PAM

Welcome everybody to Pampa Energía's second quarter of 2026 results video conference. We would like to inform you that this event is being recorded. All participants will be in listen-only mode during the presentation. After the company's remarks, there will be a Q&A session. Please send your questions in writing through Zoom chat. If anyone needs assistance, please send us a Zoom message. Before continuing, please read the disclaimer on the second page of our presentation. Let me mention that forward-looking statements are based on Pampa Energía's management beliefs and assumptions and information currently available to the company. They involve risks, uncertainties, and assumptions because they are related to future events that may or may not occur.

Investors should understand that general economic and industry conditions and other operating factors could also affect the future results of Pampa Energía and could cause results to differ materially from those expressed in such forward-looking statements. Now, I will turn the video conference to Lida.

Hi, everybody. Good morning. Thank you for joining us. First, I would like to give you a quick summary of our announcement on fertilizers. This is a new business. Then a quick summary of the quarter, so we can move on to the Q&A. Today we have only our CFO. We have a small inconvenience with Gustavo, but I think we both can do it, right? Yeah. Let me go to the slide three, which you can see. Last July, our board approved the FID for the construction of, so far, Latin America's largest urea plant, officially marking Pampa's entry into the fertilizer business. Granular urea is critical to agricultural production and global food security, and it is primarily used in the production of corn, wheat, sugarcane, and barley. Because its main feedstock is the natural gas, urea production is highly concentrated in a few countries.

While Argentina and its neighbor countries currently rely on imports from distant regions, today exposed to significant geopolitical uncertainty. The investment thesis is straightforward. It's just we aim to monetize the vast shale gas reserves that Pampa holds in Vaca Muerta through the development of high-value-added businesses. Natural gas and electricity account for approximately 70% of the production cost of urea and will be supplied by Pampa, reinforcing the competitive advantages of our vertically integrated business model while enhancing the project's operating efficiency and long-term profitability. Beyond diversifying Pampa's revenue base, the fertilizer business will also help Argentina's foreign currency generation through import substitution. We are substituting imports and increasing exports with an annual contribution of approximately $1 billion.

Brazil, which currently imports between 7 million and 8 million tons of urea per year, together with the rest of the southern corn, which has an annual deficit of about 2 million tons, will be the project's primary market. The plant will be located in Bahía Blanca on a proprietary site, strategically positioned next to one of Argentina's main export ports, Bahía Blanca, with direct connection to Vaca Muerta pipelines, existing pipelines, and close to Pampa's thermal and renewable power generation assets. This is a $2.7 billion investment to build on a turnkey basis, a 2.1 million ton per annum plant, consuming 3.3 million cubic meters per day average year, and 75 MW of power, all again supplied by Pampa. The plan is scheduled to be completed by the end of 2029.

Now that we have reached the FID, the next milestones are obtaining the RIGI and the Buenos Aires RIGI approvals, which are essential to the development of the project. Last Friday, the evaluation committee of the RIGI cleared FertilPampa's presentation. We are waiting for the formal approval to be published in the official gazette. Thus, Pampa continues to strengthen its industrial profile further through the several projects presented under the RIGI framework. We are currently participating in seven projects across oil, gas, midstream, LNG, fertilizers, NGLs. Last June, following the FID at TGS, our affiliate filed an application for the 3 billion investment on an integrated NGL project. Also, TGS's Iniciativa Privada, which consists in expanding the Perito Moreno pipeline, the San Matías dedicated pipeline for the LNG project, and the Rincón de Aranda. All those RIGI applications got approved.

Overall, these projects provide a clear roadmap for Pampa's long-term growth, supporting Argentina's export expansion, and enable us to monetize Vaca Muerta's resources further. The adjusted EBITDA amounted to $415 million, highlighted by a quarterly all-time high production of 107.5 kboe per day due to the sustained ramp up at Rincón de Aranda and gas cell supply. The new regulatory framework also had a positive impact on our power generation segment, which benefited from the strong spot margins as high fuel costs impact and drove the marginal costs up the system. That helped. We have more B2B PPA sales. To the lesser extent, increasing the national prices also boosts the petchem business, which recorded its highest quarterly EBITDA since 2023, three years ago.

Quarter-on-quarter, EBITDA grew 28%, supported by gas seasonality, stronger spot power margins, and increased petchem prices. CapEx dropped 21% year-on-year to $279 million during the quarter, of which 165 were destined to Rincón de Aranda. It is worth noting that we already invested last year, $900 million in Rincón de Aranda, and we expect to invest an additional $700 million this year as we move toward the 45 kbpd production plateau, once the CPF and Vaca Muerta Sur oil pipeline are both online next year. On slide seven, the oil and gas adjusted EBITDA was $182 million, more than double last year, driven again by Rincón de Aranda production ramp up. The gas cell supply to our power plants are resulting in higher output billing at stronger prices as fuel costs pass-through increase.

These factors were partially offset by lower realized crude oil prices due to the hedge. Quarter-on-quarter, EBITDA increased by 74%. This is mainly explained by gas seasonality. Total lifting costs grew 30% year-on-year. This is primarily driven by Rincón de Aranda ramp up, partially offset by the divestment at El Tordillo, and lower activity at El Mangrullo gas block. Cost per BOE, however, remained broadly flat at $7.7 on average as production growth offset the increase in lifting costs. If we do double click, oil lifting cost per barrel actually declined 28% to $15 in Q2. It increased quarter-on-quarter following the commissioning of the second TPF at Rincón de Aranda that increased the crude oil treatment from 20,000 barrels to 28,000 barrels per day.

Gas lifting costs also decreased 13% year-on-year to $1 per million BTU, but slightly decreased 6% sequentially due to the maintenance cost at El Mangrullo. Focusing on crude oil only, production increased three times year-on-year, purely explained by Rincón de Aranda. Realized price averaged nearly $59 per barrel. This is a little bit below last year due to the oil hedge. Without the hedge, the prices will have been $91 per barrel, resulting in approximately $64 million more of sales. Exports accounted 57% of total volume sold in Q2 2026. This is very similar year-on-year and quarter-on-quarter. Rincón de Aranda contributed one third of oil and gas EBITDA, up from 6% last year. Last year was only 6% and this year is one third. This year's quarter. This is continuing to diversify the production mix.

Oil accounting 22% of the total output. At Rincón de Aranda, the ramp up continues. As you can see, the performance is comparable to the best blocks in the Core Hub, reaching a new record of 27,000 barrels per day on May 21, actually, specifically. Since March, we have not had tying new wells, just producing from 33 wells. Even so, Rincón de Aranda averaged 22,000 barrels per day, up 22% quarter-on-quarter. The quarter's exit rate was 16,000 barrels, temporarily affected by chokes of certain wells while we completed other neighboring pads, so we avoid the frac hit. These 10 wells in said two pads were completed in July and will be tied in in August. Well, now. Which will support a rebound in production. In Q2, we also drill another 10 wells for two pads.

Currently, we have two high-spec rigs and one frac fleet operating in the block. For the remainder of the year, we expect to tie in those 10 wells that we drill and to reach an exit rate of 28,000 barrels per day. Our target remains a production plateau of 45,000 barrels per day once the CPF and the Vaca Muerta oil pipeline are online next year. Regarding RIGI, well, as we said previously, the application was formally approved on July 21 as a long-term strategic export project. The application includes the drilling and completion of 259 wells from July 2021 on, and the construction of the CPF, we are already building, oil and gas pipelines, and water treatment plants, facilities to treat the water flowback. Total estimated investment amounts to $4.5 billion, and it is expected to be deployed through 2041.

The RIGI approval represents a significant milestone for Rincón de Aranda, providing a stable framework for tax, customs, and FX incentives for 30 years. Long-term strategic export projects are also eligible for specific benefits, in particular, the exemption, the waiver on export duties starting in the second year of operation after the enrollment. In this sense, Pampa expects to export all of Rincón de Aranda's production through Vaca Muerta's oil pipeline, which is estimated to generate approximately $17 billion over the project's useful life. Moving on to gas, production increased 10% year-on-year and 4% sequentially, reaching over 14 million cubic meters per day, driven by the gas self-supply to our CCGTs under the new power market framework, partially offset by lower volumes sold under Plan Gas, and to a lesser extent, reduced deliveries to large users.

Seasonal demand from retail and CAMMESA explained the quarter-on-quarter growth, offset by lower self-supply procurement since we have faced transportation restrictions in the gas pipelines. During Q2, we tied in four new wells at Sierra Chata, bringing production to a new all-time high. At El Mangrullo, there were no new development activity, with production supported by the existing well base. At Rio Negro, four new tight gas wells were drilled, and two were connected. For the second half of the year, our plan includes drilling activity in Sierra Chata and El Mangrullo. This is aligned with our 2027 activity production plan, which considers the recently awarded transportation capacity at Perito Moreno pipeline, in which gas transported through new infrastructure is able to capture the full spot margin.

In Q2, 56% of our gas was sold under Plan Gas GSA through CAMMESA and retailers, down from the 80% last year, following the transfer of these GSAs to our power plants for self-supply. As a result, intersegment consumption increased to 31% of our total sales. This is compared to just 3% last year. Under the new framework, we expect approximately 40% of this year's production to procure our own power plants' needs. Export volumes remain flat year-on-year at 1.2 million cubic meters per day. Industrial volumes declined as we prioritize self-supply demand, which is priced at a higher price because of the higher pass-through allowed by CAMMESA. This is seasonal and the regulation guidelines. Gas prices averaged $4.6 per million BTU.

This is 15% higher than last year. This is reflecting higher fuel pass-through in power generation by CAMMESA, again, because of the winter season, plus higher retail prices following tariff increases above peso devaluation. Turning to power generation, we posted an adjusted EBITDA of $155 million in Q2. This is 39% higher than last year and 8% higher than last quarter, mainly driven by stronger spot margins and B2B margins under this new regulatory framework, as well as LNG procurement margin. However, this was offset by the mandatory maturity of Energía Plus contracts, the outage of Loma La Lata's gas turbine number 4, that is under a PPA, which is remunerated under a PPA, and the PEPE wind farms underperformance. As you know, the new guidelines will introduce marginal costs as part of the spot pricing methodology.

That marginal cost overshot during the quarter, especially during the winter season, reflecting higher fuel prices, in particular using LNG and liquid fuel oil, diesel oil. The spot margins widened specifically for the CCGTs. Though that margin is capped at 15%. We only can capture 15% of that margin. That's what I mean. The current framework allows full margin, so you can capture the whole margin, if you're using new infrastructure, such as a gas pipeline, which that's the case for Perito Moreno pipeline. That will be online next May 2027. This full margin thing is not only benefiting power generation, it's also benefiting EMP, which will be producing more gas that now has security to be transported through this Perito Moreno expansion. Full capture, the FRA equals to one instead of 15%. Pampa was awarded 3.2 million cubic meters per day in the Buenos Aires-bound trench.

It will be used to procure the gas needs of the legacy Genelba CCGT. We also participate in the second tender for the remainder of the Perito Moreno. We are waiting for the results. If the regulator grants the clearance, we should add another 0.7 million cubic meters per day to the Buenos Aires trench, plus another 1.3 million cubic meters per day in the Bahía Blanca trench. Total availability fell to 88% during the quarter, mainly due to the ongoing outage in HINISA, which now is currently, since July 31st, is no longer part of Pampa. We had some outages also in Güemes and in the mentioned Loma La Lata TG number 4. Barragán also has some scheduled maintenance. Even though it's 88% availability, we continued to outperform the peers in the national grid. 35% of the capacity was contracted, slightly higher than Q2 last year.

This is reflecting the new guidelines that boosted the B2B PPAs. Going to the financial part. Turning on to the cash flow in slide 11. We present the parent company figures, which aligns to our bond parameter. Free cash flow was negative $128 million in Q2, but improved year-on-year and quarter-on-quarter. This is mainly due to stronger EBITDA generation and lower CapEx at Rincón de Aranda, and receivables due to the better collection, though this is impacted by higher winter sales. Quarter-on-quarter improvement is explained by the release of collateral on our Brent hedge as oil prices declined. As a result, cash and cash equivalents stood at $1.3 billion at the quarter end, $604 million more than Q1. On the balance sheet, gross debt as of June was $2.6 billion.

This is mainly because of the re-tap of 2037 Notes priced at the lowest spread to the T-bills, U.S. T-bills in Pampa's debt issuance history and corporate history, I must say, Argentine corporate history. Net debt rose to $1.3 billion, representing a net leverage of 1.4 times to the last 12 months EBITDA. Concludes now this presentation. The floor is open for questions. If you have a question, please send it through the Zoom chat. We will read it first in, first receives, first served. Make sure your name and your company is there. Otherwise, we can just read it. We can also reintroduce you to the audience. Should any participant have assistance, just send us a chat through the platform. Thank you. Wait while we poll for questions. [Foreign language] Should we start?

With the new expansion projects that Alejandro Demichelis from Jefferies is asking, how do you see CapEx in the next 2 to 3 years? At what level do you expect debt to leverage to peak?

Good morning. Thank you for the question. Yeah. Evidently, we're facing challenging CapEx deployment, especially with the urea project. Also bear in mind that EBITDA, looking forward, should increase as well. Once we achieve maturity of the Rincón de Aranda investment and the Southern Energy and San Matías pipeline investments by 2028, cash flow generation will be increasing and stable. What we foresee is that net leverage should increase from current levels up to a maximum of around two times. The ratio should vary between one and a half and two times for the next 2 to 3 years, until we finish the investment in the urea project.

Great. The CapEx this year is basically around $1 billion, right?

Yeah, the CapEx this year is around $1 billion, mainly the Rincón de Aranda project. Next year.

It's a little bit lower

it's lower. Separating urea project, it will be around $700 million CapEx next year. Again, mainly Rincón de Aranda project. After that, Pampa will have only maintenance CapEx of all the business units in around-

600

600.

Yeah.

We have to add to that the equity contributions from Pampa to Fertipampa. Yeah?

Cool. Guido Visosero and Santiago Herrera from Allaria, they're asking, after this 23 jump in EBITDA for the first half of 2026, how do you expect to evolve the second half and 2027 power generation? Considering in 2027 that in the second half starts rolling out the PPAs. Do you want to?

Yeah. The second half of the year, remember that always the last quarter for Pampa is the weakest due to the seasonality of gas.

Power demand, actually.

Power demand.

Power demand.

Bear that in mind. Always the last quarter is a little bit weaker. It will be partially offset by the increase in the production of Rincón de Aranda. The oil business will keep growing. Remember the seasonality in the other segments, right?

I think he specifically only refers to power generation. Q3 is going to be higher than this one? That's what we expect because winter is-

Q4 always is

Yeah. First half is $299 million of EBITDA. We expect $600 for this year. Yeah, $600 million for this year. Basically, it jumps up in Q3, if winter allows, and then goes down. It's specifically because the Niño, right? There's more water, so it means lesser thermal power demand. In 2027, it's a combination. Second half starts rolling out PPAs, we also have the TGS' Iniciativa Privada that, hey, we have 3.2 million confirmed that we will inject it through Genelba's legacy, CCGT. Actually, it's going to start before the winter, so the most of the impact will be monetized next year, though it starts in May. Next year's EBITDA, it could go up. We are expecting 600. Well, a delta of around $100 million should things, the winter and the liquid fuel consumption, energy consumption remains pretty much similar.

In 2028, as you correctly said, it goes down. It's a combination that in 2027, the PPAs rollout doesn't much reflect because it's towards the end of the year. In 2028, you should see that it's a little bit low. It's $40 million less because the PPAs roll out, but at the same time, they join the spot market. Loma La Lata, out of the PPAs that roll out, two of them are at Loma La Lata. Loma La Lata is highly competitive because it doesn't require any gas transportation. They are very efficient machines, so they kind of rank senior among the thermal units in the system. I hope that answers the question. How do you expect to increase the stake of gas used and sold to power generation, since we noticed an increase from 3% to 31% year-on-year basis?

Well, basically, as I said in the call, the average of this year, it's around 40%. It should pick up in Q3. Actually picks more. It's highly reliant on self-supply on Q4. The demand and gas demand goes down, we expect no troubles in the gas transportation system. Going forward, 2026 is a gradual year. It's a transition year. 2027 and onwards, you should expect the following. The thermal units consume around 10 million. Only Pampa, not including Ensenada and Varese. 10 million cumeters per day, of which 8 goes to the CCGTs. 8 Loma La Lata CCGT and the 2 CCGTs are Genelba. The CCGTs are the flat consumption of gas for self-supply. That's what you should expect going forward. Third question from Allaria people.

How do you expect petrochemical business to evolve in the future, considering the 5% contribution to the consolidated EBITDA this quarter, when it usually is negative or slightly, or break even? What it is, right?

Yeah. We expect to continue contributing marginally to the EBITDA.

It was something circumstantial.

Due to the war and the high prices and bigger margins that we have this quarter in some of the products that we export, but we don't expect that to hold in the long term.

Correct. Can you give any color on how do you plan to finance the $3 billion capital urea project and the deployment along the 41 months work?

Sure. Since the beginning of the year, we've been working intensively in the financing. The idea is to finance the project through a project finance loan with limited recourse on Pampa. With that in view, we started in February, a very thorough due diligence. We've been working in six open fronts with different independent consultants to complete that due diligence and make the deal bankable. We are close to finalizing the due diligence process. We hope to end the process in August. We are negotiating the terms of the loan. I cannot disclose much more today, but I will tell you that we are well advanced. We are discussing the terms, and we expect to finance a proportion around 60/40 equity loan ratio. The deployment of the equity is more or less even except 2028.

There is a big spike of the CapEx is concentrated mainly on 2028. I will say one-third of the CapEx is on 2028, and the rest is evenly distributed on the remaining years. I will think that we start contributing capital to the project this year. The financing will be closed by the last quarter of the year, probably. The big contributions, both of debt and capital, will be on 2028. I think that covers the question.

Yeah. How much revenues and EBITDA we may expect to come from this urea project on a consolidated basis, considering more electricity and gas will be needed to produce urea?

Yeah. Well, the revenues, I think we already disclosed that.

Where?

Yes.

$1 million. Yeah, yeah.

Yeah. $1 million.

$1 million.

The math is pretty simple. Depending on the price of urea you take, you multiply 2.1 million tons of urea per year times the price of urea you would like to choose, $400, $450, $500, and that will give you the revenues. EBITDA will be around 65% of that. Again, you have to factor in the price and the net backs, whether you sell to Brazil or to Argentina, or what combination, those are the big numbers that you can easily compute. What was the rest of the question?

No, how much impact on Pampa's EMP and power? It is a very good question.

Very good question. Yeah. Remember that starting 2028, the GSA starts to mature.

Correct.

It's not clear that we are going to increase gas production for the project or substitute current production from one market to the project, okay? That is something we will have to decide moving forward.

assuming.

If we increase gas production only for this project, it's around $90 million.

$90 million

of EBITDA additional to the gas segment. Again, it's a decision that we will have to make in the next three years, okay?

The price is around $3.

The price is $3.

$3 is our internal GSA.

Internal GSA, yeah.

Yeah.

Consumption is $3.3 on average, year average.

Yeah, it picks up.

In winter.

In winter.

On average, it's 3.3 million cubic meters of gas per day.

in power, we are not planning to build new power facilities for this. Well, we don't know.

Not for this.

Not for this.

We will see.

We will.

Again, the power contribution is marginal.

Marginal.

The big contribution here is gas.

Yeah. Imagine, well, today we are selling B2B PPAs at $65. Monomic price, right? This is considering capacity, $65 to $70. Well, we were talking about the B2B PPAs boost in this quarter, basically because people are seeing the prices in the spot. If you go to the spot, the prices are really high. That's why when this deregulation started, the industrials didn't start to get into the B2B market, now they're getting into because they seem highly seasonal. It's better pay flat at a certain price of around $65 to $70 per MWh, which is this is what we expect to sell in this-

Yeah, it's around $68-

Yeah

The consumption is 77 MWh. Again, it will be additional energy capacity rather than replacement of-

I imagine myself using our renewable wind power.

That's the plan, yeah.

Yeah. Back up with our thermal units.

Exactly.

Yeah. Another question from Hilaria. People saying, considering the current production levels at Rincón de Aranda and the 10 wells are scheduled to be connected in August, what kind of production ramp-up can we expect between now and the end of the year?

Okay. Remember that the goal this year is to reach the 28,000 barrels of oil per day. This increase is like a seesaw, okay? You are tidying up wells, closing, tidying up, closing, you will see these peaks and throws of production, but the goal is to achieve the 28,000 barrels of oil per day by the end of the quarter. Again, it's not constant. The same will happen next year when you try to reach the 45,000 barrels of oil per day. The increase will be like a seesaw and a ramp-up until the 45.

What else? Bruno Montanari from Morgan Stanley, he asks, "How can we think about Pampa's long-term peak gas production considering the volumes to CESA, to their project, the sole procurement for power generation?" Well.

Yeah.

Well, that's flat actually.

Yeah. What we foresee, and this is not a projection, it's a budget, if you like. Imagine that we can procure to our own power business around 10.5 million cubic meters of gas per day, another three and a half to our urea plant, another six to CESA, to floating LNG project.

1.5 for exports.

1.5 for exports. If you would add up.

A little bit during the peak is around 20-

It's around between 20 and 22-

Peak

Peak.

Peak. Flat average is 20.

Yeah. It's around 20 million cubic meters of gas per day. Quite constant because we are selling intercompany, we avoid the seasonality. Yeah, that is what we foresee in the next three to four years when all our projects are online.

As you can see here, no retail. Assuming no retail.

Yeah, assuming no retail.

No CAMMESA power source contention during the winter.

Yeah, it is 10 to our plants, three to our urea plant, and six to our floating LNG plant.

Yeah. 10 is assuming all the plants.

Yeah.

CCGTs only is eight-

Yeah

which is the baseline, right?

Yeah.

Bruno also asked a very good question. Once we reach this peak, how long can we sustain it at the plateau and what will be required CapEx to sustain at that level? It's a very good question because we have a lot of gas. Assuming 22 Well, let's do it very conservative. Assuming 20 million cubic meters per day of annual production, and with the current, not saying resources, but 2P reserves is around securely 25 years of average life. This is only 2P, not even including the 3P-

Resources

yeah, the resources and so on. How much required CapEx? Well, if we're doing the math and assuming the average well type of our shale gas blocks is around $250 million to $300 million. Obviously considering also the CapEx to maintain the treatment plants, it's around $250 million to $300 million of CapEx per year. Okay. Can you talk about the funding strategy of urea? We talk about it, right? The funding of urea project, the strategy. We talk about it.

Yeah.

Yeah

Yeah. Well, it's what Lida presented. On the one side is to monetize our gas reserves, which is a perfect fit. On the other hand, urea business per se, which as Lida explained, the region needs a lot of urea, and it's coming from faraway regions, very unstable regions. It makes total sense to reduce logistics cost and procure ourself our own urea for the region, and don't depend from wars or geopolitical risks. The third opportunity is the REE framework, which makes this project possible. The fourth, I will say opportunity is our balance sheet. We have a lot of cash and low leverage. We've always been asked why we have so much cash, and one of the reasons is for this. We were waiting for opportunities like these ones to show, and we are ready to deploy the cash.

We're not afraid to use our balance sheet that is very unleveraged and grab these opportunities and profit from them. These are the four main angles of the project.

Well, actually, it's not a bad timing to just say this. It's 100% owned by Pampa.

Yeah.

Right? Bruno is also asking, well, about the debt. Can you share something about the tenor, the interest cost?

Well, I cannot share about the interest cost yet. We are negotiating. What we can say, which is pretty obvious, is given there is a project finance

we have a spread over our bonds, for example. Okay? We will see finally where we land the cost, we cannot foresee that. For sure, most likely, the profile will be 4 years grace period while we build the plant. The maturity, it is not close, but it will be closer to 7 years or something like that, give or take.

The last question from Bruno is about lifting costs of oil, obviously. Can you expect a normalization following the recent increase driven by the new TPF? The TPFs are rentals. They cost around $5 million per month. Basically, we commissioned a second TPF, but the production didn't go up because we choked some wells, so we avoid frack hit in the fracking of other pads. Now that everything is fracked, everything it's done, we can connect all the pads and resume the choke ones and connect the new ones. Right? Right now we expect an exit rate of lifting cost of around $10 per barrel with the two TPFs.

Once the TPF is online, and also considering the fact that the production will ramp up, we are expecting $5 by second quarter of next year, because we expect the TPF to be ready by first quarter of next year. Alejandro Christensen from Latin Securities, he's asking, how should we think about the shell gas lifting costs over next year and with Cesa coming online next year? This is a very real question because, it's all about, are we going to be highly seasonal or not? Today it's difficult to think going lower than what we are right now, around $0.80. We are now on an average year of $0.80 to $0.90 per million BTU. If we are only producing flat volumes, it could go a little bit lower, but not more than $0.60, $0.70. We'll see. Today, this is it. It's highly seasonal.

We are flooding more the curve, but still highly seasonal. About following the REE approval, when do you expect to begin drilling acreage in the north of Rincón de Aranda, and what are your initial expectations for the productivity there?

It's a good point. I would like to clarify something because we read a report stating that we were closing wells and holding back the completion of wells for the REE approval, and I want to clarify this is not the case, okay? Only new drill wells will enter the REE. All these wells that Lida explained, the 10 wells that we were fracking and are completing now, they are not in the REE project. They are from before. Okay? We didn't do that because that does not apply to the REE. It has nothing to do with that.

Not to complicate

Yeah. It's a technical thing that not to parent-child effect. We close some wells to frack another, and they don't destroy each other. That was the reason. It has nothing to do as that report stated, that we hold back the completion of the wells.

Having said that, the North Park.

The North Park

Yeah. We have some seismic works before when we started with Rincón de Aranda, now in September, next month actually, we are going to start a more comprehensive seismic studies in that area, and do a more detailed work there according to Well, Horacio didn't join us today because he's in vacations, but the team already let us know that they're working in the North Park. The northeast boundary, the boundaries of Vaca Muerta. Productivity rates, we expect to be lower than the parts that we are developing right now. That is the south strip of the block, right? Once that seismic works are done, and all the studies detail and through, we think that we could start drilling there in next 2028. 2028, end of 2027. So far, we're concentrating the south strip where most of the well inventory is located.

On the Perito Moreno expansion, which specific units do you expect to benefit from FRA1? We already talked about it, Genelba. If we get awarded in the second trench, we can use it for the peakers in Buenos Aires bound trench, which is Pilar. Ingeniero White is for the Bahía Blanca. Piedra Buena. The peakers will be used, but only seasonally wise, not year flat. The one that is consistent the whole year is the legacy Genelba. How much of their dispatch could cover? The already awarded, the whole legacy CCGT on Genelba, and a little bit more. The rest, we can use it for specific days for trading at City Gate, for trading of gas at Buenos Aires or a little bit to be used in the peakers. We'll see. Specifically in the winter season.

Beyond the transportation prepayment, will any additional CapEx be required for the plants? No. It's just what it is. With Plan Gas.Ar expire at the end of 2028, do you see integration strategy shifting toward transferring gas at lower prices to your plants and declare more competitive CVPs and maximum dispatch? Actually, this quarter is the proof of that transferring the Plan Gas.Ar volume to ourselves is better, right? Because if we didn't transfer the Plan Gas.Ar, we will be billing at $ four and a half. Now, we are billing at higher price because CAMMESA allows a higher pass-through. I will say average-wise, it must be better than the Plan Gas.Ar's average price. We'll see. I think the CCGTs have the most competitive advantage against all other units, right? All other in the peers and in our own portfolio.

They will pass through whatever CAMMESA is allowing, so that's how they are going to maximize the dispatch. I think what your question is referring to is to the peakers, and that depends. Bueno. Zafra asks about the potential unlock in Rincón de Aranda with the North Park. We already answered. Expectation for another project this year and next year. We already answered it. CESA, FLNG.

Yeah

Urea, right?

In general, you have to expect any project in our core businesses, which are power, gas, oil, and now fertilizers. We will participate, and we will look at them, and look forward to increase if there is the right opportunity.

Austin Pacheco from Maria also asks about the financing of urea. Already answered. Alvaro Leyva from BTG is asking the same. Already answered. CapEx deployment of our urea project, we already answered. Given the still favorable oil market outlook, at the fact that it generated $64 revenue losses in Q2, would you consider unwinding the hedging position?

No, we won't. I think we answered this in the previous call, that the idea is to keep this level of hedge, and naturally, as production increases, we'll have a big portion unhedged. We keep current production hedged, and whatever comes on top of that will remain unhedged. That was the original strategy, was to hedge the ramp-up until the 45,000 barrels, and this is what we are doing. Once we reach that plateau, we still have to define, but in general, what we will foresee is that the percentage of hedging will be reduced.

Cataruzzi from AdCap, he asked about petrochemicals. We already answered. He also asked about the target gas production long-term. We already answered. Milene Carvalho from JP Morgan. Well, all question and answer. Hey. From urea, she asked about the EBITDA contribution from urea. Answer.

Yeah.

The gas price for urea. Answer, $3 per MMBtu. The same as FLNG project, right? How much gas is required? Answer. Incremental CapEx for EMP for this 3.5, assuming that it's additional. I did the math, and it's not much. It's like-

Should be 100 and-

It's $100 million of CapEx, EBITDA.

$90 million of EBITDA.

Less than $50 of additional CapEx. For the 20 million production, we are calculating a maintenance CapEx of $250 million-$300 million. That's the range. Well, balance. Andre Sirignagliano asking about the CapEx facing of urea. Answer. I'm saying this because we want to be clear.

Cover all the questions.

Transparent. Yeah, transparent. Puente, Juan Ignacio Lopez. Okay.

Si.

[Foreign language]. Juan Ignacio Lopez from Puente. He's asking, we are seeing a very impressive environment for natural gas sales in the domestic market beyond the usual seasonality. I would like to ask what you attribute this improvement to, effects of the Resolution 400/2025, the deregulation, or increased pressure in the domestic market for high international prices? How do you expect this dynamic to evolve over the coming quarters? Yes, it's true. CAMMESA during the winter pass through, they are linking it or associated with the international prices of LNG. That's why we can pass through higher prices. Also, the Resolution 400/2025 contemplates this deregulation in the procurement of the gas. Remember that before it was all centralized at CAMMESA, and now it's more and more decentralized. Just to give you an idea, CAMMESA used to be procuring the whole gas and the whole grid.

Now it's doing it one-third actively. Roughly numbers. Another one-third, they say, "Okay, I'm using my plant gas and giving it to you, and you pay me back the price," which is called the assisted by CAMMESA. Then the one-third, which mostly is ours, it's self-procure gas from power plants, which is our case. The idea of CAMMESA, it's going more and more to an assisted scheme, but when plant gas is rolled out, the idea is not to reengage it. It's just all procured by the power generators. Sofia Gran. I don't know who is she, but basically, she's asking, the CAMMESA percentage, 26%.

Yes.

Gas sales. Gas sales? [Foreign language]. Have any of these contracts or volume been transferred to the power company or self-management to supply? I understood that. Well, this is what we can transfer. We couldn't transfer more of this because the one contract outstanding to transfer is Enarsa. The last round of Plan Gas.Ar, okay, the 4.2 round, minus that. The last round of Plan Gas.Ar, which is around 5 million cubic meters per day, with peaks during the winter, that one hasn't been transferred yet. As you can see, that's why we still are selling to Plan Gas.Ar, specifically to CAMMESA retailers, 56%. For example, in Q4, it should go down dramatically because CAMMESA Plan Gas.Ar retailers won't demand much gas due to seasonal reasons. Matthew Boots from Fidelity. He asked about the equity and debt structure for urea plant.

Yeah.

We already answered.

We're not trying to maximize the leverage on the project because the idea is to deploy our cash and future cash flows into this. That's why we're not having any partners, and that's why we're not maximizing leverage. We expect a structure of around 60/40. 60 debt and 40 equity. Still everything is under negotiations, but we are expecting around $1.4 billion of equity in the next 41 months.

Santander, Walter Chiavesio, he's asking repeated questions as well, but he's asking about the gas production until 2030 breakdown. We already-

Discussed that.

discussed that. Andres Cardona from Citi. Actually, he's asking, when looking at the diversified portfolio, is there any asset you consider non-core and could be eventually divested? This question-

I think was answered when I explained our core businesses.

That's self-explanatory, which is petrochemicals. Ramiro Guerrero, Bull Market. How much volume of Rincón de Aranda remains hedged through May 2027? At what weighted average price, and what additional cash collateral settlement and cash outflow should we expect under different Brent scenarios? How much is hedged from our production? That's the first question. Until when?

We hedge all our production until first quarter of next year. Yeah.

Until May. Until June.

First quarter. No, my bad.

Okay.

Third quarter.

First quarter.

Little bit less than one year of hedge.

Yeah. Weighted average price?

67.

66.

67.

67 of Brent.

Yeah. Right.

What additional cash collateral should we expect if, I don't know, different Brent scenarios, right? Today is $80. Well, with the price, you can see how much it is.

Depends on the mark-to-market decisions.

Ricardo Cabana from Itaú. Impressive investment pipeline, thank you, that expands your business franchise phenomenally. Another thank you. How do you define in one sentence what is Pampa now and its vision? Thank you.

One sentence.

In one sentence.

Tough.

Yeah, because it's 12:00 P.M.

In one sentence.

Growth.

Yeah.

Growth.

We are an Argentine company that invest heavily in Argentina and tries to monetize the reserves in Vaca Muerta through all our industrial segments. That is power, urea, LNG, et cetera.

Headliner

Pampa Energía is an Argentine company that invests heavily in Argentina and is an industrial energy company, integrated energy company. That is the

The tweet. The headline. Augusto Soto Baumann from Rosenthal Inversiones, he's asking on the receivables. You mentioned working capital seasonality, but receivables still increase significantly in this quarter. Where are the key drivers on operating cash flow? Very good question. Why increase? Because we are selling more gas. Compared to last year, Q2, we are selling 2 million more of gas.

The prices are higher.

At higher prices, here you have it. We are selling more oil, three times more oil than last year, 22% more than last quarter.

Part of the gas we revert on the following quarters.

Yeah. Correct. We sell it now; we collect it 45 days later. This is very important. Previous quarter and previous year, the days of sales outstanding was way higher than now. Now we are at 5 days of delay, so it means 47 days of total collection days, while last quarter was 50-something, and previous year was way higher because it was accommodating. DSO, it's improving, specifically from our largest clients, which is CAMMESA and Enarsa, at the same time, we are selling more. 12 days delay. So 12 on top of the 42, so it's 54. Math. Could you please understand Well, was it mainly export timing? No. Export is flat. It's 65 days. There is no increase or decrease. It's very certain.

about the receivables. CAMMESA or subsidy-related balances. How about the CAMMESA? CAMMESA is paying better.

CAMMESA is paying, yeah.

Better.

No major delays in CAMMESA.

Yeah. The subsidy, it's very important to say that it's getting smaller in money terms because something very important is that retail prices are increasing. If the retail prices are increasing, the subsidy part is smaller. Now it's just $15 million per year or something. Should we expect this to normalize in the second half, or is it new structural level as exports continue to grow? Exports, forget it.

They-

The receivables of exports. It's the same. We are exporting the same. Wait. Q3, we are going to collect what we sell in Q2, obviously.

winter prices.

Q3 is higher winter prices and higher sales. You should expect higher receivables. In Q4, usually, we collect the receivables. It's a surplus. It's an inflow, no outflow. That's how you should think about it. Liliana Yan from HSBC, a quick update on TGS. [Foreign language].

TGS, well, they have their call already.

Yeah, they have.

I think that the two main takeouts are the two big projects TGS is performing. One is the Iniciativa Privada, that should be commissioned by next winter. The other is the big

NGL

NGL, sorry, NGL project, as you know, that they are already announced the FID, and they're working heavily in the financing. They're awaiting the RIGI approval of that project. I think those are the two main

Drivers

main news about TGS. If you look at the results, they were outstanding. They improve every line of business.

Utilities, the prices, the tariff.

Looking forward, it's a very encouraging company. Doing well.

Bueno. The last question so far, and that's it's Pedro Letelier. I don't know where he is, but I know him. The province of Buenos Aires has its own investment regime, the RPIE.

Is there any conflict with the government's RIGI that could impact-

No

the Uría project?

Not at all. We filed for both. We filed for the RIGI, that we have been approved by the RIGI committee. We're waiting for the publication of the approval in the official gazette. We also applied to the provincial regime, and we are awaiting approval. There is no conflict at all. On the contrary, they're quite What is it?

Proactive.

Yeah.

Complementary.

Complimentary. Thank you. They're quite complimentary. The additional benefit from the provincial is a tax break.

Gross sales tax

Gross sales tax. Yeah. That's the main takeout. Hopefully we'll get that approval as well.

Yeah, we talk about this. RIGI's pre-approved.

Yeah. There is no conflict between the two.

On the contrary.

That's it.

Great.

All right. Thank you everybody for joining us this call. Thank you, Fito, for taking all the questions. Fito, would you like something more? Say something more?

One hour. Perfect.

Perfect.

Thank you very much.

Thank you very much. Any questions you may have, just let us know, email us. We are more than available to help you. The next call is due November. Hope to see you then. Bye. Thank you.

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-

Taking account the number.

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

Fair enough. [Warrior] 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, but we can share with you what our forecast of the budget with this, right? 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 million from E&P and $400 million and something from power generation. Beware that this is not including the JV with Paraná. A little bit over $1 billion, of course. Corporate and petrochemicals are negative. That's why it's rounding, it's $1 billion. In the consolidated level, it's including the TGS and Transener's share, equity share. It's around $1.3 billion. In the free cash flow, this is including the prepayments of TGS, CIESA, San Matias and Vientos.

It's around outflow of around $400 million, free cash flow outflow. Have you considered to grow inorganically in the oil window Vaca Muerta? This question he always asks. This is record. He asks. Good. How is an inorganic Vaca Muerta oil project ranking in terms of risk-adjusted IRRs Urea project or the San Matias pipeline? That's a good question, though.

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

Yeah.

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

Cool. Another question from, I don't know how it pronounces, sorry, but it's Gil Golet from Scotland Macau Capital. The first question about the hedge is answered, the second question is very funny. It's worth asking. It's, 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? You sold the mature oil fields.

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

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

Well, we always have to have high liquidity to keep all our options open. Yeah, it could be the case that we decide to continue tapping the market in the medium term.

Now with all this, let Okay. Ignacio Lopez from Puente. He's asking: I would like to ask the outlook for gas settlement, particularly considering the increase in production and the lower exposure to Plan Gas. Could you share your expectation for local gas prices this year, especially for bonds traded outside Plan Gas? I guess he's asking about all 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 gonna be higher than last year.

Indeed. Now with the war more. Yeah.

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

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

No.

Correct. Jorge Mauro, given that this is the last one, I swear. That's true. Okay, 10 minutes more. Sorry. Sorry for that. 12 minutes. It won't happen again.

That's-

Thank you so very much. I don't know if you would like to add some comments?

I think we covered all.

Covered all. Next earnings is on August. Okay. Thank you very much.

Thank you very much. Thank you for your attention.

Thank you.

Thank you.

Bye.

Have a good day.