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 3, 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. 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.

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 and 8 million tons of urea per year, together with the rest of the Southern Cone, which has an annual deficit of about 2 million tons, will be the project's primary market.

Moving on to the project details, 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 megawatts of power, all again supplied by Pampa.

The plant 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 Fertipampa'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 set of projects presented under the RIGI framework.

You see, 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 in a integrated NGL project.

Also TGS's private initiative, which consists in expanding the Perito Moreno pipeline, the San Matías dedicated pipeline for the LNG project, and 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.

Now moving on to the second quarter results, let me tell you, the adjusted EBITDA amounted to $415 million, highlighted by a quarterly all-time high production of 107.5 thousand barrels of oil equivalent per day due to the sustained ramp-up at Rincón de Aranda and gas self-supply. The new regulatory framework also had positive impact on our power generation segment, which benefited from the strong spot margins as high fuel costs impact and drove the marginal cost up of the system.

That helped. Also we have more B2B PPA sales.

To the lesser extent, increased international prices also boosted the petchem business, which recorded its highest quarterly EBITDA since 2023, 3 years ago. Quarter-on-quarter EBITDA grew 28%, supported by gas seasonality, stronger spot power margins, and increased petchem prices.

The 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 45,000 barrels per day production plateau once the CPF and Vaca Muerta Sur oil pipeline are both online next year.

Moving on to the slide 7, 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 self-supply to our power plants resulting in higher output, billing at stronger prices as fuel cost pass-through increased. 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.

However, 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 cost 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 would have been $91 per barrel, resulting in approximately $64 million more of sales.

Exports accounted for 57% of total volume sold in Q2 '26. This is very similar year-on-year and quarter-on-quarter.

Rincón de Aranda contributed 1/3 of oil and gas EBITDA, up from 6% last year. Last year was only 6%, and this year is 1/3, this year's quarter.

This is continuing to diversify the production mix, now oil accounting 22% of 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 tied in 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 on certain wells while we completed other neighboring pads so we avoid the frac hit.

These 10 wells in set 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 drilled 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 drilled 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 Sur oil pipeline are online next year. Regarding RIGI, well, as we said previously, the application was formally approved on July 21 as long-term strategic export project.

The application includes the drilling and completion of 259 wells from July 21 on, and the construction of the CPF we already building, oil and gas pipelines, and water treatment 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 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 Sur pipeline, which is estimated to generate approximately $17 billion billion dollars 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 volume 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 Río Neuquén, 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 production plan, which considers the recently awarded transportation capacity at the 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, and which is priced at a higher price because of the higher pass-through allowed by CAMMESA.

This is seasonal and deregulation 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 de la Lata's gas turbine number 4, which is remunerated under a PPA, and the PEPE wind farms' underperformance. As the new guidelines reintroduced marginal cost as part of the spot pricing methodology, which marginal cost overshot during the quarter, especially during the winter season, reflecting higher fuel prices, in particular using LNG and diesel oil.

The spot margins widened specifically for the CCGTs, though that margin is capped at 50%. We only can capture 50% of that margin, that's what I mean.

The current framework allows full margin, you can capture the whole margin if you are 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 E&P, which will be producing more gas that now has security to be transported through this Perito Moreno expansion.

Full capture if the FRA equals to 1 instead of 50%. Pampa was awarded 3.2 million cubic meters per day in the Buenos Aires-bound tranche, it will be used to procure the gas needs of the legacy Genelba CCGT, right?

We also participated 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 tranche plus another 1.3 million cubic meters per day in the Bahía Blanca tranche. Total availability fell to 88% during the quarter, mainly due to the ongoing outage in Nihuil, which since July 31 is no longer part of Pampa.

We had some outages also in Güemes and in the mentioned Loma de la Lata TG number 4. Barragán also had 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. Now 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 perimeter.

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.

Finally, on the balance sheet, gross debt as of June was $2.6 billion. This is mainly because of the retap of 2037 notes priced at the lowest spread to the US T-bills, in Pampa's debt issuance history and 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'll read it first receives, first served. Make sure your name and your company is there, otherwise we can't just read it, and so 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. Bueno.

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 leverage to peak?'

Good morning. Thank you for the question.

Evidently we are facing challenging CapEx deployment, especially with urea project, but also bear in mind that EBITDAs looking forward should increase as well, right? 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 1 and 1/2 and two times for the next 2 to 3 years until we finish the investment in the urea project.

Great. But, ¿cómo se llama?, the CapEx this year is basically around $1 billion, right?

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

Slightly lower.

Is lower. Separating the 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,

right?

We have to add to that the equity contributions from Pampa to Fertipampa, yeah.

Cool. Guido Bizzozero and Santiago Herrera from Allaria, they're asking, 'After this 23 jump in EBITDA for the first half of '26, how do you expect to evolve the second half and '27 on power generation?

Considering in '27 that in the second half starts rolling out the PPAs?' Do you want to—

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

Power demand, actually. Power demand.

Bear that in mind. Always the last quarter is a little bit weaker, but it will be partially offset by the increase in the production of Rincón de Aranda.

The oil business will keep growing, but 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, well, that's what we expect, because winter it's—

Q4 always is—

Yeah. First half is 300 $299 million of EBITDA.

We expect 600 $600 for this year. Yes, a little bit, $600 million for this year.

Basically it jumps up in Q3 if winter allows, and then goes down. Specifically because the Niño, right?

There's more water, it means lesser thermal power demand, so. In '27, it's a combination.

Second half starts rolling out PPAs, but we also have the TGS's private initiative that, hey, we have 3.2 million confirmed that we will inject it through Genelba's legacy CCGT. That and actually it's going to start before the winter, the most of the impact will be monetized next year, though starts in May.

Next year's EBITDA it could go up. We are expecting 600 well, a delta of around $100 million things the winter and the fuel consumption, liquid fuel consumption, LNG consumption remains pretty much similar.

In 20 '28, as you correctly said, it goes down. It's a combination that in '27 the PPAs rollout doesn't much reflect because it's towards the end of the year.

In '28, 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 de la Lata, out of this two the PPAs that roll out, two of them are at Loma de la Lata.

Loma de la Lata is highly competitive because they doesn't require any gas transportation. They are very efficient machines, 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?'

Basically as I said in the call, the average of this year it's around 40%. It should pick up in Q3 and actually it's highly reliant on self-supply on Q4.

Even though gas demand goes down, we expect no troubles in the gas transportation system. Going forward, '26 is a gradual year.

It's a transition year. '27 and onwards, you should expect the following.

The thermal units consume around 10 million, only Pampa, not including Ensenada Barragán, 10 million cubic meters per day, of which 8 goes toward the CCGTs, 8 Loma de la Lata CCGT and the two CCGTs at 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 chemical business to evolve in the future, considering the 5% contribution to the consolidated EBITDA this quarter, when usually is negative or break-even?'

What it is, right?

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 had 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 CapEx at 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.

The CapEx is concentrated mainly on 2028. I would say 1/3 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. 'So 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. The revenues, I think we already disclosed that on—

Where? $1 billion,

yeah. $1 billion!

Yeah,

$1 billion. Sí.

The math is pretty simple. Depending on the price of urea you take, but you multiply 2.1 million tons of urea per year times the price of urea you 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 netbacks, whether you sell to Brazil or to Argentina or what combination, but those are the big numbers that you can easily compute.

What was the rest of the question?

No, how much impact on Pampa's E&P and power. It's a very good question.

Very good question. Remember that starting 2028, the GSAs start 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.

But— Assuming—

Assuming

if we increase gas production only for this project, it's around

$90 million

of EBITDA additional to the gas segment. Again, it's a decision that we will have to make in the next 3 years, okay?

The price is around $3—

The price is $3.

$3 is internal GSA.

Internal GSA, yeah.

And—

Consumption is 3.3 on average, a year average.

It picks up

in—

In winter, but

on average it's 3.3 million cubic meters of gas per day. Then

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

Not for this. We will see.

Again, the power contribution is

marginal.

The big contribution here is gas.

Marginal. Imagine, well, today we are selling B2B PPAs at 65 monomic price, right?

This is considering capacity, $65 to $70. 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, and now they're getting into because they seen highly seasonal.

It's better pay more flat than pay flat a certain price of around $65 to $70 per megawatt-hour, this is what we expect to sell in this—

It's around $68,

and

the consumption is 77 megawatts-hours, so. Mhm.

Again, it won't be additional energy capacity rather than replacement of—

I imagine myself using our renewable wind farm.

That's the plan,

yeah. Back up with our thermal units, yeah.

Exactly. Another question from Allaria 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 tying up wells, closing, tying up, closing, you will see this peaks and troughs 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 we try to reach the 45,000 barrels of oil per day.

The increase will be like a seesaw and 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 SESA, to urea project, the self-procurement for power generation?'

Sí,

es

que— No, so— That's flat, actually.

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, 10.5 million cubic meters of gas per day, another 3 and 1/2 to our urea plant, another 6 to SESA, to floating LNG project—

1.5 for export.

1.5 for exports. If you add up—

A little bit during the peak, it's around 20.

It's around 20 million, between 20 to 22

peak.

Peak.

Average is 20,

no? It's around 20 million cubic meters of gas per day quite constant because we are selling intercompany, we avoid the seasonality.

That is what we foresee in the next 3 to 4 years when all our projects are online.

As you can see here, no retail, assuming no retail—

Assuming no retail, assuming—

No CAMMESA, that are circumstantial during the winter.

10 to our plants, 3 to our urea plant, and 6 to our floating LNG plant.

Yeah. 10 is assuming all the plants.

CCGTs only is 8, which is the baseline, right? Bruno also asked very good question: 'Once we reached this peak, How long can we sustain it at the plateau?

What will be required CapEx to sustain at that level?' It's a very good question because we have a lot of gas.

Assuming 20 well, let's do very conservative, assuming 20 million cubic meters per day of annual production and with the current not saying resources, but 2P reserves, it's around securely 25 25 years of average life. This is only 2P, not even including the 3P—

Resources.

The resources and so on. How much required CapEx?

If we doing the math, and assuming the average well type of our shale gas blocks is around $250 to $300 million, and obviously considering also the CapEx to maintain the treatment plants, is around $250 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. The reasons— The rationale.

Yeah. It's what Lida presented.

On the one side is to monetize our gas reserves, which is a perfect fit. On the other hand, the urea business per se, which, as Lida explained, the region needs a lot of urea and is coming from far away regions, very unstable regions, it makes total sense to reduce logistics cost and procure ourselves our own urea for the region and don't depend from wars or geopolitical risks.

The third opportunity is the RIGI framework, which makes this project possible. The fourth, I would 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 this ones to show, and we are ready to deploy the cash. We are 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.

Actually It's not a bad timing to 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?'

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 where finally we land the cost, but we cannot foresee that.

For sure, most likely the debt profile will be 4 years grace period while we build the plant, and the maturity it is not closed, but it will be closer to 7, 8, 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?' Actually, the TPFs are rentals.

They cost around $5 million per month. Basically, we commissioned the second TPF, but the production didn't grow up because we choked some wells so we avoid frac hit in the fracking of other pads.

Now that everything is frac, everything it's done, we can connect all the pads and resume the choked ones and connect the new ones, right? Right now we expect an exit rate of lifting costs of around $10 per barrel with the two TPFs.

Once the CPF is online and also considering the fact that the production will ramp up, we expecting $5 by second quarter of next year, because we expect the CPF to be ready by first quarter of next year. Alejandro Cristensen from Latin Securities, he's asking, 'How should we think about the shale gas lifting costs over the next year and with SESA coming online next year?'

This is a very good 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 80 cents.

We are on an average year of 80 to 90 cents per million BTU. If we are only producing flat volumes, it could go a little bit lower, but not more than 60 cents, 70 cents.

We'll see. Today this is it.

It's highly seasonal. We're flattening more the curve, but still highly seasonal, so.

Then about following the RIGI 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 RIGI approval, and I want to clarify this is not the case, okay?

Only new drilled wells will enter the RIGI. All these wells that Lida explained, the 10 wells that were fracking and are completing now, they're not in the RIGI project.

They're from before, okay? We didn't do that because that does not apply to the RIGI.

It has nothing to do with that. It's more of a technical—

Not to complicate—

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

Having said that, the north part—

The north part—

We have some seismic works before when we started with Rincón de Aranda, but now we're going in September—yeah, next month actually—we're going to start a more comprehensive seismic studies in that area and do a more detail work there. 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 part.

The north is 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 '28, 2028, end of '27.

Far we're concentrating in 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?

For 1,' we already talked about it, Genelba, 'but if we get awarded in the second tranche, we can use it for the peekers in Buenos Aires-bound tranche, which is Piedra Buena. The peekers will be used, but only seasonally-wise, not year flat.

The one that it's consistent the whole year is the legacy Genelba. 'How much of the 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 peekers, we'll see, specifically in the winter season.

'Beyond the transportation prepayment, will any additional CapEx be required at the plants?' No, it's just what it is.

'With Plan Gas 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 maximize dispatch?' Actually, the Plan Gas now this quarter is the proof of that transferring the Plan Gas volumes toward ourselves is better, right?

Because if we didn't transfer the Plan Gas, we would be billing at 4 and 1/2. Now we're billing at higher price because CAMMESA allows a higher pass-through.

I would say averagewise, it must be better than Plan Gas's average price. Then 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 peekers, and that depends.

Bueno. Safra asks about the potential unlock in Rincón de Aranda with the north part.

We already answer it. Expectation for another project this year and next year, we already answered it, SESA, floating

LNG,

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.

Agustín Pacheco from Arraval also asks about the financing of urea, already answer. Álvaro Leyva from BTG is asking the same, already answer.

CapEx deployment about urea project, we already answer. 'Given the still favorable oil market outlook and 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.

Naturally, as production increases, we'll have a big portion unhedged. We'll keep current production hedged, and whatever comes on top of that, we remain unhedged.

That was the original strategy, was to hedge the ramp-up until the 45,000 barrels, and this is what we're 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.

Cattaruzzi from AdCap, he asks about petrochemicals. We already answer.

He also asks about the target gas production long term. We already answer.

Milene Carvalho from JPMorgan, well, all question and answer. From urea, she asks about the EBITDA contribution from urea, answer.

The gas price for urea, answer, $3 per million BTU, the same as FLNG project, right? How much gas is required, answer.

Incremental CapEx for E&P for this 3 and 1/2 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 EBITDA—

$90 million of EBITDA. $90 million, and

less than 50 of additional CapEx. For the 20 million 20 million production, we are calculating a maintenance CapEx of $250 to $300 million.

That's the range. A ver.

Bueno, balance. Andrés Irigoyen asking about the CapEx phasing of urea, answer.

I'm saying this because we want to be clear, transparent, yeah, transparent, yeah? Puente, Juan Ignacio López, ¿okay?

Sí.

Juan Ignacio López from Puente, he's asking: 'We are seeing a better pricing 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, the deregulation, or increased pressure in the domestic market for higher international prices?

How do you expect this dynamic to evolve over the coming quarters?' Yes, it's true.

Now CAMMESA's during the winter pass-through, they are link it or associated with the international prices of LNG. That's why we can pass through higher prices.

Also the Resolution 400 contemplates this deregulation and the procurement of the gas. Remember that before it was all centralized at CAMMESA.

Now it's more and more decentralized. Just to give you an idea, CAMMESA used to be procuring the whole gas in the whole grid.

Now it's doing it 1/3 actively, roughly numbers. Another 1/3, they say, 'Okay, I'm using my Plan Gas and giving it to you, and you pay me back the price,' which is called the assisted by CAMMESA, gas acuerdo.

Then the 1/3, 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 a assisted scheme.

When Plan Gas it's rollouts, the idea is not to re-engage it, it's just all procure by the power generators. Sofia Gran, I don't know who is she, but basically she's asking, 'The CAMMESA percentage, 26,

¿qué?'

Gas sales. Sí.

'Have any of these contracts or volume have been transferred to the power company or self-management of supply? I understood that—' No sé, esta pregunta media rara.

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, ¿qué? The 4.2 round, the last round of Plan Gas, which 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, especially to CAMMESA and retailers, 56%. For example, in Q4, it should go down dramatically because CAMMESA and retailers won't demand much gas due to seasonal reasons.

Matthew Booth from Fidelity, he asks about the equity and debt structure for urea plant, we already answer.

Again, we are 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 are not having any partners, and that's why we are not maximizing the leverage.

We expect a structure of around 60/40, 60 debt and 40 equity, that will give you around It's still everything is under negotiations, but we are expecting around $1.4 billion of equity in the next 41 months.

Santander, Walter Chiarvesio, he's asking repeated questions as well, but he's asking about the gas production until 2030 breakdown, we already

discussed that.

Andrés Cardona from Citi, actually he's asking, 'When looking at a 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,

so. 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 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. I thought

until May, until June.

First quarter. No, no, but

first quarter, first quarter. A

little bit less than 1 year of hedge.

Yeah. Weighted average price?

It's

67.

56,

57.

57 of Brent.

Brent. 'What

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

Depends on the mark-to-market. Six months.

Ricardo Cavanagh from Itaú: 'Impressive pipeline 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.' In

one sentence?

In one sentence.

Tough.

Because it's 12:00 p.m., so.

In one sentence.

Growth.

We are a—

Growth.

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

I

would say that is the two main— Headliner. Headliners, 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 Bauman from Rosenthal Inversiones, he's asking on the receivables: 'You mentioned working capital seasonality, but receivables still increases significantly in this quarter and what are the key drag on operating cash flow?' Very good question.

Why increase? Because we're selling more gas.

Compared to last year Q2, we're selling 2 million more of gas—

At higher prices.

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

And—

Part of the gas will of this working capital will revert on the following quarter,

so. Correct.

We sell it now, we collect it 45 days later. This is very important.

Previous quarters and previous quarter and previous year, the days of sales outstanding was way higher than now. Now we are at 5 5 days of delay, 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 this our largest clients, which is CAMMESA and ENARSA, but at the same time, we're selling more. 12 days delay, 12 on top of the 42, it's 54.

Math. Math.

Then, 'Could you please understand—' Well, what was it, mainly export timing? No, export is flat.

It's 65 days. There's no increase or decrease.

It's very certain. Sí, porque está diciendo about the receivables.

And 'CAMMESA or subsidy-related balances, how about the CAMMESA?' CAMMESA it's paying better.

CAMMESA is paying, yeah, 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, something.

'And should we expect this to normalize in the second half, or is it new structural level as exports continue to grow?' Exports, forget it.

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, but—

Winter prices.

Q3 is higher winter prices and higher sales, you should expect a 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 Yang from HSBC: 'A quick update on TGS.

Gracias.'

TGS, well, they have their call already,

but— They have a— They have a—

I think the two main takeaways 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

project, as that they're already announced the FID, and they're working heavily in the financing, and 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 their results, they were outstanding.

They improve every line of business. Now

utilities with the tariff—

It's is a very encouraging company. Doing very well.

Bueno, the last question so far, and that's it, 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 REPI. Is there any conflict with the government's RIGI that could impact the urea project?'

No,

not at all. We filed for both.

We filed for the RIGI, and we have been approved by the comité, RIGI committee. We are waiting for the publication of the approval in the Official Gazette.

We also applied to the provincial regime, and we're awaiting approval. There is no conflict at all.

On the contrary, they're quite—

Proactive? Complementary.

Thank you. They are quite complementary.

The additional benefit from the provincial is a tax break on the—

Gross sales tax.

Gross sales tax, yeah, ingresos brutos. That's the main takeaway.

Hopefully we will get that approval as well.

We talk about this. RIGI is pre-approved.

Yeah. There's no conflict between the two, on the contrary.

That's it. 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?

1 hour, perfect.

Perfect. Thank you very much.

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 on November.

Hope to see you then. Bye.

Thank you. Bye.