this reduction in leverage is more on the back of you exiting maybe the negative assets or if you're expecting some relevant cash inflow from the divestments, and my third and final question is on CapEx. I understand you mentioned you feel too early to reassess your investment program for the year, but I would like to understand better for how long would Brent prices have to stay at the 60s in order for you to revise your drilling and CapEx activity? Thanks so much for the space. The final mature field, the production contribution for those blocks, we can, as we mentioned and you show in all our calls, we are changing from with improving production from Vaca Muerta. So there is no for us, it's not a problem. And also, I don't care a lot about production because that was almost nothing. Negative in some cases. Negative in some cases. So it's better for the investors, okay? So we are not worried about that. And also, Argentina is a free market today, so I can get the oil either way at the same price. It's not a problem. So I can make much more money if I buy. And also, you don't ask that question, but we have an excellent result in the downstream, so no problem at all. Regarding the leveraging. Well, the question from Guilherme on this is basically how we are going to be slowing down on the debt after the peak that we announced in New York because of the divestment of the mature fields. We predict that to be happening end of this second Q or during the third Q. So once we finish with that, Guilherme, what is going to happen is we are going to be taking out all the negative EBITDAs from the mature fields that are affecting our overall EBITDA. So once we finish, we are going to start seeing the YPF, and that is going to be mostly unconventional, and that will have a higher EBITDA. And you will start to see that most likely third Q and fourth Q of this year. With that, we are going to be, let's say, switching or reducing the leverage by the end of the year. We are also, let's say, as anticipated in New York, considering other divestments that may happen towards the end of the year or beginning of next year. Let's say we don't know exactly, let's say, the timing, but we have some considerations there. And with the CapEx, really, with 60, I explained that we are in lower price to be our breaking price for developing Vaca Muerta. So at 60 in Vaca Muerta, we make money, and we make good money. For sure, it's lower money than 70. It's lower money than 80 or 100. But after the time pass, you need always less capital because you are making money with that number. So we will see, and I tell before, if I have to change, I will change. But today, I don't see that it's necessary. Clear. Thanks so much. Okay. Our next question comes from Tasso Vasconcellos with UBS. Please go ahead. Hi, Horacio, Federico. Thanks for taking my questions here. I have actually one follow-up on the CapEx and one on the LNG project. Starting with the CapEx, you have released the $5 billion guidance for 2025. During the first Q right now, you just separated the $100 million disbursement to affiliates. Could you please clarify these disbursements on these affiliates and overall infrastructure projects such as Vaca Muerta, Bandurria Sur, Southern Energy, and so on? Are these already included in the $5 billion CapEx for the full year? What's the total expected breakdown here for the full year? How much you're aiming to disburse on these affiliates in 2025? The second question or follow-up on the LNG project, you have been commenting that the project is more resilient given this profile from the contracts and so on. Given that you're still negotiating these contracts, have you already noticed some pushback from potential clients regarding the pricing for these contracts? In this context, do you believe that potential Brent lower for longer, all the tensions and uncertainties from the U.S. government, could this lead you to reassess the CapEx and the size of this project to an extent? Those are my two questions or follow-ups. Thank you. Sorry. Thank you for the question. Regarding the CapEx, the $100 million, remember that we are growing. Argentina, I was a country that was producing for four or five different places and now produce for only one. That was a big bottleneck for growth production. Not for YPF, for all the companies, right? So that money is for infrastructure to grow because if not, we cannot grow. That's why we have 100. And it's all included because it's our business. Yeah. I think that, Tasso, maybe I don't know if we understood correctly your question, but the $5 billion doesn't include the contributions to affiliates. Mostly, what you see in this quarter is the finishing of all the oil and the initial construction of VMOS. So if that's your question, let's say, please let us know. Tasso? Okay. Yeah, that was the question. It's always included on the guidance or not. And the second one on the LNG project. The LNG project, remember that we have very. I would say that I'm very proud of the partner that we have, and it's all project finance. And the world needs gas, needs LNG, and they need a lot of LNG. And there is no way that the world can supply the gas without the United States. And we are in a better way than the United States. So I'm very quiet, and I know that we can deliver the LNG in Argentina, and we can be very profitable. And if they make money, we will make money. So there is no real worry about that. And also, for the quality of the company that we have, it's a good direction. You cannot see a crazy company that goes along. In all the projects, we are in the order of 25%. So there is 75% of good partners that they think that are very good business. And Vaca Muerta is huge, the reserve that they have. And I feel that I need, as a CEO and president of YPF, to develop the LNG for all the shareholders. Because if not, I'm not doing a good job. That's clear. Thank you, Horacio. Thank you, Federico. Our next question comes from Anne Milne with Bank of America. Please go ahead. Good morning. Good afternoon. Thank you very much for the call, Horacio, Federico, and Margarita. My first question is for Federico. I know you went over the balance of your debt maturities for 2025, but you have a fairly large amount in 2026. I do see that it's mostly in the local market. So my question is, do you plan to refinance most of that in the local market? And how is the local market these days? I've heard a few mixed comments that might not be quite as liquid as it was at one point. And then the second question I have is on exports. I know your exports decreased this quarter. You mentioned it was because of greater vertical integration. Could you give us an idea of when you expect your exports to increase in a more meaningful fashion? Thank you. Hey, Anne. How are you? On the first question, yes. For 2026, let's say most of what we have, it's going to be roughly speaking, we have 1.5, let's say, of refinancing in the local market and only less than 400 in the international bond market. So based on this and the current situation, we maintain, let's say, all our eyes open for the different alternatives that we have. The local market continues to be quite open for YPF. We just priced a new issue. I think that it was Monday or Tuesday. We priced $140 million for two years at 7%. So this was a bigger amount of what we were looking at, the lower interest rate of what we originally anticipated. So YPF continues to be one of the key names into the local markets. And let's say the market has been reacting very well for all our debt issues in the different alternatives that we offer from time to time. So broadly speaking, I will maintain my eyes open on what is the best alternative to refinance these maturities in 2026. As you know, international bond market, let's say, from time to time, it's reopened for Argentina since last year. And from time to time, give us, let's say, very good opportunity to refinance long-term at low rates as we did back in January. So we will see. We have different pockets of liquidities to tap, and we are going to be playing like that. But the local markets continue to be very supportive to YPF. And I'm very confident that this amount that we have in 2026, we are going to have no problem in refinancing in the local market. Thank you. Second question. It's for oil exports. Well, I think that, let's say, we are right now reducing a little bit what we export in fourth Q. Now, when we are going to be increasing, definitely related to the first oil expectation that we have for VMOS, most likely that will be, as Horacio just mentioned, the end of 2026, the last quarter there. The pipeline will be releasing 180,000 barrels. We have a share of 27%. And that will continue to grow up until final COD in, I would say, end of the first quarter or during the second quarter of 2027. At that time, the pipeline will have a total capacity of 550. And our commitment is to undertake 120,000 barrels. So that will be our export ramp-up for the coming year on top of what we can marginally add to Chile, depending on the price and, let's say, that we can obtain and the circumstances. Okay. So just to clarify, so when the VMOS is up and running, so 27% of the 180 initially, and that will increase to 120 out of the 550 in 2027 or 2028, whenever that's finished, plus Chile. Yes. It starts with the first oil of 180, and then COD will be the pipeline will be delivering up to 550, out of which the seven initial shippers have committed a total capacity of 450, out of which YPF owns 120. It's totally logical, but our incremental production depends on the capacity that we have, okay? That's why this year you see the same investment as CapEx last year, okay? Very clear. Thank you very much. Okay. You're welcome. All right. I will now turn the call back over to Horacio Marín for closing remarks. Okay. Thank you very much for the question. We are very happy to work here in YPF, and I will switch to Spanish, okay? [Foreign language] in my birthday, okay? All right. Thank you all for joining. That concludes today's call.