Welcome everybody to Pampa Energía's second quarter of 2026 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. Please send your questions in writing through Zoom chat. If anyone needs assistance, please send us a Zoom message. Before continuing, 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 to Lida. Hi, everybody. Good morning. Thank you for joining us. First, I would like to give you a quick summary of our announcement on fertilizers. This is a new business. Then a quick summary of the quarter, so we can move on to the Q&A. Today we have only our CFO. We have a small inconvenience with Gustavo, but I think we both can do it, right? Yeah. Let me go to the Slide 3, which you can see. Last July, our board approved the FID for the construction of, so far, Latin America's largest urea plant, officially marking Pampa's entry into the fertilizer business. Granular urea is critical to agricultural production and global food security, and it is primarily used in the production of corn, wheat, sugarcane, and barley. Because its main feedstock is the natural gas, urea production is highly concentrated in a few countries. While Argentina and its neighbor countries currently rely on imports from distant regions, today exposed to significant geopolitical uncertainty. The investment thesis is straightforward. It's just we aim to monetize the vast shale gas reserves that Pampa holds in Vaca Muerta through the development of high-value-added businesses. Natural gas and electricity account for approximately 70% of the production cost of urea and will be supplied by Pampa, reinforcing the competitive advantages of our vertically integrated business model while enhancing the project's operating efficiency and long-term profitability. Beyond diversifying Pampa's revenue base, the fertilizer business will also help Argentina's foreign currency generation through import substitution. We are substituting imports and increasing exports with an annual contribution of approximately $1 billion. Brazil, which currently imports between 7 million and 8 million tons of urea per year, together with the rest of the Southern Corn, which has an annual deficit of about 2 million tons, will be the project's primary market. The plant will be located in Bahía Blanca on a proprietary site, strategically positioned next to one of Argentina's main export ports, Bahía Blanca, with direct connection to Vaca Muerta pipelines, existing pipelines, and close to Pampa's thermal and renewable power generation assets. This is a $2.7 billion investment to build on a turnkey basis, a 2.1 million ton per annum plant, consuming 3.3 million cubic meters per day average year, and 75 MW of power, all again supplied by Pampa. The plan is scheduled to be completed by the end of 2029. Now that we have reached the FID, the next milestones are obtaining the RIGI and the Buenos Aires RIGI approvals, which are essential to the development of the project. Last Friday, the evaluation committee of the RIGI cleared FertilPampa's presentation. We are waiting for the formal approval to be published in the official gazette. Thus, Pampa continues to strengthen its industrial profile further through the several projects presented under the RIGI framework. We are currently participating in seven projects across oil, gas, midstream, LNG, fertilizers, NGLs. Last June, following the FID at TGS, our affiliate filed an application for the 3 billion investments on an integrated NGL project. Also, TGS's Iniciativa Privada, which consists in expanding the Perito Moreno pipeline, the San Matías dedicated pipeline for the LNG project, and the Rincón de Aranda. All those RIGI applications got approved. Overall, these projects provide a clear roadmap for Pampa's long-term growth, supporting Argentina's export expansion, and enable us to monetize Vaca Muerta's resources further. The adjusted EBITDA amounted to $415 million, highlighted by a quarterly all-time high production of 107.5 thousand barrels of oil equivalent per day due to the sustained ramp up at Rincón de Aranda and gas cell supply. The new regulatory framework also had a positive impact on our power generation segment, which benefited from the strong spot margins as high fuel costs impact and drove the marginal costs up the system. That helped. We have more B2B PPA sales. To the lesser extent, increasing the national prices also boosts the petchem business, which recorded its highest quarterly EBITDA since 2023, three years ago. Quarter-on-quarter, EBITDA grew 28%, supported by gas seasonality, stronger spot power margins, and increased petchem prices. CapEx dropped 21% year-on-year to $279 million during the quarter, of which 165 were destined to Rincón de Aranda. It is worth noting that we already invested last year, $900 million in Rincón de Aranda, and we expect to invest an additional $700 million this year as we move toward the 45,000 barrels per day production plateau, once the CPF and Vaca Muerta Sur oil pipeline are both online next year. On Slide 7, the oil and gas adjusted EBITDA was $182 million, more than double last year, driven again by Rincón de Aranda production ramp up. The gas cell supply to our power plants are resulting in higher output billing at stronger prices as fuel costs pass-through increase. These factors were partially offset by lower realized crude oil prices due to the hedge. Quarter-on-quarter, EBITDA increased by 74%. This is mainly explained by gas seasonality. Total lifting costs grew 30% year-on-year. This is primarily driven by Rincón de Aranda ramp up, partially offset by the divestment at El Tordillo, and lower activity at El Mangrullo gas block. Cost per BOE, however, remained broadly flat at $7.7 on average as production growth offset the increase in lifting costs. If we do double click, oil lifting cost per barrel actually declined 28% to $15 in Q2. It increased quarter-on-quarter following the commissioning of the second TPF at Rincón de Aranda that increased the crude oil treatment from 20,000 barrels to 28,000 barrels per day. Gas lifting costs also decreased 13% year-on-year to $1 per million BTU, but slightly decreased 6% sequentially due to the maintenance cost at El Mangrullo. Focusing on crude oil only, production increased three times year-on-year, purely explained by Rincón de Aranda. Realized price averaged nearly $59 per barrel. This is a little bit below last year due to the oil hedge. Without the hedge, the prices will have been $91 per barrel, resulting in approximately $64 million more of sales. Exports accounted 57% of total volume sold in Q2 2026. This is very similar year-on-year and quarter-on-quarter. Rincón de Aranda contributed one third of oil and gas EBITDA, up from 6% last year. Last year was only 6% and this year is one third. This year's quarter. This is continuing to diversify the production mix. Oil accounting 22% of the total output. At Rincón de Aranda, the ramp up continues. As you can see, the performance is comparable to the best blocks in the Core Hub, reaching a new record of 27,000 barrels per day on May 21, actually, specifically. Since March, we have not had tying new wells, just producing from 43 wells. Even so, Rincón de Aranda averaged 22,000 barrels per day, up 22% quarter-on-quarter. The quarter's exit rate was 16,000 barrels, temporarily affected by chokes of certain wells while we completed other neighboring pads, so we avoid the frac hit. These 10 wells in said two pads were completed in July and will be tied in in August. Well, now. Which will support a rebound in production. In Q2, we also drill another 10 wells for two pads. Currently, we have two high-spec rigs and one frac fleet operating in the block. For the remainder of the year, we expect to tie in those 10 wells that we drill and to reach an exit rate of 28,000 barrels per day. Our target remains a production plateau of 45,000 barrels per day once the CPF and the Vaca Muerta oil pipeline are online next year. Regarding RIGI, well, as we said previously, the application was formally approved on July 21 as a long-term strategic export project. The application includes the drilling and completion of 259 wells from July 2021 on, and the construction of the CPF, we are already building, oil and gas pipelines, and water treatment plants, facilities to treat the water flowback. Total estimated investment amounts to $4.5 billion, and it is expected to be deployed through 2041. The RIGI approval represents a significant milestone for Rincón de Aranda, providing a stable framework for tax, customs, and FX incentives for 30 years. Long-term strategic export projects are also eligible for specific benefits, in particular, the exemption, the waiver on export duties starting in the second year of operation after the enrollment. In this sense, Pampa expects to export all of Rincón de Aranda's production through Vaca Muerta's oil pipeline, which is estimated to generate approximately $17 billion over the project's useful life. Moving on to gas, production increased 10% year-on-year and 4% sequentially, reaching over 14 million cubic meters per day, driven by the gas self-supply to our CCGTs under the new power market framework, partially offset by lower volumes sold under Plan Gas, and to a lesser extent, reduced deliveries to large users. Seasonal demand from retail and CAMMESA explained the quarter-on-quarter growth, offset by lower self-supply procurement since we have faced transportation restrictions in the gas pipelines. During Q2, we tied in four new wells at Sierra Chata, bringing production to a new all-time high. At El Mangrullo, there were no new development activity, with production supported by the existing well base. At Rio Negro, four new tight gas wells were drilled, and two were connected. For the second half of the year, our plan includes drilling activity in Sierra Chata and El Mangrullo. This is aligned with our 2027 activity production plan, which considers the recently awarded transportation capacity at Perito Moreno pipeline, in which gas transported through new infrastructure is able to capture the full spot margin. In Q2, 56% of our gas was sold under Plan Gas GSA through CAMMESA and retailers, down from the 80% last year, following the transfer of these GSAs to our power plants for self-supply. As a result, intersegment consumption increased to 31% of our total sales. This is compared to just 3% last year. Under the new framework, we expect approximately 40% of this year's production to procure our own power plants' needs. Export volumes remain flat year-on-year at 1.2 million cubic meters per day. Industrial volumes declined as we prioritize self-supply demand, which is priced at a higher price because of the higher pass-through allowed by CAMMESA. This is seasonal and the regulation guidelines. Gas prices averaged $4.6 per million BTU. This is 15% higher than last year. This is reflecting higher fuel pass-through in power generation by CAMMESA, again, because of the winter season, plus higher retail prices following tariff increases above peso devaluation. Turning to power generation, we posted an adjusted EBITDA of $155 million in Q2. This is 39% higher than last year and 8% higher than last quarter, mainly driven by stronger spot margins and B2B margins under this new regulatory framework, as well as LNG procurement margin. However, this was offset by the mandatory maturity of Energía Plus contracts, the outage of Loma La Lata's gas turbine number 4, that is under a PPA, which is remunerated under a PPA, and the PEPE wind farms underperformance. As you know, the new guidelines will introduce marginal costs as part of the spot pricing methodology. That marginal cost overshot during the quarter, especially during the winter season, reflecting higher fuel prices, in particular using LNG and liquid fuel oil, diesel oil. The spot margins widened specifically for the CCGTs. Though that margin is capped at 15%. We only can capture 15% of that margin. That's what I mean. The current framework allows full margin, so you can capture the whole margin, if you're using new infrastructure, such as a gas pipeline, which that's the case for Perito Moreno pipeline. That will be online next May 2027. This full margin thing is not only benefiting power generation, it's also benefiting EMP, which will be producing more gas that now has security to be transported through this Perito Moreno expansion. Full capture, the FRA equals to one instead of 15%. Pampa was awarded 3.2 million cubic meters per day in the Buenos Aires-bound trench. It will be used to procure the gas needs of the legacy Genelba CCGT. We also participate in the second tender for the remainder of the Perito Moreno. We are waiting for the results. If the regulator grants the clearance, we should add another 0.7 million cubic meters per day to the Buenos Aires trench, plus another 1.3 million cubic meters per day in the Bahía Blanca trench. Total availability fell to 88% during the quarter, mainly due to the ongoing outage in HINISA, which now is currently, since July 31st, is no longer part of Pampa. We had some outages also in Güemes and in the mentioned Loma La Lata TG number 4. Barragán also has some scheduled maintenance. Even though it's 88% availability, we continued to outperform the peers in the national grid. 35% of the capacity was contracted, slightly higher than Q2 last year. This is reflecting the new guidelines that boosted the B2B PPAs. Going to the financial part. Turning on to the cash flow in Slide 11. We present the parent company figures, which aligns to our bond parameter. Free cash flow was negative $128 million in Q2, but improved year-on-year and quarter-on-quarter. This is mainly due to stronger EBITDA generation and lower CapEx at Rincón de Aranda, and receivables due to the better collection, though this is impacted by higher winter sales. Quarter-on-quarter improvement is explained by the release of collateral on our Brent hedge as oil prices declined. As a result, cash and cash equivalents stood at $1.3 billion at the quarter end, $604 million more than Q1. On the balance sheet, gross debt as of June was $2.6 billion. This is mainly because of the re-tap of 2037 Notes priced at the lowest spread to the T-bills, U.S. T-bills in Pampa's debt issuance history and corporate history, I must say, Argentine corporate history. Net debt rose to $1.3 billion, representing a net leverage of 1.4 times to the last 12 months EBITDA. Concludes now this presentation. The floor is open for questions. If you have a question, please send it through the Zoom chat. We will read it first in, first receives, first served. Make sure your name and your company is there. Otherwise, we can just read it. We can also reintroduce you to the audience. Should any participant have assistance, just send us a chat through the platform. Thank you. Wait while we poll for questions. [Foreign language] Should we start? With the new expansion projects that Alejandro Demichelis from Jefferies is asking, how do you see CapEx in the next 2 to 3 years? At what level do you expect debt to leverage to peak? Good morning. Thank you for the question. Yeah. Evidently, we're facing challenging CapEx deployment, especially with the urea project. Also bear in mind that EBITDA, looking forward, should increase as well. Once we achieve maturity of the Rincón de Aranda investment and the Southern Energy and San Matías pipeline investments by 2028, cash flow generation will be increasing and stable. What we foresee is that net leverage should increase from current levels up to a maximum of around two times. The ratio should vary between one and a half and two times for the next two to three years, until we finish the investment in the urea project. Great. The CapEx this year is basically around $1 billion, right? Yeah, the CapEx this year is around $1 billion, mainly the Rincón de Aranda project. Next year. It's a little bit lower it's lower. Separating urea project, it will be around $700 million CapEx next year. Again, mainly Rincón de Aranda project. After that, Pampa will have only maintenance CapEx of all the business units in around- 600 600. Yeah. We have to add to that the equity contributions from Pampa to Fertipampa. Yeah? Cool. Guido Bizzozero and Santiago Herrera from Allaria, they're asking, after these 23 jump in EBITDA for the first half of 2026, how do you expect to evolve the second half and 2027 power generation? Considering in 2027 that in the second half starts rolling out the PPAs. Do you want to? Yeah. The second half of the year, remember that always the last quarter for Pampa is the weakest due to the seasonality of gas. Power demand, actually. Power demand. Power demand. Bear that in mind. Always the last quarter is a little bit weaker. It will be partially offset by the increase in the production of Rincón de Aranda. The oil business will keep growing. Remember the seasonality in the other segments, right? I think he specifically only refers to power generation. Q3 is going to be higher than this one? That's what we expect because winter is- Q4 always is Yeah. First half is $299 million of EBITDA. We expect $600 for this year. Yeah, $600 million for this year. Basically, it jumps up in Q3, if winter allows, and then goes down. It's specifically because the Niño, right? There's more water, so it means lesser thermal power demand. In 2027, it's a combination. Second half starts rolling out PPAs, we also have the TGS' Iniciativa Privada that, hey, we have 3.2 million confirmed that we will inject it through Genelba's legacy, CCGT. Actually, it's going to start before the winter, so the most of the impact will be monetized next year, though it starts in May. Next year's EBITDA, it could go up. We are expecting 600. Well, a delta of around $100 million should things, the winter and the liquid fuel consumption, energy consumption remains pretty much similar. In 2028, as you correctly said, it goes down. It's a combination that in 2027, the PPAs rollout doesn't much reflect because it's towards the end of the year. In 2028, you should see that it's a little bit low. It's $40 million less because the PPAs roll out, but at the same time, they join the spot market. Loma La Lata, out of the PPAs that roll out, two of them are at Loma La Lata. Loma La Lata is highly competitive because it doesn't require any gas transportation. They are very efficient machines, so they kind of rank senior among the thermal units in the system. I hope that answers the question. How do you expect to increase the stake of gas used and sold to power generation, since we noticed an increase from 3% to 31% year-on-year basis? Well, basically, as I said in the call, the average of this year, it's around 40%. It should pick up in Q3. Actually, picks more. It's highly reliant on self-supply on Q4. The demand and gas demand goes down; we expect no troubles in the gas transportation system. Going forward, 2026 is a gradual year. It's a transition year. 2027 and onwards, you should expect the following. The thermal units consume around 10 million. Only Pampa, not including Ensenada and Varese. 10 million cumeters per day, of which 8 goes to the CCGTs. 8 Loma La Lata CCGT and the 2 CCGTs are Genelba. The CCGTs are the flat consumption of gas for self-supply. That's what you should expect going forward. Third question from Allaria people. How do you expect petrochemical business to evolve in the future, considering the 5% contribution to the consolidated EBITDA this quarter, when it usually is negative or slightly, or break even? What it is, right? Yeah. We expect to continue contributing marginally to the EBITDA. It was something circumstantial. Due to the war and the high prices and bigger margins that we have this quarter in some of the products that we export, but we don't expect that to hold in the long term. Correct. Can you give any color on how do you plan to finance the $3 billion capital urea project and the deployment along the 41- month work? Sure. Since the beginning of the year, we've been working intensively in the financing. The idea is to finance the project through a project finance loan with limited recourse on Pampa. With that in view, we started in February, a very thorough due diligence. We've been working in six open fronts with different independent consultants to complete that due diligence and make the deal bankable. We are close to finalizing the due diligence process. We hope to end the process in August. We are negotiating the terms of the loan. I cannot disclose much more today, but I will tell you that we are well advanced. We are discussing the terms, and we expect to finance a proportion around 60/40 equity loan ratio. The deployment of the equity is more or less even except 2028. There is a big spike of the CapEx is concentrated mainly on 2028. I will say one-third of the CapEx is on 2028, and the rest is evenly distributed on the remaining years. I will think that we start contributing capital to the project this year. The financing will be closed by the last quarter of the year, probably. The big contributions, both of debt and capital, will be on 2028. I think that covers the question. Yeah. How much revenues and EBITDA we may expect to come from this urea project on a consolidated basis, considering more electricity and gas will be needed to produce urea? Yeah. Well, the revenues, I think we already disclosed that. Where? Yes. $1 million. Yeah, yeah. Yeah. $1 million. $1 million. The math is pretty simple. Depending on the price of urea you take, you multiply 2.1 million tons of urea per year times the price of urea you would like to choose, $400, $450, $500, and that will give you the revenues. EBITDA will be around 65% of that. Again, you have to factor in the price and the net backs, whether you sell to Brazil or to Argentina, or what combination, those are the big numbers that you can easily compute. What was the rest of the question? No, how much impact on Pampa's EMP and power? It is a very good question. Very good question. Yeah. Remember that starting 2028, the GSA starts to mature. Correct. It's not clear that we are going to increase gas production for the project or substitute current production from one market to the project, okay? That is something we will have to decide moving forward. assuming. If we increase gas production only for this project, it's around $90 million. $90 million of EBITDA additional to the gas segment. Again, it's a decision that we will have to make in the next three years, okay? The price is around $3. The price is $3. $3 is our internal GSA. Internal GSA, yeah. Yeah. Consumption is $3.3 on average, year average. Yeah, it picks up. In winter. In winter. On average, it's 3.3 million cubic meters of gas per day. in power, we are not planning to build new power facilities for this. Well, we don't know. Not for this. Not for this. We will see. We will. Again, the power contribution is marginal. Marginal. The big contribution here is gas. Yeah. Imagine, well, today we are selling B2B PPAs at $65. Monomic price, right? This is considering capacity, $65 to $70. Well, we were talking about the B2B PPAs boost in this quarter, basically because people are seeing the prices in the spot. If you go to the spot, the prices are really high. That's why when this deregulation started, the industrials didn't start to get into the B2B market, now they're getting into because they seem highly seasonal. It's better pay flat at a certain price of around $65 to $70 per MWh, which is this is what we expect to sell in this- Yeah, it's around $68- Yeah The consumption is 77 MWh. Again, it will be additional energy capacity rather than replacement of- I imagine myself using our renewable wind power. That's the plan, yeah. Yeah. Back up with our thermal units. Exactly. Yeah. Another question from Allaria. People saying, considering the current production levels at Rincón de Aranda and the 10 wells are scheduled to be connected in August, what kind of production ramp-up can we expect between now and the end of the year? Okay. Remember that the goal this year is to reach the 28,000 barrels of oil per day. This increase is like a seesaw, okay? You are tidying up wells, closing, tidying up, closing, you will see these peaks and throws of production, but the goal is to achieve the 28,000 barrels of oil per day by the end of the quarter. Again, it's not constant. The same will happen next year when you try to reach the 45,000 barrels of oil per day. The increase will be like a seesaw and a ramp-up until the 45. What else? Bruno Montanari from Morgan Stanley, he asks, "How can we think about Pampa's long-term peak gas production considering the volumes to CESA, to their project, the sole procurement for power generation?" Well. Yeah. Well, that's flat actually. Yeah. What we foresee, and this is not a projection, it's a budget, if you like. Imagine that we can procure to our own power business around 10.5 million cubic meters of gas per day, another three and a half to our urea plant, another six to the floating LNG to CESA, to floating LNG project. 1.5 for exports. 1.5 for exports. If you would add up. A little bit during the peak is around 20- It's around between 20 and 22- Peak. Peak. Peak. Flat average is 20. Yeah. It's around 20 million cubic meters of gas per day. Quite constant because we are selling intercompany, we avoid the seasonality. Yeah, that is what we foresee in the next three to four years when all our projects are online. As you can see here, no retail. Assuming no retail. Yeah, assuming no retail. No CAMMESA power source contention during the winter. Yeah, it is 10 to our plants, three to our urea plant, and six to our floating LNG plant. Yeah. 10 is assuming all the plants. Yeah. CCGTs only is eight- Yeah which is the baseline, right? Yeah. Bruno also asked a very good question. Once we reach this peak, how long can we sustain it at the plateau and what will be required CapEx to sustain at that level? It's a very good question because we have a lot of gas. Assuming 22 Well, let's do it very conservative. Assuming 20 million cubic meters per day of annual production, and with the current, not saying resources, but 2P reserves is around securely 25 years of average life. This is only 2P, not even including the 3P- Resources yeah, the resources and so on. How much required CapEx? Well, if we're doing the math and assuming the average well type of our shale gas blocks is around $250 million to $300 million. Obviously considering also the CapEx to maintain the treatment plants, it's around $250 million to $300 million of CapEx per year. Okay. Can you talk about the funding strategy of urea? We talk about it, right? The funding of urea project, the strategy. We talk about it. Yeah. Yeah Yeah. Well, it's what Lida presented. On the one side is to monetize our gas reserves, which is a perfect fit. On the other hand, urea business per se, which as Lida explained, the region needs a lot of urea, and it's coming from faraway regions, very unstable regions. It makes total sense to reduce logistics cost and procure ourself our own urea for the region, and don't depend from wars or geopolitical risks. The third opportunity is the RIGI framework, which makes this project possible. The fourth, I will say opportunity is our balance sheet. We have a lot of cash and low leverage. We've always been asked why we have so much cash, and one of the reasons is for this. We were waiting for opportunities like these ones to show, and we are ready to deploy the cash. We're not afraid to use our balance sheet that is very unleveraged and grab these opportunities and profit from them. These are the four main angles of the project. Well, actually, it's not a bad timing to just say this. It's 100% owned by Pampa. Yeah. Right? Bruno is also asking, well, about the debt. Can you share something about the tenor, the interest cost? Well, I cannot share about the interest cost yet. We are negotiating. What we can say, which is pretty obvious, is given there is a project finance we have a spread over our bonds, for example. Okay? We will see finally where we land the cost, we cannot foresee that. For sure, most likely, the profile will be four years grace period while we build the plant. The maturity, it is not close, but it will be closer to seven years or something like that, give or take. The last question from Bruno is about lifting costs of oil, obviously. Can you expect a normalization following the recent increase driven by the new TPF? The TPFs are rentals. They cost around $5 million per month. Basically, we commissioned a second TPF, but the production didn't go up because we choked some wells, so we avoid frack hit in the fracking of other pads. Now that everything is fracked, everything it's done, we can connect all the pads and resume the choke ones and connect the new ones. Right? Right now, we expect an exit rate of lifting cost of around $10 per barrel with the two TPFs. Once the TPF is online and also considering the fact that the production will ramp up, we are expecting $5 by second quarter of next year, because we expect the TPF to be ready by first quarter of next year. Alejandro Christensen from Latin Securities, he's asking, how should we think about the shell gas lifting costs over next year and with CESA coming online next year? This is a very real question because, it's all about, are we going to be highly seasonal or not? Today it's difficult to think going lower than what we are right now, around $0.80. We are now on an average year of $0.80 to $0.90 per million BTU. If we are only producing flat volumes, it could go a little bit lower, but not more than $0.60, $0.70. We'll see. Today, this is it. It's highly seasonal. We are flooding more the curve, but still highly seasonal. About following the RIGI approval, when do you expect to begin drilling acreage in the north of Rincón de Aranda, and what are your initial expectations for the productivity there? It's a good point. I would like to clarify something because we read a report stating that we were closing wells and holding back the completion of wells for the RIGI approval, and I want to clarify this is not the case, okay? Only new drill wells will enter the RIGI. All these wells that Lida explained, the 10 wells that we were fracking and are completing now, they are not in the RIGI project. They are from before. Okay? We didn't do that because that does not apply to the RIGI. It has nothing to do with that. Not to complicate. Yeah. It's a technical thing that not to parent-child effect. We close some wells to frack another, and they don't destroy each other. That was the reason. It has nothing to do as that report stated, that we hold back the completion of the wells. Having said that, the North Park. The North Park Yeah. We have some seismic works before when we started with Rincón de Aranda, now in September, next month actually, we are going to start a more comprehensive seismic studies in that area and do a more detailed work there according to Well, Horacio didn't join us today because he's in vacations, but the team already let us know that they're working in the North Park. The northeast boundary, the boundaries of Vaca Muerta. Productivity rates, we expect to be lower than the parts that we are developing right now. That is the south strip of the block, right? Once that seismic works are done, and all the studies detail and through, we think that we could start drilling there in next 2028. 2028, end of 2027. So far, we're concentrating the south strip where most of the well inventory is located. On the Perito Moreno expansion, which specific units do you expect to benefit from FRA1? We already talked about it, Genelba. If we get awarded in the second trench, we can use it for the peakers in Buenos Aires bound trench, which is Pilar. Ingeniero White is for the Bahía Blanca. Piedra Buena. The peakers will be used, but only seasonally wise, not year flat. The one that is consistent the whole year is the legacy Genelba. How much of their dispatch could cover? The already awarded, the whole legacy CCGT on Genelba, and a little bit more. The rest, we can use it for specific days for trading at City Gate, for trading of gas at Buenos Aires or a little bit to be used in the peakers. We'll see. Specifically in the winter season. Beyond the transportation prepayment, will any additional CapEx be required for the plants? No. It's just what it is. With Plan Gas.Ar expire at the end of 2028, do you see integration strategy shifting toward transferring gas at lower prices to your plants and declare more competitive CVPs and maximum dispatch? Actually, this quarter is the proof of that transferring the Plan Gas.Ar volume to ourselves is better, right? Because if we didn't transfer the Plan Gas.Ar, we will be billing at four and a half. Now, we are billing at higher price because CAMMESA allows a higher pass-through. I will say average-wise, it must be better than the Plan Gas.Ar's average price. We'll see. I think the CCGTs have the most competitive advantage against all other units, right? All other in the peers and in our own portfolio. They will pass through whatever CAMMESA is allowing, so that's how they are going to maximize the dispatch. I think what your question is referring to is to the peakers, and that depends. Bueno. Zafra asks about the potential unlock in Rincón de Aranda with the North Park. We already answered. Expectation for another project this year and next year. We already answered it. CESA, FLNG. Yeah Urea, right? In general, you have to expect any project in our core businesses, which are power, gas, oil, and now fertilizers. We will participate, and we will look at them, and look forward to increase if there is the right opportunity. Austin Pacheco from Maria also asks about the financing of urea. Already answered. Alvaro Leyva from BTG is asking the same. Already answered. CapEx deployment of our urea project, we already answered. Given the still favorable oil market outlook, at the fact that it generated $64 revenue losses in Q2, would you consider unwinding the hedging position? No, we won't. I think we answered this in the previous call, that the idea is to keep this level of hedge, and naturally, as production increases, we'll have a big portion unhedged. We keep current production hedged, and whatever comes on top of that will remain unhedged. That was the original strategy, was to hedge the ramp-up until the 45,000 barrels, and this is what we are doing. Once we reach that plateau, we still have to define, but in general, what we will foresee is that the percentage of hedging will be reduced. Cattaruzzi from AdCap, he asked about petrochemicals. We already answered. He also asked about the target gas production long-term. We already answered. Milene Carvalho from J.P. Morgan. Well, all question and answer. Hey. From urea, she asked about the EBITDA contribution from urea. Answer. Yeah. The gas price for urea. Answer, $3 per MMBtu. The same as FLNG project, right? How much gas is required? Answer. Incremental CapEx for EMP for this 3.5, assuming that it's additional. I did the math, and it's not much. It's like- Should be 100 and- It's $100 million of CapEx, EBITDA. $90 million of EBITDA. Less than $50 of additional CapEx. For the 20 million productions, we are calculating a maintenance CapEx of $250 million to $300 million. That's the range. Well, balance. Andre Sirignagliano asking about the CapEx facing of urea. Answer. I'm saying this because we want to be clear. Cover all the questions. Transparent. Yeah, transparent. Puente, Juan Ignacio Lopez. Okay. Si. [Foreign language]. Juan Ignacio Lopez from Puente. He's asking, we are seeing a very impressive environment for natural gas sales in the domestic market beyond the usual seasonality. I would like to ask what you attribute this improvement to, effects of the Resolution 400/2025, the deregulation, or increased pressure in the domestic market for high international prices? How do you expect this dynamic to evolve over the coming quarters? Yes, it's true. CAMMESA during the winter pass through, they are linking it or associated with the international prices of LNG. That's why we can pass through higher prices. Also, the resolution contemplates this deregulation in the procurement of the gas. Remember that before it was all centralized at CAMMESA, and now it's more and more decentralized. Just to give you an idea, CAMMESA used to be procuring the whole gas and the whole grid. Now it's doing it one-third actively. Roughly numbers. Another one-third, they say, "Okay, I'm using my plant gas and giving it to you, and you pay me back the price," which is called the assisted by CAMMESA. Then the one-third, which mostly is ours, it's self-procure gas from power plants, which is our case. The idea of CAMMESA, it's going more and more to an assisted scheme, but when plant gas is rolled out, the idea is not to reengage it. It's just all procured by the power generators. Sofia Gran. I don't know who is she, but basically, she's asking, the CAMMESA percentage, 26%. Yes. Gas sales. Gas sales? [Foreign language]. Have any of these contracts or volume been transferred to the power company or self-management to supply? I understood that. Well, this is what we can transfer. We couldn't transfer more of this because the one contract outstanding to transfer is ENARSA. The last round of Plan Gas.Ar, okay, the 4.2 round, minus that. The last round of Plan Gas.Ar, which is around 5 million cubic meters per day, with peaks during the winter, that one hasn't been transferred yet. As you can see, that's why we still are selling to Plan Gas.Ar, specifically to CAMMESA retailers, 56%. For example, in Q4, it should go down dramatically because CAMMESA Plan Gas.Ar retailers won't demand much gas due to seasonal reasons. Matthew Poots from Fidelity. He asked about the equity and debt structure for urea plant. Yeah. We already answered. We're not trying to maximize the leverage on the project because the idea is to deploy our cash and future cash flows into this. That's why we're not having any partners, and that's why we're not maximizing leverage. We expect a structure of around 60/40. 60 debt and 40 equity. Still, everything is under negotiations, but we are expecting around $1.4 billion of equity in the next 41 months. Santander, Walter Chiarvesio, he's asking repeated questions as well, but he's asking about the gas production until 2030 breakdown. We already- Discussed that. discussed that. Andrés Cardona from Citi. Actually, he's asking, when looking at the diversified portfolio, is there any asset you consider non-core and could be eventually divested? This question- I think was answered when I explained our core businesses. That's self-explanatory, which is petrochemicals. Ramiro Guerrero, Bull Market. How much volume of Rincón de Aranda remains hedged through May 2027? At what weighted average price, and what additional cash collateral settlement and cash outflow should we expect under different Brent scenarios? How much is hedged from our production? That's the first question. Until when? We hedge all our production until first quarter of next year. Yeah. Until May. Until June. First quarter. No, my bad. Okay. First quarter. Little bit less than one year of hedge. Yeah. Weighted average price? $67. $66. $67. $67 of Brent. Yeah. Right. What additional cash collateral should we expect if, I don't know, different Brent scenarios, right? Today is $80. Well, with the price, you can see how much it is. Depends on the mark-to-market decisions. Ricardo Cavanagh from Itaú. Impressive investment pipeline, thank you, that expands your business franchise phenomenally. Another thank you. How do you define in one sentence what is Pampa now and its vision? Thank you. One sentence. In one sentence. Tough. Yeah, because it's 12:00 P.M. In one sentence. Growth. Yeah. Growth. We are an Argentine company that invest heavily in Argentina and tries to monetize the reserves in Vaca Muerta through all our industrial segments. That is power, urea, LNG, et cetera. Headliner Pampa Energía is an Argentine company that invests heavily in Argentina and is an industrial energy company, integrated energy company. That is the The tweet. The headline. Augusto Soto Baumann from Rosental Inversiones, he's asking on the receivables. You mentioned working capital seasonality, but receivables still increase significantly in this quarter. Where are the key drivers on operating cash flow? Very good question. Why increase? Because we are selling more gas. Compared to last year, Q2, we are selling 2 million more of gas. The prices are higher. At higher prices, here you have it. We are selling more oil, three times more oil than last year, 22% more than last quarter. Part of the gas we revert on the following quarters. Yeah. Correct. We sell it now; we collect it 45 days later. This is very important. Previous quarter and previous year, the days of sales outstanding was way higher than now. Now we are at five days of delay, so it means 47 days of total collection days, while last quarter was 50-something, and previous year was way higher because it was accommodating. DSO, it's improving, specifically from our largest clients, which is CAMMESA and ENARSA, at the same time, we are selling more. 12 days delay. So, 12 on top of the 42, so it's 54. Math. Could you please understand Well, was it mainly export timing? No. Export is flat. It's 65 days. There is no increase or decrease. It's very certain. about the receivables. CAMMESA or subsidy-related balances. How about the CAMMESA? CAMMESA is paying better. CAMMESA is paying, yeah. Better. No major delays in CAMMESA. Yeah. The subsidy, it's very important to say that it's getting smaller in money terms because something very important is that retail prices are increasing. If the retail prices are increasing, the subsidy part is smaller. Now it's just $15 million per year or something. Should we expect this to normalize in the second half, or is it new structural level as exports continue to grow? Exports, forget it. They- The receivables of exports. It's the same. We are exporting the same. Wait. Q3, we are going to collect what we sell in Q2, obviously. winter prices. Q3 is higher winter prices and higher sales. You should expect higher receivables. In Q4, usually, we collect the receivables. It's a surplus. It's an inflow, no outflow. That's how you should think about it. Lilyanna Yang from HSBC, a quick update on TGS. [Foreign language]. TGS, well, they have their call already. Yeah, they have. I think that the two main takeouts are the two big projects TGS is performing. One is the Iniciativa Privada, that should be commissioned by next winter. The other is the big NGL NGL, sorry, NGL project, as you know, that they are already announced the FID, and they're working heavily in the financing. They're awaiting the RIGI approval of that project. I think those are the two main, Drivers main news about TGS. If you look at the results, they were outstanding. They improve every line of business. Utilities, the prices, the tariff. Looking forward, it's a very encouraging company. Doing well. Bueno. The last question so far, and that's it's Pedro Letelier. I don't know where he is, but I know him. The province of Buenos Aires has its own investment regime, the RPIE. Is there any conflict with the government's RIGI that could impact- No the Urea project? Not at all. We filed for both. We filed for the RIGI, that we have been approved by the RIGI committee. We're waiting for the publication of the approval in the official gazette. We also applied to the provincial regime, and we are awaiting approval. There is no conflict at all. On the contrary, they're quite What is it? Proactive. Yeah. Complementary. Complimentary. Thank you. They're quite complimentary. The additional benefit from the provincial is a tax break. Gross sales tax Gross sales tax. Yeah. That's the main takeout. Hopefully we'll get that approval as well. Yeah, we talk about this. RIGI's pre-approved. Yeah. There is no conflict between the two. On the contrary. That's it. Great. All right. Thank you everybody for joining us this call. Thank you, Fito, for taking all the questions. Fito, would you like something more? Say something more? One hour. Perfect. Perfect. Thank you very much. Thank you very much. Any questions you may have, just let us know, email us. We are more than available to help you. The next call is due November. Hope to see you then. Bye. Thank you.