Good morning, everyone, and thank you for waiting. I'm Raquel Cardas from IR, and we would like to welcome everyone to Pampa Energía's Fourth Quarter 2024 results video conference. We would like to inform you that this event is being recorded. All participants will be in listen-only mode during the presentation. After the company's remarks, there will be a Q&A session. Questions can only be submitted in writing through Zoom. Should any participant need help, please send us a chat message. Before proceeding, please read the disclaimer on the second page of our presentation. Let me mention that forward-looking statements are based on Pampa Energía's management beliefs and assumptions and information currently available to the company. They involve risks, uncertainties, and assumptions because they are related to future events that may or may not occur. Investors should understand that general economic and industry conditions and other operating factors could also affect the future results of Pampa Energía and could cause results to differ materially from those expressed in such forward-looking statements. Now, I will turn the video conference over to Lida. Please go ahead. Thank you, Raquel. Say hello, everyone, and thank you for joining our conference call. I will make a quick summary of 2024 and Q4. You may find more details in our earnings release and financial statements. For today's Q&A, let me introduce here our CEO, Gustavo Mariani, our EVP and head of E&P, Mr. Horacio Turri, and our new CFO, Adolfo Zuberbuhler, Pito. First, we wanted to review 2024, a year that was challenging from the very beginning. Despite this, the macro outperformed expectations, and we advanced with the development of Rincón de Aranda, our flagship shale oil project. As one of the country's leading gas producers, we reached a new all-time high this 2024, marking a 21% growth in year-average output and an impressive 80% increase since 2017. This is driven by our top-performing wells in Vaca Muerta. It is worth highlighting, we hit 100,000 barrels of oil equivalent per day again during the winter. This is the most critical supply period of the year. While 2024's output was entirely gas, we will diversify into shale oil once Rincón de Aranda comes online. In the power segment, we commissioned PEPE VI Wind Farm. This is adding another 140 megawatts of green energy, having grown nearly 50% since 2017. With a strong focus on operational excellence, we achieved an impressive 95% availability rate in 2024, reaffirming our position as the country's leading IPP. EBITDA grew 19% year-on-year and 29% compared to 2017, mostly coming from power and gas and contributing to another milestone. Net debt fell to $410 million, the lowest since 2016. Now, turning to Q4 only, the quarter was marked by strong performance in gas upstream and power. Gas production rose 11% year-on-year, with shale gas increasing its share from 32% in 2023 now to nearly 50% in 2024. Power units recorded a 94% availability rate, with a notable recovery in the PPA units. Also, as I mentioned before, the balance sheet keeps getting stronger with extended maturities and improved equity. We are preparing for the shale oil ramp-up in early 2024 starting as of April, currently operating with four drilling rigs and one frac fleet while building the necessary facilities. The adjusted EBITDA for the quarter amounted to $182 million. This is up 60% from last year, driven by increased gas deliveries from thermal power generation. The contribution of PEPE VI improved PPA performance in addition to the tariff hikes benefiting TGS and Transener. Higher operating costs and lower exports at the Brazilian FX partially offset these gains. The quarter-on-quarter decrease was due to the seasonality. Notably, in 68% of our quarters, EBITDA was dollar-linked due to the successive peso increases in spot energy and utilities, rising to 88% at the parent company. CapEx in Q4 was 20% lower year-on-year, mainly because of the shale gas ramp-up in 2023, partially offset by final payments for PEPE VI and the ongoing development in Rincón de Aranda. Moving to E&P on slide five, adjusted EBITDA was $36 million in Q4, down 26% year-on-year, largely due to the lower sales to industries and Chile, as well as higher operating costs. The impact exports settled at the differential FX, which amounted to last year's Q4 $24 million, nearly zero this Q4. These factors were offset by increased gas production for thermal power generation. The beginning of Rincón de Aranda's development and program overhauls pushed the total lifting cost up 29% year-on-year. Lifting costs per BOE rose to $8.7 per BOE, while gas lifting costs increased by 10% to $1.2 per million BTU, also influenced by the lower seasonal output. Total production averaged nearly 62,000 BOE per day, 9% higher than last year. When we zoom in, crude oil represented 6% of the output and 25% of the E&P's revenue, while gas accounted for 94% of the production. El Mangrullo contributed 54% of the Q4 production, while Sierra Chata increased to 30%, growing production 34% year-on-year in Sierra Chata without new wells connected, new wells drilled during the quarter. During 2024, we connected three wells, so Sierra Chata's annual production rose 40% versus 2023 in the year-average. El Mangrullo output also increased 12% year-on-year without additional DUCs in the quarter, with an annual production up 23% from three wells connected in 2024. In Río Neuquén, which is a non-operating block, production averaged 1.3 million cubic meters per day, similar to the last year's quarter. The average gas price for the quarter was $2.9 per million BTU, down 10% due to lower exports to Chile and sales to industries, partially offset by better retail prices following the tariff increases. As you can see right below, most local gas deliveries were directed to CAMMESA for thermal power generation. Okay, so let me briefly comment on our progress on Rincón de Aranda. In Q4 2024, the production averaged almost 1,000 barrels per day, which is in line with the expected decline curves for these well types. Since September last year, we have been drilling pads to prepare DUCs on the way to complete three pads so far. The frac fleet arrived in early February, and we already fracked the first pad, and we are in preparation for the second and in preparation for Duplicar, which should be online early April. By May, we plan to have two pads connected, bringing output to 8,000 barrels per day. To reach this year's plateau, we plan to complete five more pads targeting 20,000 barrels per day by December of this year. We are building pipelines, preparing early production facilities, building the central processing facility, water treatment pools, etc., etc. So before we move on from E&P, I wanted to do a real quick update on the reserves. Total proven reserves rose 16% to 1,231 million barrels of oil equivalent. This is driven by the increased activity in Sierra Chata and El Mangrullo, our flagship shale gas blocks, as well as testings in Rincón de Aranda. Shale reserves grew 60% year-on-year to 132 million barrels, with shale oil now accounting for 9% of the total of the shale reserves, marking the first time it has been booked. The remaining 91% is shale gas. The reserve replacement ratio, the RRR, was 2.2 times, maintaining an average life of 8.6 years. Since 2019, proven reserves have increased by 71%, with a sharp growth in our proven shale reserves, particularly in shale oil, since last year. So moving on to power generation on slide nine, we posted an adjusted EBITDA of $86 million this quarter, up 7% year-on-year, mainly explained by the contributions of PEPE VI and the PPAs and recovering legacy spot prices, partially offset by higher operating expenses. Q4 slightly fell 4% year-on-year because of the life extension overhaul that we are doing in Genelba, old CCGT, and lower water levels in Pichi Picún Leufú hydro. The hydro dispatch from Loma La Lata and the commissioning of PEPE VI offset these effects. Take-or-pay capacity payment, especially from the PPAs, were the main EBITDA driver, reflecting the outstanding capacity availability, which improved to 94% from the 93% last year due to fewer thermal outages. In 2025, we plan to upgrade Barragán's gas turbines, adding another 11 megawatts, and conduct a major overhaul in Loma La Lata gas turbine in March. Well a quick brief on PEPE VI expansion, which is no longer a project. The COD was completed last November 2021, bringing the total installed capacity to 140 megawatts. Now, Pampa operates 427 megawatts of wind energy, ranking us among the country's top five renewable IPPs. Moving to slide 11, we show the restricted group figures that reflect the bond perimeter. Free cash flow in Q4 generated $82 million, supported by the working capital inflows from the winter receivables, the highest revenue-making period of the year. Day sales outstanding stood at 45 days, meaning just a three-day delay, alongside robust operating cash flow from power and gas. After last year's CapEx for the shale gas ramp-up, 2024 spending was mainly just maintenance focus, spiced up by Rincón de Aranda development. The total CapEx for the quarter was $154 million, but Rincón de Aranda was more than half of it. In December, we issued a $360 million international bond maturing in 2034 to improve our debt profile, redeeming the remaining 2027 notes at par. This resulted in a cash increasing to $1.7 billion, though after the 2027 bond repayment just this year, cash stood at $1.3 billion, more than 50% than last year's $834 million cash. The next slide shows our consolidated financial position, including our affiliates at ownership, but just let's keep focusing on the restricted group. Gross debt stood at $2 billion, up 44% year-on-year due to the 2031 and the 2034 bond issuances for $770 million total, which directly funded the repurchase of 2027 notes. It's noteworthy that besides further extending the average life to 4.2 years and securing the lowest spread to USD LIBOR in the history of the Argentine corporates, the net debt dropped to $410 million. This is 33% down year-on-year and 0.6 times net leverage ratio. This is the lowest ratio and the lowest level since 2016 when we acquired the former Petrobras Argentina. This was mainly because of the strong cash flow inflow from power generation and gas operations alongside improved collections from CAMMESA and ENARSA. In sum, we successfully met one of our key 2025 goals, extending the large maturity wall for 2027 and to 2031 and beyond with highly competitive rates, shielding our financial position to support the development of Rincón de Aranda. Now concludes our presentation. The floor is open for questions. If you have a question, please send us through Zoom chat. I will read it and answer them in the order received, first in, first out. So please make sure you put your name, your company, so we can introduce you to the audience. Should any participant need assistance, just write in the Zoom chat. Please hold just while we poll for the questions. The first question, all right? Marina Mertens, sorry, from Latin Securities, she asked, how do you expect regulatory changes introduced by the Secretary of Energy to impact Pampa, particularly regarding the ability for generators to self-procure the fuel? What impact do you anticipate for both E&P and power generation segments? Hello, good morning, everybody. Thank you all for participating. Thank you, Marina, for your question. First thing that I have to say is that it is too early to tell. What the regulatory authority has issued are basically guidelines that the regulator put over the table for all the participants to comment on those guidelines. And the idea, and that is written in this guideline, is that throughout this year, they will prepare the definitive regulatory changes that should be implemented after the winter, basically beginning by November of 2025. From now until November, we do not expect many changes. The capacity of self-procure, our own fuel, will not have—we don't expect it to have a significant impact during this month. Probably some impact before the winter start, no impact at all during the winter. And then in November, we'll expect the new changes. What we expect basically for ourselves that we are integrated is that we will be able during this summertime to be able to increase our sales of natural gas because we will be using our gas in our own thermal plants. But we don't have yet clarity about what will happen with prices in the market. So it's too early to tell, but we do not expect in the next quarter any significant impact. All right. The second question. In recent quarters, strong cash flow generation has significantly reduced net debt. However, with growth plans that include investments in Rincón de Aranda, Vaca Muerta Sur, the LNG project, and potentially a urea plant, how do you expect leverage to evolve? Look, the one clarification I will make is that we are, as you know, moving forward full speed with the development of commitment to participate in the Vaca Muerta Sur, the oil pipeline. The other two, the floating LNG project and the urea plant that we are studying, those are, as I said, projects that are being studied. The floating LNG, the final investment decision has not been taken yet. We are very eager and committed to this project, but there are a few hurdles that we need to resolve before taking the final decision. Nevertheless, the floating LNG project, one of its beauties is that the initial CapEx for this project is rather low, although it implicates significant commitments going forward once you assume the commitment to charter the boat for 20 years. For the urea plant, if that is a decision, as we have explained before, that we will be taking probably by the end of this year, and our expectation is to do the project in a subsidiary, so it will not affect the ratios of Pampa. We expect to finance the UREA project as a project finance, obviously with an equity contribution coming from Pampa, but on a separate vehicle. So I'll let the Pito complete. We expect this year, as we have said before, because of the significant CapEx that we will be deploying in Rincón de Aranda, for the first time, we will have a year with negative free cash flow, so investing more than our EBITDA generation, so our net leverage will go up. As Lida said, it is currently in a very comfortable situation of 0.6. We expect it to grow about 1.2 times net debt. So a very marginal increase in year 2026, probably in year 2027. In year 2027, it will be more or less equalized. And sorry, in 2026 and in 2027, we will go back to significant free cash flow generation. Well, the next one, Guido Bizzozero, from Allaria. What is the plan for Rincón de Aranda if Brent prices go to $60-$65 per barrel? Okay, good morning, everybody. First thing to say is that when we are looking at prices, we don't look at the spot price, but rather we take a look at the future curve, and that is much more stable than the spot prices. Having said so, we also decided to hedge approximately 65% of the production of 2025, so we feel pretty comfortable with that and the prices that we achieved with that hedging. So we don't see any major changes in our investment plan for 2025, which is basically the ramp-up of Rincón de Aranda going up to a level of 20,000 barrels per day by the end of the year. Great, awesome. Next question from Bruno Montanari from Morgan Stanley. Can you talk about the appetite, sensitivity to sustaining, accelerating, or decelerating CapEx for Rincón de Aranda, which is, can you talk about it? Okay. Okay. Well, it's more or less the same thing as we mentioned before. We are already committed for 2025, and we will not be accelerating or decelerating the rhythm of investment and/or drilling or completion during the next year or even 2026, which probably will be a matter of rolling over our hedge position for the year after 2025. So we will keep on doing so in order to have a stable or at least a much more certain cash flow. Group is questioning, what's the hedge price? Well, the hedge price is around $72 per barrel. He asked, what happens if the Brent goes below, below, below $60, for instance? It's the same. It's the same. We are hedged. We're going to be hedged. I don't know if that went out or we have to repeat. It's okay. He says, the price, which one, the hedge price or hedge price? The hedge price, $72 per barrel. $72 and if the drilling pace will go down below $60, it's the same? It's the same thing. Same thing, right? And the opposite, which levels of prices will make you feel to accelerate the pace of Rincón de Aranda's development? Okay. Yeah. Well, first thing, it's important to clarify that this is not like opening a valve and closing a valve whenever you want. It takes time to commit the necessary equipment for drilling, and particularly for completion. There is a lead time that it makes it very difficult to make decisions on the very short term in terms of accelerating the drilling and completion of the wells. So there is not much room there, at least in a period of approximately one year, to accelerate significantly or decrease the rhythm of drilling and completion. Of course, it is easier to decide eventually to stop fracking and decide to remove the frac fleet, but obviously that has costs associated, which I don't think we would like to burden on our shoulders. Great. So another question for you, Horacio. Come on. About the recent revolution from shale gas and oil, thinking about the de-risking. Okay. Of Rincón de Aranda, when could we expect to see more meaningful reserve addition in that specific area? We will see a significant change in our reserve portfolio in Rincón de Aranda by the end of 2025. By that time, hopefully, we will have already drilled and completed 28 wells, which will obviously boost significantly our total reserves, particularly shale oil reserves in the Pampa portfolio. Right. Power generation for Gus. Could you comment on what are the management expectations regarding further resolutions, allowing generators to sign new PPAs? Is Pampa analyzing potential investments in greenfield power generation assets? No, we are not currently analyzing any new investment in power generation. What we are analyzing that it's related is the recent invitation to install a battery package within the city of Buenos Aires. That is an investment that we are studying, but we haven't taken any decision yet. And regarding the further PPAs, we do have the B2B market to sign PPAs with what we have installed, our wind farms for the MATER. But we have already sold all that capacity, so there's no need to—we need to renew some contracts that are maturing, but we don't need to sell new capacity. Thank you. Next question from Invertir en Bolsa, Ignacio Sniechowski. I hope I pronounced well. My first question is about the cost of sales, which increase, thus lowering the gross margin. I understand that this is mainly explained by higher lifting costs, but could you provide a little bit more color on this? I guess all the segments have this thing, right? Yeah, but. No. I understand he's asking about the increase in lifting costs during the last quarter of 2024. Okay. That has to do particularly. It's basically based on natural gas lifting costs, and it has to do with the reduction in our production. So less production, the same fixed costs, so you have an impact in your lifting. It's not that we are less competitive now. And then a lot of, there also is a component which happens not only in the gas industry, but all over Argentina, and it has to do with new prices or inflation in dollars. Yeah. It happens the same in power generation, and specifically in Petrochemicals, where most of the costs are in pesos, and the fact that the peso real is really, it's appreciated gets y our margins tight. The second question from Ignacio concerns about power generation. Now, PEPE VI, excluding potential case that the hydros are not renewed. Well, it's about the increased capacity. We don't have any greenfields projects in the pipeline. Last, if you wanted to be more color on that. Sorry. One thing that we like about Pampa and its diversified portfolio of business segment, it's the capacity to allocate capital wherever we see it makes more sense. As we've been explaining, we are very enthusiastic with the opportunity after acquiring Rincón de Aranda in 2023 to develop the oil segment, and we are putting all the focus and the effort of the company in the development of Rincón de Aranda, especially from a CapEx perspective. Regarding renewable projects, I think in the past, it has been an excellent use of our capital, taking advantage of our peso generation and being able to access the official exchange rate when there was a huge gap between the official exchange rate and the blue chip swap. We did, we built those renewable wind farms. When measuring dollars, half the cost of what it costs anywhere else in the world. That gave the project, now that the gap between the official and the blue chip swap has narrowed, gives the project nice dollar IRR. Now that the blue chip swap has, the spread has collapsed, the yields in these projects are for us not attractive enough, and we prefer to deploy capital on other segments than something like what we are doing in Rincón de Aranda. So that's more color to the question. Great. I think we talked about it, but what do you think in general? The deregulation that happened, the study, the guidelines out there, do you think it's positive in general or negative? They are definitely very positive for the sector as a whole, and especially for Pampa for several reasons. The first one is that we are an integrated company. The rationale behind that decision early at the very beginning of Pampa is being able to procure our own fuel so that our gas production goes into our power plants, something that we haven't been able to take advantage of in the past decade. We hope we will be able to take advantage of that situation beginning at the end of this year. The second thing is that it's very good news for Pampa because of the competitiveness of the portfolio of our power generation assets. We have CCGTs with very high thermal efficiency. We have CCGTs located at the wellhead, so that means that we don't have to incur gas transportation costs, which adds to the competitiveness of our assets. It's definitely excellent news. It is not easy, as we have always said, to eliminate all this regulation and going from a highly regulated environment to a free market situation. It takes time to implement it. It will need time to go all the way to that situation, but it's definitely a move in the right direction and excellent news for Pampa. Great. Gustavo Faria from Bank of America, he asked what the next steps regarding this regulation and procedures and what's the implementation process of this power sector liberalization. Next steps are the sector, different market participants, like power generators, distributors, big industries. Everybody that is involved in the sector will give its comments to the Secretary of Energy and this guidelines will go from guidelines into definitive regulatory... Framework. Yeah, a new regulatory framework that we expect will be published during the winter so that the sector will have time to adapt and take any decisions necessary to be implemented beginning in November. Gustavo is also asking a little bit like how the prices will work in the double click, comparing, for example, greenfield projects, new energy with this spot market or this new potential B2B market that is going to be created. How different how the prices dynamics will work in each succession? Again, it's too early to tell. One thing that I would say is that you have to keep in mind that the regulator will always keep in mind the total cost of the system. Knowing that if the total cost of the systems goes up, that means that the final user will have to pay higher prices or that the national government will have to increase subsidies. The regulator will be very focused on avoiding any significant increase in the overall cost of the system. So I imagine more than an increase in the cost of the system that would increase the margins for power generator. I imagine more stable prices, but a redistribution so that you have to focus on the portfolio that each power generator owns and how this new regulation affects its portfolio. I, as a base case, would assume maintaining current prices. Something that is in the guideline is that the regulator is thinking about for the spot price going into a marginal system, but not to a full marginal system until we end the transition. I think that what the regulator thinks about the transition until there is new gas transportation infrastructure in place so that the system can fully eliminate the use of liquids. The regulator will not allow margins to go up significantly, and they will cap the margins of the power generator, again, with the goal of avoiding hikes or significant price increases in the sector. Great. He asked about EBITDA again. It's too early to tell how it's going to impact. We'll turn again to Horacio. Gustavo asked, what's the outlook of gas exports to Chile and Brazil in 2025 regarding capacity and pricing? Wait, looking on the gas prices and then looking long term, most of the upside from gas exports will be coming from new pipelines or new LNG? Let's go first to Chile. We've seen during the last quarter of 2024 a reduction in the Chilean gas demand, just a mirror of what happened in Argentina, a combination of hydro and low temperatures for the summer. Now we're looking at ramping up of the Chilean demand. We are currently exporting around 1.4 million cubic meters per day at a price which is around $5 per million BTU at the wellhead. That will probably be reduced in the coming 15 days, the next two weeks when we foresee a reduction in temperatures and a mild climate as the autumn sets in, and we will go back to our previous exports levels that are in the range of 600,000 meters per day. Having said so, it is also true that by May of 2025, we expect these first exports through the Gasoducto del Pacífico to the region of the Biobío in Chile. That will be around 350,000 cubic meters per day. So we will be back to our 1 million cubic meters per day exports to Chile again. And regarding prices, we don't foresee major differences from what happened, what's happening right now. In terms of the future and Brazil, the question is whether we are going to be exporting through pipelines or through LNG. I would say that we will be doing probably both. Argentina will be probably doing both, exporting through the existing capacity infrastructure, obviously to Chile, which is already happening through GasAndes and starting with Gasoducto del Pacífico. And we will have to see how it works with Brazil, whether the possibility of moving gas from Vaca Muerta to the region of São Paulo is going to happen in which volumes and prices. The potential demand is around 20 million cubic meters per day, but it's still a question mark on what the transportation cost is going to be and whether that gas is going to be competitive or not in Brazil vis-à-vis the LNG imports of the Brazilian industry. LNG, well, we can mention our LNG project very, very, very briefly. As Gustavo mentioned before, we are in the process of deciding whether we will move forward with an FID or not in the coming future. The project consists of two vessels, the first one of 2.5 million tons per year and the second one 3.5, so a total of 6 million tons per year, both, which represents approximately 25 to 26 million cubic meters per day. We have a 20% participation in the project. We will still have to understand the final economics. We need transportation capacity to be built from Neuquén to the spot where the vessels are going to be moored. And this is something that we will be analyzing in the coming months. Great. Another question for you. And this is coming from Claudia Rivera from Santander. She asked what happened with the margins in oil and gas this quarter is lower than the previous quarter. Is something that it's going to see recurrently during the year? I think she doesn't know that it's seasonal. Yeah. She's comparing with the previous quarter. And there's basically two things happened there. They're lower prices because of seasonality and lower volumes. So that's basically why. Yeah. The best quarters in Pampa and for power and gas is? Yes. Third and third quarter, particularly. Second and third. Second and third when the winter is. And Q4 is the weakest because it's the. It's always the transition, yeah. The transition from winter to spring and summer. And Q2, Q3, Q1, let's say Q1 is the first place. Q1 for 2025, January was not, I mean, it was not outstanding, but I would say that probably February and March are going to be so. The demand has been pretty strong, not only in Argentina, but also, as I mentioned, in Chile. So I think we're going to be looking at least from the gas standpoint to a good first quarter in 2025. Cool. Awesome. Next question. Well, Florencia Torres from MetLife, she's asking for the potential deregulation. I think we covered it all. Yeah. And this is another caller. She's asking for CapEx budget per business in 2025. Let me give you a reminder. We don't give guidance, but we do can share with you our budget initially right now. Again, read the disclaimer that we said. You want to say something about the budget of CapEx or I can tell? No? It's close to $1 billion, right? More than $1 billion. Total CapEx, $1.1 billion. Yeah. Total CapEx for this year around north of $1.1 billion, being Rincón de Aranda, about $750 million of that $1.1 billion will be deployed in Rincón de Aranda for the development of our shale oil reserves. Yeah. Basically, power and gas is just maintenance, right? Yes. Natural gas is just a few wells to be drilled this year, around four wells. We're going to be drilling, yeah, four. Drilling and completing. Four wells? [audio distortion] Right. We will be drilling one pad in Sierra Chata for 2025, and eventually, we'll start the drilling and complete, particularly the drilling of an additional two pads for 2026. Great. Great. Another question. How much do you expect Rincón de Aranda to contribute for the total EBITDA in 2025? Our estimated EBITDA for Rincón de Aranda is around $180 million for 2025. And this is for Gus. I know that it's only less than 1% of the EBITDA. Can you give me any update on the damages in Nihuiles? The damage on Nihuiles, there are three dams along the river. Two of them have been damaged, and the damage has been catastrophic. This is 130 megawatts between both of them of capacity. The damage, as I said, has been catastrophic. It's still very hard to get to the site because the road has been destroyed. We still, despite this problem happened several weeks ago, cannot access to the site with heavy equipment to do the remediation of all the damage. But we still have to do the assessment, the proper assessment of the damage of the equipment. That will take several months. So probably three or four months from now, we will be in the condition to say how much it will cost and how long it will take to get those two centrals, to those stations to be able to dispatch again. We have full coverage from the insurance company, both from a material perspective and also loss of income. Nevertheless, this is way below 1% of our EBITDA generation. So it's a very marginal issue for Pampa. Great. Andres Cirnigliaro from Balanz. I think we already covered, but not with this detail. He says, what's the FID? This is FID on the urea plant. What's the timeline? What's the estimates and production that we are thinking about? We are thinking about a plan of 2 million tons production per year that will consume about 3 million cubic meters of natural gas per day. That's roughly the size of the plant that we are estimating. And that's what we need to, one of the most important data that we are looking for is what will be the total cost of building this plant that we estimate it will be in the range of $2.5 billion. Timeline, we are expecting the proposals from the EPC contractors by the third or fourth quarter of this year. So it will be a decision that Pampa will be taking most probably by year-end. Very good. Pedro Letelier, he's asking if there is any progress with the conversion of the North Pipeline, gas pipeline, in terms of increasing gas exports. I think you addressed a little bit, yeah, in the previous question about Bolivia and Brazil. Florencia, again, she's piping up, asking regarding fuel procurement. While you're an integrated company, how easy is it for you guys to self-supply your plants under current infrastructure? Do you need further infra development to be 100% self-supplied? It's a weird question. I think your question relates to gas transportation availability. We have, for example, Loma La Lata, that is located at wellhead that doesn't need any transportation because of its location, so that can be easily supplied. In the case of Genelba, we do have some firm gas transportation capacity that we own. So we are able to service half of one of the CCGTs of Genelba. Other than that, we depend on new gas transportation capacity and having to acquire firm gas transportation capacity from future infrastructure being built. And the Iniciativa Privada, the private initiative that TGS has proposed and that we expect that will be that the process will soon move forward with the Secretary of Energy or with ENARSA putting in the street the bidding documents for that private initiative. That could be an alternative for Pampa to acquire gas transportation capacity for some of the remaining assets. We don't need to secure firm gas transportation capacity for all our assets. So only for those that we hope that they will be dispatched on a firm basis throughout the year, those are the ones that make sense to acquire firm transportation capacity. Yeah. Well, this is very important for this transition period of time. CAMMESA will still procure the PPAs at least. So it's never going to be. So far for this time period, time being, it's not going to be 500% self-procure, right? It's only for the spot. And as you said very well, for the peakers, it doesn't make any sense. Okay. Let's get to another question quickly. Tom Devine from Beekman Place Advisors. Cost of capital in general terms rank major segments of your business by expected return of capital. I don't know what question went on. Rank them. But cost of capital, the WACC. Cost of capital, you said. No. For For the impairment. For the impairment, we publish in our financial statements the footnotes and how we calculate the cost of capital by segment. If I remember correctly, I think for power generation, it's like 12%. For E&P, like 13%, no? And so on. Next question, the last one. Oh, no, the previous one. This is for you, Horacio. Regarding hedge contracts for oil, what's the length of the contract? As we mentioned before, we hedged May, December 25. There's one last question from f rom Bruno Montanari. When we talk about LNG project, you're talking about only from Golar, right? That is right. We're talking about the Golar project. Reviewing on my cell phone, there's no more questions. And just in time, in 1:00 P.M., just one hour, I thought we reached the top of the hour. Thank you so much, the three of you, for being here. Thank you for attending our conference call. If you have any questions, just email us. Raquel and I will be more than happy to help you. I hope you have a good day. We see each other next May for the Q1 results. Have a good day. Thank you. Thank you.