PAM

I would like to welcome everyone to Pampa Energía's Q1 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. I will turn to Lida.

Thank you, Lila. Hi, thank you, Raquel. Hello, everyone, thank you for joining us. I will make a quick summary 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. In Q1, production exceeded 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. Rincón de Aranda, which began ramping up a year ago, is now producing approximately 25,000, right? barrels of oil per day today.

We, 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 EBITDA amounted to $325 million. This is a 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 EBITDA, increasing 8x versus Q1 last year. Quarter-on-quarter, EBITDA grew 41%, supported by synergies between gas and power businesses, as Rincón de Aranda and Genelba CCGTs 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 Aranda. Moving on to slide four, the oil and gas Adjusted EBITDA was $104 million in Q1, 2.5x last year, driven by Rincón de Aranda, higher gas production for self-supply to our thermal power plants, exports, and industrial demand. These factors were partially offset by lower realized crude oil prices and higher royalties, transport, and treatment costs associated with the production growth. Rincón de Aranda contributed 54% of the segment's EBITDA in this quarter, up from the 15% last year. Quarter-on-quarter, EBITDA 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 outputs from our non-operated blocks and in El Mangrullo. The production mix continued to diversify, with oil accounting for 19% of total production, entirely driven by Rincón de Aranda. Lifting 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 lifting costs decreased 10% year-over-year to $0.90 per million BTU, and 23% quarter-over-quarter lower. This is supported by higher gas output. Oil lifting costs declined sharply to below $10 per barrel from $41 in Q1 last year.

Thanks again to Rincón de Aranda's ramp up and the divestment of mature fields. Focusing on crude oil, output multiplied by six year on year to 19,500 barrels per day as Rincón de Aranda ramp up following the commissioning of the duplicate trunk 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 oil 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 volumes sold in Q1. At Rincón de Aranda, the ramp-up continues to progress as planned.

Average production during Q1 reached 18,200 barrels per day across 43 producing wells, up 7% quarter-on-quarter. In Q1 last year, production was below 1,000 barrels per day. During Q1 this year, six wells were drilled and 16 wells were tied in, of which seven 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 tie in an additional 20 wells and reach 20,000 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 Sur 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. On March 9, we submitted the project's application to the RIGI 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 sales 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 cubic meters per day to 1.5 million cubic meters. We expect this level to continue throughout the remainder of the year. El Mangrullo 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 pad tied in during the Q4 at Sierra Chata explains the 70% year-on-year growth, while El Mangrullo just dropped slightly 7%. During the quarter, Sierra Chata drilled three new wells, so completed the four-well DUC pad. For the second half of the year, the plan includes drilling two additional pads and tie in one pad before the winter, aligned with the seasonal gas demand from our power generation business. At El Mangrullo, the plan is just to drill a six-well pad, which will remain as a DUC inventory. Gas prices averaged $2.9 per million BTU, flat year-on-year, due to the export, lower export prices offset by higher retail prices as tariffs increase above peso devaluation.

In Q1, 47% of our gas was sold under Plan Gas GSAs through commercial retailers, down from the 82% exposure last year following the transfer of said GSAs to our CCGTs. As a result Interco consumption, or actually inter-segment 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. As for power generation, the slide seven, we posted Adjusted EBITDA of $144 million in Q1. This is 11% year-over-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.

Total availability fell though to 90%, mainly due to the ongoing outages in Güemes since January last year, and the outage that we had in the gas turbine number four in Loma de la Lata, this is not a CCGT, which is expected to return to service in next month, in June. A scheduled maintenance at Paraná. However, Pampa's thermal availability continues to outperform the peers in the national grid, as you can see in the chart. In addition, 32% of our installed capacity was contracted in the B2B market, whereas PPAs with CAMMESA or in the MATER, covering the levels before the implementation of the framework. Regarding the extension of the Perito Moreno gas pipeline and its final sections toward Buenos Aires metro area.

On April 15, TGS awarded the tender's first tranche corresponding to 4.8 million cubic meters per day out of the 12 m per day of expansion in the transportation capacity. This is 40% of the expansion. Pampa secure 3.2 million cubic meters per day, representing 27% of the expansion capacity and two-thirds of the first tranche tender. The transportation contract is for 35 years, under take or pay, or in this context is ship or pay, and requires prepayment of the first 15 years of tariffs, which in our case amounted to approximately $330 million, VAT 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. A new deregulation guidelines creates two key drivers of profitability for Pampa. We secure additional transportation capacity for additional gas produced from our upstream operations for self-supply, enable further monetization of our reserves. Second, it enhances the profitability of our power generation assets, particularly our CCGTs. Turning on to the cash on page eight, we show the parent company figures aligned with the Pampa parameter.

Free cash flow was negative $404 million in the Q1, explained by collateral requirements related to the oil hedge, extensive CapEx at Rincón de Aranda. On top of that, we have the payments associated with last year's CapEx, and a slightly higher days 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. The net debt rose to $1.2 billion, representing a net leverage of 1.5x to the last 12 months EBITDA. 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 is displayed correctly to introduce yourself to the audience. Should any participant have need help, please send us a chat message. Please hold while we poll for questions. Thank you. Okay, Guido Bizzozero from Allaria. Considering the awarded 3.2 million cubic meters of gas capacity in the Perito Moreno pipeline expected for May, well, yeah, in winter 2027, how much annual revenue and EBITDA contribution do you expect from this? Can we forecast a similar award? First, how much do you expect?

How much do we expect is? 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. 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. But again, this is dependable upon many estimates, but 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, no.

This year. That, yes.

Yeah.

This 15% increases up to 35% by year.

2028.

2028.

Yeah.

No. I think it's 2030, no?

No, no. 2028.

Okay.

Yeah.

That is the rough estimate for power generation, and there is an additional increase in the EBITDA coming from the E&P segment because of I don't know if you have the figure in Horacio.

There, as Lida Wang and Gustavo Mariani mentioned, additional gas being dispatched into the market. That would represent approximately around $50 million-$60 million of additional EBITDA for the E&P business.

Very conservative, yeah. Conservatively.

Yeah.

Yeah. Of course, from our affiliate, TGS.

Yeah, that's right.

That's it. That's the 27% of that, right?

That's right.

That's the package.

On the other hand, we are prepaying for this transportation capacity. Within the four installments in the next 12 months, we will be paying to TGS, prepaying the transportation tariff 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% award for the second tranche of 7.2 million cubic meters per day next June?

Gas distribution companies has a preference over-

Priority.

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

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

No, nothing.

Yeah.

None.

Likewise for Diamante.

Yes.

Yeah. Both concessions is like we shake hands and that's it.

Basically.

Basically. We noticed a decrease in power generation EBITDA margin. It is explained by the self-procurement gas on the new tariff scheme. How do you expect to evolve in the coming quarters?

Can you read the question?

It says the EBITDA margin reduced in power generation. I know why. Let me tell you. Now with the new regulation, right, we have more sales because we are selling gas on the MP through the electricity, right? Before we didn't. Before it was a pass-through, right? It's like, kind of like inflate. It was very low sales, but the EBITDA normal, you know what I mean? Before it wasn't like, apples to apples, we have a bunch of things. Now it's like what it should be. Like, you are selling electricity with the associated fuel, right? The right price. No, no longer, something like a cost plus situation. Of course, the EBITDA represents that. That's. It's not like we are losing profitability. It's just now it's more apples to like for like.

No. Actually, in the contract, no, the margins have increased.

Increased, yeah. That's right. The EBITDA, the what it matters.

Yes.

Is that the EBITDA.

Nominal margins are increased, but the total sales-

Yeah.

-have increased significantly more because now you have to deduct the cost of-

Right.

-of fuel. nominal numbers are better, the ratio is worse.

Worse. It's more comparable to another utility in the world.

Yep.

I hope the, if not, let me know. Could you give some color about the increase in the working capital in the quarter? We saw an increase in trade receivables of around $500 million. Let me tell you. The working capital, as you can see, mostly of this $343 million is like $250 is for the oil hedge, collateral requirements, that you got. Well, you can. Or actually, Adolfo Zuberbühler can tell you it's better.

75% of $75 million of payments of last quarter's, last year's actually, CapEx. We increased the PPA last year, we are paying it this year. Very little, $20 million of higher DSO, days of sales outstanding, small delays on the payments. Now it was last year's December, it closed at six days of delays. This quarter, it closed at 12 days, so it's a six-day deterioration, just nearly six days. Now it's back to seven days of DSO. Now it's back to normal, putting it in this way. You wanna add something? Well, let's move on. How do you expect to evolve the free-

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

Yeah.

-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, the CapEx, plan for Rincón de Aranda, and any other disbursements for projects like CIESA and urea in the future?

Vito, you wanna answer that?

Sure.

Vito.

Vito.

Sorry. Good morning, everyone. As you can perfectly see, we are undergoing regular investments. This was reflected in our net leverage that increased to 1.5x as we expected. Going forward, EBITDA is growing as well. In fact, this is our record quarter, we're very thrilled that our investments are paying back. The base case is if we continue with our base plan or base scenario, is that EBITDA keeps growing, the company will naturally deleverage. In fact, if we don't pursue new projects, net leverage will go to zero in two or three years.

That being said, we will probably need to increase gross debt to finance this high CapEx and, for example, the TGS expansion. The growth of debt will go in line with the growth of EBITDA, so we expect net leverage to keep around 1.5x this year and gradually go down as Rincón de Aranda starts to ramp up and all the investments start to profit to deleverage again. Going forward, that is why, going forward, we're going to have no leverage. We are pursuing or we are studying new investments and new alternatives to apply our future free cash flows.

Thank you.

Thank you, Vito. Next, Santiago Herrera from Allaria: Could you give us some color Urea project, future deployment of CapEx and expected sales and EBITDA contribution beyond the year 2030?

Let me say this Urea 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. The reason why the project had a lot of publicity lately was we engaged IDB and IFC for the project finance. They published the environmental permits in their websites, and that gave publicity 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 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. To give you some color Urea 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. 65% of the cost of producing urea is natural gas. Another 10% or 15% is electricity. Two products where Argentina and Pampa, it's very competitive.

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 sold for around $1 billion.

Today, because of the disruption in the Middle East, at current prices of urea would be almost twice that much. 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 Q3 or at some point in the Q4 of this year. 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 RIGI application for the northern area of Rincón de Aranda? What means this $4.5 billion investment above 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 Rincón de 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 midstream infrastructure needed through the life of the project. Basically, that investment, will de-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. Well, the next question from Santiago is regarding Transener. Can you give us a dimension of what this power transmission grid expansion represents for the country? For Transener, if it was awarded regarding CapEx, revenues or EBITDA, do you expect a significant change in prices versus the current framework scheme?

Say again?

If you feel like with the current framework scheme, the wholesale prices of power will increase a lot or not.

Will decrease. Regarding 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.

Buenos Aires.

Buenos Aires metropolitan area. That will be the first auction to be launched. Transener could participate as any other. The difference for Transener is, even if not awarded the construction of the line, Transener regulatory-wise has the supervision of, collects 3% of the total cost of the new line constructed. Obviously Transener has very good competitive advantage to be awarded the operation and maintenance. Again, we are still waiting and nothing has been decided yet by the Secretary of Energy on power transmission bid.

Yeah. Until then, we are still curtail in the power generation, right? There is not much we can do.

Yeah. A few hours or days in a year there's some restrictions.

Well, there's the next question coming from Alejandro Demichelis from Jefferies. With 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.

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 Urea plant, we will have no debt. Okay? In the meantime, when we grow, we have opened all the pockets for financing. Our bonds are trading greatly in the international market, we can tap that market if needed. We have the local market that recently we issued $200 million at 5.49%, which is a very competitive rate. 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.

You will see us issuing more debt, but keeping leverage levels in this area of around 1.5x and going down to zero in the coming years. That being said, if we pursue a new project like the Urea plant, this might change. As Gustavo explained, this is very early still to give any guidance. We have to define the financial structure of that project and see how that will impact in the short term leverage. We naturally will impact, but we have to have more clarity on the numbers to give any guidance. It's early to say.

Cool. Next question comes from Matias Cattaruzzi from AdCap. He's asking, other questions are already answered. Net debt leverage ratio, answered. The third question, though, is Medanito Brent spread tightening material with the premium now passes or moves. 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. Any premium on top of Brent will be captured by Pampa.

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 math, right? Or in the B2B market, to fulfill the energy generation capacity available for PPAs, B2B PPAs. Are you being able to fulfill the capacity available, or is there any some spare capacity?

Okay. 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 Energía Plus market and the MATER market.

We have always been very active. We have a huge, several hundred clients that we provide energy. 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've sold around 30% or 30% to something percent of our total capacity. That will take more time to be completed. I mean, Once we sell capacity, it provides us an additional market to the, an additional margin to the price that we sell capacity to CAMMESA.

Yeah.

That will take time because it's larger number.

That was expected.

Yes.

All right. Okay. Next question from Gustavo Faria, which it's partially answered. It's about the fertilizers plant, but it's associated with you, Horacio, which he asks how much CapEx comes from the higher gas production at the gas fields from associated from the fertilizers project.

How much will be the additional CapEx?

Yeah.

Urea project will come in line in 2030. That will be after the Plan Gas ends. Therefore, we still need to understand what's gonna be our mix of sales by 2030. Eventually, it will. That's why I'm mentioning, because the amount of CapEx needed will depend on how much additional demand Pampa would like to engage.

Service, yeah.

Exactly, to service. If we decide eventually to reduce our sales to the, let's say, residential market and keep that gas to Urea project, then the CapEx is completely different as it, on the other hand, we decide to supply the urea on top of all of our additional demand.

Yeah. Correct. Good answer. The next question is for you, Gustavo. What will be the commercialization strategy for the fertilizers in 2030?

Okay. No, I just about Argentina currently consumes about less than 2.5 million tons per year of urea, and approximately half of that is locally produced by Profertil. Our first option will be local prices, local demand. 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 exactly the opposite side of the world. Again, too soon to tell what will be our commercial strategy, but it will be domestic and an export sales.

All right. The people from Latin Securities, Alejandro Christensen and Jorge Gasztowtt ask, how is the treatment plan on Rincón de Aranda progressing, 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 UAE.

From Dubai.

From Dubai. To answer your question, the plant will be commissioned by the month of March 2027.

Cool. Have you hedged any production beyond Q1 2027 so far this year, or do you plan to?

Basically, we have one year forward. Yes, we probably will 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, 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 E&P.

Okay. How much, what amount of gas?

No, prices.

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

Yeah, during the summer, it's just like the Plan Gas free market.

During the summer, it's the Plan Gas.

Yeah. Inter-intersegment-wise, it will be, like, very similar to what is Plan Gas, right?

No, no. It's significantly higher.

Oh, really? Oh, yeah.

The Plan Gas has a price for the summer and another price for the winter.

It's approximately, let's say, $2.something and $5. Today, with the markers that we are looking at for the May, the month of May, we are looking at prices that are around $10 per million BTU for this generation segment.

We are capturing all.

It's almost twice the planned price.

Yeah. We are capturing all of it.

That we're capturing right now.

Yeah.

But, but-

It's just to allocate-

Who gets that?

-revenues or margin between-

Yes

the power segment and the E&P segment. It's-

Cool. He says, should we expect the variable cost component, known as CVP, recognized by CAMMESA to remain broadly stable over the time, given its structure? Actually, the CVP is not stable because as Horacio was saying, it's seasonal. In winter, CVP shoots up because of the cost of gas, right?

Yes. I would say that is 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. If this continues, this should be reflected in the gas market.

Is there a positive spread between the CVP, you declare to CAMMESA and what your intercompany gas procurement costs? Actually, no. In order to be competitive, no.

No.

Can we have like a spread against what we declare before CAMMESA, in CAMMESA, what the real CVP is, actually? No.

Yeah. It's part of our commercial strategy, the declaration of the CVP. That's something that we do every two weeks.

And-

So, so-

It's part of the commercial strategy, declaring your CVPs, not necessarily the real CVP. No. There is a margin included in the CVP that you declare to CAMMESA, yes.

Yes. Yeah, it's a 25%.

Well, it depends.

Yeah.

Every week is different.

Different. Yeah. CAMMESA does declare, does calculate theoretical CVPs. You cannot go very different from what you declare. What you declare, you can go very different from what theoretically CAMMESA calculates for you. You cannot say $1 CVP.

If you declare expensive, you are not dispatched.

Yeah, no.

if you declare below the cost,

You are not making money. Yeah.

I sorry. I don't understand it.

Yeah.

I think we answered that. Let's move.

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

I think not today. Eventually at one point during the summer, we had to post higher collateral than we. As prices came down, we recovered. I think today we are more or less at the same level.

Yeah. Correct. Well, Sorry. It's gonna be six hours. Lisa Belen from Morgan Stanley, she asks, under one of the easy one: Could you give me some color from the gas export perspective in the coming quarters, Horacio? If there's any sales to Brazil? How is Chile evolving?

Okay. Our exports, base, are basically to Chile, all of them, both through the GasAndes 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 is, do you expect RIGI for Rincón de Aranda to be approved the next few weeks?

I don't think so.

If you take a look at, initially, RIGIs were approved in two, three months, the first few RIGIs that were approved. For other RIGIs, it took six to seven months. Although we are pushing and trying to get the approval as fast as possible, I think it will take a few more months.

Once approved.

Number one, 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 pads number 14 and 15 that have already been drilled and completed after the date of our presentation, of the submittal of the request for RIGI. So-

All right. Once approved, what's the next steps from there? Nothing. It's just working, right?

Enjoying.

Enjoying. Well, no, work. Work.

Yeah, work.

Francisco Cascaron from Bank Vontobel, he's asking, "My question will be regarding the OCI or other comprehensive income results in the ARS balance sheet. We have also USD balance sheet as well. Can you explain the loss approximately of, I don't know how much, in, ARS 300 billion, that's $13. 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. That is, that will be offset with future physical sales of oil at higher prices. That price is an unrealized.

I know.

Yeah, it's not reflecting in EPS.

Yeah.

It will compensate with future higher sales of the physical oil.

Also, can you give us explanation of the ARS 184 million jump in financial derivatives instrument on current liabilities? Is exactly that, right? It's the mark to market. Mark to market. All right. Andres Inocenciano from Balanz. What price is Pampa hedged for the year going forward?

The average price until April next year is ARS 65.

ARS 65.

ARS 65.

ARS 65. Brent.

Of course, this is the Brent mark.

Agustin Pacheco from Banco Mariva. Power gen, CapEx just $2 million in Q1 versus $35 million quarterly D&A. Is this a 1Q 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 base?

I think it's in the range of $70 million, no?

Correct.

Like $70 million-$80 million average annually per year. There are some years that are significantly higher and some years that is lower. That depends on the major maintenance that the turbines need to go through every several years.

Cool.

Average, around $80 million. That's why it is just a coincidence that this Q was so low. This year it should be in the average range.

Yeah, yeah. $70 million budget. The quarterly D&A or the D&A actually is because we are a functional currency in dollars, so we are increasing PPE and we are doing the D&A. That's why. We have increases in the past few years, so it's a normal amount.

Yeah. Probably the ARS 35 million that he mentions in previous year, it's not only maintenance, but it's probably the end of the PEPE VI, the wind farm. The end of, I think it was in the Q1 of this year, payments related to the last.

Wind farm.

The last wind farm that we built.

Correct. Alvaro Garcia from BTG, he's asking what are the expected losses from the hedging strategy in 2026 and 2027.

This is, we don't consider that a 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 a very good profitability and IRR for the project. Obviously, now that prices are higher, it's something that we knew it could happen. It could go the other way, as it did last year, and we profit from this strategy. The strategy is to provide stability to the results. That was the goal. That's it.

Cool. It's 12:00 P.M. We have, like, three pages of questions. Like, a lot of questions.

Different questions? Of different subjects?

Yeah, like, can you imagine? What Daniel Guardiola from BTG, he's asking main benefits on the deregulation. We already covered that, he's asking when the first PPAs with CAMMESA are expiring and what is expected the impact in UV, EBITDA. The first PPAs, the first one is expiring in July this year. It's a very small one, 35 MW. Next year is another 300 MW. Then until 2035, we have the 400 MW of CCGT in Genelba. I will say, roughly speaking, the most important amount is next year's 300 MW. In total, they represent this roughly 400 MW together. They roughly represent $100 million EBITDA today.

With the deregulation and the fact that the east side of the country will get more gas transportation, and we don't know what's gonna happen in another long time, it depends on the international prices and so on. The impact because of the deregulation is smoother than before. It's lower EBITDA, of course, but it's not like a sharp drop like we used to preview before with the regulated peso spot market. urea business, what's the IRR lever in dollars now?

That, I think we already covered urea.

Yeah. If shares continue trading at these multiples, why not prioritize aggressive share buybacks instead of pursuing inorganic growth? What inorganic?

urea, I think it's mentioned.

That's organic.

Organic?

You are doing by yourself, so it's organic.

You're not buying.

M&A is inorganic.

inorganic. Okay.

We have a lot of things to do.

It's a question that has many answers. I think we've been very aggressive when there was an opportunity to be very aggressive. In the future, if there is another opportunity to be very aggressive, we will be very aggressive again. On the contrary, exactly, one point to take into account is the liquidity of the stock. Definitely the buyback that we did had an impact on the liquidity of the stock. 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. Gamze Alper from Impera Capital from Turkey. She's asking, what's the well inventory of Rincón de Aranda, 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. 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. How many years she asked? How many years of production?

No, no. She, she says, if it stays at 45,000, how many years can you keep up the plateau?

If we-

Good afternoon, everyone, and thank you for waiting. I'm Raquel Cardasz from IR, and we would like to welcome everyone to Pampa Energía's Fourth Quarter of 2025 Results Video Conference. We would like to inform you that this event is being recorded. [Operator Instructions] Before continuing, -- 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 operation 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.

Hello, Raquel. Thank you very much. And hello, everyone. Good afternoon. Thank you for joining our call. I will make a really quick summary so we can spend more time on questions with the management today. Q&A, we have our CEO, Mr. Mariani; our CFO, Mr. Zuberbuhler; and our Head of Oil & Gas, Mr. Turri. So let's go ahead with the first slide where we make a quick summary of 2025. November 25, 2025, marked our 20th anniversary of Pampa and the creation of Pampa. Back in 2005, we did not produce any oil or gas or did not generate any single megawatt hour of generation, electricity. So 20 years later, Pampa accounts for 9% of the country's total natural gas production and reached a record daily production of 104,000 barrels of oil equivalent during the winter of 2025. This year also marked a steep change in our upstream profile. Our black flagship shale oil development at Rincón de Aranda began the year producing less than 1,000 barrels of oil per day and now reached a 20,000 barrel goal by December of last year. As a result, total annual average production exceeded 84,000 barrels of oil equivalent per day. This is 8% higher than last year and 73% up since 2017, the year after we acquired Petrobras Argentina, reflecting the sustained organic growth and disciplined capital allocation. In the Power segment, we consolidated a 15% share of Argentina's net electricity output, achieving an outstanding 94% thermal availability rate in 2025, reaffirming our position as the country's leading IPP and demonstrating a reliable, efficient fleet operating under a gradually normalizing market framework. At a consolidated level, EBITDA grew 8% year-on-year, surpassing the $1 billion mark, mostly driven by power, gas and Rincón de Aranda. While oil and gas and power each represent half of the EBITDA, we expect that ongoing growth at Rincón de Aranda will further expand Oil and Gas footprint in the EBITDA. So Pampa and its subsidiaries are deeply committed to the country's energy development. In 2025, we hit a new record high of $1.4 billion in CapEx, of which roughly half was testing to Rincón de Aranda, the largest single project development investment in our 20-year history. In 2026, we expect to set a new record high, allocating $770 million in Rincón de Aranda, very similar to last year to reach production plateau, plus another $400 million for maintenance across our operations and around $600 million for TGS'’ private initiative project. So moving on to the Q4 results. The quarter's adjusted EBITDA amounted to $230 million. This is a 26% year-on-year increase. Power generation was the main contributor, where, since November the new guidelines for the whole electricity market have allowed power producers to operate under a more decentralized scheme, improving price signals and enabling us to capture operational efficiencies and synergies with our E&P gas. Rincón de Aranda was the second key driver with this production ramping up -- ramp-up accounting for 23% of the quarter's EBITDA, supported by 10 active paths as of today. Our capital structure continues to strengthen following the issuance of our 12-year international bond. We closed the year with a net debt-to-EBITDA ratio of 1.1x and average debt life of almost 8 years. Quarter-on-quarter EBITDA decreased due to the gas seasonability -- seasonality, sorry, offset by Rincón de Aranda and steady contributions from our utilities, TGS and Transener. CapEx surged 81% year-on-year to $371 million in the quarter, of which $249 million were invested in the development of Rincón de Aranda. Okay. So moving on, on the Slide 6. The Oil and Gas segment adjusted EBITDA was $77 million in Q4, more than doubling last years, driven by Rincón de Aranda, increased gas exports and industrial demand. Higher transport and treatment costs partially offset these gains. Compared to Q3, EBITDA declined due to the gas seasonality, but was smoothed by Rincón de Aranda. Lifting costs averaged $8 per barrel of oil equivalent, slightly below last year due to higher crude oil output and stronger gas demand, offset by increasing gas treatment costs and the lease of temporary facilities at Rincón de Aranda. Quarter-on-quarter, lifting cost per boe increased due to this gas seasonality. Gas lifting costs remained flat year-on-year at $1.2 per million BTU, an average of $1 during the 2025, but rose quarter-on-quarter, again, because of the gas seasonality, while oil declined sharply to below $11 per barrel from $36 last year's Q4. This is because -- mainly because of Rincón de Aranda's ramp-up and the divestment of mature conventional blocks. Remind you all that last year, Q4, Rincón de Aranda was really a greenfield, produced only from one well. On top of that, we were recording trucking expenses, testing expenses, and we also held a lot of mature blocks that today are divested. Total production averaged more than 81,000 barrels of oil equivalent per day, up 32% year-on-year. This is led by Rincón de Aranda and Sierra Chata, partially offset by decreases at El Mangrullo and in nonoperated blocks as well as the divestment of El Tordillo. Quarter-on-quarter, production dropped 18%, again, explained by the gas seasonality. The production mix continues to evolve with oil rising to 22% of total output, driven entirely by Rincón de Aranda. Crude oil prices averaged nearly $61 per barrel in Q4. This is 10% lower than last year due to the weaker Brent prices. Without the hedging at Rincón de Aranda, our realized price will have been $53 per barrel. So focusing now exclusively on Rincón de Aranda, the ramp-up stays on track. In Q4, we reached the first goal of 20,000 barrels per day after tying two pads -- two new pads with an average quarterly production of 17,100 barrels per day. This is a 19% increase quarter-on-quarter. As of today, 10 pads are online, of which 3 of them are currently undergoing testing -- well testing. And -- plus we have another two pads, DUC pads and two other pads are under fracking. In 2025, Rincón de Aranda, contributed $126 million of EBITDA. Infrastructure build-outs, thanks to the RIGI incentive regime continues in parallel with the field development. Next month, we are installing an additional temporary processing facility with a focus on reaching 28,000 barrels by mid-2026, a key milestone toward the final production target of 45,000 barrels expected in 2027. So moving to Gas. Sales grew 10% year-on-year, but dropped 23% from Q3. This is, again, explained by seasonality. Mangrullo continued to lead the output, though its share shrank to 46%, while Sierra Chata grew to 38% share with production up 39% year-on-year, supported by a new pad that we tied in during the quarter. Together, they accounted for 84% of the total gas production. Gas prices averaged $3 per million BTU, flat year-on-year. Industry sales supported the pricing, offset by lower export prices due to the Brent underperformance and a drop in residential due to the lag tariff pass-through of the devaluation. In Q4 this year, 72% of our gas was sold under the Plan Gas GSA, CAMMESA and Retail, down from the 81% Q4 last year due to the transfer of certain rounds of the Plan Gas volumes to fuel self-procurement in power, which represented 4% of the total sales in Q4 '25. Now in December, we started to formally doing the self-procurement of gas in Genelba and Loma de la Lata. The self-procurement increased to 41% on average in January 2026. So as a result, Plan Gas GSA exposure shrank to 37%. With the new guidelines, in place, we expect 40% of this year's production to supply our own gas -- our own power generation, capturing margins and leveraging synergies between these two core businesses. Before moving from E&P, I want to just do a quick update on reserve. Total proven reserves rose 28% to 296 million boe, driven by our increased activity in Sierra Chata and specifically in Rincón de Aranda. Shale reserves grew by 55% year-on-year to 204 million barrels and with shale oil now accounting for 19% of total reserves. The reserve replacement ratio was 3.2x, extending the average life to 10.2 years. Since 2019, proven reserves have increased 118% with the most significant expansion coming from shale since 2023 when the year when we started to actively develop Vaca Muerta formation. Okay. So moving to power generations. We posted an EBITDA of $111 million in Q4, up 28% year-on-year, mainly driven by stronger spot prices under the new guidelines, especially -- partially offset by power dispatch at Genelba's new CCGT due to the program maintenance. Total availability declined to 91% due to the scheduled maintenance in Genelba and Loma de la Lata and the ongoing outage that we are experiencing in HINISA since January. However, Pampa's’ thermal availability continues to outpace the national grid under the new framework, also Energía Plus B2B contracts were discontinued, though we managed to recontract in the B2B market. So contract capacity remained stable year-on-year. With the new framework also performance balances between contracted capacity and the spot margin. So value creation also can be driven by efficiency and fuel management. Those units with high load factors and self-procure fuel will achieve higher margins. Turning to cash flow on Slide 11. We show the parent company figures because this is aligned with our bond perimeter. Despite the higher CapEx at Rincón de Aranda, we posted a limited $20 million free cash outflow in Q4, offset by strong EBITDA and working capital inflows mostly from winter collections. As a result, cash and cash equivalents stood at $1.1 billion at the quarter end. This is $210 million more than September close. Finally, on the balance sheet, gross debt was nearly $1.9 billion, down 9% since 2024 December. In November last year, we issued a $450 million international bond maturing in 2037 with a record 20-year tenure. This is the first long-dated issuance by an Argentine corporate over a decade and extending our average life to almost 8 years. The proceeds from this issuance and the 2034 notes that we issued in May were used to redeem all the outstanding international bonds, the '26, the '27, the '29 notes and some of the local dollar bonds. As a result, net debt reached to $801 million. This is 1.1 net leverage, maintaining a conservative capital structure while funding growth. Well, so this concludes the presentation. Thank you for hearing me. Now the floor is open for questions. [Operator Instructions]

All right. So we start -- Alejandro Demichelis from Jefferies. How do you see the evolution of production? Please split between oil and gas and of drilling and completion and lifting costs in 2026? Production, drilling -- D&C, lilfting costs.

Okay. Good afternoon, and thank you, everybody, for joining. Regarding production, let's go first to oil. We are, as Lida mentioned, currently in around 19,000 barrels per day. Our target is to reach 25,000 barrels per day by the end of March, beginning of April and then keep on ramping up to 27,000, even 28,000 barrels per day as of the half of the year. All of this is coming out of Rincón de Aranda. In terms of natural gas, we just closed February around 14 million cubic meters per day. We will probably be reaching a peak of around 18 million cubic meters per day during the winter and an average of approximately 13.5 million cubic meters per day compared to 12.5 million cubic meters per day in 2025. In terms of drilling and completion, in Rincón de Aranda, we drilled 20 wells. We're going to be drilling 20 wells and completing 35. And in Sierra Chata, we will be drilling and completing 8 wells each. And I'm missing lifting costs, which are in the range of -- will be in the range of $10 per barrel.

Yes, until we get...

Until we get the CPF. We are talking about 2026 and a little bit less than $1 per million BTU in our gas operations.

Great. So let's go to the next question. Next question comes from [ Guido Visocero from Nalaria ] about the hedging. How are the royalties settled? Are they include in the hedge? Or is that independent and settled at the market?

No, royalties do not have any connection to the hedging. They are set at the market price.

All right. Next question, Alejandro Christensen from Latin Securities. How much impact have you seen so far from Resolution 425-25? And how much additional impact do you expect in 2026? Could you provide some color on the EBITDA growth outlook for this segment next year? Next year, I guess, '27, right?

This year. Good afternoon, everybody. Thank you for joining. The impact of the resolution so far, it's -- I think what we have been saying in previous calls is between 10% and 15% vis-a-vis the EBITDA generation that we had in 2025. More or less. And that is what we expect for the segment as a whole when you compare 2026 vis-a-vis the previous year.

I guess 2027 is too early to say, right?

Say it again.

2027, it's too early to say.

Too soon to say. Yes. What this resolution brings is also an improvement in our E&P business, and that is thanks to the fact that now we are self-procured. We are selling the gas and our thermal power use is provided by our E&P segment. So that also brings -- and again, we are expecting here, but it's so far what we have seen in January and February, a 10% increase in quantity in the natural gas produced by the segment, and that is thanks to the fact that we are self-procuring in our thermal plants.

We're kind of not putting much number of that profit, right? So we are -- the number you said is only for power generation, but the fact that we are self procuring this vertical integration, we are not putting a number so far ,an effect, right? An impact.

Yes, that's correct. So that's -- in our projections, we expect on the power generation segment around 10% to 15% increase in EBITDA and another increase coming from the fact that the total gas produced by the E&P segment will also go up by around 10%.

That's right. All right. Next question coming from Alejandro. Alejandro as well he says, have you signed any PPAs with private counterparties for energy or capacity?

Yes, we have been very active since November that this new resolution is -- our commercial team has been extremely active. If I remember correctly, I think that we have sold like 70 -- now you can sell energy and capacity. We've been active in both. Signed more than 100-something contract for a total of around 70 megawatts. So yes, we have been very active there.

All right. And then how are you seeing natural gas demand and pricing in the industrial sector, industrial evolving during Q1 '26?

We see the industrial demand is stable. It accounts for less than around 10% of our overall production. And given the changes in the self-procurement it's not a segment that we are very familiar, we are not that interested. So it would have an effect in Pampa Energía.

All right. Next question coming also from Alejandro. What percentage of oil production remains unhedged throughout 2027?

Throughout 2027 means until or until the end of 2027?

Probably it means until 2027 in English, right? But I don't know.

So we are fully -- basically, we are fully hedged 1 year going forward. So until first quarter of next year, we are fully hedged.

All right. Next question coming from Bull Market, Felipe Collazo. Following the deregulation, has Pampa been able to start acquiring gas from its own wells? I think it's all self answer. Can you give a guidance of what the savings in fuel costs will amount during 2026? Savings in fuel costs? I don't see savings.

We're making profit out of it.

We are vertically integrated.

Exactly.

Yes. So we are producing more than before, right?

That's right.

So January, we produced.

We are particularly producing more during 2026 in the winter time.

Yes, it will be more like...

We will have a flat curve.

But Q1 is already higher than Q1...

We already said that February ended up with almost 14 million cubic meters per day.

Well, yes, last year first quarter, it was a little bit different because Q4, it was very bad, and they took -- CAMMESA took more gas. But even that, the production...

Just taking into account that the overall average of '25 was 12.5 million cubic meter, and we're saying that only February is around 14 million cubic meters per day. So we will definitely be -- our estimation is that we will be producing around 13.5 million to 14 million in 2026.

How long do you expect the RIGI approval to take for the Rincón de Aranda treatment plant. We used to think that application has been filed by mid-2025 when it was first announced. But some news articles from about a month ago suggest it was just done last January. Could you clarify that?

Yes. I don't recall when we filed the RIGI for upstream, but it was definitely third -- fourth quarter -- of last year. We haven't been approved yet. But recently, they have -- there was a new decree adding upstream of oil to the RIGI. So we are starting to file for an additional -- yes, an overall RIGI for the full development of Rincón de Aranda.

All right. Do you plan to fund the CapEx by via new debt issuance?

Hi everyone. The base case scenario, the answer is no. The idea is we have a big cash position that we have been acquiring with our free cash flow and last year debt issuance. So the base case is that we use part of that cash to complete our CapEx investment of this year. That being said, if we decide to embark in new projects or any other new investments, we'll have to revalue that decision, and that base scenario. And of course, there is always-- I am very opportunistic. So if spreads keep tightening, that is something that we will look. But the base case scenario is that we will face the capital investments with our cash position.

Next question comes from Juan Ignacio Lopez from Puente. I think we haven't answered this yet. But what's the guidance about CapEx for 2026, Oil and gas and Power?

Around total CapEx?

Sorry. Before that, we don't give guidance. But I will give you -- we will share with you what our Board approved by the budget -- for the budget, right?

As Lida says, the restricted group only. So it's basically it's around $1.1 billion, basically $1 billion, the E&P segment and it's less than $100 million on power generation because it's only maintenance CapEx. So we don't have any project -- any new project going on, on that -- on the Power Generation segment. That answers?

And oil?

Oil almost around...

$1 billion.

Awesome. So next question, he says specifically, how much of that is maintenance and how much is scheduled for thermal plants this year? It's pretty much...

Yes, it's around $80 million, and it's all -- maintenance CapEx, yes.

And second, guidance regarding free cash flow. Which, again, we don't do guidance, but we can share with you what it's approved by the budget. And what crude realized price are you assuming for your base case scenario?

So we expect total CapEx, including maintenance CapEx, investment CapEx and the equity that we will deploy to our joint ventures. All that will imply more or less $500 million negative cash flow after all investments. So that is what will bring the cash position from $1.2 billion to $700 million roughly.

All right. What else? And the price of oil. The price of oil assumed for the budget. I think it was less than $58.

Well, that's the one assuming the budget. But I think what is relevant here is the hedge price that is around $66.

Yes, that's correct. A little bit above $66, right? So the hedge is Brent, right? And then after discounts and export duty, which is 8%, it is roughly a little bit lower than -- roughly a little bit above $58 depending on the discount.

Wellhead, you mean?

Wellhead and it's realized FOB. The wellhead, you have to account the transport -- okay. Next question. Cattaruzzi Matías from Adcap. How should we think the quarterly production ramp-up through 2026, particularly toward the -- around 24,000 barrels per day level by second quarter of '26 and around 28,000 by third quarter.

We've been through that. That's exactly he's answering the question.

But then after -- so the [ 828 well ] in the chart, we put like it's like 20 and then sharply goes up to the plateau?

No. It's not going to happen.

What do you think...

It's not financially efficient. So it's going to be -- probably going to be a ramp-up curve going from 28,000 to 45,000 in around 5 to 6 months.

Okay. Matías is asking -- given that Pampa has more gas reserves that it can currently monetize, would you consider monetizing part of our -- of your gas acreage portfolio for farm out or farm downs or asset sales?

We could consider it, but we are not actively seeking to do so.

Could you update us -- another from Matias. Could you update us on Southern Energy FLNG project, specifically timing, expected volumes and potential EBITDA CapEx contribution from Pampa and what the LNG FOB price assumption, it's basically the Coca-Cola, everything.

In terms of timing, we are expecting the first boat by second half of 2027 and the second one by the second half of 2028 for a total demand of 6 million tons per year. That's around -- roughly around 25 million to 26 million cubic meters per day. We have 20% out of that. And the biggest capital or the biggest CapEx involved in the project now is the construction of the dedicated gas pipeline from Cartagena to San Antonio state, which will account for probably around $1.5 billion.

Hopefully less than that.

Hopefully less than that, from $1.3 billion to $1.5 billion. And out of which we could consider that 60% will be financed and maybe 30% to 40% is going to be equity. And out of that, we have 20%. So that's a major CapEx that we'll be facing.

Francisco Cascarón from DON Cap, he is asking what new opportunities do you foresee in the generation segment, if any? Do you expect...

I'm sorry, just to add something that's relevant. We signed our first long-term contract with CFA, the German agency for 2 million tons per year.

It's binding? This is binding?

It's already binding. Yes more than binding.

Great awesome. For sale?

Binding for both.

Great. All right. Shifting to power generation. Francisco Cascarón from DON Cap, is asking, do you foresee any opportunities there? Do you expect to increase installed capacity this year or in the near term?

Increase this year impossible because these projects take several years to be installed. What could be done in the short term could be something like batteries. And today [ Tamesa ] our Secretary of Energy announced a new auctions of batteries similar to the one that was done last year. The one done last year was within the Buenos Aires area, and this one is all around the country, but has been published today. Honestly, I didn't have time to take a look at it. Usually, these are small projects, very competitive. We have colleagues very aggressive on pricing. So not sure whether we are going to be actively in this auction.

That's it. Okay. So [ Houting Pacheco from, Maria ] he's asking, given the improvement in power prices under the new wholesale electricity market framework, are you now seeing higher returns in power generation relative to shale oil? What a question?

Relative to shale oil. We are seeing higher returns on the power generation vis-a-vis previous year relative to shale oil. The power generation margins have improved. I still think that shale oil provides a higher expected returns than power generation.

There are two animal right?

Yes, two different animal, exactly different risk -- exactly. But despite these changes, we are very comfortable with the development that we are doing in Rincón de Aranda and adding the oil segment to pump. That is where the question is...

Talk about, yes. Well, with the recent extension of the, RIGI, are you thinking to apply? I think we answered that.

Yes. We are starting to apply for the upstream part of Rincón de Aranda.

He is asking -- I think it's too early to answer, but expected impact on project economics and timing. So we can give him a quick summary of the relief, if I may. So it's basically after the third year, you get export duties abolished removed, right, the third year. The tax rate goes down from 35% to 25%, accelerated depreciation, so the imposable amount, it's smaller as well. So that helps through the first years of the operation. BAT can be -- BAT credit can be monetized. What else, if I can remember -- pretty much that, right? But it's a 30-year time that they give you, right, the RIGI. And then, of course, free disposal of all the proceeds abroad. If you export, you can keep it. I think that's the key takeaways from RIGI.

Totally.

That's not AI. We produce that. I have to think about it. So he said, well, congratulations from [indiscernible] He's asking the RIGI upstream, how broadens the scope of the Rincón de Aranda project and how could accelerate the development?

He is asking...

The whole impact.

Okay. The RIGI-- the possibility of the RIGI is going to give a significant, let's say, help to develop the northern part of Rincón de Aranda, which will have an impact both in the ramp-up curve and also in the total amount of oil to be recovered from the area. So we think that this is a major change in the overall economics of the project.

He's asking, should we expect any updated production guidance and timing, meaning adding RIGI or drilling capacity or having more capacity contracted?

It will probably happen. It's not going to change the short-term curve, but it's going to have an impact in the medium term, something we're still analyzing and obviously, it's contingent to the RIGI application.

All right. Someone I don't know, like its name, it's Armando, which is very weired. He's asking a question that we will usually answer. Do the company is planning distribute any dividends in the near future?

No. We're not planning to distribute dividends in the near future. As Fito explained, we have a negative free cash flow this year, and we expect still too early to say, but something that even or slightly positive in 2027. But we still see a lot of opportunities to continue growing. So because of this situation, we are not planning dividends in 2026.

From [indiscernible] asking he wants to double click on the CapEx estimates. For Rincón de Aranda $770 million budget for this year, how much is wells versus infrastructure?

Yes, it's approximately $500 million in wells and the difference will be facilities.

How much in maintenance for generation is $80 million that we said. TGS, what we said is considering Perito Moreno expansion and maintenance, yes, it's $600 million of expansion of the Perito Moreno.

This year. Okay.

No, no, no. Total, it's over $700 million.

Okay. But we haven't talked about TGS CapEx.

Very briefly in the evolving chart-- evolution chart. Maintenance on TGS, like $90 million per year, more or less, total, right, the trunk -- the regulated trunk, the liquids and what is left for midstream. That's $90 million per year. What should we expect for next year? Well, for Rincón de Aranda, when we reach plateau, it's just maintenance.

Yes. So I mean it's just drilling and completing for the -- to fill up the decline.

Gas, we are already.

Gas, we already reached our peak, our plateau.

But when we have CISA, we will...

When we have CISA, we need to decide whether we're going to be supplying all of the demand above CISA or we will be replacing some of our demand with CISA, something that we need to.

In power generation, we don't have any projects in the pipeline. So that's it. Next question from Ignacio. It's, what are the conditions of the B2B PPAs that you signed? Which is very, very broad, like we have some in HINISA, some in...

Yes. Just to give you example -- information. But I think the volume is around 70 megawatts prices for energy in the mid-50s.

Yes, we are doing summer winter. We are doing peak, off peak.

They are 1-year contracts.

Yes, 1-year contracts. We have first year -- mostly of that 70 megawatts is first year, which is mainly -- it's mandatory, but we have some second tier. That's it.

Yes. In terms of capacity what the regulation has in order to incentivize the contractualization is that industries pay a higher capacity charge than what we collect. So that incentivize contractualization because we sell our capacity a little bit better than what we sell to CAMMESA and industries get a reduced price from what CAMMESA charge to them.

Yes. Well, Andresi Miliano from Balance. The liberalization of the power market contemplates procure energy by distributors. When do you consider this will be fully implemented? And how do you expect to impact your power segment? I guess the B2C conference is what he's asking, that we haven't done any...

No, we haven't done any yet. Probably some of our colleagues, especially the hydro -- the recently -- the hydro units have that, but have not -- that is not yet a public information. So that is a market that we need to see how it will evolve. I don't have any clarity right now.

Another question comes from Andres Cardona from Citi. Regarding power generation, we already answered. The second question, is there any short to midterm M&A opportunity? Is there more likely to be for upstream or for power generation?

There's nothing in the short term. So there's nothing in the pipeline. That is the question that we are studying neither in E&P or power generation. Harder to see how that is going to evolve going forward, but we are not actively engaged in any M&A opportunity.

This question was answered in previous calls, but well, there is always a new audience. Do you have any information about Rincón de Aranda. Specifically in the type curve, like, for example, with estimated URs, IP30, D&C cost per barrel?

We don't give any guidance...

Very good. I don't know, it's like around 1.5 million.

Okay. It's probably around 1.1 million barrels of EUR. And in terms of cost, we should be hitting $15 million per well approximately.

Well it's fully considered the whole thing.

All of it, all of it. All the way to the collecting pipeline.

Correct. Which sometimes is different from the measure from other players.

Yes, of course, of course.

Another question from someone I don't know is called [indiscernible] . How is Pampa involved in [indiscernible]?

No, we are not involved.

Can you give us from, [ Santiago -- Valeria ] can you give us some color from the next maintenances in power plants program in the power plants? Usually, we do it when it's offpeak, right?

No. Obviously, we do it either in autumn or in fall. I think there are plan -- and this year, I don't have anything in my mind for this fall, probably during -- sorry, Spring or fall. But I don't recall at this moment which plant has significant maintenance. Most probably will be Genelba and Loma de la Lata, those are the two2 relevant ones.

The legacy, right, the legacies. All right. Is there any change in 2026 CapEx considering the oil prices? This is a recent price of appreciation? No, nothing at all. Guido Visocero, his boss, he's asking urea project. Is there any further information to share about this project?

No, not at this point, not at this point. We're still working a lot. But as it usually happens, there are delays. So it will take at least another semester to have more information about this project.

Gustavo Faria from Bank of America. He's asking a little bit different from the hedge, but he said how does the Pampa's oil prices hedge works in this new environment of high oil prices?

I would say that last year, we realized like in average, $7 profit from...

Per barrel, right?

$7 per barrel profit from our hedge strategy. This year and since today, we are probably losing $4 or $5 per barrel in our hedge strategy. But we will see how prices evolve throughout the remaining of the year.

Gustavo is also asking, are you open for new investments outside power and gas -- oil and gas? Within Pampa structure?

As long as within the scope of energy of Pampa, we are open to anything. We are not studying apart from the urea project, we are not studying or not planning any different investment.

Okay. So Jonathan Swart from [indiscernible] is asking, why did you retire production from Plan Gas Round 1 and Round 3?

Reallocated to our power generation.

To vertically integrate.

To vertically integrate.

We still have some from the last round, the 4.2, right?

Yes, we still have that...

Which...

We're still negotiating eventually the handing over of that gas back to Pampa to be able to, say again, decide what to do with that gas rather than sell it to NASA.

Well, he's asking also, could you explain about the $55 million positive impairment, so recovery of impairment in generation? Yes. So Central Piedra Buena, our 620 megawatts in Bahía Blanca, it's a 2 steam turbine that load factor is very low. This -- last year was high because it was a dry year, but usually it's low. So under the legacy scenario under the old regulated remuneration, they have an impairment. Now that we have this new scheme that also recognizes a big -- like a big -- it's a 30% boost in the capacity because Central Piedra Buena can also operate under alternative fuels. This is way better than anybody can pay. Just because of that flexibility, it's cash in more money and cash in more cash flow. That's why we reversed that impairment. I hope that was clear. Okay. Next, news on the fertilizer plant. Does the sale of Profertil to Adecoagro affects your decision?

No, it does not.

Okay. The one-off offtake agreement mentioned by CISA, the German's price maturity?

Okay. It's an 8-year contract until 2036. And the pricing has to do with a formula that takes into account ETF and Brent -- I'm sorry, Henry Hub and Brent.

50-50.

50-50.

With certain percentages of discount. I think we did it all, and it's 7:26 I can't believe it. So I will check -- she's pulling for questions. But we are doing this because we have agenda constraints. All the people that asked why the stock was halted in nicely because Argentina closed and we were not allowed to file after 6:00 p.m. Argentina, and that's 4:00 p.m. in New York, and we are not allowed. So it's trading hours in New York. That's why we were halted. No speculations here because people ask me a lot of things. No questions? No more questions. So, Gus, Horacio and Fito would you like to add something else that we didn't talk about?

No. We covered it off. Thank you all for joining. I hope it was useful.

All right. Thank you very much. See you next May. Bye.