Pampa Energia (NYSE:PAM) reported second-quarter financial results on Wednesday. The transcript from the company's second-quarter earnings call has been provided below.
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Summary
Pampa Energia announced its entry into the fertilizer business with the approval of a $2.7 billion investment to build Latin America's largest urea plant, aiming to monetize its shale gas reserves and diversify revenue.
The company reported a Q2 adjusted EBITDA of $415 million, a 28% increase quarter-on-quarter, driven by record oil production and improved power generation margins.
CapEx decreased by 21% year-on-year to $279 million, with significant investments in the Rincón de Aranda project, which aims to reach a production plateau of 45,000 barrels per day by next year.
The company's power generation segment saw a 39% year-on-year increase in adjusted EBITDA to $155 million, benefiting from strong spot margins under a new regulatory framework.
Pampa Energia's free cash flow was negative $128 million in Q2, but cash and equivalents increased to $1.3 billion, with gross debt at $2.6 billion and net debt at $1.3 billion.
Future strategic plans include a focus on completing the urea plant by 2029, increasing gas production and maintaining a leverage ratio between 1.5 and 2 times in the next two to three years.
Management emphasized a strong growth trajectory, driven by strategic investments in Vaca Muerta's resources and a robust industrial energy model in Argentina.
Full Transcript
OPERATOR
Welcome everybody to Pampa Energia's second quarter 2026 results video conference. We would like to inform you that this event is being recorded. All participants will be in listen-only mode during the presentation. After the company's remarks, there will be a Q&A session. Please send your questions in writing through the chat. If anyone needs assistance, please send us a Zoom message. Before continuing, please read the disclaimer on the second page of our presentation.
Let me mention that forward-looking statements are based on Pampa 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. Hi everybody. Good morning. Thank you for joining us. And first I would like to give you a quick summary of our announcement on fertilizers. This is a new business and then a quick summary of the quarter so we can move on to the Q and A. Today we have only our CFO. We have a small inconvenience without Gustavo, but I think we both can do it, right? Yeah. So let me go to slide 3 which you can see. Last July our board approved the FID for the construction of Latin America's—so far Latin America's—largest urea plant, officially marking Pampa Energia's entry into the fertilizer business.
Granular urea is critical to agricultural production and global food security, and it is primarily used in the production of corn, wheat, sugarcane, and barley. Because natural gas is its main feedstock, 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. We aim to monetize the best shale gas reserves that Pampa Energia 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 Energia, reinforcing the competitive advantages of our vertically integrated business model while enhancing the project's operating efficiency and long-term profitability. So beyond diversifying Pampa Energia'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, with direct connection to Vaca Muerta pipelines—existing pipelines—and close to Pampa Energia'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 Energia. 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 approvals, which are essential to the development of the project. Last Friday the evaluation committee of the RIGI cleared Fértil Pampa's presentation, so we are waiting for the formal approval to be published in the Official Gazette.
Thus, Pampa Energia continues to strengthen its industrial profile further through the several projects presented under the RIGI framework. We are currently participating in seven projects across oil and gas, LNG, fertilizers, NGLs. Last June, following the FID at TGS, our affiliate filed an application for the $3 billion investment on an integrated NGL project. Also TGS's private initiative, which consists in expanding the Perito Moreno pipeline, a dedicated pipeline for the LNG project, and on the Aranda.
All those RIGI applications got approved. Overall, these projects provide a clear roadmap for Pampa Energia's long-term growth, supporting Argentina's export expansion and enabling us to monetize Vaca Muerta's resources further. Well, 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 impacted and drove the marginal costs up the system. So that helped, and also we have more B2B PPA sales. To a lesser extent, increased international prices also boosted the PET business, which recorded its highest quarterly EBITDA since 2023. Quarter on quarter, EBITDA grew 28%, supported by gas seasonality, stronger spot power margins, and increased PET prices.
Capex dropped 21% year on year to $279 million during the quarter, of which $165 million 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 to 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 accrual 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 $7.70 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, increased quarter on quarter following the commissioning of the second TPF at Rincón de Aranda that increased the crude oil treatment from 20,000 barrels to 28,000 barrels per day. Gas lifting costs also decreased 13% year on year to $1 per MMBtu, but slightly decreased 6% sequentially due to the maintenance cost at El Mangrullo.
So 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 57% of total volume sold in Q2 '26. This is very similar year on year and quarter on quarter. Rincón de Aranda contributed one third of oil and gas EBITDA, up from 6% last year—so last year was only 6% and this year's quarter this is one third—continuing to diversify the production mix. Now oil accounting 22% of the total output. At Rincón de Aranda the ramp-up continues. As you can see, the performance is comparable to the best blocks in the core, reaching a new record of 27,000 barrels per day on May 21st. 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 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 2 pads were completed in July and will be tied in in August—which will support rebound in production. In Q2 we also drilled another 10 wells from four 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 are already building oil and gas pipelines and water treatment plant facilities to treat the flowback water. The total estimated investment amounts to $4.5 billion, and it is expected to be deployed through 2041. So the RIGI approval represents a significant milestone for Rincón de Aranda, providing a stable framework for tax, customs, and FX incentives for 30 years. Long-term strategic export projects are also eligible for specific benefits, in particular the exemption to waiver on export duties starting in the second year of operation after the enrollment.
In this sense, Pampa Energia expects to export all of Rincón de Aranda's production through the Vaca Muerta Sur pipeline, which is estimated to generate approximately $17 billion over the project's useful life. Moving on to gas, production increased 10% year on year and 4% sequentially, reaching over 14 million cubic meters per day, driven by the gas self-supply to our CCGTs under the new power market framework, partially offset by lower volumes sold under Plan Gas and, to a lesser extent, reduced deliveries to large users.
Seasonal demand from retail and CAMMESA explained the quarter on quarter growth, offset by lower self-supply procurement since we have faced transportation restrictions in the gas pipelines. During Q2 we tied in four new wells at Sierra Chata, bringing production to a new all-time high. And in El Mangrullo there was no new development activity, with production supported by the existing well base. At Río Negro, four new tight-gas wells were drilled and two were connected.
For the second half of the year, our plan includes drilling activity in Sierra Chata and El Mangrullo. This is aligned with our 2027 Activity Production Plan, which considers the recently awarded transportation capacity at the Perito Moreno pipeline, in which gas transported through new infrastructure is able to capture the full margin—the full spot margin. In Q2, 56% of our gas was sold under Plan Gas GSAs 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 remained flat year on year at 1.2 million cubic meters per day. Industrial volumes declined as we prioritized self-supply demand, 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 MMBtu. This is 15% higher than last year, 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 maturity—mandatory maturity—of Energía Plus contracts, the outage of Loma de la Lata's gas turbine number four that is under a PPA—which is remunerated under a PPA—and the PEPE wind farms underperformance. As you know, the new guidelines reintroduced marginal costs as part of the spot pricing methodology, which caused marginal cost overshoot during the quarter, especially during the winter season, reflecting higher fuel prices, in particular using LNG and liquid fuel oil, diesel oil.
So the spot margins widened, specifically for the CCGTs, though that margin is capped at 15%. We only can capture 15% of that margin—that's what I mean. The current framework allows full margin—so you can capture the whole margin—if you are using new infrastructure such as a gas pipeline, which is the case for the 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.
So full capture—the FRA equals to 1 instead of 15%. Pampa Energia was awarded 3.2 million cubic meters per day in the Buenos Aires–bound tranche. So it goes to the—it will be used to procure the gas needs of the legacy Genelba CCGT, right? And 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 Iwiles—which now is currently since July 31st is no longer part of Pampa—and we have some outages also in Güemes and in the mentioned Loma de la Lata TG4. 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 re-tap of 2037 notes priced at the lowest spread to the T-bills USD in Pampa Energia's debt issuance history—and corporate history, I may say, Argentine corporate history. Net debt rose to $1.3 billion, representing net leverage of 1.4 times the last 12 months EBITDA.
So, concludes now this presentation. The floor is open for questions. If you have a question, please send it through the Zoom chat. We will read it first in, first served. Make sure your name and your company is there; otherwise we can just read it and we can also reintroduce you to the audience. Should any participant need assistance, just send us a chat through the platform. Thank you. Wait for a while we poll for questions. Moana, should we start with the new expansion projects that Alejandro de Micheris from Jefferies is asking?
How do you see capex in the next two to three years? At what level do you expect debt to leverage to peak?
UNKNOWN, Pampa Energia executive
Good morning. Thank you for the question. Yeah, evidently we're facing challenging CAPEX deployment, especially with the urea project. But also bear in mind that EBITDA looking forward should increase as well. Right. Once we achieve maturity of the Rincón de Aranda investment and the Southern Energy and some Matías pipeline investments by 2028, cash flow generation will be increasing and unstable. So what we foresee is that net leverage should increase from current levels up to a maximum of around two times.
And the ratio should vary between one and a half and two times for the next two to three years until we finish the investment in the urea project.
UNKNOWN Analyst
Great. But the CAPEX this year is basically it's around 1 billion, right? Yeah.
UNKNOWN, Pampa Energia executive
The CAPEX this year is around 1 billion, mainly during the project. Next year it's lower. Separating urea project, it will be around 700 million CAPEX next year, again mainly project, and after that Pampa Energia we have only maintenance CAPEX of all the business units in around 600. Right. We have to add to that the equity contributions from Pampa to Fértil. Pampa. Yeah.
UNKNOWN, Pampa Energia IR
Cool. Gilro and Santiago from Alaria, they're asking: after this 23 jump in EBITDA for 1H26, how do you expect to evolve the second half and '27 power generation? And considering in '27 that in the second half starts rolling out the PPAs. Do you want to...
UNKNOWN, Pampa Energia executive
Yeah. So the second half of the year, remember that always the last quarter for Pampa Energia is the weakest because of, due to the seasonality of gas. Actually 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. So the oil business will keep growing, but remember the seasonality in the other segments. But I think he specifically only refers to power generation.
So Q3 is going to be high. Higher than this one. Well, that's what we expect because winter, winter is Q4. Yeah, yeah, yeah. So first half is $299 million of EBITDA. We expect 600 for this year. Yes, a little bit, yeah, $600 million for this year. So basically it jumps up in Q3 if winter allows, and then goes down, and specifically because El Niño, right, there's more water, so it means lesser thermal power demand. So in '27 it's, yeah, it's a combination.
Second half starts rolling out PPAs but we also have the CTGS's private initiative that hey, we have 3.2 million confirmed that we will inject it through Genelba's legacy CCGT that actually is going to start before the winter, so most of the impact will be monetized next year, though it starts in May. So next year's EBITDA, it could go up. We are expecting 600, well a delta of around $100 million, things should, things, the winter and the fuel consumption, the liquid fuel consumption, LNG consumption remains pretty much similar, but in 2028 as you correctly said, goes down.
So it's a combination that in 2017 the PPAs rollout doesn't much reflect because it's towards the end of the year, but in 2018 you should see that it's a little bit lower. It's $40 million less because the PPAs roll out, but at the same time they join the spot market. Loma La Lata, out of the PPAs that roll out, two of them are at Loma La Lata. Loma La Lata is highly competitive because they don't require any gas transportation and they are very efficient machines.
So they kind of rank senior among the thermal units in the system. I hope that answers the question. How do you expect to increase the stake of gas used and sold to power generation since we notice an increase from 3 to 31% year-on-year basis? Well, basically, as I said in the call, the average of this year is around 40%. It will pick up. You should pick up in Q3 and actually picks more. It's highly reliant on self-supply. On Q4, even though demand and 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: Pampa consumes — the thermal units consume — around 10 million, only Pampa not including Ensenada, 10 million cubic meters per day, of which 8 goes to the CCGTs — 8 Loma La Lata CCGT — and the 2 CCGTs are Genelba, so the CCGTs are the flat consumption of gas for self-supply. That's what you should expect going forward. Third question from Alaria people: How do you expect petrochemical business to evolve in the future, considering the 5% contribution to the consolidated EBITDA in this quarter, when usually it's negative or slightly or break-even.
What it is, right? Yeah, we expect to continue contributing marginally to the EBITDA. Yeah, it was something like circumstantial, yeah. Due to the war and the high prices and bigger margins that we have this quarter in some of the products that we export, but we don't expect that to hold in the long term. Correct.
UNKNOWN Analyst
Can you give any color on how do you plan to finance the 3 billion capital urea project and the deployment along the 41 months' work?
UNKNOWN, Pampa Energia executive
Yeah, sure. So 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 Energia. With that in view, we started in February a very thorough due diligence. So 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 finally end the process in August, and we are negotiating the terms of the loan. So I cannot disclose much more today, but I will tell you that we are well advanced, we are discussing the terms, and we expect to finance a proportion around 60/40 equity/loan ratio. The deployment of the equity is more or less even, except 2028 there is a big spike — the CAPEX is concentrating mainly on 2028. I will say one third of the CAPEX is on 2028 and the rest is evenly distributed on the remaining years.
So I think that we start contributing capital to the project this year. The financing will be closed by the last quarter of the year probably, and the big contributions — both of debt and capital — will be on 2028. I think that covers the question.
UNKNOWN Analyst
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?
UNKNOWN, Pampa Energia executive
Yeah, well, the revenues, I think we already disclosed that on... where 1 million. Yeah. So the math is pretty simple. Depending on the price of urea you take, you multiply 2.1 million tons of urea per year times the price of urea you 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 Argentina or what combination.
But those are the big numbers that you can easily compute. And what was the rest of the question?
UNKNOWN Analyst
No, how much impact on...
UNKNOWN, Pampa Energia executive
Very good question. Yeah. Remember that starting 2028 the GSA starts to mature. Correct. So if it's not clear that we are going to increase gas production for the project or substitute a current production from one market to the project. Okay. That is something we will have to decide moving forward. But assuming we increase gas production only for this project, it's around $90 million of EBITDA additional to the gas segment. But again, it's a decision that we will have to make in the next three years.
The price is around $3. The price is $3. $3 is internal GSA. GSA. Yeah. Yeah. And consumption is 3.3 on average, year average. Yeah, it picks up in winter, but on average it's 3.3 million cubic meters of gas per day. And then in power, we are not planning to build new power facilities for this. Well, not for this. Not for this. We will see. Again, the power contribution is marginal. The big contribution here is gas. Yeah, but imagine like, well, today we are selling B2B PPAs at 65 monomic price, right?
This is consuming capacity 65 to 70. Well, we were talking about the B2B PPAs boost in this quarter basically because people are seeing the prices in the spot. If you go to the spot, the prices are really high. That's why when this deregulation started, the industrials didn't start to get into the B2B market, and now they are getting into — because they see it's highly seasonal. Better pay more flat than pay flat at a certain price of around 65 to $70 per megawatt-hour, which is what we expect to sell in this.
Yeah, it's around $68 and the consumption is 77 megawatt-hours. So. But again it won't be additional energy capacity, rather than replacement of... I imagine myself using our renewable — that's the plan — yeah, yeah, and backup with our thermal. Exactly.
UNKNOWN, Pampa Energia IR
Yeah. Well, another question from Alaria people, saying: considering the current production levels at Rincón de Aranda and the 10 wells scheduled to be connected in August, what kind of production ramp-up can we expect between now and the end of the year?
UNKNOWN, Pampa Energia executive
Okay, remember that the goal this year is to reach the 28,000 barrels per day. This increase is like a seesaw: you are tidying up, wells closing, tidying up, closing. So you will see these peaks and troughs of production. But the goal is to achieve the 28,000 barrels per day by the end of the quarter. Again, it's not constant. The same will happen next year when you try to reach the 45,000 barrels per day. The increase will be like a seesaw and ramp up until the 45.
UNKNOWN, Pampa Energia IR
What else? Bruno Montanari from Morgan Stanley, he asks: how can we think about Pampa's long-term big gas production considering the volumes to CESA, to their project, the self-procurement for power generation?
UNKNOWN, Pampa Energia executive
Well... so... Well, that's flat actually. Yeah. So what we foresee — and this is not a projection, it's a budget if you like — imagine that we can procure to our own power business around 10.5 million cubic meters of gas per day, another three and a half to our urea plant, another six to the floating LNG — to Cesar — to floating energy project, 1.5 for exports. If you would add up a little bit during the peaks, around 20. So it's around 20 million, between 20 and 22 peak-peak.
Flat is — average is 20. Yeah. So it's around 20 million cubic meters of gas per day. Quite constant because we are selling intercompany so we avoid seasonality. But yeah, that is what we foresee in the next three to four years when all our projects are online. So as you can see here, no retail. Assuming no retail. Yeah, assuming no retail, no CAMMESA during the winter, 10 to our plants, 3 to our urea plant, 6 to our floating energy. 10 is assuming all the plants.
CCGT is only 8, which is the baseline. Right. Guru also asked a very good question: Once we reach this peak, how long can we sustain it at the plateau? And what will be required CAPEX to sustain at that level? It's a very good question because we have a lot of gas. So assuming 22... 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 years of average life.
This is only 2P, not even including the 3P, the resources, and so on. How much required CAPEX? Well, if we're doing the math and assuming the average well type of our shale gas blocks is around 250 to 300 million, and obviously considering also the CAPEX to maintain the treatment plants, it's around 250 to $300 million of CAPEX per year. Okay, can you talk about the funding strategy of urea? We talked about it, right? The funding of urea project.
The strategy we talked about. Yeah, yeah. Well, it's what Lida presented on the one side: to monetize our gas reserves, which is a perfect fit. On the other hand, urea business per se, which as Lida explained, the region needs a lot of urea and it is coming from far away regions, very unstable regions. So it makes total sense to reduce logistics cost and procure ourselves our own urea for the region and not depend on wars or geopolitical risks. The third opportunity is the RIGI framework, which makes this project possible.
And the fourth, I will say, opportunity is our balance sheet. We have a lot of cash and low leverage. We've always been asked why we have so much cash, and one of the reasons is for this. We were waiting for opportunities like these ones to show, and we are ready to deploy the cash. We are not afraid to use our balance sheet that is very unleveraged and take these, grab these opportunities and profit from them. So these are the four main angles of the project.
UNKNOWN, Pampa Energia IR
Well, actually, it's not a bad timing to just say this. It's 100% owned by Pampa. Yeah, right. Bruno is also asking about the debt. Can you share something about the tenor, the interest cost?
UNKNOWN, Pampa Energia executive
Well, I cannot say about the interest cost yet. We are negotiating, but what we can say, which is pretty obvious, is given there is a project finance, we will have a spread over our bonds, for example, so we will see finally where we land the cost, but we cannot foresee that for sure. Most likely the profile will be four years' grace period while we build the plant, and the maturity, I cannot... it is not closed, but it will be closer to seven. Seven years or something like that, give or take.
Well, the last question, Bruno, is about lifting costs of oil. Obviously, can you expect a normalization following the recent increase driven by the new TPF? Well, 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 to avoid frac hit in the fracking of other pads. But now that everything is fracked, everything is done. We can connect all the pads and resume the choked ones and connect the new ones.
So right now we expect an exit rate of lifting costs of around $10 per barrel with the two TPFs. But once the CPF is online, and also considering the fact that the production will ramp up, we are expecting $5 by second quarter of next year because we expect the CPF to be ready by first quarter of next year. Alejandro Christensen from Latin Securities, he's asking how should we think about the shale gas lifting costs over the next year, and with CESA 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 $0.80. We are on an average year of $0.80 to $0.90 per million BTU. But if we are only producing flat volumes, it could go a little bit lower, but not more than $0.60–$0.70. We'll see. Today it is highly seasonal. It's becoming more... we are flooding more the curve, but still highly seasonal.
So, and 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. The RIGI — only new drilled wells will enter the RIGI.
So all these wells that Lee explained, the 10 wells that we were fracking and are completing now, they're not in the RIGI project. They are from before. So 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 — yeah, it's a technical thing — not to have the parent-child effect. So we closed some wells to frack another and they don't destroy each other. That was the reason. It has nothing to do, as that report stated, that we held back the completion of the wells.
Having said that, the north part... the north part, yeah, we had some seismic works before when we started with Rincón de Aranda, but now we are going in September — yeah, next month actually — we are going to start more comprehensive seismic studies in that area and do more detailed work there. According to — well, Horacio didn't join us today because he's in vacations, but the team already let us know that they're working in the north part. The north is at the boundary of Vaca Muerta, so 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. But once those seismic works are done and all the studies are detailed and through, we think that we could start drilling there in next 2028, end of '27. But so far we're concentrating on the south strip, where most of the well inventory is located. On the Perito Moreno expansion, which specific units do you expect to benefit from FRA1?
We already talked about it, but if we get awarded in the second tranche, we can use it for the peakers in Buenos Aires bound tranche, which is Pilar. White is for the Bahía Blanca PP. So the peakers will be used but only seasonally-wise, not year-flat. The one that is consistent the whole year is the legacy. How much of their dispatch could cover the already awarded? The whole legacy CCGT and a little bit more. So the rest we can use it for specific days, for trading at City Gate for trading of gas at Buenos Aires, or a little bit to be used in the peakers.
We'll see, specifically in the winter season. Beyond the transportation prepayment, will any additional CapEx be required for other plants? No, no. It's just what it is. Will 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 CCGTs and maximize dispatch? Actually, the Plan Gas now in this quarter is the proof of that. Transferring the Plan Gas volumes to ourselves is better, right?
Because if we didn't transfer the Plan Gas, we would be billing at four and a half; now we are billing at higher price because Cammesa allows a higher pass-through. So, I will say, average-wise it must be better than Plan Gas's average price. And then we'll see. I think the CCGTs have the most competitive advantage against all other units — all other peers and in our own portfolio. They will pass through whatever Cammesa is allowing, so that's how they are going to maximize the dispatch.
I think what your question is referring to is to the peakers, and that depends on Safra. Asked about the potential unlock in Rincón de Aranda with the north part; we already answered it. Expectation for another project this year and next year; we already answered it. Right? Yeah, 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.
UNKNOWN, Pampa Energia IR
From Mario, also asked about the financing of Urea — already answered. Alvaro Leva from BTG is asking the same — already answered. CapEx deployment about Urea project — we already answered. 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?
UNKNOWN, Pampa Energia executive
No, no, we won't. I think we answered this in the previous call, that the idea is to keep this level of hedge and naturally as production increases we will have a big portion unhedged, so we keep current production hedged and whatever comes on top of that will remain unhedged. So that was the original strategy — to hedge the ramp-up until the 45,000 barrels — and this is what we're doing. So 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.
Kataruzi from ADCAP asked about petrochemicals — we already answered — and he also asked about the target gas production long term — we already answered. Mileni from Carvalho from JP Morgan — well, all question and answer. From Urea, she asked about EBITDA contribution from Urea — answer: price, the gas price for urea — answer: $3 per MMBtu, the same as FLNG project, right? How much gas is required? Answer. Incremental CapEx for E&P for this: three and a half assuming that it's additional.
I did the math and it's not much. It's like, should we fund them? It's $100 million of CapEx, EBITDA $90 million of EBITDA, $90 million, and look, less than 50 of additional CapEx for the 20 million production. We are calculating a maintenance CapEx of $250 to $300 million. Yeah, that's the range. Balance. Andre Serano asking about the CapEx phasing of Urea — answer. I'm saying this because we want to be clear. Transfer — yeah, transparent. Yeah.
Puente — Juan Lopez. Okay, Juan Ignacio Lopez from Puente, he's asking: we are seeing a better price 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, to deregulation or increased pressure in the domestic market for high international prices. How do you expect this dynamic to evolve over the coming quarters? So yes, it's true.
Now Cammesa's during the winter pass-through, they are linked or associated with the international prices of LNG. That's why we can pass through higher prices. But also the resolution 400 contemplates this deregulation and the procurement of the gas. Remember that before it was all centralized at Cammesa and now it's more and more decentralized. Just to give you an idea, Cammesa used to be procuring the whole gas in the whole grid; now it's doing it one third actively — roughly numbers.
Another one fourth 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-gas acuerdo, and then the one fourth, which mostly is ours, is self-procured gas from power plants, which is our case. The idea of Cammesa is going more and more to the assisted scheme, but when Plan Gas is rolled out — and the idea is not to re-engage it — it's just all procured by the power generators. Sophia Grand — I don't know who she is — but basically she's asking: the Cammesa percentage — 26k Gas Sales, Gas sales — have any of these contracts or volume been transferred to the power company or self-management to supply? I understood that. Ah, well, this is what we can transfer. We couldn't transfer more of this because the one contract outstanding to transfer is Inara, the last round of Plan Gas. Okay, the 4.2 round minus the last round of Plan Gas, which is around 5 million cubic meters per day, with peaks during the winter — that one hasn't been transferred yet.
So as you can see, we still — that's why we still are selling to Plan Gas, specifically to Cammesa and retailers — 56%. But for example, in Q4 it should go down dramatically because Cammesa and retailers won't demand much gas due to seasonal reasons. Matthew Boots from Fidelity — he asked about the equity and debt structure for Urea Plant — we already answered. Again, we're not trying to maximize the leverage on the project because the idea is to deploy our cash and future cash flows into this.
That's why we're not having any partners and that's why we're not maximizing the leverage, so we expect a structure of around 60/40 — 60 debt and 40 equity — giving you — that will give you around... still, everything is under negotiations, but we are expecting around $1.4 billion of equity in the next 41 months can Walter Garvezio from Santander — he's asking repeated questions, but he's asking about the gas production until 2030 breakdown. We already discussed that. Andre Cardona from Citi — actually he's asking, when looking at the diversified portfolio, is there any asset you consider non-core and could eventually be divested? This question I think was answered when I explained our core businesses, so it's self-explanatory, which is petrochemicals. Ramiro Guerrero — bull market: how much volume of Rincon de Aranda remains hedged through May 2027, at what weighted average price, and what additional cash collateral settlement and cash outflow should we expect under different Brent scenarios? So how much is hedged from our production? That's the first question. Until when we… …hedge all our production until next first quarter of next year. Until May, until June — first quarter. No, no, but first quarter, first quarter — a little bit less than… …one year of hedge. Yeah. Weighted average price: 67.6667 of Brent. Yeah. What additional cash collateral should we expect? I don't know — different Brent scenarios, right. Today it's 80, so with the price you can see how much it is. Depends on the mark-to-market positions. Ricardo Cabana — 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. One sentence — in one sentence, yeah, because it's 12 pm, so. One sentence: growth. Yeah. We are 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, i.e., power, urea, LNG, etc. I would say that is the two main headliners — that it is an Argentinian company that invests heavily in Argentina and it's an industrial energy company, integrated energy company — that is the tweet, the headline.
From Rosenthal in Merciones — he's asking on the receivables. You mentioned working capital seasonality, but receivables still increase significantly in this quarter. And where are the key drags on operating cash flow? Very good question. Why the increase? Because we are selling more gas compared to last year. Q2 we are selling 2 million more of gas. Prices — higher prices. So here you have it. We are selling more oil — three times more oil than last year — and 22% more than last quarter.
And part of the gas will revert — this working capital will revert in the following quarters. Yeah, correct. And we sell it now; we collect it 45 days later. This is very important. Previous quarters and previous year the days of sales outstanding was way higher. And now we are at five days of delay, so it means 47 days of total collection days, while last quarter was 50-something. And previous year was way higher because it was accommodating. So DSO is improving, specifically from our largest clients, which is Cammesa and Arsa.
But at the same time we are selling more. Twelve days delay — so 12 on top of the 42, so it's 54. Matt, Matt, Matt. Then could you please understand — well, what was it mainly export time? No, export is flat. It's 65 days. There is no increase or decrease. It's very certain. I'm segmentizing about the receivables and Cammesa or subsidy-related balances. How about the Cammesa? Cammesa is paying better. Yeah, better. No major delays. Yeah, subsidy is 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. So now it's just $15 million per year or something. And should we expect this to normalize in the second half, or is it a new structural level as exports continue to grow? Exports — forget it. The receivables of exports — it's the same. We are exporting the same.
But wait — Q3 we are going to collect what we sell in Q2, obviously winter prices. But Q3 is higher winter prices and higher sales, so you should expect higher receivables. But in Q4, usually we collect the receivables; it's a surplus. It's an inflow, not an outflow. That's how you should think about it. Liliana Yam from HSBC — a quick update on TGS. Gracias. Well, they have their call already. Yeah, they have a… But I think that the two main takeouts are the two big projects TGS is performing. One is the Iniciativa Privada that should be commissioned by next winter. And the other is the big NGL project. As you know, they already announced the FID, and they're working heavily on the financing, and they're awaiting the RIGI approval of that project. I think those are the two main drivers. Yeah, main news about TGS, and if you look at the results, they were outstanding.
They improved every line of business. Utilities price is a very encouraging company. I mean, doing well. One — on 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… No. We filed for both. We filed for the RIGI — we have been approved by the committee — we're waiting for the publication of the approval in the Official Gazette. And we also applied to the provincial regime, and we're waiting approval, and there is no conflict at all.
On the contrary, they're quite… Proactive. Yeah, yeah. Complementary. Thank you. They're quite complementary. The additional benefit from the provincial is a tax break on the gross sales tax. Gross sales tax — yeah. That's the main takeout. So hopefully we get that approval as well. Yeah, we talked about this. RIGI is pre-approved. Yeah, yeah, yeah, yeah. But there is no conflict between the two. On the contrary.
UNKNOWN, Pampa Energia IR
Great. All right. Thank you everybody for joining us on this call. Thank you, Fito, for taking other questions. Fito, would you like something more — say something more?
UNKNOWN, Pampa Energia executive
One hour. Perfect. Perfect. Thank you very much.
UNKNOWN, Pampa Energia IR
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.
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