Conference. We would like to inform you that this event is being recorded. All participants will be in listen-only mode during the presentation. 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 management beliefs and assumptions and information currently available for 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'll turn the video conference over to Lida.
Hi. Thank you, Raquel. Hello, everyone, and thank you for joining us today. First, let me give you a quick summary of the quarter so we can move on to the Q&A fast, here with the senior management. Today, we have our CEO, Mr. Mariani, our Head of Oil and Gas, Mr. Horacio Turri, and our CFO, Mr. Adolfo Zuberbühler, here. Before getting into the quarterly results, let me highlight that all the seven projects in which Pampa participates have now been all approved under the RIGI framework in this beautiful slide, with the latest corresponding to Fértil Pampa, basically, AKA the urea project, and TGS's NGL project. All these projects represent approximately $30 billion in approved investments. However, let me clarify that Pampa only directly involved in Fértil Pampa and Rincón de Aranda, while the others are affiliates where Pampa has a stake on it.
All these investments provide a clear roadmap for Pampa's long-term growth, supporting Argentina's export expansion and enabling us further to unlock the potential of Vaca Muerta's resources. Also in the recent months, additional gas transportation capacity has been tendered, and Pampa secured 9.6 million cubic meters per day of new capacity through the Perito Moreno pipeline. The map shows the routes and destinations covered by this capacity. The newly awarded 9.6 million cubic meters per day, together with the 2.5 previously contracted, and the 3.5 million cubic meters per day of gas consumed at the wellhead by Central Loma La Lata power plant, brings a total of 15.6 million cubic meters per day. This figure does not consider, however, the San Matías Pipeline. This expanded capacity is key to further integrating our E&P business with the natural gas requirements of our thermal power generation and future urea facility.
It will also create opportunities to market gas at competitive prices in the Buenos Aires metro area, secure firm contracts of exports to the north of Chile and Brazil, and enhance margins in our power generation business. In particular, double-click here, under the new deregulation framework for power generation, electricity generated using natural gas transported through new infrastructure is eligible to capture the full dispatch margin in the spot market. So, it means the FRA is equal to one. Looking ahead, by 2030, we expect peak gas demand to reach 15.5 million cubic meters per day. This is, again, excluding the FLNG. Of this, the 12 million, notice that it's flat consumption, while the other 3.5 is seasonal. Turning to slide five, the Q3 results, the adjusted EBITDA reached $398 million, up 23% year-on-year.
This is boosted by stronger spot and B2B PPA margins in our power segment, plus the benefits of gas self-supply. Quarter-on-quarter, EBITDA slightly declined 4%, impacted by lower crude oil inventories and the oil hedge. However, this was offset by higher gas realized prices. Oil and gas remain our largest EBITDA contributor, accounting for 55% of the total EBITDA. CapEx rose 85% year-on-year to $585 million during the quarter, more than doubling quarter-on-quarter, because of the ramp-up in investment at Fértil Pampa following its FID, while spending at Rincón de Aranda moderated as the project moved closer to the production plateau. Moving on to slide six, the oil and gas adjusted EBITDA was $170 million in Q3, broadly stable year-on-year, and 7% below last Q.
Gas self-supplies to our thermal power plants, mainly to our high load factor CCGTs, Genelba and Loma La Lata, benefit from stronger pass-through prices, plus increasing retail sales supported the segment, partially offset by the impact of increased lifting costs and royalties. Production averaged 99.7 thousand BOE per day, flat year-on-year, with oil increasing its share to 22% of the total production. The sequential decrease was mainly driven by the lower gas demand for power generation as milder weather associated with El Niño reduced thermal dispatch, together with temporary oil well shut-ins during August and July, at nearby D&C activities to prevent frac hits, partially offset by the contribution of 10 new wells tied in at Rincón de Aranda in August. Lifting costs grew 31% year-on-year to $77 million. This is mainly explained by the second TPF at Rincón de Aranda.
Lifting costs remain stable, however, quarter-on-quarter, though if we measure it per BOE, decrease because of the lower output. CapEx in the segment was $209 million, down 22% year-on-year and 8% quarter-on-quarter. Of this amount, $158 million were destined for Rincón de Aranda and $51 million for gas, as we will discuss in detail in the next slides. Let's now take a closer look on the gas business. Adjusted EBITDA was $119 million. This is up 6% year-on-year, but slightly 2% down below Q2, supported by gas self-supply to our thermal power plants and stronger retail sales, partially offset by soft thermal dispatch and royalties associated with higher prices. Production averaged 13.2 million cubic meters per day, 6% lower year-on-year and 8% below Q2.
Deliveries to our CCGTs, Genelba and Loma La Lata, supported the volumes, but this was more than offset by lower industrial and export deliveries, as well as the milder weather linked to El Niño that we explained before. By block, Sierra Chata led the gas output, increasing 29% year-on-year, while El Mangrullo declined 35%. Both operated blocks accounted for 86% of Pampa's total gas production. Regarding destination of our gas sales, 61% of the gas was sold under the Plan Gas through retailers and CAMMESA, down from the 71% last year due to this transfer of GSAs, but up from the 56% that we recorded last quarter, explained by the higher retail sales. Intersegment consumption for self-supply was 30% of the total sales, in line with the 41% last quarter, but significantly higher than the 9% reported last year.
Exports represented 6% and industries only 3%, down from the 12% last year, as we are prioritizing self-supply for power generation. And why? Because during the quarter, gas prices averaged $5 per million BTU. This is 12% higher year-on-year, explained by the greater recognition of the cost of our own gas allocated to power generation, as CAMMESA allowed the gas pass-through prices to be partially linked to LNG prices during the winter months. Finally, gas CapEx was $51 million, in line with the last year, 20% below Q2, mostly allocated to well drilling and completion. In Sierra Chata, four wells were drilled during the quarter, which are still pending on completion, and began drilling an additional well in September, which is still in progress. In El Mangrullo, no wells were drilled or connected in the quarter, and the production supported by the well base.
However, drilling activities have recently resumed in El Mangrullo. At Río Neuquén, two new tight gas wells were drilled, four were completed, and three additional were brought into the production during the quarter. Moving on to crude oil on the next slide. Adjusted EBITDA was $51 million. This is 14% lower year-on-year and 16% lower than Q2, impacted by the oil hedge and higher lifting costs, partially offset by the production ramp-up. Compared to Q2, the $10 million decrease was due to lower crude oil inventories. Total crude oil sales reached 23,000 barrels per day, 15% higher year-on-year and 9% above Q2. Export represented 52% of the volume sold compared to 57% last quarter and 47% last year.
The average realized price net of hedge, net of export duties and discounts was $55.7 p er barrel, 9% below last year and 5% below last quarter, impacted by the Brent hedge and higher discounts on local sales. Without the hedge, the realized price would have been $84 per barrel, equivalent to approximately $60 million in additional sales. Rincón de Aranda averaged 21,000 barrels per day during the quarter. The sequential decrease mainly reflected, again, by the temporary well shutting completion activity in nearby pads to prevent frac hit. Ten new wells were tied in during August, bringing the production to a monthly average over 26,000 barrels per day in September, the highest to date. We also achieved a new daily production record of 28.7 thousand barrels per day on September 12, reaching full low capacity at the temporary processing facilities. At quarter end, we have 13 DUCs.
Since then, 10 of that DUCs were already started completion activity, and the remaining three are expected to be completed next year. Rincón de Aranda lifting cost was $32 million, or almost $17 per BOE per barrel, which doubled year-on-year and increased 6% quarter-on-quarter. This is following the second TPF that allow us to ramp up to 28,000 barrels per day of production and low, but also impact by lower output. Once production achieves stable 28,000 barrels per day, we estimate that lifting costs should lower to $12 per barrel. Crude oil CapEx was $158 million. This is 27% lower year-on-year, 4% below Q2, mainly because most of the investments on the CPF have already been made, with commissioning expected in the first quarter of 2027. Of the total, $102 million were wells, $48 million facilities, and $8 million pipelines.
Okay, turning on to power generation, we posted an adjusted EBITDA of $160 million in Q3. This is 33% year-on-year up and 3% up quarter-on-quarter, mainly driven by stronger thermal spot and B2B margins under the new framework, which introduce marginal pricing for spot electricity. These gains were partially offset by the end of Energía Plus contracts, higher maintenance expenses, and weaker MATER performance. Regarding dispatch, El Niño drove the hydro dispatch, but negatively impacted the thermal dispatch, especially in the peakers, as mild weather reduced electricity demand. Pampa's total availability reached 94%, flat year-on-year, recovering from the 88% in last quarter, despite the outage that happened in Ensenada Barragán. Thermal availability stood at 95%, above the 80% that the national grid recorded. Installed capacity decreased to 5.2 GW following the end of Los Nihuiles hydropower concession.
At the same time, the share of contracted capacity rose to 37% of our capacity. This is up from 35% last quarter and 32% last year, thanks to the new deregulation guidelines. Moving on to slide 10, we want to picture how our 5.2 GW of capacity generated $170 million in the quarter. Contracted capacity represents 37% of the total capacity, but contributed 59% of the segment's EBITDA, led by CAMMESA PPAs and a growing B2B PPAs, providing stable source of cash flow. Under the new deregulations, we expect B2B PPAs to continue growing as power generators are free to contract the whole capacity and up to 20% of the energy produced as of April next year, and 80% in April 2028, reaching full unrestricted contracting as from January 2029. This is a year earlier than what the deregulation guidelines provided initially.
Turning on the spot market, CCGT generated $68 million. This represents 43% of the segment's EBITDA, explained by higher marginal prices in the power grid, supported by increased fuel costs, particularly LNG and liquids. The impact of the new spot framework is clearly visible in the margins by technology, excluding fuel, though, in the right of the slide. Our spot CCGTs earned $42 per megawatt hour in Q3, of which $31 corresponds to the dispatch margin, again boosted by the seasonal pricing and the fuel management, self-management, which allow us to capture stronger margins, especially in our senior rank CCGTs, even as dispatch fell to 19%. By contrast, spot peakers earned $17 per megawatt hour, while their dispatch declined due to the lower efficiency and its position in the merit order.
Next year, same quarter, with the TGS's Perito Moreno expansion online, we expect Genelba's CCGT margins to increase, as we will be dispatching power using new transportation infrastructure that we explained way before at the beginning of this call, enabling Genelba to capture the full margin. Turning to slide 11, we show the parent company figures cash flow aligned with the bond perimeter. Free cash flow was $-388 million in Q3. This is $394 million lower year-on-year and $260 million lower than last quarter. This is mainly due to the CapEx driven by Fértil Pampa and Rincón de Aranda, increased collateral from crude oil hedging, and the prepayment of TGS's Perito Moreno gas transportation capacity. Together, they more than offset the $304 million of EBITDA and dividends collected from Transener.
As a result, cash and cash equivalents stood at over $1 billion at the quarter's end, $154 million more than a year ago, but $246 million less than Q2. Finally, on the balance sheet, gross debt as of September was $2.8 billion, up from the $2.6 billion recorded last quarter, mainly because of the issuance of the corporate bond series 28 for $138 million. Net debt rose to $1.7 billion, representing net leverage of 1.7x over the last 12 months EBITDA, rising from 1.4 x last quarter. After the quarter end, we issued additional $220 million at 6.5%, which brings our pro forma cash position to $1.3 billion. All right, this concludes the presentation.
Now, the floor is open for questions. If you have a question, please send it to the Zoom chat. We will read it and answer in the order received, first in, first out. Make sure your name and the company are displayed correctly so we can introduce yourself to the audience and know who you are. Should any participant need assistance, please send us a chat message. Please hold while we poll for questions. Thank you. [inaudible]
Well, no. We have a ton of questions, beginning with Alejandro Demichelis from Jefferies. He is asking, "How do you see the evolution of natural gas prices in Argentina after Plan Gas finishes?" Horacio?
Tough question. Good morning, everybody. Actually, the answer will be more conceptual than quantitative. We see the future of gas market in Argentina as being supplied by two different sources of gas, associated gas and dry gas. We don't think that associated gas will be enough to fulfill the demand curve even during the summer, so our assumption is that the dry gas, dry shale gas, like the one coming from Sierra Chata or El Mangrullo or Aguada Pichana, will be the gas setting the marginal price. This is going to be at least our understanding of how the market is going to move. It's going to be looking at marginal prices set by the least competitive dry gas reservoir.
Cool. Second question from Alejandro says, "How much extra third-party gas volumes do you need or would you like to contract?"
So far, we feel comfortable with the amount of gas that we have already contracted, and we don't have any plans in the near future to increase that amount of gas.
Well, I'm going to move on to Guido Bizzozero and Santiago Herrera from Allaria. They have a bunch of questions. First, share buyback program. Given the recent market volatility and sharp declines, is a share buyback program being considered for Pampa, TGS, or Transener? I recall the previous program for Pampa was set on September last year, actually, at a maximum of $60 per ADR, prior to the approval of several RIGI projects.
Yeah. I think you gave part of the answer in your question. Pampa and TGS have significant CapEx plans going forward. In order, in the case of Pampa, to Rincón de Aranda to get to the plateau level, we need to continue investing next year ahead of the free cash flow generation in order to reach the plateau of production. As you know, we are also paying the CapEx for the urea project this year, next year. So, for the moment, share buybacks in Pampa, for the time being, we are not planning. In the case of Transener, it could be a possibility, but hasn't yet been discussed with our partners. Anything else?
All right. Second question is, considering the requested additional 4.5 million cubic meters per day capacity to expand the GPM to Perito Moreno, what are your expectations for CapEx, revenues, and EBITDA for TGS and Pampa?
I do not recall the numbers for TGS. Do you recall how much CapEx does TGS need to do in order to-
4.5 million additional?
Yeah.
[Non-English content], 4.5 million.
4.5 million additional.
Yes.
Okay, [Non-English content] .
Yeah, but-
[inaudible]
Yeah, it's around-
180.
[inaudible]
[Non-English content]
Okay. That is basically CapEx that TGS needs to do in order to increase compression capacity in the GPM pipeline. Pampa doesn't need to do any CapEx. It will pay for that extra capacity through the tariff. TGS, through that tariff, will recover the CapEx that it will be doing.
This new capacity that goes to Bahía, we are going to use it for?
We are going to use it for the urea plant and for some of the power generation that we have in that area.
The peakers, yeah.
Mm-hmm. Correct.
Yeah, notice that out of the 4.5 million, 4.3 million goes to us.
Yes.
Yes.
Next question, regarding the recent changes introduced in the Resolution 400/2025, basically the deregulation in the power market. Could you provide insight into how this might impact future revenues and EBITDA for the power generation segment?
Again, as Horacio said, I will not be giving numbers because I do not have them on top of my head, but conceptually. Beginning next year, the FRA, that is the percentage of the margin, the difference between the spot price or the marginal price in the system and our CVP, our cost of production. Each generation this year has been allowed to capture 15% of that margin. Beginning January of next year, we will be allowed to capture 25% of that margin. Through that will have an impact on EBITDA. Also, the change in this resolution is the ability for legacy thermal units to sell to the-
B2B
B2B PPA market a larger amount of the capacity, going from 20%, the current 20%, to 60%.
Of the energy, actually.
Sorry, of the energy. That is correct. This year, we were allowed to sell up to 20% of the energy produced, and beginning next year, we will be allowed to sell, or beginning May of next year?
April.
April of next year, we will be allowed to sell up to 60% of the energy produced. When we sell to the B2B market, we have a higher, like close to 40% higher prices. The third way in which our EBITDA for power generation will increase is because of the gas transportation that we have acquired that will allow, for example, Genelba, the combined cycle of Genelba, to fully capture 100% of the margin. So this FRA goes from 25% to 100%, and that will have a significant impact on the EBITDA generation of Genelba.
To be more precise with the TGS figure regarding investment, it's $150 million.
Less. Hey.
Better.
Better.
Better for TGS.
Yeah. But it's very important to say it's the percentage of the B2B quota, let's say, to be sold. It's as a percentage of what you produce, and the more you produce, the more efficient you are, the more you produce. The more you produce, the more quota you have.
Next question for you, Horacio.
Me.
Could you share additional details on the expected evolution of crude oil production for Rincón de Aranda over the coming quarters, as well as the volumes hedged through April 2027? Do you plan to maintain a hedging strategy moving forward? There's a lot of questions.
That's a lot of questions. Let's move first to the production. We are forecasting to end up 2026 with 28,000 barrels per day. That's the maximum capacity of our two TPFs. Probably that level of production will remain so for first quarter or similar to that. Then we will be looking probably at a slow swing in the production due to the ramp-up and the drilling and completion needed in order to achieve that ramp-up. That will probably hit the production levels by June, July, and then we will see a ramp-up curve going up to 40,000 barrels per day by the end of 2027.
Then, well, hedge.
Yeah.
Who is going to ask? As well as the volume hedge until next year. Well, the hedge. The topic, the hedge.
The question was if we are planning to maintain the hedging strategy.
And what-
Yes, definitely we are going to maintain a hedging strategy. What we learned is not to be as aggressive as we have been last year. Going forward, I don't think that the hedging will surpass 50% of our expected production. This year, unfortunately, we fully hedged the expected production for this year, and for a few reasons, the production ran a little bit below of what we expected. So now, we are every month rolling forward the excess contracts for next year. So, we are already hedging next year through this rollover of contracts. Yeah, obviously, rolling over at current market prices.
But volumes, would you like to explain how many volumes?
Going forward, we plan not to exceed 50% of expected production.
Cool. All right, next question, also for Horacio. How do you anticipate the mix between local sales and exports will evolve once the Vaca Muerta Sur pipeline becomes operational and reaches maximum capacity?
Okay. Argentina is producing today around 1 million barrels per day, out of which 500,000 is consumed locally. So all of the new demand, let's say, that comes from the additional pipeline will go fully to the export segment. 100%.
100%. How do you see gas prices evolve? It's kind of. This is different from the other questions because he says, "How do you see the evolution of realized prices for Pampa evolve in Q4 and 2027?"
Okay. Pampa, until 2028, is part of the Plan Gas. So basically, our gas price will be settled by the Plan Gas prices. Even our exports to Chile are-
Linked with-
A proxy to the, or linked to the Plan Gas. What we will see eventually is a change. Eventually, no, we will see a change in two aspects. One is the possibility of supplying additional gas to our power plants, as we did in 2026. There will be a significant change in the new gas that we will be delivering to our power plants through the new, or the expansion of the GPM pipeline, through the iniciativa privada of TGS. That will change significantly the gas price during those 90 or 100 days.
Mm-hmm. Cool. Q4, let me remind you all that that's our softest quarter.
Q4, we're going to be looking at the summer Plan Gas prices, which are around $2.9 per million BTU.
Correct.
Talking about 2027, we will have the upside of both the additional gas and the EPE from TGS.
Correct. Do you expect that next winter, so the gas prices for pass-through and power to-
Yeah.
Be similar to this year or to be lower than this year?
Will be a little bit lower. Will be around $6.9 per million BTU, for the additional gas.
For the additional gas.
Now, for the new gas coming out of the transportation expansion, we will be looking, as Gustavo mentioned, the FRA equals one. We were looking at the marginal price of LNG.
Yeah.
As Pampa.
Correct. We are capturing-
We are capturing-
Through the other side. Yeah.
Exactly.
That's why it's a good thing to have two businesses, right? Well, and then, well, it's kind of related, but to what extent could Pampa increase the proportion of gas dedicated to self-consumption for its power plants? Today it's 30%. Well, this quarter, we've presented 30% for intersegment. How do you envision to end up this year and for the upcoming years?
Well, for the coming years, particularly looking at 2027 with the coming online of the TGS expansion, we will have approximately 5.5 million cubic meters additional gas being delivered during the winter to our power plants.
So, like a percentage of the-
Percentage of the total, no.
50%, 40%?
No.
40% of total?
Of the total? We'll probably be a little bit more than that.
But I'm thinking year average, though.
I don't have-
Probably close to 50%.
Close to 50%, no?
Yeah. Looking at the total demand of 19.5-
Yeah.
Probably will be close to 50%.
Correct.
Well, we still have the restrictions of the Plan Gas.
The Plan Gas.
It will be increased because of the new transportation capacity that we have purchased, but we are still confined to the restrictions of the Plan Gas. So, beginning January of 2029, when the market will be completely free, we will be able to fully.
To learn.
Fully supply our power generation plants. Not until the Plan Gas expires.
Great. The next question comes from Latin Securities, George Gastaut and Alejandro Christensen. They are asking, "Will the 6 million cubic meters per day of third-party gas, associated gas, secured in October replace Pampa's own volumes or supplement them later this decade?" It's a weird question because he's asking...
It will be a complement to Pampa's overall portfolio because we will be Just to bear in mind, we will be increasing our gas demand through the IPA of TGS and the new fertilizer plant, on one hand, and we will be, by the end of 2028, look, we're going to be doing it before, but by the end of 2028, we should have negotiated our new gas contracts with the distribution companies and the industry, the exports. It's a complement. We don't see it as a replacement of Pampa's production necessarily.
Yeah. It's what you said at the beginning, right? Is thinking that-
We were very, I would say, very lucky to retain that gas, which is pretty cheap. It doesn't mean that we are not in a position to supply additional demand with our dry gas reservoirs.
The most important thing is that the dry gas will settle the marginal pricing.
Definitely.
Yeah.
That's the way we see the market.
Yeah.
That's the way we see, yeah.
Yeah, that's the takeaway that we wanted to ask. Our vision is that, however, shale oil will bring a lot of associated gas. The need, the demand, the nature, what the market demands in Argentina, it won't be
It's higher.
higher than the associated gas.
It's what Horacio explained at the beginning. In the next few years, we don't believe that associated gas, that will be growing a lot in the next few years, but despite that growth, it won't be enough to fully supply the Argentine market. So, as long as associated gas doesn't fully fulfill the demand, the local demand, somebody will have to develop associated gas. Sorry, develop dry gas.
Dry gas.
That dry gas has a higher price. We believe above $3, it is going to be above $3. That, we believe, will be setting the marginal price of-
Especially in winter, needless to say.
I am talking about average price, though. Because of the seasonality, obviously, gas Spot price will be very cheap in the summer and should be close to import parity during the winter. But in average, if you need somebody who has dry gas to be developed, you will have to pay, in average, a price that compensates the capital allocated. We believe that price will be above $3.
Cool. Because this is the second part of the question. How cheap do you think associated gas can become over the next years in Vaca Muerta?
Well, the best reflection of that is our tender. We tender for five years, starting 2028, 2029, and 2030, and that's the best reflection of the market that we can see.
Cool. The next two questions of George and Alejandro repeat. It's about the hedge, it's about Rincón de Aranda, so we already talked about it. One of the questions is, will temporary shut-ins during drilling will keep causing swings in Rincón de Aranda?
Yes, definitely, because that's the way the ramp-up works. I mean, it's a paradox, but the more you drill and complete, the more you have to shut in other wells, and that's the way to increasing the plateaus.
Another question about the future, near future. How do you expect El Niño stronger hydrology to weigh on the thermal dispatch and spot margins in Q4 and first quarter of next year?
Yes, we believe it will have some impact, obviously, but in our case, we don't expect anything relevant. That's basically because our CCGTs, we believe will be The dispatch won't be affected. Obviously, the dispatch of the peakers will be fully affected, but we weren't considering that our peakers were going to be dispatched at this season of the year. In summary, we expect minor impact coming from El Niño on our power generation segment.
The next question is, what do you think drove the government to raise the B2B market quotas for energy quotas to 60% from April next year? Is there enough demand to contract all this full share, or how much of your legacy fleet do you plan to contract?
What drove the government? I think were a few reasons. First, from the moment that the resolution was published, I think the whole industry felt that 20% was too little, especially because not all the equipment has the efficiency to sell to the B2B market. Only CCGTs are the ones offering energy at competitive prices to this demand. So, 20% of that was too little, and increasing that to 60% makes a lot of sense. Also, as you know, this government looks to fully liberalize or deregulate the market. This is a transition going from 20% to 60%, then to 80%, and full liberalization beginning 2029.
Yeah, a year before.
A year in advance of what was previously.
Stipulated.
Yes.
But it was like instead of 20%-100%, yeah, 20%-100%, it's like more gradual, right? What do you-
How much do we plan to contract? We plan to contract as much as we can, as much as the competition allow us. Just one thing to keep in mind that next year, Genelba, because of the gas transportation that we have acquired for Genelba, it will be better off to sell to the spot market because it will be fully capturing the full margin than selling to the B2B market. Taking Genelba aside, we plan to sell as much as we can from the rest of the CCGTs.
Loma, the peakers.
With the CVP, meaning the production costs for power generation declaration floor dropping, do you expect competition between generators to intensify? What does it mean for spot prices?
Yes, I think it will have some impact on the. Basically, this might be a little bit technical, but the regulation, when you are not able to supply your PPA contract if you are not dispatched, if you are not online. This might create some competition among generators with PPAs to make sure to be dispatched in order to supply your PPAs. Unfortunately, it is something that we think should be corrected, but it is not easy, is that currently the regulation does not allow a generator to buy energy from another generator to supply your contract. That is why we expect some higher competition among generators, and we have an impact eventually on spot prices.
Moving on, Agustín Pacheco from Mariva, he is asking, "Regarding the urea project," first question about urea, "what percentage of the $2.7 billion investment is covered by the lump sum turnkey contract?"
All of it.
Exactly.
Does the agreement include penalties for construction delays?
Yes, of course. The contract has LDs, standard LDs, and provisions typical of this type of contracts.
It's to highlight, it's a lump sum turnkey, right?
It's a lump sum turnkey contract, with infinity make good obligation from part of the EPC companies.
Not only delays, also performance.
Performance, of course, quality, performance, and delays.
Awesome. Once TGS gas pipeline expansions become operational, what is the estimated, [Non-English content] . What is the estimated, no, [Non-English content] . What is the estimated incremental impact on power generation EBITDA and gas? We talk about power, which is $100 million, but gas, how much additional gas EBITDA will E&P benefit from the TGS's expansion? If you want, we can go to urea back.
[Non-English content]
[Non-English content] $ 30 million.
If you take the 5.5 additional million cubic meters per day, and you assume the margin that we're getting out of selling that gas, it's in the range of $30 million.
Perfect.
Bueno. Next is Bruno Montanari from Morgan Stanley. He asks about the Rincón de Aranda performance, so we already answered that. We also talk about the mindset about the oil hedging. He asking about urea. What levels of CapEx should we expect next quarter? Are there news about the evolution of the project finance?
Yes. The total CapEx will be deployed in the next three years. For this year, we already deployed $300 million, which is what we needed for this year. CapEx deployment will concentrate heavily on 2028. I will give you big figures, but think of around $600 million-$700 million next year, and probably $1 billion on 2028. We're working on the financing. We are in the middle of negotiations, so I cannot disclose much. What we can say is that we started the process on February. We've been through a very exhaustive and detailed and hard due diligence of the project for the last eight months. We completed that successfully. We can finance this as a project finance. We are working, as of today, on the final documents of the loan and the final pending credit approvals. We're aiming to close the financing by year-end or this year.
We have to keep it up. There is another question. Does the 1.5 x, 2 x net debt EBITDA range for the coming years still hold?
Yeah. The idea, as you can see, we used a lot of time here. As you can see, we have been tapping the markets, and we have been issuing debt, and we have been piling up a lot of cash. This has three reasons. One, we want to move ahead of our investment plan and secure all the financial needs this year. Secondly, and related to the first, we want to avoid, if possible, any turmoil in the market next year, due that it is an election year. Also, there are a lot of risky projects and a lot of capital needs. As you know, capital is limited, so we will be all competing for the same limited basket of capital.
In that sense, is that we act first and issue a lot of debt this year, and you can see that the gross leverage increased a lot, and this is the reason. We have a lot of cash ready for our aggressive investment plan that we have, and we want to secure everything this year as soon as possible. That is why you see gross leverage increasing, and because of our CapEx plan that we started deploying, also our net leverage is increasing. So, the 1.5x, 2 x, it is a reasonable range. Probably we will move closer to the 2x faster than expected. Once EBITDA starts to grow, that ratio will be reduced.
Thank you, Fito. Next question. Very good. Next question, it is about from Puente, Juan Ignacio Lopez. He is asking regarding the recent tenders in Megsa. Could you reveal the identity of the counterparties?
No, we cannot.
Next question.
I don't think we can. I don't think it's relevant, and I don't think we can.
Second, should we view this transaction as a part of a broader strategy of securing long-term gas supply through periodic tenders, potentially taking advantage of favorable market pricing? Or do you consider that Pampa has already secured the volumes required to cover its expected needs, or the least for the time being?
As you said, for the time being, we are happy with the 6 million we have acquired. That is around 50% of the expected flat gas need of Pampa for those years. Going forward, we will evaluate whether it is better for us to invest capital and develop our own reserves, or we have the opportunity to buy cheaper gas in the market. For the time being, there is no decisions to be made. As you know, for 2028, we tried to acquire 2 million cubic meters per day, and we were only offered 1 million. CapEx for next year, in order to be able to supply our demand in 2028, remains more or less the same. It reduces slightly. These purchases obviously have an impact on the CapEx going forward, 2028 and 2029.
Right. Jake Roberts from TPH, Tudor, Pickering, Holt, is asking something similar about this. Well, about the replacement, we already tapped that, right? He is asking, because these volumes depend on third parties, operators drilling oil wells on their own schedules, what delivery warranties exist? Meaning deliver or pay, or take or pay.
Yeah. We do have a deliver or pay clause in the contracts, which is one, I mean, during the summer, which is not very relevant in terms of obligations because there is surplus gas during the summer, is one time the gas price. During the winter, we have 3x as a penalty, the deliver or pay. That is a big incentive for the counterpart to comply.
Although we are not disclosing our counterparties, they are very big and strong creditworthy companies.
Awesome. He is also asking, TPH, "Well, you said that the own management of fuel generated 25% margin over the CVP. Now that it has been amended, that the ranges are shrinking, how much of the $160 million EBITDA, the Q3, adjusted by this markup?" Meaning, he says, "Okay, now it is" Bear with me. Next year, it is 17.5% instead of 25%. How much less EBITDA it means?
I do not expect anybody in this table to have that figure on top of their mind.
Okay, 28%. 2028, I forget.
Yeah. Basically, now going back to power generation EBITDA, yeah, there are several factors that affect on the upside and some factors that affect on the downside. Overall, the positive factor will, I am completely sure, be higher than the downside factors. But I do not have the breakdown of each of them. We do not have the breakdown of each of them.
Yeah, definitely will be less EBITDA, of course, because it's the-
Because of this impact. But there will be more EBITDA because of the other reasons that we said. Increase sales to-
B2B
To B2B. The FRA1 for Genelba.
More gas.
Yeah.
Oil and oil. I know, we know it's not the development QE at the moment, and there are only few oily wells drilled, but how are you thinking about the long-term resources potential for unconventional development at Rincón and Río Neuquén block, which is not operated by us?
Yeah, it's a good remark. It is not operated by us. It's very preliminary, and we are still in the phase in which we are discussing with the operator about the future development and the convenience of different action plans. It's not defined yet.
Okay, next question. We have a lot of questions. Shut up. Andrés Cardona from Citi, urea project already tapped by Fito, and the credit, how the project financing is going on, already tapped by Fito. Stefan Zwinger. Anyone? Stefan, or first name first. Stefan Zwinger, I guess he's from Sweden, asking about the oil hedge. We already tapped that. Daniel Guardiola.
He is asking, "Have you hedged beyond first half?" No, we haven't hedged yet beyond first half of 2027.
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Okay, up to July. We have only 300 contracts in July. But basically, so far, we are hedged until July of next year, not a small portion of our production in the last two months, in June and July.
Okay. Next question coming from Daniel Guardiola from BTG. First, negative free cash flow and the path to recovery. Restricted group free cash flow was negative for almost $400 million in the Q3 2026, marking a second consecutive quarter of cash burn. Could you bridge the outflow between growth CapEx, working capital, hedge settlements, and collateral postings? When do you expect free cash flow to turn positive, both including and excluding the urea project? Easy one.
Yeah. Daniel always asks the right questions. Let's forget for a minute the urea project. We have three sources of CapEx. One is the maintenance CapEx of our operations. If you think Pampa at plateau level of Rincón de Aranda, the maintenance CapEx should be around $600 million-$650 million, right? 100 power, 200 to 250 gas, and the remaining oil. The second source of CapEx is the new investments, which the major now is-
And I think the 250 you mentioned for gas was the old number-
The old number.
Not taking into account the purchases that we have done. So, that number will be lower.
The second source is Rincón de Aranda, which the project is finishing next year. The remaining CapEx in Rincón de Aranda will be to ramp up the production, mainly, to reach the new plateau. Next year will be a CapEx of around $400 million to reach that plateau. The third source of CapEx that we are having this year and the next is the equity contributions to all our affiliates, VMOS, San Matías, Southern Energy, and the prepayment of gas of all the capacity that Lida showed that we're prepaying. We're prepaying that this year and the next. All that sums out to around $250 million each year.
What I'm saying is next year we will also have negative free cash flow because of this, because of the remaining CapEx of Rincón de Aranda and the remaining CapEx of these affiliates and the prepayment of gas. By 2028, free cash flow should turn positive. We won't have any new CapEx in Rincón de Aranda except maintenance and any new CapEx in the affiliates or prepayment of gas. One more year of negative free cash flow at Pampa level. This is a conservative figure, not including any dividends from our subsidiaries or any extras or any M&A or sales or anything.
Working capital stays as it is. The pace of payment, the collections stays as it is. What we show in the cash flow in the bridge, it's basically, we put it there. It's basically the prepayment, which is around $50 million for this quarter, plus the rest is basic. No, but in the bridge, because he wants to know the breakdown of that, and basically, I don't know, $68 million, right? The rest is basically the impact of the derivatives and the posting of. Hedging losses and liquidity. Realized prices were almost $56 versus $84 without hedge. How much cash settlements and additional collateral requirements separately affected quarterly cash flow? What collateral remains outstanding, and when could that cash be released? In the balance sheet, you can see it. But you can see how much collaterals we have posted.
It's, I think, if I'm not mistaken, it's almost $300 million, but that's all the collaterals posted. Then you have to. If we close the position today, that will be returned, but also we have to. The mark-to-market, it's at loss. So, you have to deduct. I think what it's. If we have to close the position today, it's around $100 million that are returned back. That's as of September 30. What else? Forward hedging strategy, we already talked about that. Rincón de Aranda 2027 development.
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Are hedge volumes linked to financing-
Requirements.
Requirements or discretionary risk management?
It's not related to financing requirements. It's fully discretionary risk management or our own decision.
Mm-hmm. Rincón de Aranda 2027 development, we talk about everything. Next year CapEx, Fito talked about it, but drilling completion schedule. Yeah.
We will be drilling 32 wells, and completing 27.
Urea CapEx and funding following the almost $300 million invested in this quarter. Could you provide the annual spending schedule for the $2.7 billion? How much is already contractually committed?
All of it.
All of it. No, we don't have potential partners. It's fully equity of Pampa.
Okay. What explains the large initial outlay? It's the need to buy the long lead items, and that's why there was a She's asking why-
She's asking.
Sorry.
The calendar year is the prepayment of the contract EPC offshore, which represent around 21% of the contract offshore.
And what explains the large initial outlay? The fact that our contractor needs to buy the-
Yeah, secure all the equipment, start to placing the buy orders as soon as possible. That's why.
It's $300 out of $2.7 billion, so I don't know. It's a small compare. All right. Sophia Grant, she's asking, "What percentage of the thermal capacity do you expect to be contracted at spot?" Well, obviously the maximum.
Yeah, I don't have a percentage in my head.
The second question is more interesting. "What prices are we signing in the thermal B2B contracts?"
I think the market is currently around $55.
$55.
It was.
$55. Well, no, it was margins, no? It was a margin. You have to add the fuel, right? $55 flat.
Around that.
Around that. What tenor?
It's basically one-year contract. That's the usual.
She might be from a competition, right? Because she's asking, "What are the main counterparties?" Obviously large users, right? Well, no. Good quality though. We are very strict on that. Good quality, large users such as, I don't know, Coca-Cola.
Yeah, but in order to continue growing, we will need to tap the distribution companies.
The B2C company, B2C PPAs.
B2C PPAs. Yeah, basically the distribution companies.
The third question she asked, "Well, the new transportation capacity will bring FRA1 to all thermal plants?"
No.
No. Only for those that, Genelba for sure, and the peakers.
It's not that we will have enough for all-
Obviously.
Our power plants.
But for the peakers during the winter, for example.
Yes.
If they are dispatch.
In the next year, it will be enough for Genelba and another 150 MW, something like that.
Bueno. A ver, are you planning to be Okay, good question. Bull Market asking, "Los Nihuiles tender, are you planning to bid? What level of investment are you comfortable with, given that leverage?"
It's not on the market yet. We will have to take a look at the conditions of the tender, see how attractive it is, and we will take the decision at that point.
He is asking also, "Is there any additional prepayment for the 4.3 million cubic meters per day additional in Bahía Blanca?"
No. We already answered that. It will be repaid to TGS through the tariff. We do not have to prepay anything.
How much roughly of the $330 million of prepayment remains to be paid?
50%, no? I think we paid. There were four installments, we paid two of them.
Yeah, and two next year.
Or one at the end of this year and one.
I think it's January, yeah. I know what we have, but it's half this year, half next year.
Other question from Francisco Bertin from Moneda. Slide 10, the capacity margin is the capacity revenue for the plants divided by the dispatch energy? Yes. That's what we collect from the take-or-pay divided by the energy that we dispatch. Less the fuel, obviously. So we can compare apples to apples. Brian Nunes from Fort Washington asking from the hedging. I think we covered it all. Also Francisco from Moneda is asking, "In the plants that are in the spot, which percentage of the dispatch have been contracted? At which prices the thermal CCGT has been contracted?" Well, we talk about the prices, and I think one-third, yeah? It's 30% of the 37% you see there. If you break down, 10% it's spot B2B. [inaudible ]
No.
[inaudible] For the total, it was 10%.
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Ah, from the total, including the PPS. Okay.
Yeah.
Okay. We sold all that we could. So the 20% that we were allowed to sell-
We were long sold in May, March.
We sold it very quickly at the beginning of the year.
Everybody, actually.
Yes. That is a proof that the 20% was short of the need of the market.
Correct. Agustín Pacheco from Mariva asking for urea project. We already covered that. Rosental Inversiones asking, "You now see Rincón de Aranda reaching 40,000 at the end of 2027 versus the 45,000 plateau previously guided for the fourth quarter. When do you expect to reach the 45,000 barrels per day, and what lifting cost per BOE do you expect a plateau with the CPF running versus the $12 you guided at 28,000 barrels per day?
Okay. We will be reaching, hopefully, the 45,000 barrels by the first quarter of 2028. And once the CPF is running and we reach the plateau, the lifting cost will be close to $6 per barrel. Sorry.
[audio distortion] The 45 is what? Is 45?
It was 45. We are saying 40 by the end of 2027, 45 by the first quarter of 2028.
Because ramp-up takes time, come on.
Takes time and effort.
And effort, right?
And 45 barrels is the maximum capacity of the plateau.
That's the maximum capacity of the plateau.
The average will be something-
Probably something in between-
Below because when you complete the pad, you touch the 45,000, then you drop, you touch it again. Every time you complete the pad, you-
That is very true.
You reach the 45,000, but the average will be a few-
Probably 43 or-
Yeah, a few thousand barrels below that maximum.
The last question, and this is the last question. Andrés Cardona from Citi is asking, "Little new power generation capacity has been developed since 2024." This is true. "And the system has been tight for a while. What does it need to change to see more capacity to be developed? Is that a regulatory event? Do you see risks for blackouts? [audio distortion]
The reality is that the demand in Argentina hasn't been growing for quite a long time. So, yes, it's true that the market is tight, but it's tight only a small percentage of the total hours of the year. So less than 10% of the total hours of the year, the market is tight. When very hot days in the summer, very cold days in the winter, the market is tight. All the rest of the year, the market has an excess supply of energy capacity. So, it's not a regulatory event that is needed. It's basically an increase in demand. And regarding risk of blackouts, no, not for generation capacity situation. There could be blackouts related to distribution problems, but I don't see a risk of blackouts because of lack of power generation capacity.
Cool. Two more questions. Should we expect any dividend distribution from Federico Cabelli from Adcap?
No buybacks and no dividends.
No buybacks and no dividends.
Only growth. Federico Miguez from one618, but former-
one618.
one618. "What are the drilling and completion costs per well you've seen for the next year drilling plan?" I swear this is the last one.
We've seen a significant reduction in our drilling and completion costs in the past year. I am assuming that we are talking about Rincón de Aranda. So, we foresee a total well cost of approximately $12 million-$12.5 million.
Perfect. We are done. Thank you so much for holding us with us. This is the last call of the year. You want to say something?
I think we did. We covered them all the questions.
Any questions you may have, just do not hesitate to contact us, Raquel and I. We are more than available for you. Thank you so much. See you next year, Q4 earnings call.
Thank you for participating everybody. Bye-bye.