Pampa Energía S.A. (PAM) Q3 2025 Earnings Report, Transcript and Summary

Good morning. Thank you for waiting. I'm Raquel Cardasz from IR, and we would like to welcome everyone to Pampa Energia's Third Quarter of 2025 Results Video Conference. First, we would like to inform you that this event is being recorded. [Operator Instructions] Before continuing, please read the disclaimer on the second page of our presentation. Let me mention that forward-looking statements are based on Pampa Energia'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 Energia and could cause results to differ materially from those expressed in such forward-looking statements. Now I will turn the video conference to Lida.

Thank you, Raquel. Hello, everyone, and thank you for joining our conference call. I will make a quick summary of Q3, so we can spend more time on Q&A with the management. Today, we have our CEO, Gustavo Mariani; our Head of Oil & Gas, Mr. Horacio Turi; and our CFO, Mr. Adolfo Zuberbuhler. The quarter's standout performance came from Rincón de Aranda, where the production ramp-up is translating into strong EBITDA, supported by 7 active pads today. Oil is emerging as a meaningful contributor, now accounting for 34% of our EBITDA in the E&P and therefore, 18% of total E&P in the quarter. In power generation, after 6 years and amid the ongoing deregulation, the winter, we self-procure gas for our Loma de la Lata power plant, boosting both power and E&P margins. Winter demand pushed us to a new all-time high in production, almost 18 million cubic meters per day of gas delivered smoothly without any disturbance and disruptions. And following the September market volatility, management demonstrated confidence in the company's fundamentals by repurchasing 1.5% of the company's share capital at $59 -- close to $59 per ADR. Today, the stock is trading nearly $90. So let's move into the quarter's financial results. The adjusted EBITDA amounted to $322 million. This is a 16% year-on-year increase. This is mainly driven by Rincón de Aranda, steady shale oil growth, higher B2B sales, and the contribution of PP6 wind farm. Quarter-on-quarter, EBITDA also improved due to Rincón de Aranda and gas seasonality. CapEx surged 183% year-on-year, reaching to $332 million, of which $174 million were invested in the development of Rincón de Aranda. Moving on to Slide 4. The Oil and Gas adjusted EBITDA was $171 million in Q3. This is a 40% year-on-year increase, largely due to Rincón de Aranda, again, increased exports and strong industrial demand, as well as sub procurement margin in Vaca Muerta, for Vaca Muerta power plant. These variations were partially offset by soft retail demand in September due to milder weather and the end of the peak winter peak contracts under the Plan Gas SA. Higher gas treatment costs and the lease of temporary facilities at Rincón de Aranda, offset by the higher production, highly increased the lifting cost to $6.4 per BOE. Quarter-on-quarter, lifting cost per BOE actually sharply decreased due to the higher output and stable total cost. Gas lifting costs remained flat year-on-year at $0.90 per million BTU, but dropped quarter-on-quarter 17%, while oil saw significant cuts, thanks to Rincón de Aranda. We will address that later. Total production averaged nearly 100,000 barrels equivalent of oil equivalent per day. This is a 14% increase year-on-year, led by Rincón de Aranda and Sierra Chata, but partially offset by decreases in El Mangrullo and nonoperated blocks. Quarter-on-quarter, production rose 18%, again, explained by Rincón de Aranda and gas seasonality. The production mix continues to evolve with oil rising to 17% of the total output, driven entirely by Rincón de Aranda ramp-up. Crude oil prices averaged $61 per barrel in Q3. This is a 15% decrease than last year due to the Brent underperformance. However, our hedge in Rincón de Aranda's production helped mitigate the price drop. Without the hedge, our realized price will have been $60 per barrel, excluding -- this number is excluding quality or logistics discounts and any duties, export duties. This is a sort of FOB price. Focusing now on the Slide 5 in Rincón de Aranda. As you can see on the chart above, the ramp-up remains on track. During Q3, average production reached 14,400 barrels per day. This is almost 3x Q2 levels, driven by the 3 new pads that we tied in during the quarter. Post quarter, a seventh new pad was connected, elevating output to 16,000 barrels of oil per day. Currently, we have 1 frac fleet in the block ready to tie in 3 DUCs. And we have 2 high-spec rigs drilling the next -- another 3 pads for the next year's campaign. We expect to exit 2025 producing 20,000 barrels of oil equivalent per day. To support further growth and leverage idle capacity, trumpa capacity in the pipeline, we plan to install an additional temporary facility next year, increasing production to an average of 28,000 barrels per day by the second half of 2026. Our target is 45,000 barrels per day by 2027 once Vaca Muerta oil Sur pipeline and our central processing facility as known as CPF are brought online. Another important highlight this quarter is the drop in lifting cost per barrel, as anticipated when we announced Grinoianas development. Our goal is to stabilize at $5 per barrel, in line with our peers, with the CPF playing a key role in achieving this milestone. Okay. In Slide 6, moving to gas. Sales held steady year-on-year at 14 million cubic meters per day. This is 8% higher than Q2, as explained early by seasonality. And Mangrullo continued to lead the output, though its share shrunk to 50%, while Sierra Chata grew to 38% of total output with a year-on-year production increase of 33%. In July, we hit a new all-time high in gas production of 17.6 million cubic meters per day, driven by Sierra Chata's peak of 6.3 million cubic meters per day. The most recent tiding pad of 3 wells delivered 2.7 million cubic meters per day. So imagine per well how much it is, highlighting its solid productivity. A new 4-well pad is now undergoing fracking. Shell accounted for 64% of the Q3's output. Gas prices averaged at $4.4 per million BTU. This is flat year-on-year. Fuel procurement for Loma de la Lata power plant during the winter and industry sales supported this price, offset by lower export prices affected by the brand underperformance. 72% of our gas was sold under Plant gas GSA, CAMESA retail. This is down from 86% last year. This is due to the cell procurement, which accounted 6% of the total gas output and gas sales, sorry, and improved deliveries of B2B sales and exports. Export remained steady at 1.2 million cubic meters per day amid the heavy winter that we experienced, up 146% year-on-year due to the low hydro in Chile. Switching to power generation on Slide 7. We posted an EBITDA of $120 million in Q3. This is 8% increase year-on-year, mainly explained by PEPE 6 wind farm fuels procurement margin in Loma de la Lata plus higher seasonal capacity payments for open cycles, partially offset by a 9% drop in generation due to the weaker demand. So availability declined to 94% due to scheduled maintenances in Gela and Loma de la Lata in September and the ongoing outages that is having NSA since January. New energy, particularly under take-or-pay PPAs continue to support 66% of the segment's EBITDA. We will discuss expectations of this new framework during the Q&A. Turning to cash flow on Slide 8, we show the restricted group figures because this is aligned with our bond perimeter amid high CapEx. And at Rincón de Aranda, we generated $6 million free cash flow in Q3, driven by the strong EBITDA generation and improved working capital. Q3 marked our peak in EBITDA and sales. And during the second half of the year, working capital typically moves as we collect winter sales. So results, cash and cash equivalents stood at $881 million at the quarter end, in line with Q2. Finally, in the balance sheet, gross debt was nearly $1.8 billion. This is 16% down since December 2024, following the redemption of the 2027 and 2029 notes that were funded with proceeds from the 2034 notes. Net debt rose to $874 million, 1.3x net leverage ratio, reflecting the CapEx outflows and collaterals on oil hedge. However, post quarter, we repaid $47 million in net for prefinancing loans and recover $84 million from OCP Ecuador guarantees funds that should have been released back in March. Therefore, we maintain a 1.1x net leverage and a strong cash position of approximately $920 million. However, our liability management efforts extended the average life to 5.6 years, strengthening our financial profile and reducing near-term maturities amidombiaandas development. So well, this concludes the presentation. Now I turn the floor is open for questions.

[Operator Instructions] Well, let's go first. The first one is Guidoosolaria from Italy. He's asking, considering that during Q3 2025, inventories of crude oil were sold by approximately 2,800 barrels per day and that since October, the 1,600 barrels per day contribution from El Toro will not be anymore. How do you expect total oil production to evolve in the upcoming quarters?

Our best expectation for the fourth quarter of 2025 is between 18,000 and 19,000 barrels per day.

So ramping up from Q3.

That's right. Because of the coming online of Pad #11.

Great. So basically, going forward, it's going to be Rincón de Aranda plus associated oil from gas fields.

But very little. Very little. I mean the main driver is Rincón de Aranda.

Good. Second question from Guo. We noticed a sequential improvement in lifting costs from $7.6 per barrel per BOE to $6.8 6.4. How do you expect to evolve during 2026 until the CPF is ready? This is per BOE, right?

Yes, I understand the question. The main change in 2026 is going to be the ramping up of Rincón de Aranda from the ending -- year-end of around 19,000 to 20,000 barrels up to 28,000 barrels on the second half. Therefore, we will see a reduction in our lifting cost for oil from $10 to around $9.1, $9.2 per barrel, and that will drive down our overall lifting cost to around $6.2 per barrel equivalent.

Do you see any potential to reduce lifting costs in gas?

I wouldn't say so. I would say that probably there's going to be -- is going to keep stable. We are pretty much keeping more or less the same expectation of production so far. If there's going to be an additional production to come online, probably those lifting costs will be reduced.

Great. How do you expect to evolve the gas market during the summer season considering the lack of local demand, export market to Chile, and more associated gas from oil fields?

Okay. There is always seasonality, obviously, in the Argentine market. Good news is that we do have a take-or-pay clause in our contracts of 75%. And more or less, that matches with the real demand during the summer. So we will be delivering what we already have contracted as a take-or-pay. Regarding the associated gas, I would say that, that will have much more influence in the spot market, in the gas spot market, and we are not in that market. So it's not going to be -- it's not going to have any influence on our overall price.

Yes. What do you think about Chile? Do you think it's going to maintain these levels?

Chile, we are -- well, we are consistently increasing our exports to Chile. If we compare with last year, we will -- we come from around 0.5 million cubic meters per day. to around 1.2 million, 1.3 million cubic meters per day this year. That has to do with 2 main drivers. One is the launching of the export to the Pacific region pipeline with around 400,000 to 500,000 million cubic meters per day, and also has to do with higher demand on the Gas Andes region from the Chilean side.

Now it matches to Santiago, right?

It's not only Santiago, but all the central region of Chile. Yes.

So you expect that it could continue around 1 million.

It's going to be around a little bit more than that, probably 1.2 million, 1.3 million cubic meters per day. Basically maintaining what we do have today and eventually increasing a little bit in the Pacific.

Fourth, could you give us any color on how you expect to improve during 2026 revenues and EBITDA in the Power Generation segment, considering the new framework established by the Resolution 400? This question is also addressed by Alejandro Demichelis from Jefferies, I want to say. Another people, sorry.

We basically expect that the EBITDA of the segment will improve by at least 15% next year due to these resolutions. But there's still -- this is based on several assumptions. Now the market has become much more complicated to predict, now that we are moving into kind of a marginal price system. It will also depend on how successful we are on the B2B market and how many -- how much of our energy we are able to sell it with higher margins than CAMESA to the B2B market, but that's going to be very competitive. So the other relevant thing that the secretary still needs to publish the details on how producers of gas can take out their contracts from CAMESA. So in order for us to self-fulfill our power generation unit, we need to cancel or extinguish our obligation with CAMESA. The Secretary of Energy is working on that resolution. The details of that resolution will impact on this matter. So still too early to be precise on what to expect, but I would say that you should be expecting at least 15% -- 10% to 15% improvement in the segment.

What levels of CapEx and leverage are you forecasting for 2026? Are you planning to finance it?

Well, level of CapEx for 2026 is going to be more or less similar to CapEx of this year of around $1 billion to $1.1 billion. In terms of how we are planning to finance it, Lida showed our... Slide. Lida showed our cash position. The cash that we are showing there does not take into account the cash that we have posted as collateral for the hedges -- for hedging the Brent. That's something that is for us is also cash that we can convert into cash in just 1 day, but it's not considered cash by the accounting rules. So we have a very large cash position. We have a very good debt profile that we always like to improve even better than what it is. Argentina, as you have seen, is a volatile country. So we always like to play on the safe side with a very comfortable financial position. I will add to that, that next year, we have a full year of oil production that this year we didn't have. We have a full year of an average of 240, 4,000 barrel per day that will add additional cash flow that we did this year, we had to face with our own cash position.

Well, moving on to Alejandro Demichelis from Jefferies. The first question is it was exactly the same as Guido about the deregulation. We talk about it. Second question is with the increased CapEx from the subsidiaries and the CapEx requirement, what do you see -- when do you see that the net debt peaking? When and where net debt peaking?

Well, as you can see in the last slide, our net debt has remained very, very low, around 1.1. As we've been speaking with investors, this question was repeated many times. We expected to have reached the highest peak by now at around 1.2, 1.3, we were saying that because this year was the -- as I said before, the year with a lot of CapEx and production of oil just started. Next year, the production of oil will be constant in the whole year. So we shouldn't increase net leverage match or above these current levels of around 1.1, 1.2, 1.3. Next year, we probably have more debt, but we will have more EBITDA. So the ratio will keep around this level. And this is a level that we feel very comfortable and very prudent.

Next question comes from George Gast from A Securities. I know that Pampa's free cash flow was positive this quarter despite the ongoing expansion at Ringonderana. How is the rest of the year looking on this front? Are you expecting any reductions in the D&C costs to help over the next few quarters?

Okay. We are working permanently in the reduction of the D&C costs. Actually, in 2025, we were successful in reducing our drilling time in around 15% and our completion time in around 13%. That resulted in an overall reduction in our well costs of around 6% to 7%, going from $16 million to a little bit above $15 million. And in 2026, we expect to keep on going this way and eventually rate -- sorry, achieve reductions in the range of 5% in the overall cost of the wells. I would add that the reason why the free cash flow was positive this quarter is because this is the best quarter of the year for Pampa. But this year, overall, as you know, we have -- we are investing a lot in Rincón de Aranda. So our CapEx this year are above our EBITDA generation. So definitely a year of negative free cash flow, and that's why our net debt went up. And next year, that because of the reasons that Pito explained, it's going to be reduced significantly because next year, our EBITDA is going up, our CapEx remained flat. So there will -- it's going to be a more balanced year than 2025.

Awesome. Well, the next question is coming from Francisco Cascaron from Capital. What was the amount of -- what about the amount of noncash deferred income tax that was, I guess, recorded in this quarter? And do we expect any impact of this account of this size in Q4 2025 answer or I mean...

This happens on time to time when there is a big gap between the devaluation rate and the inflation in pesos. So whenever this happens, we may have this cash deferred income tax in one quarter. That's what happened in the last -- in this quarter. It's very hard for us to project if it's going to happen in the following quarters because it will depend on these variables that are out of our control. Whenever the inflation and the devaluation move together, this won't happen. But if they wide -- the difference between them is increased or widened, then we will have again. So we cannot predict only no one knows, but if the macro balances remain normal, this should happen again.

Great. A Luis from Morgan Stanley. What should we expect in terms of Rincón de Aranda drilling pace for Q4 2025? And how was the production during the month of October?

Production during the month of October was around -- more than 16,000 barrels. And we will be in the next quarter, we will be drilling 4 pads. We are drilling pad #7 and #12, and we will be drilling in short time, #13 and what we call #10.

But basically yes, drilling more, but completing -- still completing this year 7 pads.

Yes. The only part that is going to be completed in short time is one more to be completed -- Well, again, the production for October was around more than 16,000 barrels -- we will be drilling in the last quarter 4 pads. We are currently drilling pad #7 and # 12. We will be drilling pads # 13, and we are almost starting to drill pad #10 Bs, or an additional 3 more wells to the organic inferior in Pad 10. That's regarding the drilling. What Gustavo mentioned around -- about our activity and how many rigs we have. Currently, we have 3 high-spec rigs, and -- but it's going to be for a short time until we finish with the 3 wells of the organic Gunferior pad #10, then we will remain with 2 high-spec drill rigs and 1 e-fleet.

Great. Second question is in terms of investments, should we expect a maintenance in 2025 expectations for CapEx? How should it evolve going into 2026? So we talk about $1 billion. pretty similar, right? Yes.

This year is basically what we projected on the budget or slightly lower than what we projected on the budget because of very small delays in the deployment on some payments that are not going to be done this year, but are going to be done early next year. So it's going to be around $1.1 billion. And next year, we expect roughly to maintain that level of CapEx. That is basically until we finish the ramp-up of Rincón de Aranda because -- as we said, Rincón de Aranda takes 70%, 75% of that number.

Yes. Okay. So Juan Ignacio from Puente. Given the recent launch of the Secretary of Energy new regulatory framework for the power market and the explicit focus on free contracting through bilaterals or B2B PPAs and cost reflected marginal pricing, what is Pampa's commercial strategy to navigate this transition? And how do you plan to maximize the opportunities presented by this new scheme, particularly regarding securing long-term private contracts?

Okay. Fortunately, we have a very well-seasoned commercial team because we have always been active on whatever B2B market was available for us, and we always been a very active player on the B2B market. Now that this market increases, we have a very good muscle. And obviously, we are going to try to gain a good market share in this B2B market for 2 reasons, basically because we expect to improve our margin vis-a-vis selling our energy to CAMESA; and second, to diversify our sources of clients, so being less dependent on CAMESA and a diversified portfolio of industrial clients and distribution companies, power distribution companies.

Right. Carolina Carneiro from Safran. She's asking, well, it's a bit of a broad question, but it's good to ask this. Can you comment on the new rules published for the wholesale electricity market, if there's any next step that you talk a little bit about that and impacts for the companies? Well, first thing first, you have to read the summary I previously laid out -- we preciously laid out in the earnings release. But basically, in a nutshell, it's a marginal system, right? C, we cap for this period of time, right? There's going to be a B2B market. So the good news is that Pampa is around in the power sector in power generation, right? It's 20% of our EBITDA is B2B, and 80% is CAMESA. Now that's going to shift. It will be more than 20 -- I don't know how much will be, but surely, it will be more than 20% B2B. This is a good diversification. And well, that's basically more. And then, of course, for the first time, we will be able to -- well, actually, we started this winter, but we can continuously self-procure fuel to our own power units, and it's a great chance for our CCGTs.

Yes. But again, there's still rules to be published by the Secretary of Energy. We are not able to withdraw the contracts from CAMESA yet and sell and provide the fuel to our plants yet. We hope that at any moment, the sooner the better that would be published, and it will allow us to self fulfill our power generation plants.

At the same, we need to see the open season for the transport -- the plant.

Exactly. This is not only gas, but also transportation capacity that the Secretary of Energy has to decide out of the 21 million cubic meters of gas transportation contract that CAMESA had, how much will remain in CAMESA, how much will be transferred to gas distribution companies. So there are a few things that need to be clarified before having a better visibility of what's going to happen in 2026.

The good news is already out there. It's already kind of implemented. It's just we need to... The details. Yes, small details. That's right. Updates on Gonderana, we already talk about it. So let's move on to Matiasataruzi from ACA. Upstream Pampa hit 17,300 barrels per day in Q3 ' 25 in Ringonderanda with numbers above the guidance. What is the fourth quarter 2025 exit rate targets? We already talked about that, 20,000 barrels per day and 2026 quarterly ramp-up because we put... Quarterly... Above 60. All the path to the 45,000 plateau by 2027. So he wants all details.

All of the details. Okay. So we will be exiting 2025 around 20,000 barrels, as we mentioned. By February next year, end February, beginning of March, we should have the additional temporary production facility. So we'll be able to have their ramp-up around 000 barrels of additional oil. It's going to 24,000 barrels by the second quarter of 2026. And by the third quarter of 2026, we should be reaching a peak of around 28,000 barrels per day. And then by January, February of '27, once the central processing facility is in place, our plan is a very quick ramp-up from those 28,000 barrels to 45,000 barrels, which is the overall target.

Great. He's asking for D&C, which we already talked about. We talked about that. Lifting cost, we already talked about that. This -- as soon as this call is done in 10 minutes, it's uploaded to the cloud, so you can access to the replay easily. So keep assume 10 minutes. And then he's asking -- this is a more detailed question, but the lifting cost breakdown between shale gas and Shell oil. I would say Shell gas is what we have -- we are seeing today is $0.80. Sierra Chata --

Between Mangrullo and Sierra Chata, it's around $0.80.

Yes. Serra Chata cheaper.

Cheaper than Mangrullo.

Mangrullo, amazingly, it was the opposite. Given the productivity, right? And then Shell oil.

We've already talked about that. It's around $10. It's going to be going down to $9 by -- with the installation of the second temporary production facility.

Well, -- and then in power, he's asking something like kind of similar, but with the normalization, what -- how quickly can Pampa migrate legacy thermals, basically, how quickly we can get B2B PPAs. We already talked about that, about the muscle of commercial.

It's a question that I don't have an answer. We will have to.

We have a handicap, but it doesn't mean... Exactly. It doesn't mean that we are guaranteed. And then -- this is a very odd question. This is what is your 2026, 2027 spot price range under the new dispot rules? How sensitive is our EBITDA to an increase of $5 per megawatt hour? I think he's asking for the marginal cost because now that is the higher the marginal cost, the higher EBITDA, right? What marginal costs are you seeing? Question?

It's difficult. Unfortunately, I don't have all the numbers on top of my head. It's very very different summer than summer prices could be in the $30, $40 summer and winter in the lower demand on the summer. Off a peak. And in the winter, probably in the 80s or 90s or 100. Next year, there shouldn't be any significant change from current year. Hopefully, in 2027, the system will see a decrease in the marginal spot prices because there's going to be new gas available in the market as I think I don't recall when we mentioned, but our subsidiary, TGS has been awarded to increase the transportation capacity of the Gasutoeritooreno by 14 million cubic meters of natural gas per day. So that will have an impact during winter times because we will be -- as a country, we will be able to replace imports of LNG and even more important, import and consumption of diesel oil in thermal plants with local natural gas. So that will have an impact reducing spot prices. On 2026, there shouldn't be any significant change.

Yes. Well, there's a lot of variables like weather and hydrology. Exactly. Renewable penetration, right. Anyways. Ricardo Vo from Safra, is there any other projects or infra auctions, gas pipeline batteries, renewables, PPAs that the company may be interested in?

Well, this is the auction of the Comau power plants that we are studying all the opportunities. That is something that is -- there's no new delays, it's going to take place this coming Friday. I don't have any other infrastructure auction on top of my head. Do you?

The second tranche of the [indiscernible].

I don't see it.

You don't see it.This point. With the private initiative, you think like it's kind of... To --... But the good news is that, that private initiative gives gas to the eastern side of Argentina where a lot of the most efficient power plants are located. Good. Then Daniel Guardiola, BTG, he's asking -- well, the first question is about the new regulation answer, broadly answered, I think. Well, at least what he's asking. Second question is about the hydro action, but zooming in on the potential CapEx that you might engage or might commit if you get awarded? And what -- do you envision the remuneration? How do you envision the remuneration of these plants? I guess if it's going to happen or not because it's the...

It's a fixed dollar remuneration -- for a 30-year contract. And the upside is on an increased portion of your energy production that can be sold to the B2B market. So initially, the first 2 years is only 5% of your energy can be sold to the B2B market, then it goes for another 2 years at 10%, 15% until in year '20, it reaches that 100% of your energy can be sold to the B2B market. Meanwhile, you are selling your energy to CAMESA at this fixed dollar price adjusted by inflation. By U.S. inflation. And do you -- it does involve any CapEx if awarded? But there are maintenance CapEx. But in most of the plants, those CapEx because these are fairly new and very well-maintained plants, those CapEx come at 2/3 of the -- in the last 10 years of the concession. So from year '20 to year 30, most of those CapEx have to be done.

Great. Then he's asking about, well, about lifting cost, D&C, we already covered. That. Yes. But he's asking a more interesting question is, do you foresee any additional M&A opportunities in Vaca Muerta? If so, what will be the priority, oil or gas?

There has been many opportunities, and I'm sure there's going to be many opportunities in the future as well. Our focus, if any, would be increasing our reserves of Shell oil. We have reserves of shale gas in excess of our expected production over the next -- so we don't need any additional gas reserves. And we -- if there's a good opportunity. But as you know, we are price sensitive. We -- so we are -- we will be waiting for what we consider a good opportunity to increase our portfolio of reserves of oil.

But there's no -- well, I know it's, there's no processes ongoing.

No, no, nothing. We are interested in.

Right. Another question from Daniel. He's asking, can you share with us the expected IRRs of the LNG project that you are currently developing, I guess, Sarn Energy? And if it's possible, what will be the incremental EBITDA for Pampa Link to this project?

Okay. Let's go to the incremental EBITDA. The best part. So there are 2, say, segments of this business, the CSA side regarding the liquefaction of the LNG and the sale of the LNG itself. And then there is the upstream segment, which is basically supplying those 6 million cubic meters per day that the vessels will be needing from Pampa from our participation of 20%. The EBITDA related to the upstream segment of the business is around $140 million per year once we reach the 6 million cubic meters per day. IRR of the overall project is going to depend on the FOB price of the LNG that we sell. And I think we mentioned this in the previous call. Above -- if we are able to sell above $7.5, it's going to be a very good project. If we are selling below, it's going to be lower IRR return that we expect. We know we are going to have good years, regular years, and bad years, but we are very optimistic in the overall project. On the average is going to fine.

All right. Hari from NCA, has Pampa hedged any portion of its 2026 production? If so, what percentage was covered and at what average price those hedges were executed?

Okay. We hedged almost 100% of our production. 2026, I mean I have... Very good portion of it, right? A portion of it... Sorry, I'm here. So I would say it's around 80% of next year and the average price is including this year. So what is left of this year and the rest of next year is around $68 -- over $68 per barrel.

This is Brent, right? Then translating to Palm Bio, we have a lot of stuff that we have to pay export duties. There are some discounts, very minor though for logistics and quality, and then other stuff if we sell locally, transportation fees, and so on. Right. Jonathan Schwark from Deadwire. Are you planning to cancel the 0.8 million ABRs that you bought back? Is 0.8 million all you have on your own shares or you have more?

I don't recall if we have -- do we have shares from previous buyback?

No, you cancel it.

We cancel -- so no. There's no as of today, most probably that we are going to cancel these shares as well. We have to do by law. Well, eventually, we could do a convertible uses for something, but that's -- we are not starting that opportunity. So most probably that they are going to be canceled in the next shareholders' assembly.

What is the status of your plan to build a fertilizer urea plant?

We are awaiting from there's been some delays on the -- our original schedule. So now we are expecting by the end of the year to have -- we have already received -- yes, the technical part of the -- and we are studying from the suppliers, the technical part of the project, but we still haven't received the prices. We should receive that by year-end. And so we are expecting that number.

Great. Okay. Felipe from Market. What is the current state of the payment days in gas from ENRSA? What is Pampa's exposure to this?

Vito, do you have Exposure? ERSA has been improving significantly over the past few months. So at one point, we had like almost 2 months of delay. And now it has less than a month, right? Yes. Yes, it's like 20 days. That's right. And then the debt it shrink a lot. Right now, the debt is like less than 60 million -- around $60 million. So it's like in pesos, it's like ARS 90 billion. And exposure is -- we just sell. Those MXN 19 billion that you mentioned. No, but where we sell ENRSA, why is a client not ours? We sell under applying gas, but a fraction of applying glass to them. the last round that we won, it's -- our offtake is ESA.

Next question, I better keep it up. from Pro regarding the 3 DUC pads plus the 3 that you are currently drilling. Is it part of your policy to maintain the inventory of that type of wells? Or is it due to the limitation related to the facilities' capacity? I guess why do we have DUCs this question?

Well, we have DUCs because we need to -- as he's mentioning, we need to anticipate the ramp-up once the facility is in place. So if we are going to be installing a facility in March 2026, increasing around 7,000 to 8,000 barrels per day, we need to anticipate those DUCs, so we can complete those quickly and hit the ramp-up rate.

Well, some questions have been answered. Laura from Nice to meet you. Any further bond placement on the cross-border markets?

Well, as you know -- I'm sorry, I'm going to extend a little bit in the question. But as you know, in 2024, we started a process of refinancing all our debt. We issued 2 bonds. We called another 2, as Lisa explained, that show that we were -- and we are very active in the international bond market. And as we've been explaining, we've been funding our CapEx with our own cash position and our free cash flow. So all these issuance were opportunistic rather than a need to finance any CapEx or any M&A. They were all -- we tap the market in very opportunistic manners, and that will be the case going forward. So we don't need to issue bonds. We don't need to finance any specific out-of-the-ordinary course of business. But if we see an opportunity, we will take it. We will take it. If we can improve our debt profile, if we can issue a very long-term bond, or if we can issue at a very low rate, that is something that we might do always in the spirit of calling or paying short-term debt and issuing longer-term debt. Yes, that is something that we might do. And we are always very active, and we execute our transactions very fast. So this can happen overnight. I think that answers the question.

Awesome. Ignacioski from Iberia. He's asking regarding the remaining stake of Pampa has in GeoPark. As far as I know, it is now nearly 4%. Are you planning to sell?

Currently, we don't have any position in GeoPark. We sold them all, making us more profit. It's basically -- I think we finished selling the stake in September after the significant sell-down in the Argentine market, we decided to switch... So the main goal is was we saw our stock very cheap, and we launched a share buyback program, as you all know. So we disinvested in GeoPark, and at $58 million, we decided to buy back our shares with that capital. It was a better investment. Yes, even significantly more than what we spent in the... We spent $48 million, and GeoPark trade was $33 million, $34 million. The profit from that trade was the 2 dividends we collected during the holding period and... Something else... Price was more or less neutral. But in general, that was our strategy.

Regarding OCP, the warranty was $100 million. Are there any changes to collect the remaining? Yes, the guarantee was $100 million, but we had cash collateral of $84 million. The rest was based on the balance sheet of Pampa. So the guarantee is completely collected. So there's nothing remaining there. Awesome. And that's it. 12:59. We ended all the questions. Some of them, they've already been answered, so you can access the replay and check it out. So thank you for being here. Gustavo, Oracio, Ito, do you have anything...

Thank you, everybody, for joining. I hope it was useful. See you next time. Bye-bye.

Bye.