Pampa Energia S.A.

And we would like to welcome everyone to BAMPA Energías first 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 message in the Zoom chat. 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 to Lidia. Thank you, Lidia.

Hi, thank you, Raquel. Hello, everyone, and thank you for joining us. I will make a quick summary so we can spend more time on the Q&A with the senior management today. We have our CEO, Mr. Gustavo Mariani, our head of oil and gas, Mr. Horacio Turri, and our CFO, Mr. Adolfo Zuberbühler. So, in Q1, production seeded 100,000 barrels of oil equivalent per day, reaching a new quarterly all-time high, driven by the sustained ramp-up at Rincón de Aranda and higher gas outputs under the new power generation framework. Rinconeranda, which began ramping up a year ago, is now producing approximately 25,000 barrels, 1,000 barrels of oil per day today. With the new regulatory framework, we also had a positive impact on our power generation segment as our non-PPA CCGTs benefited from stronger spot margins dispatch margins. Also, leveraging our solid balance sheet, in April, we successfully issued $200 million in three-year bullet notes at a highly competitive rate of 5.49 fixed rate. Adjusted BDA amounted to $325 million. This is 48% up year-on-year. As mentioned before, Rincón de Aranda, gas operations, and power generation were the main contributors. Rincón de Aranda alone represented 17% of the quarter's total EBDA, increasing eight times versus Q1 last year. Quarter-on-quarter, EBDA grew 41%, supported by synergies between gas and power businesses. self-supply gas for thermal dispatch, enhancing spot margins. The CAPEX rose 36% year-on-year to $242 million during the quarter, of which $163 million were invested in the development of Rincón de Arana. Moving on to the slide four, The oil and gas adjusted BDA was $104 million in Q1, two and a half times last year, driven by Lincoln de Aranda, higher gas production for self-supply to our thermal power plants, exports, and industrial demand. These factors were partially upset by lower realized crude oil prices and higher royalties, transport, and treatment costs associated with with the production growth. Rincón de Aranas contributed 54% of the segment's ABDA in this quarter, up from the 15% last year. Quarter on quarter, ABDA increased by 36%, mainly due to higher gas demand for CCGT self-supply and exports to Chile. As we mentioned before, total production averaged more than 100,000 barrels equivalent per day, primarily contributed by Rincón de Aranda and Sierra Chata, partially offset by lower output from our non-operated locks and in Mangrush. The production mix continued to diversify, with oil accounting for 19% of total production entirely driven by Rincón de Aranda. Lift-in costs averaged $6.1 per BOE. This is down 11% last year and 23% sequentially, explained by higher oil and gas output, outpacing a stable cost base, and the divestment of mature non-operated oil assets. Gas lift-in costs decreased 10% year-on-year to $0.90 per million BTU, and 23% quarter-on-quarter lower. This is supported by higher gas output. Oil lifting costs equate sharply to below $10 per barrel from $41 in Q1 last year. Thanks again to Rincon Yeranda's ramp-up and the divestment of mature fields. Focusing on crude oil, output multiplied by 6 year-on-year, to 19,500 barrels per day. As Rincón de Aranda ramped up following the commissioning of the Duplicar Trump pipeline last April, last year's April, realized prices averaged $58 per barrel in Q1. This is 15% lower than last year due to the old hedge. Without the hedge, realized prices will have been more than $69 per barrel resulting in approximately $21 million of additional revenue. Exports accounted for 55% of total volume sold in Q1. So, at Rincón de Aranda, the ramp-up continues to progress as planned. Average production during Q1 reached 18.2 thousand barrels per day across the 43 producing wells, up 7% quarter-on-quarter. In Q1 last year, production was below 1,000 barrels per day. During Q1 this year, 6 wells were drilled and 15 wells were tied in, of which 7 came online last March, bringing the quarter's exit rate to more than 21,000 barrels per day. For the remainder of the year, we expect to tighten an additional 20 wells and reach 28,000 barrels per day milestone by mid-this year, mid-2026, supported by the second temporary facility that was commissioned in late March. We target a production plateau of 45,000 barrels per day once the central processing facility and the Vaca Muerta oil sewer pipeline are online. It is worth noting that Rincón de Aranda completed its first full year of operations with clear efficiency gains already visible. Drilling performance improved from 200 meters per day on the first pad last year to nearly 330 meters per day on the most recent pad. This is more than a 50% improvement. Completion activity also improved from almost seven to nine stages per day an increase of over 30%. This improvement reflects the team's consistent execution and shorter cycle times across the development program. Also, on March 9, we submitted the project's application to the REHE incentive program, which is expected to accelerate the development in the northern area of Rincón de Aranda. support a fast ramp-up, and sustain plateau production for a longer period. The estimated investment under the project amounts to $4.5 billion, including new shale oil wells and associated infrastructure. Approval remains pending. Okay, moving on to the gas, production grew 17% year-on-year and 28% from Q4 to almost 14 million cubic meters per day, driven by gas cell supply to our CCGTs under the new power market framework, higher exports to Chile, and stronger industrial demand. Exported volumes increased 65% year-on-year from 900,000 900,000 bottle, 1,000 cubic meters per day to 1.5 million, yeah. And we expect these levels to continue for all the remainder of the year. El Mangrush and Sierra Chata, our two operated blocks, accounted for 88% of the total gas production. No new wells were connected during the Q1, although a new path tied in During the Q4, Sierra Chata explains the 70% year-on-year growth, while Mangrusha just dropped slightly, 7%. During the quarter, Sierra Chata drilled three new wells, so completed the four-well DUC path. For the second half of the year, the plan includes drilling two additional paths and tying in one pad before the winter, in line with the seasonal gas demand from our power generation business. At El Mangrucho, the plan is just to drill a six-well pad, which will remain as a DUC inventory. Gas prices average $2.9 per million BTU, flat year-on-year, due to the export. Lower export prices, offset by higher retail costs, prices as tariffs increased above peso valuation. In Q1, 47% of our gas was sold under planned gas GSAs through commercial retailers, down from the 82% exposure last year, following the transfer of said GSAs to our CZGPs. As a result, interco consumption, actually intersegment consumption, increased to 32% of total sales compared to just the marginal 2% last year. Under the new framework, we expect approximately 40% this year's production to supply our own power generation assets. So for power generation, in the slide seven, we posted a adjusted PDA of $144 million in Q1, This is 11% year-on-year and 30% quarter-on-quarter increase, mainly driven by stronger spot margins at our CCGTs under the new guidelines in the wholesale electricity market, which operates under a marginal pricing system that benefits efficient units. So total availability fell, though, to 90%. mainly due to the ongoing outages in Iwiles since January last year, and the outage that we had in the gas turbine number four in Loma de Alata, this is not a CTGT, which is expected to return in service next month, in June, and is scheduled maintenance at Barragán. However, Pampa's thermal availability continues to outperform the peers in the national grid, as you can see in the charts. In addition, 32% of our result capacity was contracted in the B2B market, whereas PPAs were in the maps, covering the levels before the implementation of the framework. Regarding the expansion of the Perito Moreno gas pipeline and its final sections toward Buenos Aires metro area, on April 15, PGS awarded the tender's first trench correspondent to 4.8 million kilometers per day out of the 12 meters per day of expansion in the transportation capacity. This is 40% of the expansion. Pampa Secure, 3.2 million kilometers per day, representing 27% of the expansion capacity and two-thirds of the first transgender. The transportation contract is for 35 years, undertake or pay, or in this context is cheaper pay, and requires prepayment of the first 15 years of tariffs, which in our case amounted to approximately $340 million, BAT included, payable in four installments with final maturity in next year, April, The expansion is expected to begin operations during the winter of 2027. Participation in this gas pipeline expansion is underpinned by a clear economic rationale. Under the new power market framework, electricity generated using gas transported through new infrastructure, such as the Perito Moreno and its final sections expansion, captures the full dispatch, margin when sold in the spot market with a FRA or FRA equal to one. Therefore, a new deregulation guidelines creates two key drivers of profitability for Pampa. They secure additional transportation capacity for additional gas produced from our upstream operations for self-supply, enable further modernization of our reserves, Second, it enhances the profitability of our power generation assets, particularly our CCGTs. So, turning on to the cash flow on page 8, we show the parent company figures aligned with the bond parameter. Free cash flow was negative $404 million in the Q1 period. explained by collateral requirements related to the oil hedge, extensive, intensive capex at Rincon de Aranda, and on top of that, we have the payments associated with last year's capex, and a slightly higher base of sales outstanding, offset by strong EBITDA generation. As a result, cash and cash equivalents stood at $677 million at the quarter end, $414 million less than Q4. Finally, on the balance sheet, gross debt as of March was nearly $1.9 billion, similar to the end of 2025, but the net debt rose to $1.2 billion, representing a net leverage of 1.5 times to the last 12 months APDA. Well, so this concludes our presentation. Now the floor is open for questions. If you have a question, please send it through Zoom chat. We will read it and answer in the order received. Make sure your name and your company's display correctly to introduce yourself to the audience. Should any participant need help, please send us a chat message. Please hold while we poll for questions. Thank you. Okay, so Guido Bisocero from Alaria. Considering the awarded 3.2 million kilometers of gas capacity in the Perito Moreno pipeline expected for May, well, yeah, in winter 2027, how much annual revenue and EBTA contribution do you expect from this? Can we forecast a similar award? First, how much do you expect?

Fair enough.

How much do we expect? It's not an easy number to provide because it will depend basically on what will be in the winter of 2027 and in future winters, what will be the prices, the marginal cost of the system, and that will be dependable on prices of LNG and prices of diesel oil, and how many days during the winter those fuels will be set in the marginal price in the system. To give you a rough idea, we think It could be in the, but again, this is dependable upon many estimates that could be in the range of $100 million. That is basically what we are expecting because of, as Lida explained, With this firm capacity of gas, we will be able to capture the full margin, not only the 15% margin, the 15% that the current regulation allow us to capture.

This year, though?

This year, yes. This 15% increases up to 35% by year 2028. No, the English 2030.

Okay.

So that is the rough estimate for power generation, and there is an additional increase in the EBDA coming from the EMP segment because of, I don't know if you have the figure in the lotto.

There are, as Vida and Gustavo mentioned, additional gas being dispatched into the market, and that would represent approximately around 50 to 60 million of additional EBITDA for the E&P business.

Very conservative, yeah. Conservatively. Yeah. Yeah. And then, of course, for our affiliate, TGS.

Yeah, that's right.

That's the 27% of that, right?

That's right.

That's the package.

Yeah. On the other hand, we are prepaying for this transportation capacity. So in four installments in the next 12 months, we will be paying to TGS, prepaying the transportation carries to TGS for the next 15 years, and that amounts to $330 million, 280 plus VAT. is the exact figure.

Correct. Can we forecast a similar 30% of war for the second trench of 7.2 million kilometers per day next June?

Gas distribution companies has a preference over... Priority. Priority over power generators. distribution companies decided not to participate in the first tranche of the option. That was this, you have to prepaid the tariff. That's where we were very aggressive on securing this gas transportation. But in this second tranche, the gas distribution companies have a priority over us, so it will depend on the amount of gas that they need to secure. On whatever is left from the distribution companies, then we may be able to secure a similar percentage as we secure in the first range.

Awesome. All right, should we expect any results? Nothing to do with it. Any results for the expiration of Los Nihiles hydropower plant concession? If we have any money? No, nothing.

No, nothing.

Yeah, likewise for Diamante. Yes. Both concessions, it's like we shake hands and that's it. Basically. Basically, yes. We notice a decrease in power generation EBITDA margin. It is explained by the sub-procurement gas and the new tariffs scheme. How do you expect to evolve in the coming quarters?

Can you review the question?

It says the EBITDA margin reduced in power generation. I know why. Let me tell you. Now with the new regulations, right, we have more sales because we are selling gas on EMP through the electricity, right? So, and before we didn't. Before it was a pass-through, right? So, it's like kind of like inflate. It was very low sales, but the EBDA normal. You know what I mean? So, before it wasn't like apples to apples. We have a bunch of things. But now it's like what it should be, like you are selling electricity with the associated fuel, right, the right price, no longer something like a cost-plus situation. And then, of course, the EBTA represents that. It's not like we are losing profitability. It's just now there's more apples to apples, life or life.

Actually, in the contract, the margins have increased.

Increased, yeah. That's right.

The EBDA, what it matters is that the EBDA... Nominal margins are increased, but the total sales have increased significantly more because now you have to deduct the cost of fuel. So nominal numbers are better. The ratio is worse.

But it's more comparable to another utility in the world. I hope it's not. Let me know. Could you give some color about increasing the working capital in the quarter? We saw an increase in trade receivables of around $500 million. No, let me tell you. So the working capital, as you can see, mostly of this $343 million, it's like $250 million for the oil hedge collectible requirements. Well, you can tell us better. And then 75% of, $75 million of payments of last quarter's, last year's actually, capex. We increased the PPA last year, and then we are paying it this year. Then very little, $20 million of higher DSO, days of sales outstanding, small delays on the payments. But now it was last year's December. It closed at six days of delays. This quarter closed at 12 days. So it's a six-day deterioration, just nearly six days. But now it's back to seven days of DSO. So now it's back to normal, putting it in this way. You want to add something? Well, let's move on. How do you expect to evolve the free cash flow?

I would say it's very normal with increasing sales that we have to have a higher working capital.

That is correct. How do you expect to evolve the free cash flow in the following 12 months, considering the installments to be paid to TGS, to CapEx, plan for Rincón de Arana, and any other diversions for projects like CESA and UREA in the future?

Sure.

Sorry.

Good morning, everyone. As you can perfectly see, we are undergoing record investments. and this was reflected in our net leverage that increased to 1.5 as we expected. Going forward, EBITDA is growing as well. In fact, this is our record quarter, so we're very thrilled that our investments are paying back. And the base case is if we continue with our base plan or base scenario, is that EBITDA keeps growing, so the company will naturally deliver it. And in fact, if we don't pursue new projects, net leverage will go to zero in two or three years. So, that being said, we will probably need to increase gross debt to finance these high capex and for example the TGX expansion, but the growth of that will go in line with the growth of the DDA, so we expect net leverage to keep around 1.5 this year and gradually go down as Triconderanda starts to ramp up and all the investments start to profit to deliver it again. So going forward, and that is why that going forward we're going to have no leverage. We're pursuing or we're studying new investments and new alternatives to apply our future free cash flows.

Thank you. Thank you, Tito. Next, Santiago Herrera from Alaria. Could you give us some color about the URIA project, future deployment of CAPEX and expected sales and a BTA contribution beyond the year 2030?

Let me say this about the URIA project. As you know, we have been working for a while and we continue working on several fronts. That includes engineering of the plan, negotiating the EPC with potential suppliers, environmental permit, the project finance. All of this takes a lot of time and the reason why the project had a lot of publicity lately was we engaged IDB and IFC for the project finance, they needed, they published the environmental permits in their websites and that gave publicity to, but they need to, this is part of the process, they need to have this public for at least six months before being able to move forward. That's why it was published a couple, I think, like a month ago. All in all, the decision is not has not been taken yet. This will be such an important move for Pampa that obviously the moment that we decide to move forward, we will do an IR day to fully explain why we are moving forward with this project. But to give you some color why a new project, I think We already went through in previous call about this. Probably Argentina is one of the few gas-producing countries in the world that imports urea. Sixty-five percent of the cost of producing urea is natural gas. Another 10 or 15 percent is electricity. Two products were Argentina and Pampa. It's very competitive. So developing urea is a way to monetize our very competitive gas reserves. The other rationale is that not only Argentina is importing from the Middle East and from Russia and from the whole South America. South America has a deficit of 10 million tons of urea per year that we are importing. The plant that we are envisioning is a 2 million tons per year of urea. In terms of sales at normal historical prices, that would be sales for around $1 billion today because of the disruption in the Middle East. At current prices of urea would be almost twice that much. But again, it's a project that makes a lot of sense for Pampa that we are working on several fronts, and we hope to take the final investment decision by the end of the third quarter or at some point in the fourth quarter of this year. And once we do that, you will be fully informed about all the details.

As we always do. All right. Cool. Could you give us some color about the REHI application for the northern area of Rincon de Aranda? What means this 4.5 investment about the already 1.5 billion plan for the area? Could you clarify that? How do you expect this may accelerate and sustain the plateau in the future?

Okay. The full field development for Rigon d'Aranda, it's in the range of $4.5 billion. That takes into account both the drilling and completion of our wells and all of the nutrient infrastructure needed through the life of the project. And basically that investment will... develop both the south of Rincón de Aranda, which is so far the most productive rock we've seen in the area, and also the northern block of Rincón de Aranda, which will enable the production plateau to be sustained for approximately six to eight more years.

All right. Then the last question from Santiago is regarding Transener. Can you give us a dimension of what this power transmission grid extension represents for the country? And for Tencent, if it was awarded regarding cap as revenues for EBDA, do you expect a significant change in prices versus the current framework scheme? If you feel like with the current framework scheme, the wholesale prices of power will increase a lot or not?

Well, because regarding the grid expansion, high voltage grid expansions, I don't think there is anything new other than some press. Nothing has been published lately by the Secretary of Energy, as I believe. We are expecting... the government to do an auction for new power lines, basically to strengthen the supply of energy to the AMBA area, to the Buenos Aires metropolitan area. That will be the first auction to be launched. Transener will could participate as any other. The difference for Transcener is even if not awarded the construction of the line, Transcener regulatory wide has the supervision of, so collects 3% of the total cost of the new line constructed. And obviously, Trassenet has very good competitive advantage to be awarded the operation and maintenance. But, again, we are still awaiting, and nothing has been decided yet by the Secretary of Energy on power transmission.

Until then, we are still curtailed from the power generation, right? There is not much we can do.

Yeah, a few... hours or days in a year, then there are some restrictions.

Yeah. Well, so there's the next question coming from Alejandro de Michelis from Jefferies. We're growing capex at both Pampa and the subsidiaries. Could you please indicate how do you see financing for the projects and for the group and the level of leverage? Do you see Pampa getting into the next two, three years?

Two, three years is a lot. Right. It's going back to the question I answered before. In two, three years, if we don't pursue any other new projects like the real plant, we will have no debt, okay? So in the meantime, when we grow, we have opened all the pockets for financing. Our bonds are trading greatly in the international market, so we can tap that market if needed. And also we have the local market that recently we issued $200 million at 5.49%, which is a very competitive rate. So, as I explained before, we probably will increase our gross debt. However, in terms of leverage, we will keep the leverage because our EBITDA is growing fastly. As you can see, this is our record quarter. So... We will see us issuing more debt but keeping leverage levels in this area of around 1.5 and going down to zero in the coming years. That being said, if we pursue a new project like the rear plant, this might change but as Gustavo explained, this is very early still to give any guidance. We have to define the the financial structure of that project and see how that would impact in the short-term leverage. Naturally, it will impact, but we have to have more clarity on the numbers to give any guidance. So it's hard to say.

Cool. So next question comes from Matias Cataruzzi from ATCAP. He's asking, well, all our questions are already answered. net debt leverage ratio? Answer. The first question, though, is Medanita brand spread piloting material with the premium now, apostles or moose, is there room to capture this improved spread in the remaining quarters, or does the hedge effectively cap realization for the full year?

The hedge is related to the market, to Brent, so any premium on top of rent will be captured by Pampa. Cool.

Well, next question comes from Gustavo Faria from Bank of America. He asks, power sector, new framework, how are the discussions with the clients, I guess in the mass, right, or in the B2B market, to fulfill the energy generation capacity available for PPAs, B2B PPAs? Are you being able to fulfill all the capacity available, or is there any spare capacity?

Yeah, the new regulations separated the market into energy and capacity. For energy, for legacy capacity, generators are allowed to sell up to 20% of the expected energy production on B2Bs. We have already completed that very fast, very efficient, thanks to the strong commercial team that we have and something that we have always been used to because of our participation in the former Energia Plus market and the matter market. So we have always been very active. a huge, several hundred clients that we provide energy. So I think we were the first one in Argentina to complete the sale of the 20% of energy available to sell. Regarding capacity, we can sell all our capacity. I think we are we sold around 30% or 30-something percent of our total capacity. That will take more time to be completed. And once we sell the capacity, it provides us an additional margin to the price that we sell capacity to Gamesa. But that will take time because it's a larger number.

And that was expected. Yes. All right. Okay. And next question from Gustavo Faria, which it's partially answers about the fertilizers plan, but it's associated with you, Horacio, which he asks, how much capex comes from the higher gas production at the gas fields associated from the fertilizers project?

How much would be the additional capex? Yeah. Okay. Okay. The Urea project will come in line in 2030. So that will be after the planned gas ends. Therefore, we still need to understand what's going to be our mix of sales by 2030. Eventually, it will – and that's why I'm mentioning, because the amount of capex needed will depend on how much additional demand Pampa would like to – Exactly, to service. If we decide eventually to reduce our sales to the, let's say, residential market and keep that gas to feed our urea project, then the CAPEX is completely different. On the other hand, we decide to supply the urea on top of all of our additional demand.

Correct. Good question. So the next question is for you, Gustavo. What will be the commercialization strategy for the fertilizers? In 2030. Okay.

Argentina currently consumes about less than 2.5 million tons per year of urea. And approximately half of that is locally produced by ProFertil. So our first option will be local prices, local demand. But given the restraints on the project finance that require us to sell, to export a higher percentage in the first few years, probably we'll be exporting to the neighboring countries. All our neighbors consume urea from Middle East, Russia, and Georgia. exactly the opposite side of the world. So, again, too soon to tell what will be our commercial strategy, but it will be domestic and export sales.

All right. The people from Latvian Securities, Alejandro Christensen and George Gastaut, ask, how is the treatment plan And which quarter do you expect it will COD?

Okay. It's progressing with no problems at all. Some minor delays on the desalinization modules that were scheduled to come from the OEI. From Dubai. From Dubai. To answer your question, the plan will be commissioned by the month of March 2027.

Cool. Have you hedged any production beyond first quarter 27 so far this year, or do you plan to?

Basically, we have one year forward. And yes, we... probably we'll continue with the hedging strategy moving forward, probably not so aggressively as we've done this year. During the ramp up, we wanted to ensure the stability of the results. That's why we decided to hedge 100% of our production. Going forward and as production continues to grow, we will be reducing the percentage of the quantity hedge to probably around 50%. Cool.

Next question, in the gas supply for the intersegment procurement structure, is the structure as a fixed price contract? He's asking how much power generation is buying the gas from EMP?

Okay. What amount of gas?

No, prices.

Prices are regulated by CAMESA. There is a maximum price, which is linked to the, let's say, LNG FOB Argentina. It's 55% of that. And that's the prices which we sell both our gas to our own power plants.

Yeah, and during the summer, it's just like the planned gas.

During the summer, it's the planned gas.

Yeah. But inter-segment-wise, it will be, like, very similar to what is plant gas, right?

No, no, no. It's significantly higher. I mean... Oh, really? Oh, yeah, yeah. The plant gas has a price for the summer and another price for the winter. It's approximately, let's say, 2.something and 5. And today... With the markers that we are looking at for the month of May, we are looking at prices that are around $10 per million BTU for this generation segment.

That we're capturing all of it.

Almost twice the planet's price.

That we're capturing all of it.

That we're capturing right now.

But it's just to allocate revenues or margin between the power segment and the EMP segment. It's not a... Cool.

And then he says, should we expect the variable cost component known as CBP recognized by Camisa to remain broadly stable over the time, given the structure? Actually, the CBP is not stable because, as Horacio was saying, the seasonal and winter CBP shoots up because of the cost of gas, right?

Right. I would say that it's the first time in many years that Argentina is showing the correct price signal in the gas market. This means that the price significantly escalates during the winter and is very, very cheap during the summer. And this continues, this should be reflected in the gas market.

Mm-hmm. Is there a positive spread between the CBP you declared to CAMESA and what your intercompany gas procurement costs? Actually, no. In order to be competitive, no. He says, can we have like a spread against what we declare before CAMESA, in CAMESA, what the real CBP is? Actually, no.

It's part of our commercial strategy, the declaration of the CBP. That's something that we do every two weeks. And it's part of the commercial strategy, declaring your CBP. It's not necessarily the real CBP. There is a margin included in the CBP that you declare to CAMESA, yes.

Yeah, it's a 25%.

Well, it depends. Every week is different.

Yeah, so Kamesa does calculate theoretical CDPs. You cannot go very different from what you declare. So what you declare, you can go very different from what theoretically Kamesa calculates for you. So you cannot say $1 CDP.

If you declare expensive, you are not dispatching. Yeah, I know. If you declare below the cost, you are dispatching. Yeah. Sorry, I don't understand. Yeah. But I think we answered that.

Let's move. How should we think about the release timing for collateral posts against the oil hedges? Has Pampa had to post any additional margins since March 31st?

I think not today, because... But eventually, at one point during this time, we had to post higher collaterals. Then as prices came down, we recovered. So I think today we are more or less at the same level.

Yeah, correct. Well, sorry. It's going to be six hours. Lisa Belen from Morgan Stanley, she asks – The easy one. Could you give me some color from the gas export perspective in the coming quarters? Horacio, are there any sales to Brazil? How is Chile evolving?

Okay. Our exports are basically to Chile, all of them, both through the Gazandes pipeline and the Gasoducto del Pacífico pipeline. We are... hitting 1.5 million of exports, and it's been pretty stable, and that's what we foresee for the rest of the year.

Well, this is a very, like, I think we didn't answer this. Do you expect RIGI for Rincón de Arana to be approved in the next few weeks?

I don't think so. If you take a look at the... Initially, RIGIs were approved in... Two, three months, the first few rigs that were approved. Then for other rigs, it took six to seven months. So although we are pushing and trying to get the approval as fast as possible, I think it will take a few more months.

And once approved?

No, just one clarification on what Gustavo said is that even if we get approved, let's say, two months from now, the benefits will apply for the paths number 14 and 15 that have already been drilled and completed after the date of our presentation of the submittal of the request for RE.

All right. So once approved, what's the next step from there? Nothing. It's just working, right?

Enjoy it.

Enjoy it.

Well, no, work, work. Yeah, work.

Francisco Cascaron from Don Cap, he's asking, my question will be regarding the OCI or other comprehensive income results in the pesos balance sheet. We have also dollar balance sheet as well. Can you explain the loss approximately of, I don't know how much, 300 billion pesos, but there's in dollars. Is it related to the losses not perceived for the production hedge for the rest of the year?

Yes, it's reflected in the... Other comprehensive income. Exactly, and that will be offset with future physical sales of oil at higher prices. So that's why it's an unrealized... You know. Yeah, but it's not reflecting the P&L, it's reflecting the... Patrimonio Neto, in the network.

In the network.

And it will compensate with future higher sales of the physical oil.

And also, can you give us an explanation of the 184 million jump in financial derivatives instruments on current liabilities? It's exactly that, right? It's the mark-to-market. Mark-to-market. All right, so Andres from Balance. What price is Pampa Hedged for the year going forward?

The average price until February next year is 65.

65.

Brand. Of course, this is the brand marker.

Cool. Austin Pacheco from Banco Mariva. PowerGen, CapEx, just $2 million. $2 million. in Q1 versus 35 million quarterly DNA. Is this a one Q timing effect or should we recalibrate our maintenance capex assumption lower going forward? What normalized annual level do you consider appropriate for the current asset space?

I think it's in the range of 70, 70, 80 million dollars average annually per year. But there are some years that Significantly higher and some years that is lower. That depends on the major maintenance that the turbines need to go through every several years. Average, around $80 million. That's just a coincidence that this queue was so long. But this year it should be in the average range.

Yeah, $70 million budget. And the quarterly DNA, or the DNA actually, is because we are a functional currency in dollars. So we are increasing PPE and we are doing the DNA. That's why we have increases in the past few years. So it's a normal amount.

Yeah. And probably the $35 million that he mentions in previous year, it's not only maintenance, but it's probably... the end of the PP6, the wind farm. I think it was in the first quarter of this year. Payments related to the last wind farm that we built. Correct.

Alvaro Leyva from BTG. He's asking, what are the expected losses from the hedging strategy in 2026 and 2027?

Again, this is... We don't consider that losses. The goal when we decided the hedging policy was to ensure stability of results, especially during the ramp-up and the first phase of the development of Rincón de Aranda. At the level that we hedge, we secure very good profitability and IRR for the project. Obviously, now that prices are higher, it's something that we knew it could have happened. It could have gone the other way, as it did last year, and we profit from this strategy. But, again, this strategy is to provide stability to the results. That was the goal, and that's it.

Cool. It's 12 o'clock. We have like three pages of questions, like a lot of questions. Different questions?

Different subjects?

Yeah, like, can you imagine? So, like, Daniel Guardiola from BTG, he's asking... main benefits on the deregulation. We already covered that, but he's asking when the first PPAs with Kamesa are expiring and what is expected to impact in EVDA. So the first PPAs, the first one is expiring in July this year. It's a very small one, 35 megawatts. Next year, it's another 300 megawatts. And then until 2035, we have the 400 megawatt of CCGT in Geneva. So I will say, roughly speaking, the most important amount is next year's 300 megawatts. In total, they represent roughly 400 megawatts together. They roughly represent $100 million EBDA today. But with the deregulation and the fact that the the east side of the country will get more gas transportation and we don't know what's going to happen in a long time and depends on the international prices and so on. The impact because of the deregulation is smoother than before. It's lower EBDA, of course, but it's not like a sharp drop like we used to preview before with the regulated peso spot market. Uria business. What's the IRR lever in dollars?

No. I think we already covered Uria.

Yeah. If shares continue trading at this multiple, why not prioritize aggressive share buybacks instead of pursuing an organic growth? What in organic?

Uria, I think it's mentioned.

That's organic. Organic? Because you are doing it by yourself, so it's organic. You're not buying it. And my name is Inorganic. Ah, Inorganic. Okay. We have a lot of things to do.

Yeah. It's a question that has many answers. I think we've been very aggressive when there was an opportunity to be very aggressive. And in the future, if there is another opportunity to be very aggressive, we will be very aggressive again. On the contract, exactly. One point to take into account is liquidity of the stock. Definitely the buybacks that we did had an impact on the liquidity of the stock. So there are several issues to take into account. Obviously the attractiveness of the investments that we are doing we think are competing extremely well with the possibility with the buyback of shares.

All right. Gamsy Alpar from Impera Capital from Turkey. She's asking, what's the well inventory of Rincón de Arana, including the north? Can the production go over 45,000 barrels per day?

Okay. The total inventory, it's more than 300 wells. out of which two-thirds is in the south, one-third is in the north. And obviously the production can go up to more than 45,000 per day, but that's what we consider a reasonable plateau because that's what we dimension our CPF for. And how many years, she asked, how many years of production?

No, no, she said if it stays at 45,000, How many years can you keep up the plateau, taking into account the number?

Okay, so taking into account the size of our processing facility, we expect approximately 15 years of production at 45,000.

Daniel has more questions. He's asking, what's the expected EBDA and free cash flow generation for 2026? And let me give you a disclaimer here. We don't give guidance. This is Argentina, but we can share with you what our forecast of the budget is, right? What's the expected BDA and free cash flow generation? For 2026. Actually, no generation. I'll flow for 2026, right? We don't give guidance, but we can share with you the budget, which is... The APDA for the parent company is around $1 billion, composed by $600 from EMP and $400 from Power Generation. Beware that this is not including the JV with Baranam. a little bit over $1 billion, of course. Then corporate and petrochemicals are negative. That's why it's rounding this $1 billion. In the consolidated level, it's including the TGS and TransCenter's share, equity share. It's around $1.3 billion. Then in the free cash flow, this is including the prepayments of TGS, CESA, San Matias, and And by demos, it's around an outflow of around $400 million, free cash flow outflow. Have you considered to grow inorganically in the oil window of Vaca Muerta? This question, he always asks. But he asks, good. How is an inorganic Vaca Muerta oil project ranking in terms of breeze-adjusted IRRs against the URIA project or the San Matias pipeline? That's a good question, though.

That's a good question. We are permanently looking at opportunities in oil, in the shale oil window. It's very hard to give an IRR because it will very much depend on the quality of the asset. So I would say that for a good asset, definitely we will be tempted to go ahead into inorganically operation. Okay.

Yeah, regarding San Matias, it's not a project itself. It's part of the investment of the floating LNG project, and it's done by the same shareholder structure of CESA, not of the whole project.

Cool. Another question from, I don't know how he pronounces, sorry, but I guess it's from Scarlet Macau Capital. The first question about the hedge is answered, but the second question is very funny. But it's worth asking. With abundant gas potential in Argentina, what about petrochemicals? It is barely profitable, or does it make sense to keep it, or would you consider selling it to simplify the company, like you sold the mature oil fields?

We are looking for... We are looking for alternatives, but nothing is on the table at this point.

Cool. Edward Palmer, he's asking, given the negative cash flow generation, are you planning to raise additional debt or it is a focus on improving working capital management?

A little bit was cut by... We always have to like to have high liquidity to keep all our options open. So, yeah, it could be the case that we decide to continue tapping the market in the medium term.

Well, you know, with all this... Okay. Ignacio Lopez from Puente. He's asking, I would like to ask Diallo for gas settlement, particularly considering the increase in production and the lower exposure to plant gas. Could you share your expectation for local gas prices this year, especially for volumes traded outside plant gas? I guess he's asking about the industry.

He's asking about the market in an overall view, I think.

Yeah.

Well, as we mentioned before, it's the first time in many years that they are giving the right signal to the market. So our Our view is that the gas prices for 2026 are going to be higher than last year. Indeed. And now with the warm war, yeah. With the war and particularly in the domestic market with the possibility of selling your gas at least a percentage versus the alternative import parity.

Correct. Okay, Armando Moretti, he's asking, do you plan to pay dividends?

No.

Jorge Mauro, given that this is the last one, I swear. So, given... Ah, listo, sí. That's true. So, okay. Ten minutes more. Sorry. Sorry for that. Twelve minutes. It won't happen again. Thanks. Thank you very much. I don't know if you would like to add some comments.

I think we covered all.

We covered all. Next, Ernest is from August. Okay, thank you very much.

Thank you very much. Thank you for your attention. Thank you.

Thank you. Bye. Have a good day.