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. All participants will be in listen-only mode during the presentation.

After the company's remarks, there will be a Q&A session. Questions can only be sent in writing through Zoom.

Should any participants need assistance, please send us a chat message. Before continuing, please read the disclaimer on the second page of our presentation.

Let me mention that forward-looking statements are based on Pampa Energía's management beliefs and assumptions and information currently available to the company. They involve risks, uncertainties, and assumptions because they are related to future events that may or may not occur.

Investors should understand that general economic and industry conditions and other operational 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. 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 and gas Mr. Turri.

Let's go ahead with the first slide, where we make a quick summary of 2025. November 25, 2025, marked our 20th anniversary, Pampa and the creation of Pampa.

Back in 2009 2005, we did not produce any oil or gas, or did not generate any single megawatt-hour of 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, and our 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 a 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, cooperating 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.

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 destined 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. Moving on to the Q4 results, the quarter 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 wholesale electricity seg- 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 pads 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 1.1 times and average debt life of almost 8 years. Quarter-on-quarter EBITDA decreased due to the gas seasonality, 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 were invested the development of Rincón de Aranda. Moving on the slide 6, the oil and gas segment adjusted EBITDA was $77 million in Q4, more than doubling last year's, driven by Rincón de Aranda, increased gas exports, and industrial demand.

Higher transport and treatment costs partially offset this 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 costs 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, 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 tracking expenses, testing expenses, and we also had 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 was led by Rincón de Aranda and Sierra Chata, partially offset by decreases at El Mangrullo and in non-operated 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 would have been $53 per barrel. 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 in two new pads, with an average quarterly production of 17.1 thousand barrels per day. This is a 19% increase quarter-on-quarter.

As of today, 10 pads are online, of which three of them are currently undergoing well testing, and plus we have another two DUC pads, and two other pads are under fracking. In 2025, Rincón de Aranda contributed $126 million of EBITDA.

Infrastructure build-out, 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.

Moving to gas, sales grew 10% year-on-year, but dropped 23% in Q3 from Q3. This is, again, explained by seasonality.

El 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 lagged tariff pass-through of the devaluation.

In Q4 this year, 72% of our gas was sold under the Plan Gas PSA, 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 be doing the self-procurement of gas in Genelba and Loma de la Lata.

The self-procurement increased to 41% on average in January 2026. As a result, Plan Gas PSA exposure shrank to 37%.

With the new guidelines in place, we expect 40% of this year's production to supply 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 reserves.

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, with shale oil now accounting for 19% of total reserves.

The reserve replacement ratio was 3.2 times, 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, the year when we started to actively develop Vaca Muerta formation.

Moving to power generation, we posted an EBITDA of $111 million in Q4, up 28% year-on-year, mainly driven by stronger spot prices under the new guidelines, partially offset by lower dispatch at Genelba's new CCGT due to the program maintenance. Total availability declined to 91% due to this scheduled maintenance in Genelba, Loma de la Lata, and the ongoing outage that we are experiencing in Ensenada 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.

Contracted capacity remained stable year-on-year. With the new framework also, performance balances between contracted capacity and dispatch margin.

Value creation also have been driven by efficiency and fuel management. Those units with high load factors and self-procured fuel will achieve higher margins.

Turning to cash flow, on slide 11, we showed 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 tenor.

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 20 34 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.

This concludes the presentation. Thank you for hearing me.

Now the floor is open for questions. If you have a question, please send it through Zoom chat.

We will read it and answer them in the order received. Make sure your name and your company is displayed so we can correctly introduce you to the audience.

Should any participant need assistant, please send us a chat message. Please hold while we poll for questions.

Thank you. All right.

We start. Alejandro Demichelis from Jefferies: "How do you see the evolution of production, please a split between oil and gas, and of drilling and completion, and lifting costs in 2026?"

Production, drilling, D&C, lifting costs.

Hey, good afternoon and thank you everybody for joining. Regarding production, let's go first to oil.

We are, as Lida mentioned, currently 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.

In Sierra Chata, we will be drilling and completing eight wells each. I'm missing lifting costs, which will be in the range of $10 per barrel.

Until we get the CPF. Until we get the CPF, but we're talking about 2026.

Yeah.

A little bit less than $1 per million BTU in our gas operations.

Great. Let's go to the next question.

Next question comes from Guido Bizzozero from Allaria, about the hedging: "How are the royalties settled? Are they including 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?

Would you provide some color on the EBITDA growth outlook for this segment next year?" Next year I guess 2027, right?

This year. Hi, 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, it's between 10 and 15% vis-à-vis the EBITDA generation that we had in 2025.

More or less. That is what we expect for the segment as a whole when you compare 2026 vis-à-vis the previous year.

I guess 2027 is too early to say, right?

Say again?

2027 is too early to say.

Too soon to tell, yes.

Yeah.

What this resolution brings, it's also an improvement in our E&P business, and that is thanks to the fact that now we are self-procured. All the gas that 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.

That is thanks to the fact that we are self-procuring in our thermal plants.

We kind of not putting much number of that profit, right? 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.

That's correct. In our projections, we expect on the power generation segment, at around 10 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 Soares says: "Have you signed PPAs with private counterparties for energy or capacity?"

Yes, we have been very active since November, our commercial team has been extremely active. If I remember correctly, I think that we have sold 70 MW.

Now you can sell energy and capacity. We've been active in both, signed more than 100 and something contracts for a total of around 70 MW.

Yes, we have been very active there.

All right. Then: "How are you seeing natural gas demand and pricing in the industrial sector, 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 and the self-procurement, they are not that interested.

It wouldn't have an effect in Pampa, in natural gas.

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?

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

Basically, we are fully hedged 1 year going forward. Until first quarter of next year, we are fully hedged.

All right. Next question, coming from Bull Market, Felipe Golaço: "Following the new regulation, has Pampa been able to start acquiring gas from its own wells?"

I think it's all answered. "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

now.

We're producing more than before, right?

That's right.

January we produced

We'll be particularly producing more during 2026 in the wintertime.

It will be more like

We will have a flat curve.

Q1 is already higher than Q1.

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

Last year first quarter, it was a little bit different because Q4 it was very bad and CAMMESA took more gas. Even that, the production

Just take into account that the overall average of '25 was 12.5,

and

we're saying that only February is at around 14 million cubic meters per day. Our estimation is that we'll be producing around 13.5 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 had been filed by mid-2025, when it was first announced, but some news articles from about 1 month ago suggest it was just done last January.

Could you clarify that?"

Yep. I don't recall when we filed the RIGI for upstream, but it was definitely by fourth quarter of last year.

We haven't been approved yet, but recently there was a new decree adding upstream of oil to the RIGI, we are studying to file for an overall RIGI for the full development of of Rincón de Aranda.

All right. "Do you plan the fund the capex via new debt issuance?"

Hi, everyone. This answer is no.

The idea is we have a big cash position that we have acquired with our free cash flow and the last year net issuance. 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 have to revalue that decision and that eight-base scenario. Of course, we are very opportunistic.

If spreads keep tightening, there is something that we will look. The base case scenario is that we will face the capital investments with our cash position.

Great. Next question comes from Juan Ignacio Lopez from Balanz: "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 we will share with you what did our board approved for the budget, right?

Yeah. As Lida says, we're a strict group on, basically it's around $1.1 billion.

Basically $1 billion, the E&P segment, and less than $100 million on power generation because it's only maintenance capex. We don't have any new project going on on the power generation segment.

That answers? Okay.

Oil? No, he didn't say.

Oil is almost around the $1, 1 billion, billion. Great.

$1 billion. Awesome.

Next question he says is specifically: "How much of that is maintenance, and how much is scheduled for thermal plants this year?" It's pretty much

It's around $80 million, and it's all maintenance capex, yes.

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 we are assuming for your base case scenario?"

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.

That is what will bring the cash position from $1.2 billion to $700 million roughly.

All right. What else?

The price of oil.

Will be?

The price of oil assumed for the budget. I think it was less than $60, it's $58.

That's the one assuming the budget, but I think what is relevant here is the hedged price that is around $66.

That's right. A little bit above $66, right?

The hedge is Brent, right?

Then

after discounts and export duty, which is 8%, it's roughly a little bit above $58, depending on the discount.

Wellhead, you mean?

No, wellhead, it's realized, FOB. Because wellhead you had to account the transport.

Transportation. Um-huh.

Okay. Next question.

Oh, no. I'm never doing this 6:30.

We're never doing this 6:30 again. Esta.

Catteruccia Matías from Adcap: "How should we think the quarterly production ramp-up for 2026, particularly toward 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 is if they ask That is exactly he's answering the question.

He's answering. Then after, in 28, in the chart, we put 28 and then sharply goes up to the plateau.

No, that's not going to happen.

What do you Definitely

that's

not going to happen.

No, that's steep. No, and it's not financially efficient, it's probably going to be a ramp-up curve going from 28,000 to 45,000 in around 5 to 6 months.

Matías is asking: "Given that Pampa has more gas reserves that it can currently monetize, would you consider monetizing part of your gas acreage portfolio through farm-outs or farm-downs or asset sales?"

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

"Could you update us," another from Matías, "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?" Basically need the whole call, everything.

Yes. 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 roughly around 24 to 20 25 to 26 million cubic meters per day, and we have 20% out of that. The biggest capex involved in the project now is the construction of the dedicated gas pipeline from Tratayén to San Antonio Este, which will account for probably around $1.5 billion.

$1.4. $1.4, $1.3 to $1.5, and out of which we could consider that 60% will be financed, and maybe 40 30 to 40% is going to be equity, and out of that, we have 20%.

That's the major capex that we will be facing.

Francisco Cascaron from Doncap 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 is relevant, we signed our first long-term contract with SEFE, the German agency, for 2 million tons per year.

Is it binding?

It's already binding.

It's signed,

yes. It's more than binding.

Great. Awesome, the first sale.

Binding for both. For both sides.

Great. All right, shifting to power generation, Francisco Cascaron from Doncap, he's 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 would be something like batteries, and today CAMMESA or the Secretary of Energy announced 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. Has been published today.

Honestly, I didn't have time to take a look at it. Usually these are more projects very competitive.

We have colleagues very aggressive, very aggressive on pricing, not sure whether we are going to be actively in this option.

Great. Oh, that's it.

Agustín Pacheco from Arriba, 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?

Impossible.

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

They're two animals, right?

Two different animals, exactly. Different risks, 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 Pampa. That is where the question is pointed.

Talking

about, yeah.

Yes. Well,

"With the recent extension of the RIGI, are you thinking to apply?" I think we answered that.

Yes, we are studying to apply for the upstream part of Rincón de Aranda.

He's asking, I think it's too early to ask to answer, but: "Expected impact on project economics and timing?" We can give him a quick summary of the RIGI, if you if I may.

It's basically after the third year, you get export duties abolished, removed, right?

After

the third year. The tax percent the tax break rate goes down from 35 to 25%.

Accelerated depreciation, the taxable amount is smaller as well, so that helps through the first years of the duration. VAT can be VAT credits can be monetized.

What else? If I can remember.

I think that's mainly it.

It was pretty much that, yeah, right? It's a 30-year time that they give you, right?

The RIGI. Then, of course, a free disposal of all the proceeds abroad.

If you export, you can keep it. I think that's the key takeaways from RIGI.

That's right.

That's not AI who produced that. I have to think a lot of it.

He said, well, congratulations from Daniel Zapata from Proficio. He's asking: "The RIGI upstream, how broadens the scope of the Rincón de Aranda project, and how could accelerate the development?"

¿Querés contar, Horacio? De la parte norte.

He's asking. How's

the impact 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. We think that this is a major change in the overall economics of the project.

He's asking: "Should we expect the updated production guidance and timing, meaning adding rigs 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 is contingent to the RIGI application.

All right. Someone I don't know, who is name is Armando Moretti, which is very weird.

He's asking a question that we will surely answer: "Do the company's planning distributing 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 probably even so slightly positive in 2027.

We still see a lot of opportunities to continue growing, because of this situation, we are not planning dividends in 2026.

From Moneda Patria, Ignacio Irassabal asking he wants to double-check the capex estimates. For Rincón de Aranda, $770 million budget for this year: "How much is wells versus infrastructure?"

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

Right. "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 the expansion of the Perito Moreno.

This year.

This year. No, total is over $700 million.

We haven't talked about the TGS capex.

Very briefly

in

the Ah. folding chart, evolution chart.

I missed it.

Maintenance of TGS, $90 million a year, more or less. Total, right?

The trunk, the regulated trunk, the liquids, and what is left midstream, that's $90 million per year. "What should we expect for next years?"

Woof. For Rincón de Aranda, when we reach plateau, it's just maintenance.

It's just drilling and completing to fill up the decline.

Um-huh. Gas, we're already

Gas, we already reached our

That

peak or plateau.

When we have SESA,

we need to decide whether we are going to be supplying all of the demand about SESA, or we will be replacing some of our demand with SESA. It's something that we need to Yeah.

In power generation, we don't have any projects in the pipeline.

Um-huh.

That's it. Next question from Ignacio is: "What are the conditions of the B2B PPAs that you signed?"

Which is very very broad. We have some in Ensenada, some in

The PPA has better information, but I think the volume is around 70 MW, prices for energy in the mid-50s.

We are doing summer, winter. We're doing peak, off-peak.

They are 1-year contracts.

Yeah, 1-year contracts. We have a first-tier, mostly of that 70 MW is first-tier, which is mean it's mandatory, but we have some second-tier.

That's it.

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. 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 charges them.

Yeah. Andrés Milliano from Balanz: "The liberalization of the power market contemplates self-procuring 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 contract is what he's asking.

That we haven't done any, right?

No, we haven't done any yet. Probably some of our colleagues, especially the hydro units have done, but that is not yet public information.

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 Andrés Cardona from Citi: "Regarding power generation, we already answered this. The second question: Is there any short- to mid-term M&A opportunity?

Is there more likely to be for upstream or for power generation?"

There's nothing in the short term, there is nothing in the pipeline. That is a question that we are studying neither in E&P or power generation.

Hard to see how that is going to evolve going forward, but no we are not actively engaged in any M&A opportunity.

This question was answered in previous calls, but, well, the public is renewable, there's always new audience, so: "Do you have any information about Rincón de Aranda, specifically the type curve, for example, what's the estimated EURs, IP30, D&C cost per barrel?"

We don't give any guidance.

There you go. I can tell.

It's around 1.3.

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

Your well, it's fully, consider the whole thing.

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

Correct. Which sometimes are different from the measured from other players.

Of course. Of course.

Another question from someone I don't know, it's called Guillermo Goulou: "How is Pampa's involved in Transener sale?"

No, we're not involved. Um: "Can you give us,"

from Santiago Herrera, Allaria, "Can you give us some color from the next maintenances in power plants program in power in the power plants?" Usually we do it when it's off-peak, right?

No, obviously we do it either in autumn or in fall, if I think they are planned and this year, I don't have anything in my mind for this fall, probably for spring. Spring.

Spring.

Spring or fall. I don't recall at this moment which plant has significant maintenance plan.

Most probably will be Genelba, Loma de la Lata. Those are the two relevant ones.

The legacies, right? The legacies.

All right. "Is there any change in 2026 capex considering the oil prices?

This is a new or recent peso appreciation?" No, nothing at all.

Guido Bizzozero, his boss, he's asking: "Urea project, is there any further information to share about this project?"

Not at this point. We're still working a lot, but as it usually happens, they are delays, it will take at least another semester to have some more information about this project.

Gustavo Farias 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?" Hedge?

I would say that last year, we realized 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.

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?" We hope.

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. Jonathan Schwartz from DebtWire is asking: "Why did you retire production from Plan Gas Round 1 and Round 3?"

To reallocate for power generation.

To vertically integrate.

To vertically integrate,

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

We still have

with Enarsa, which we're

still negotiating eventually the handing over of that gas back to Pampa to be able to again decide what to do with that gas rather than selling to Enarsa.

He's asking also: "Could you explain about the $55 million positive impairment, recovering from impairment in generation?" Central Piedra Buena, our 620 MW in Bahía Blanca, it's a two steam turbine that load factor is very low.

This last year was high because it was a dry year, but usually is low. Under the legacy scenario, under the old regulated remuneration, they have an impairment.

Now that we have this new scheme, that also recognizes it's a 30% boost in the capacity because Central Piedra Buena can also operate under alternative fuels, this is way better than anyone can pay. Just because of that flexibility, it's catching more money, catching more cash flow, that's why we reversed that impairment.

I hope that was clear. Next.

"News on the fertilizer plant, does the sale of Profertil to Adecoagro affects your decision?"

No, it does not.

Okay. "The one off-take agreement mentioned by SESA, the Germans,"

SEFE,

SEFE, "Price, maturity?"

It's an 8-year contract until 2036, and the pricing has to do with a formula that takes into account TTF and Brent.

Henry Hub and Brent.

Henry Hub and Brent. Not TTF.

No. 50/50,

no? 50/50.

With certain percentages of discount and

I think we did it all, and it's 7:26. I can't believe it.

Let me check. She's polling for more questions.

We are doing this because we have agenda constraints. All the people that ask why the stock was halted in NYSE, because Argentina closed and we were not allowed to file after 6:00 PM Argentina, and that's 4:00 PM New York.

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.

Gustavo, Horacio, Fito, would you like to add something else that we didn't talk about? No,

we covered it all. Thank you all for joining.

I hope it was useful.

All right. Thank you very much.

See you next May. Bye.