Ypf Sociedad Anonima Q1 FY2025 Earnings Call

Thank you for your patience. My name is Danica, and I will be your conference operator today. I would like to welcome everyone to the YPF First Quarter 2025 Earnings Webcast Presentation. I will now 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’s Investor Relations 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 Marin; and our CFO, Mr. Federico Barroetave. 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 2. Our remarks today and answers to your questions may include forward-looking statements, which 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 accordance with IFRS, but during the presentation, we might discuss some non-IFRS measures such as adjusted EBITDA. Finally, according to the relevant fact release last December, as from 2025, the new business structure of YPF is in place. The main changes are as follows: first, we split the Gas & Power segment into two segments: LNG and Integrated Gas and New Energies. Second, we renamed the downstream segment as midstream and downstream. And third, we reallocated our midstream gas business that used to be in the Gas & Power segment to midstream and downstream segments. 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 increase in profitability resulting from the initial disbursement in mature fields in accordance with the first two pillars of the project. In addition, we report improved refining and marketing margins, where our strategic efforts have played a crucial role in this performance to align our prices with international parties and enhance our operational efficiency metrics. Let me also highlight that without the negative contribution of our mature fields, our profit adjusted EBITDA during this quarter would have been roughly $1.35 billion. Internally, adjusted EBITDA remained stable as the robust growth in our shale operation and higher local fuel prices of Q1 this year were offset by the extraordinarily low OpEx in Q1 last year after the discrete evaluation of December 2023, but partially softened by lower value of inventory due to this devaluation. In terms of shale oil, we produced 31% more than Q1 last year, which now represents 55% of our total oil production. This outstanding growth was boosted by record drilling performance, especially in March. First, we achieved the fastest unconventional drilling speed of 551 meters per day in our El género block for an oil well with 2,573 meters of lateral length in 10 days. Second, in the same month, we built the deepest unconventional well of 7,828 meters with a useful lateral length of 4,501 meters in La Amarga Chica block at the speed of 353 meters per day. In both cases, our real-time intelligence center contributed to efficiently design the roadmap and casing process and mitigate operations. In our downstream business, we reached a record high refinery utilization of 94% in Q1, even with the 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 designed to facilitate data-driven decision-making in real time, focusing 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 a collaborator to accelerate our digital transformation, implementing artificial intelligence that evolves incrementally, making complex decisions by using algorithms that are supervised by our experts, allowing us to optimize efficiency across the global supply chain. Regarding our LNG projects, last week Southern Energy also known as SESA, received approval for the 20-year agreement for a 2.45 MTPA floating LNG HILLI, expected to be operational in 2027. With respect to HILLI, a few weeks ago, the SPV obtained a 3-year export permit from the Secretary of Energy, for a maximum daily volume of 10.4 million cubic meters per day starting July 1 of 2027. Moreover, the Rio Negro province approved the environmental impact assessment. Additionally, a few days ago, the Secretary of Energy approved the RIH for a total capacity range between 1.5 million 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 31. If approved, it is expected to be operational in 2028. This second vessel allows the construction of a 100% dedicated gas pipeline from the southern Mattila house 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 gas producers in Argentina, including YPF through its subsidiary, Sur Inversiones Energéticas. Our equity stake in SESA is 25%, while our commitment for gas production is 27.5%. On the other hand, in mid-April, we signed an MOU with ENI, the strategic partner for the Argentina LNG 3 project, to analyze the development of upstream transportation and gas liquefaction facilities through two floating LNG projects, using 6 MTPA each for a total of 12 million tons per year. Considering all this advancement and the project development agreement signed last December, we showcase our strategic plan for the Argentina LNG 2 project with a capacity of 10 million tons per year, which allows us to reach almost 30 million tons per year of the Argentina LNG project, as defined when YPF launched its 4 to 5 plan in March last year. Moving to our quarterly results, we reported revenue of $4.61 billion in Q1, reflecting a 3% sequential decline mainly explained by lower seasonal local demand for diesel oil and fertilizers and reduced oil export volume as we increase the vertical integration with our La Plata refinery. These effects were partially offset by higher local fuel prices and peak seasonal demand for natural gas from power plants. Inter-annually, revenue grew by 7%, mainly boosted by shale activity, including increased oil exports. Improvements in tariffs from MetroGAS and slightly higher local fuel prices and our agribusiness sales have also played a role in enhancing our quarterly revenues. Nevertheless, revenues were partially offset by the discontinuation of jet fuel sales from our Chile subsidiary. Q1 adjusted EBITDA amounted to $1.24 billion, increasing by 48% sequentially, primarily driven by increased prices of fuels and other refined products, aided by higher Brent prices as well as OpEx savings related to the partial sale of mature fields, in addition to higher value inventories and processing levels in our refineries to accumulate stock before our upcoming maintenance program. On the other hand, EBITDA was negatively impacted by slightly higher costs of oil purchases from third parties. Internally, adjusted EBITDA remained flat as robust shale production was counterbalanced by the exceptionally low OpEx recorded last year due to the December 2023 devaluation. This last effect was partially mitigated by lower values of inventories due to the same devaluation. Also, Q1 last year was affected by lower availability of crude oil and adverse weather conditions that impacted La Plata refinery, while Q1 this year recorded a strong processing level to accumulate stock before the next maintenance stoppage, as mentioned previously. Let me remark once more that without our mature fields, our proxy adjusted EBITDA would have been $1.35 billion. In the coming quarters, we expect to continue reducing this impact and deliver even stronger EBITDA to achieve the guidance for the year, which will range from $5.2 billion to $5.5 billion, considering an annual average Brent price of $72.50 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 subsidiaries and higher negative financial results driven by lower gains from 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. Internally, the net result showed a significant decline 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 payable. As highlighted earlier, mature fields also impacted our net results. Without our 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, with 75% allocated to unconventional assets. This level of CapEx is fully in line with our guidance for the year ranging from $5 billion to $5.2 billion. Sequentially, Q1 CapEx declined by 8%, mainly because during Q4 we recorded higher CapEx in downstream activities related to revamping works and seasonality, partially offset by higher sale activities. Inter-annually, CapEx increased by 4%, mainly boosted by shale operations. On the financial side, we reported negative free cash flow of $957 million in Q1, although adjusted EBITDA was similar to 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, holding a 54.45% stake, which is a shale gas block in Vaca Muerta. As a result, our net debt grew to $8.3 billion, reaching a net leverage ratio of 1.8x. We expect it to return to a level of 1.5 to 1.6x by year-end, considering an annual average Brent price of $72.50 per barrel. Focusing on the upstream segment, Q1 total hydrocarbon production increased by approximately 5%, both sequentially and annually, reaching 552,000 barrels of oil equivalent per day, primarily driven by shale contributions which now account for an outstanding level of 58% of total output. On the other hand, mature field output reduced by 11% versus the previous quarter, mainly due to the effect of already divested blocks. Crude oil production amounted to 270,000 barrels per day in Q1, reflecting a year-on-year increase of 6%, primarily driven by shale expansion, which effectively offset reductions in conventional oil, especially in mature fields. Notably, shale oil production grew an impressive 31% year-over-year, affirming our strategic focus on Pillar 1 and in line with our 2025 annual target of over 155,000 barrels per day. As a result of the production ramp-up, our oil exports predominantly to Chile grew by 34% interannually, reaching 36,000 barrels per day, representing 13% of our oil production. Sequentially, oil exports were reduced by 11% as we expanded vertical integration with our refineries. Beyond crude oil, natural gas production in Q1 increased by 9% sequentially, delivering over 37 million cubic meters per day, mostly due to higher seasonal demand from power plants. NGLs production amounted to 47,000 barrels per day, returning to normal levels due to the reactivation of mega facilities following maintenance. In Q1, total lifting costs reached $15.3 per barrel of oil equivalent, reflecting a sequential 12% reduction, predominantly driven by the completion of divestment of certain mature fields. If we exclude this mature field effect, our processing lifting cost for Q1 would have been below $9 per barrel of oil equivalent, considering that we continue to reduce our exposure to mature fields; our best estimate for 2025 average lifting costs could be $12 per barrel of oil equivalent. Assuming our core CapEx, lifting costs were $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, the local pricing environment has been more stable. On the natural gas side, prices stood at a similar level of $3 per million Btu, primarily derived from the off-peak season price of plant gas. Now moving on to 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 activity by drilling 51 horizontal oil wells, 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 aligns with our estimated number of wells to be drilled during the year 2025, which amounts to 190 operated and 15 non-operated shale oil wells on a gross basis, where net working interest should be around 55%. In terms of completion and timing of wells, we also accelerated activities in our operating blocks, completing 53 and tying in 47 horizontal wells on a gross basis, recording increases of 83% and 21%, respectively, compared to Q1 last year. Once again, we successfully set a new record high shale oil production, delivering 147,000 barrels per day in Q1, signifying over 50% growth compared to the annual average production of 2023. This production level indicates a positive start for the year to reach the 2025 target of 155,000 barrels per day. 76% of 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 emphasize that sequential growth was driven by contributions from the La Angostura Sur 1 block, located in the southern hub of Vaca Muerta, which has displayed outstanding productivity. In terms of efficiency in our unconventional operations, on the drilling side, we reached an average of 304 meters per day in our core hub blocks. Despite beginning the year with drilling speeds below our expectations in certain wells in the Aguada del Chañar block, in March we successfully achieved the fastest unconventional well in the same block, as mentioned earlier. Expecting further improvements, we are confident of achieving the annual target of 350 meters per day. On the fracturing side, we recorded 235 days per month in our unconventional operations—strong performance in line with the target this year of 260 days per month. Moving on to our downstream segment, during Q1, we continued adjusting local fuel prices to converge fully with international parities, preserving our leading market share. As a result, local fuel prices measured in dollars were up 2% versus the previous quarter and 1% compared to the same period last year, while the gap with imports stood in positive territory at 1% in Q1, compared to 3% in Q4, and minus 7% in Q1 last year. Moreover, driven by an international price downward trend, we reduced local fuel prices by an average of 4% starting this month. Regarding fuel sale volumes, it decreased by 5% sequentially to 3.4 million cubic meters but was below the contraction observed by the competition. The main decrease stemmed from diesel, which was affected by lower seasonal demand. Since the second night of April, diesel demand has begun to grow again. Additionally, 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. During Q1, we implemented more than 100 initiatives that allowed us to capture efficiencies amounting to over $70 million, including energy consumption, steam and gas recovery optimization, as well as service contracts rearrangement and reduced shutdown maintenance costs. Lastly, regarding refinery utilization, we processed 318,000 barrels per day in Q1, which expanded 5% sequentially, yielding a robust refinery utilization rate of 94%, buoyed by improved performance of the La Plata refinery during Q1, which was adversely impacted by maintenance shutdowns in Q4. Let me clarify once more that the higher processing level enabled us to accumulate inventory of refined products before the upcoming maintenance stoppages. Inter-annually, processing levels increased by 6%. Now let me share our progress in terms of midstream oil expansions. Regarding the existing Oldelval oil pipeline expansion and the Duplicar plus project, it was successfully completed in early April, increasing transportation capacity from 330,000 barrels per day at the end of December to 540,000 barrels per day today. Let me highlight that the original capacity of Oldelval before execution of the project was approximately 225,000 barrels per day. Therefore, Oldelval has more than doubled its capacity in close to two years, significantly contributing to the evacuation of shale oil from Vaca Muerta. YPF holds a roughly 25% stake in Oldelval. We will use this expansion to transport our shale oil to our La Plata refinery, optimizing our vertical integration. Regarding the Vamos Vaca Muerta oil pipeline South, the new 100% oil export dedicated pipeline has begun construction at the start of this year. The SPV has already started receiving the pipes and has begun construction work in the oil pipeline routes and trench excavation. Additionally, initial steel plates have been received for initial tank assembly at the export terminal, where we are now working on ground movements and civil works. The operational progress of this process is roughly 4.5% as of the end of March. Now I will turn the call over to Federico.

Thank you, Horacio. Switching to the financials. 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 Bemos 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 18% reduction of our cash and cash equivalents. In terms of financing, as mentioned during the last call, in January, we issued a 9-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 to 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 May 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 local bonds in February: $140 million with a 2-year tenure at 6.25% and a $60 million deal with a 6-month tenure at 3.5%. Following the quarter, we also issued a $204 million linked bond in April and, more recently, in May, another $140 million bond—the first one having a 15-month tenure at 3.95% and the second one having a 2-year tenure at 7%. Over 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 upgraded YPF's 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 the prior quarter, amounting to $1.2 billion, while our net debt increased to $8.3 billion. Consequently, our net leverage ratio also increased from 1.6 to 1.8x, as anticipated during our Investor Day last month. Once we fully divest of mature fields, we estimate to end the year with a net leverage ratio of 1.5x or 1.6x, considering an annual average Brent price of $72.50 per barrel. With this, we conclude our presentation and open the floor for questions.

Hi, good morning. Actually, this is 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 gives you a decent present today. Looking at the questions, my first question is about how resilient the company is amid the current uncertain and bearish environmental prices. I wanted to know from Horacio, if you can please share with us what the current Brent breakeven level is in terms of EBITDA and cash flow that the company currently has? My second question will also be in the same vein, to gain a better understanding of the required CapEx needed to keep your current production stable, especially considering the bulk of your production is shale oil and shale gas, where the decline rates can be very steep.

Okay. Thank you very much. Because you wished me Happy Birthday, I’ll answer the second question first. For the first question, if you see the— I think it’s Slide 37, if my memory serves me right. If you go to that slide, you can see that every $10 reduction in Brent translates to an average of $900 million. That is the answer. If I take Brent at $60, our EBITDA will be 4.4%. That's everything I explained in New York. For the second one, it’s in the order of $2 billion to maintain our production. But we are going to grow.

Yes, good morning. Alejandro Demichelis here from Jefferies. Horacio, Federico, one question, please, as a bit of a follow-up. In the current oil price scenario we are seeing, when you were in Europe, you talked about some flexibility on your plans. What is your latest thinking in terms of how you’re seeing CapEx activity levels and also the risk that some of these disposals may not be completed because your buyers may have trouble financing those?

Okay. First, I would like to say that if we have to change our program, we will change it, okay? I won’t take any decision in panic. There are many uncertainties and plenty of volatility in the prices. While we are decreasing, we continue to monitor. If there is any very positive news, we may bounce back. We’ll wait; if we need to stop, we will stop. But it’s not the moment today for that.

Hi everyone, Horacio, Federico, Margarita. Thanks for taking 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 cash flow related to the mature assets. I was wondering if you could provide more color on this impact. Also, could we expect a further impact related to the divestments of the assets that are yet to be divested? My second question is regarding the LNG projects—could you walk us through the necessary steps for the final investment decision for the LNG projects that are more advanced? Specifically, the Southern Energy JV, because there is still another vessel to be brought, if I am not mistaken, and also the project with Shell, because you already have the offtakers.

Okay. The first question, what I can tell you is we are very proud of what we did in the mature fields. Moreover, with a lower price, you should also be proud of us because we made YPF very resilient at low prices, okay? Regarding mature fields, there was a decrease in the Province of Santa Cruz. We have seen in a couple of months, we are finishing all operations in Santa Cruz. The same is true for Girasole; it is a small one. We are working hard on the divestments, especially those with Shell that are in the last stages. I estimate we will be out by Q3 of this year because you have to consider all the requirements for signing all the documents and following all the laws for the different provinces. Regarding additional investment, we think it could be some in material, but not a lot. We have almost everything completed on that end. For the second question concerning LNG projects, for the SESA, the one signed for Argentina LNG 1, we are targeting the FID for the first ship by May 4. For the second one, we must sign the FID before the end of July. The second project—Argentina LNG 2 with Shell— is currently in a bidding process for FID, which will come probably end of next year. With the Argentine 3 project in conjunction with ENI, our goal is to have both companies sign the FID by the end of the year. That is our goal, but things may adjust as we work and see what is happening in the world.

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 the most competitively priced provider, do you expect to capture additional market share, and what is the best strategy for quarterly improvements in market share?

Okay. The pricing strategy that we have is the same as any company around the world in a free market. It’s as simple as that. Therefore, I observed that in the United States, over the weekend, prices of ethane went down. So, that is our strategy. It’s impacted by the price of oil, taxes, and the price of biofuel. We must be mindful of the market share.

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, from the 550,000 barrels scheduled for the third quarter of ‘27 to the first half of the year. However, the slide you showed today mentioned no reference to the 180,000 barrels addition by the fourth quarter of 2026. Are you still targeting that first stage by the end of next year? The second question is that media is reporting that Southern Energy is negotiating already the gas pipeline with an international company. Do you know the size of the pipeline investment and its technical characteristics, and why not keep an open bidding process?

Okay. The COD of VMOS was affected, but it’s in line with what we said. For the first stage, it’s between the end of Q3 and Q4 of ‘26 for 180,000, while the 550,000 is anticipated for the first—let’s say the middle of Q2 ‘27. As stated initially, there is no delay. We are working hard on that project. As for your question regarding the CapEx for the gas pipeline, yes, we are in discussions with an international company, and the open option process is not happening because if we can secure a good deal for the partners, we prefer that. If the tariff is favorable for the project, we think this is great for everyone involved. However, if we cannot reach an agreement on the tariff, we will consider a bidding process as mentioned.

Hi everyone. Thanks for taking my questions. I have three quick ones. The first one is a follow-up on the divestment of mature fields. I understand roughly 11 blocks were already fully divested, right? I would like to get a sense of the production contribution from those closed blocks. And my second question regarding the further divestments of mature fields: if you could correct me if I am wrong, but you mentioned expecting to bring leverage down as you divest those legacy fields. I would like to understand if this reduction in leverage relies more on exiting EBITDA-negative assets or if you are expecting relevant cash inflow from these divestments. My third and final question is on CapEx. I understand you mentioned it’s still too early to reassess your investment program for the year. But I would like to understand better how long Brent prices would need to stay in the $60s for you to consider revising your drilling and CapEx activity.

The mature fields have seen production contributions from those blocks, as we’ve mentioned, and you saw in all our calls, we are transitioning with improving production from Vaca Muerta. Therefore, this is not a problem for us. I also want to clarify that production there was not significant because the EBITDA was almost nothing, sometimes even negative, so this is better for investors. Argentina is a free market today. I can obtain oil at the same price regardless of the field. It’s not a problem for me to buy elsewhere, and additionally, we have had excellent results in downstream, so we don't foresee any issues. Regarding the leveraging issue, as you mentioned from Guilherme, this will occur after our peak which we announced in New York due to divesting from mature fields. We expect this to start taking effect end of Q2 or during Q3. Once we finish, we will start to see YPF with higher EBITDA. This transition will be more focused on unconventional fields, which will lead to better EBITDA, likely visible in Q3 and Q4. With that completion, we expect to steadily begin reducing leverage toward the end of the year. We are also considering further divestments that may happen later this year or early next year, though we can't specify an exact timing. About the CapEx, as long as Brent stays at $60, we can still operate Vaca Muerta profitably. So, the lower the price, the less profit we make, but as time progresses, it will demand less capital because we will start generating returns at that threshold. We will monitor the situation closely and I will make decisions as required, but for now, I don’t consider it necessary.

I think that the question from Guilherme on this is basically how we are going to be slowing down the debt after the peak we announced in New York because of the divestment of the mature fields. We predict this to happen by the end of Q2 or during Q3. Once we finish with divestments, we will start taking away all the negative EBITDA from mature fields that are affecting our overall EBITDA. Once this transition concludes, we expect to show the market a clearer picture of YPF, which will be mostly focused on unconventional production, leading to more robust EBITDA. This should start showing in the 3Q and 4Q of this year. With that, we should see both revenue growth and reductions in leverage by the end of the year. We are also considering other divestments as mentioned earlier for later this year or early next year.

Hi Horacio, Federico. Thanks for taking my questions. I have one follow-up on CapEx and one on the LNG project. Starting with CapEx, you released the $5 billion guidance for 2025. Now during the first Q, you just separated the $100 million disbursement to affiliates, so could you please clarify that disbursement on these affiliates and other infrastructure projects such as Vaca Muerta Sur and Southern Energy? Are these already included in the $5 billion CapEx for the full year? What’s the total expected breakdown for the full year? How much are you aiming to disburse on these affiliates in 2025? The second question is a follow-up on the LNG project. You have been mentioning that the project is particularly resilient, given their profile of contracts and so on. However, since you are still negotiating these contracts, have you already noticed some pushbacks from potential clients regarding pricing for these contracts? Additionally, do you think that potential lower Brent for a sustained period or tensions and uncertainties from the U.S. government could compel you to reassess CapEx and the size of these projects?

Thank you for the questions. Regarding CapEx, the $100 million includes growing investments. Argentina was a country producing from four or five different places, and now probably for only one. So, it poses a bottleneck for growth production— not just for us but for all companies. This allocation is for infrastructure to enable growth because if we do not, we cannot advance, which is essential for Vaca Muerta. And yes, it is all included because it’s our business.

Yes. I think, Tasso, to clarify, the $5 billion does not include the contributions to affiliates. What you saw in this quarter mostly concerns the completion of Oldelval and the initial construction of VMOS. If that’s your inquiry, please confirm.

Regarding the LNG projects, I am very proud of the partners we have; this is all project financed. The world needs LNG and a lot of it; there’s no way to supply gas without the U.S., and we’re in a better position than them. I feel comfortable knowing we can deliver LNG in Argentina profitably. We will make money if our partners do well. There is concern, but it’s more about the quality of the company that we work with. In all projects, we are typically at 25%. Thus, 75% of reliable partners consider this a good business, based on Vaca Muerta’s reserves. As CEO, I must focus on developing LNG for all shareholders because it’s a critical part of my performance.

Good morning. Good afternoon. Thank you very much for your 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 substantial amount in 2026. I see most is 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 have heard mixed comments that suggest it might not be quite as liquid as it once was. My second question is on exports. I know your exports decreased this quarter, and you mentioned it was due to greater vertical integration. Can you give us an idea of when you expect your exports to increase more significantly?

Well, on the first question, yes, for 2026, most of what we have to refinance lies in the local market, with about 1.5 billion to refinance locally and less than 400 million in the international bond market. Based on this, and considering the current situation, we will keep our options open regarding refinancing this amount. The local market remains quite open for YPF. Recently, we priced a new issuance of about $140 million for 2 years at 7%, larger than what we were initially looking at interest rate-wise. YPF continues to be a key name in the local market. Thus, I am confident that we will have no issues refinancing our 2026 maturities. Regarding oil exports, we are currently reducing our exports for Q1. We expect, however, that we will ramp up significantly with anticipated increases in oil output from VMOS, likely by the end of 2026. The pipeline will then deliver up to 180,000 barrels in initial exports, ramping up to 120,000 barrels once fully operational in 2027.

That’s fully correct. Initially, we will produce 180,000 barrels, and then the pipeline will stabilize at 550, of which we will commit ourselves to 120,000 barrels. This offers us good opportunities to expand our export routines, subject to capacity availability. Therefore, this year, you will see a CapEx level akin to last year’s.

Thank you all for joining.