I would like to welcome everyone to Pampa Energía's first quarter of 2026 results video conference. We would like to inform you that this event is being recorded.

All participants will be in listen-only mode during the presentation. After the company's remarks, there will be a Q&A session.

Please send your questions in writing through Zoom chat. If anyone needs assistance, please send us a message in the Zoom chat.

Before continuing, please read the disclaimer on the second page of our presentation. Let me mention that forward-looking statements are based on Pampa Energía's management beliefs and assumptions and information currently available to the company.

They involve risks, uncertainties, and assumptions because they are related to future events that may or may not occur. Investors should understand that general economic and industry conditions and other operating factors could also affect the future results of Pampa Energía and could cause results to differ materially from those expressed in such forward-looking statements.

Now I will turn to Lida.

Thank you, Lida. Hi, thank you Raquel.

Hello everyone, and thank you for joining us. I will make a quick summary so we can spend more time on the Q&A with the senior management.

Today we have our CEO, Mr. Gustavo Mariani, our head of oil and gas, Mr.

Horacio Turri, and our CFO, Mr. Adolfo Zuberbühler.

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 output under the new power generation framework. Rincón de Aranda, which began ramping up a year ago, is now producing approximately 25,000, right, barrels, thousand 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 3-year bullet notes at a highly competitive rate of 5.49% fixed rate.

Adjusted EBITDA amounted to $325 million. This is 8 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 8 times versus Q1 last year.

Quarter-on-quarter, EBITDA grew 41%, supported by synergies between gas and power businesses as Loma de la Lata and Genelba CCGTs self-supplied 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 the slide 4, the oil and gas adjusted EBITDA was $104 million in Q1, 2.5 times 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 33 36%, mainly due to higher gas demand for CCGT self-supply and exports to Chile.

As we mentioned before, total production averaged more than 100,000 barrels equivalent per day, primarily contributed by Rincón de Aranda and Sierra Chata, partially offset by lower output from our non-operated blocks and 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-operating non-operated oil assets.

Gas lifting costs decreased 10% year-on-year to $0.90 per million BTU and 23% quarter-on-quarter lower. This is supported by higher gas output.

Oil lifting costs 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 6 year-on-year to 19,500 barrels per day as Rincón de Aranda ramped up following the commissioning of the Duplicar 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 would have been more than $69 per barrel, resulting in approximately $21 million of 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, 6 wells were drilled and 15 wells were tied in, of which 7 came online last March, bringing the quarter's exit rate to more than 21,000 barrels per day.

For the remainder of the year, we expect to tie in an additional 20 wells and reach 28,000 barrels per day milestone by mid this year, mid 2026, supported by the second temporary facility that was commissioned in late March. We target a production plateau of 45,000 barrels per day once the central processing facility and the Vaca Muerta Oleoducto 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 7 to 9 stages per day, an increase of over 30%.

This improvement reflects the team's consistent execution and shorter cycle times across the development program. Also on March 9, we submitted the project's application to the RIGI incentive program, which is expected to accelerate the development in the northern area of Rincón de Aranda, support 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.

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 self-supply to our CCGTs under the new power market framework, higher exports to Chile, and stronger industrial demand. Exported volumes increased 65% year-on-year from 900,000 900,000 thousand cubic meters per day to 1.5 million.

Yeah. We expect these levels 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 a pad tying during the Q4 at Sierra Chata explains the 70% 70% year-on-year growth, while El Mangrullo just dropped slightly 7%.

During the quarter, Sierra Chata drilled 3 new wells, completed the 4-well DUC pad. For the second half of the year, the plan includes drilling 2 additional pads and tie in 1 pad before the winter aligned with the seasonal gas demand for our power generation business.

At El Mangrullo, the plan is just to drill a 6-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 increased above peso devaluation.

In Q1, 47% of our gas was sold under the Plan Gas GSAs through Cammesa and retailers, down from the 82% exposure last year, following the transfer of said GSAs to our CCGTs. As a result, interco consumption, actually intersegment consumption, increased to 32% of total sales compared to just No, their 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, on the slide 7, we posted an adjusted EBITDA of $144 million in Q1.

This is 11% year-on-year and 30% quarter-on-quarter increase, mainly driven by stronger spot margins at our CCGTs under the new guidelines in the wholesale electricity market, which operates under a marginal pricing system that benefit efficient units. Total availability fell, though, to 90%, mainly due to the ongoing outages in Los Nihuiles since January last year and the outage that we had in the gas turbine number 4 in Loma de la Lata.

This is not a CCGT. Which is expected to return in service in next month, in June, and a scheduled maintenance at Barragán.

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, whether it's PPAs with Cammesa or in the in the MAT, covering the the levels before the implementation of the framework.

Regarding the expansion of the Perito Moreno gas pipeline and its final sections toward Buenos Aires metro area, on April 15, TGS awarded the tender's first tranche corresponding to 4.8 million cubic meters per day out of the 12 meters per day of expansion in the transportation capacity. This is 40% of the of the expansion.

Pampa secured 3.2 million cubic meters per day, representing 27% of the expansion capacity and 2/3 of the first tranche tender. The The transportation contract is for 35 years under take-or-pay or, in this context, it's 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 4 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 1.

Therefore, 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 flow, page 8, we showed the parent company figures aligned with the bond perimeter.

Free cash flow was negative $404 million in the Q1, explained by collateral requirements related to the oil hedge, extensive intensive CapEx at Rincón de Aranda, and, 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 and, but the net debt rose to $1.2 billion, representing a net leverage of 1.5 times 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. Guido Bizzozero from Allaria: Considering the awarded 3.2 million cubic meters of gas capacity in the Perito Moreno pipeline expected for 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?

It's not a 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 of the marginal cost of the system. That will be dependable on prices of LNG and prices of diesel oil and during how many days during the winter those fuels will be setting 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, could be in the range of $100 million. That is basically what we are expecting because of, as Lida explained, with this firm capacity of gas, we will be able to capture the full margin, not only the 15% margin the 15% that the current regulation allow us to capture.

This year, though.

This year, yes. This 15% increases up to 35% by year

2028. Yeah.

No, I think it's 2030. No,

2028.

Okay. That is the rough estimate for power generation.

There is an additional increase in the EBITDA coming from the E&P segment. I don't know if you have that figure in [foreign language]?

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

Very conservative, yeah. Conservatively.

Yeah.

Then, of course, from our affiliate, TGS.

That's right.

That's the 27% of that, right?

That's right.

That's a package. Yeah.

On the other hand, we are prepaying for this transportation capacity, in 4 installments in the next 12 months, we will be prepaying the transportation tariffs 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 priority over power generators. Gas distribution companies decided not to participate in the first tranche of the auction.

That was this with you have to prepaid 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, it will depend on the amount of gas that they need to secure. On whatever is left from the distribution companies, then we may be able to secure a similar percentage as we secure in the first tranche.

Of course. All right.

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

No, nothing.

Yeah. Likewise for Diamante.

Both concessions was 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 and the new tariff scheme. How do you expect to evolve in the coming quarters?

Can you repeat the

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 E&P through the electricity, right?

Before we didn't. Before it was a pass-through, right?

It was very low sales, but the EBITDA normal. Before it wasn't like apples to apples.

We have a bunch of things. Now it's what it should be like.

You are selling electricity with the associated fuel, right, at right price, no longer something like a cost-plus situation, and then, of course, the EBITDA represents that. It's not like we are losing profitability.

It's just now it's more apples-to-apples, like-for-like.

No, actually on the contrary. Nominal margins have increased.

Increased. Yeah.

That's right. What matters is that the EBITDA is

Nominal margins are increased, but the total sales have increased significantly more because now you have to deduct the cost of fuel. Nominal numbers are better, the ratio is worse, but

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

Yeah.

I hope, 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. No, let me tell you.

The working capital, as you can see, mostly of this $343 million, 250 is for the oil hedge collateral requirements that Horacio and Gustavo can tell us better. Then $75 million of payments of last year's CapEx.

We increased the PPA last year and then we are paying it this year. Then very little, $20 million of higher DSO, days of sales outstanding, small delays on the payments.

Now it was last year's December, it closed at 6 days of delays. This quarter closed at 12 days, it's a 6-day deterioration, just nearly 6 days.

Now it's back to 7 days of DSO, now it's back to normal, putting it in this way. You want to add something?

Let's move on. How do you expect to evolve the free-

By the way, it's very normal with increasing sales that we have to have a higher working capital, no?

That is correct. How do you expect to evolve the free cash flow in the following 12 months, considering the installments prepaying to TGS, the CapEx plan for Rincón de Aranda, and any other divestments for projects like CIESA and Urea in the future?

Tito, you want to answer that?

Sure.

Tito,

estás muteado. Tito, estás muteado.

Sorry. Good morning, everyone.

As you can perfectly see, we are undergoing regular investments, and this was reflected in our net leverage that increased to 1.5 as we expected. Going forward, EBITDA is growing as well.

In fact, this is our record quarter, we're very thrilled that our investments are paying back. The base case is if we continue with our base scenario, is that EBITDA keeps growing, the company will naturally deleverage, and, in fact, if we don't pursue new projects, net leverage will go to 0 in 2 or 3 years.

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

Thank you,

Tito. Next, Santiago Rea from Allaria: Could you give us some color about the urea project, future deployment of CapEx and expected sales and EBITDA contribution beyond the year 2030?

Let me say this about the urea project. As we have been working for a while and we continue working on several fronts that includes engineering of the plant, negotiating the EPC with potential suppliers, environmental permits, 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 project finance.

They published the environmental permits in their websites and that gave publicity. This is part of the process.

They need to have this public for at least 6 months before being able to move forward. That's why it was published a couple, I think 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'll do an IR Day to fully explain why we are moving forward with this project.

To give you some color why a 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 South America.

South America has a deficit of 10 million tons of urea per year that we are importing. The plant that we are envisioning is a 2 million tons per year of urea.

In terms of sales, at normal historical prices, that would be sales for around $1 billion. Today, because of the disruption in the Middle East, at current prices of urea, would be almost twice that much.

Again, it's a project that makes a lot of sense for Pampa, that we are working on several fronts, and we hope to take the final investment decision by the end of the third quarter or at some point in the fourth quarter of this year. 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 investment about the already $1.5 billion plan for the area? Could you clarify that?

How do you expect this may accelerate and sustain the plateau in the future?

Okay. The full-field development for 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 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 6 to 8 more years.

All right. Then the next question from Santiago is regarding Transener: Can you give us the main 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?

Sirin?

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

or decrease. Regarding grid expansions, high-voltage grid expansions, I don't think there is anything new.

Nothing has been published lately by the Secretary of Energy, as I believe. We are expecting the government to do an auction for new power lines basically to strengthen the supply of energy to the AMBA area,

to the

Buenos Aires metropolitan area. That will be the first auction to be launched.

Transener 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.

It 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. But

Yeah. Until then, we're still curtailed in the power generation, right?

There is not much we can do.

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

Yeah. 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?

The level of leverage do you see Pampa getting into the next 2, 3 years? 2, 3 years is a lot, but

It's going back to the question I answered before. In 2, 3 years, if we don't pursue any other new projects like the urea plant, we will have no debt, okay?

In the meantime, while 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.

Also 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 deleverage 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 1.5 and going down to 0 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.

It 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 Cataruzzi from Adcap.

He's asking, well, other questions about RIGI answered, net debt leverage ratio answered. The third question though, it's Medanito-Brent spread tightening material with the premium now, Puesto Morales?

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 marker, to Brent, any premium on top of Brent will be captured by Pampa.

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

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 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've sold around 30% or 30-something percent of our total capacity. That will take more time to be completed, and once we sell capacity, it provides us an additional margin to the price that we sell capacity to Cammesa.

That will take time because it's a larger number.

That was expected.

Yes.

All right. A next question from Gustavo Faria, which it's partially answers about the fertilizer plant, but it's associated with you, Horacio, which he asks: How much CapEx comes from the higher gas production at the gas fields associated from the fertilizers project?

How much would be the additional CapEx?

Yeah. Okay.

The

urea project will come in line in 2030, so that would be after the Plan Gas ends. Therefore, we still need to understand what's going to be our mix of sales by 2030.

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 feed our urea project, then the CapEx is completely different as if on the other hand we decide to supply the urea on top of all of our additional demand.

Yeah. Correct.

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

Okay. No, Argentina currently consumes about less than 2.5 million tons per year of urea, and approximately half of that is locally produced by Profertil.

The first option will be local demand. Given the restraints on the project finance that require us 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 export sales.

All right. The people from Balanz Securities, Alejandro Dristas and George Gasztowtt, ask: How is the treatment plant on Rincón de Aranda progressing, and in 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. From Dubai.

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

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

Basically, we have 1 1 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, and as production continues to grow, we will be reducing the percentage of the quantity hedged to probably around 50%.

Cool. Next question: In the gas supply for the intersegment procurement structure, is it structured as a fixed-price contract?

He's asking how much power generation is buying the gas from E&P.

Okay. 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, and that's the price at which we sell, quote, our gas to our own power plants.

During the summer is just like the Plan Gas price.

During the summer, it's the Plan Gas,

that's right. Intersegment-wise, it will be very similar to what is Plan Gas, right?

No, no, no. It's significantly higher.

Oh, real? Oh, yeah, yeah.

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

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

That we're capturing.

It's almost twice the Plan Gas.

That we're capturing all of it.

That we're capturing right now.

It's just to allocate revenues or margin between the power segment and the E&P segment.

Cool. Then he says: Should we expect the variable cost component known as CVP recognized by Cammesa to remain broadly stable over the time, given this structure?

Actually, the CVP is not stable because, as Horacio was saying, the seasonal. In winter, CVP shoots up because of the cost of gas, right?

Yes. I would say that it's the first time in many years that Argentina is showing the correct price signal in the gas market.

This means that the price significantly escalates during the winter and is very, very cheap during the summer. 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 you intercompany gas procurement costs? Actually, no.

In order to be competitive, no.

He says,

can we have a spread against what we declare in Cammesa, what the real CVP it is, actually?

It's part of our commercial strategy, the declaration of the CVP, something that we do every 2 weeks, and

so

it's part of the commercial strategy declaring your CVPs. It's not necessarily the real CVP, there is a margin included in the CVP that you declare to Cammesa, yes.

It's a 25%.

So It depends. Every week is different.

It's

different, yeah. Cammesa does calculate theoretical CVPs.

You cannot go very different from what you declare. What you declare, you can't go very different from what theoretically Cammesa calculates for you.

You cannot say $1 CVP.

If you declare expensive, you're not dispatched. If you declare below the cost,

you are dispatched. That's why

I don't understand the

Yeah.

I think we answered that. Let's move.

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

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

Correct. Sorry, it's going to be 6 hours.

Luiza Belém from Morgan Stanley, she asks, another 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 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.

I think we didn't answer is, Do you expect the RIGI for Rincón de Aranda to be approved the next few weeks?

I don't think so.

No. Initially, RIGIs were approved in 2, 3 months, the first few RIGIs that were approved.

Then for other RIGIs, it took 6 to 7 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

No, just one clarification on what Gustavo said is that even if we get approved, let's say, 2 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?

Enjoy

it. Enjoy it.

No, work, work. Francisco Cascarón from Dun Capital, he's asking: My question will be regarding the OCI or other comprehensive income results in the pesos balance sheet.

We have also dollar balance sheet as well. Can you explain the loss approximately of $300 billion pesos, but there's in dollars.

Is it related to the loss not perceived for the production hedge for the rest of the year?

Yes, it's reflected in

other comprehensive income.

Exactly. That will be offset with future physical sales of oil at higher prices.

That's why this is an unrealized

Gain or

loss. It's not reflected in the

P&L, it's reflected in the net worth.

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

Also: Can you give us explanation of the $184 million jump in financial derivatives instruments on current liabilities? It's exactly that, right?

It's the mark-to-market. Mark-to-market.

All right. Andrés Emiliano from Balanz: What price is Pampa hedged for the year going forward?

The average price until April next year is $65.

66? $65.

$65, Brent.

Of course, this is the Brent marker.

Cool. Agustín Pacheco from Banco Mariva: PowerGen 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 assumptions 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, no,

$70-$80

million average annually per year. There are some years that significantly higher and some years that is lower.

That depends on the major maintenance that the turbines need to go through every several years.

Cool.

Average, around $80 million. That's why it's just a coincidence that this Q was so so low, no?

This year, it should be in the average range,

no? It's $70 million budget.

The quarterly D&A, or the D&A actually, it's because we are functional currency in dollars, we are increasing PP&E and we are, right, doing the D&A, that's why, and we have increases in the past few years, it's a normal amount.

Yeah. Probably the $35 million that he mentions in previous year is not only maintenance, but it's probably the end of the PEPE 6, the wind farm I think it was in the first quarter of last year, payments related to the last

wind farm

that we built.

Correct. Álvaro Leyva from BTG, he's asking: What are the expected losses from the hedge strategy in 2026 and 2027?

Again, we don't consider that losses. The goal when we decided the hedging policy was to ensure stability of results, especially during the ramp-up and the first phase of the development of Rincón de Aranda.

At the level that we hedge, we secure a very good profitability and IRR for the project. Obviously, now that prices are higher, it's something that we knew it could have happened.

It could have gone the other way, as it did last year and we profit from this strategy. Again, the strategy is to provide stability to the results.

That was the goal, and that's it.

Cool. It's 12:00.

We have three pages of questions. A lot of questions.

Different questions? On this different subjects?

Can you imagine? 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 EBITDA. The first PPAs, the first one is expiring in July this year.

It's a very small one, 35 megawatts. Next year is another 300 megawatts.

Then until 2045, we have the 400 megawatts of CCGT in Genelba. I will say, roughly speaking, the most important amount is next year's 300 megawatts.

Total, they represent this roughly 400 megawatts 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 going to happen in along time, and 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 on leverage in dollars? No.

I think we already covered urea.

Yeah. Shares continued trading at this multiples.

Why not prioritize aggressive share buybacks instead of pursuing in organic growth? What in organic?

Urea, I think is mentioned.

That's organic.

Organic? Because

you are doing by yourself, it's organic.

You're not buying. Yeah.

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, actually, one point to take into account is the liquidity of the stock.

Definitely the buybacks 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 are, we think, are competing extremely well with the possibility or with the buyback of shares.

All right. Gamze Acar from Tera Yatırım 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 2/3 is in the south, 1/3 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 dimensioned our CPF for. How many years she asked?

How many years of production?

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

Okay.

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

Daniel Guardiola has more questions. He's asking: What's the expected EBITDA and free cash flow generation for 2026?

Let me give you a disclaimer here. We don't give guidance.

This is Argentina. We can share with you what our forecast of the budget it is, right?

[foreign language] What's the expected EBITDA and free cash flow generation

for 2026?

2026. Actually, no generation, outflow for 2026, right?

We don't give guidance, but we can share with you the budget, which is the EBITDA for the parent company, it's around $1 billion, composed by 600 from E&P and 400 and something from power generation. Beware that this is not including the JV with Barragán, a little bit over $1 billion, of course.

Then corporate and petrochemicals are negative, that's why it's rounding is $1 billion. In the consolidated level, this is including the TGS and Transener's share, equity share, it's around $1.3 billion.

Then in the free cash flow, this is including the prepayments of TGS, CIESA, San Martín, and Oldelval, it's around a outflow of around $400 million free cash flow outflow. Have you considered to grow inorganically in the oil window of Vaca Muerta?

This question, he always asks. He asks.

Good. How is an inorganic Vaca Muerta oil project ranking in terms of risk-adjusted IRRs against the urea project or the San Matías pipeline?

That's a good question, though.

A good question. We are permanently looking at opportunities in oil, in the shale oil window.

It's very hard to give an IRR because it will very much depend on the quality of the asset. I would say that for a good asset, definitely we will be tempted to go ahead into an inorganically operation.

Yeah.

Regarding San Matías, it's not a project itself. It's part of the investment of the floating LNG project, and it's done by the same shareholder structure of CIESA, not of the whole project.

Cool. Another question from I don't know how he pronounces, sorry, but I guess it's Guigolet from Scarle Macau Capital: The first question about the hedge is answered, but the second question is very funny, but it's worth asking: With abundant gas potential in Argentina, what about petrochemicals?

It is barely profitable, or does it make sense to keep it, or would you consider selling it to simplify the company, like you sold the mature oil fields?

We are looking for alternatives. Nothing is on the table at this point.

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

We always like to have high liquidity to keep all our options open. It could be the case that we decide to continue tapping the market in the medium term.

Cool. Ignacio López from Puente.

He's asking: I would like to ask the outlook for gas segment, particularly considering increasing production and the lower exposure to Plan Gas. Could you share your expectation for local gas prices this year, especially for volumes traded outside Plan Gas?

I guess he's asking about the industries or

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

Yeah.

As we mentioned before, it's the first time in many years that they are giving the right signal to the market, our view is that the gas prices for 2026 are going to be higher than last year.

Indeed. Now with the war, more, yeah.

With the war and particularly in the domestic market with the possibility of setting your gas at an alternative at least a percentage at an alternative import parity.

Correct. Armando Moretti, he's asking: Do you plan to pay dividends?

No.

Jorge Mauro: This is the last one, I swear. Ya contestamos, ¿verdad?

Listo, sí. That's true.

Okay, 10 minutes more, I'm sorry. Sorry for that.

12 minutes. It won't happen again.

Thank you very much. I don't know if you all like to add some We've

covered all.

For all, next earnings is on August. Thank you very much.

Thank you very much. Thank you for your attention.

Thank you.

Thank you. Have a good day.