Pampa Energía S.A. (PAMP) Earnings Call Transcript & Summary

Thank you for waiting. I'm Raquel Cardasz from IR, and we would like to welcome everybody to Pampa Energia's Second Quarter of 2026 Results Video Conference. We would like to inform you that this event is being recorded. [Operator Instructions] Before continuing, please read the disclaimer on the second page of our presentation. Let me mention that forward-looking statements are based on Pampa Energia's management beliefs and assumptions and information currently available to the company. They involve risks, uncertainties and assumptions because they are related to future events that may or may not occur. Investors should understand that general economic and industry conditions and other operating factors could also affect the future results of Pampa Energia and could cause results to differ materially from those expressed in such forward-looking statements. Now I will turn the video conference to Lida.

Hello, 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&A. Today, we have only our CFO. We have a small inconvenience with Gustavo, but I think we both can do it, right? Yes. So let me go to the 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'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 is the natural gas, urea production is highly concentrated in a few countries, while Argentina and its neighbor countries currently rely on imports from distant regions today exposed to significant geopolitical uncertainty. The investment thesis is straightforward. It's just we aim to monetize the best shale gas reserves that Pampa holds in Vaca Muerta through the development of high value-added businesses. Natural gas and electricity account for approximately 70% of the production cost of urea and will be supplied by Pampa, reinforcing the competitive advantages of our vertically integrated business model while enhancing the project's operating efficiency and long-term profitability. So beyond diversifying Pampa's revenue base, the fertilizer business will also help Argentina's foreign currency generation through import substitution. We are substituting imports and increasing exports with an annual contribution of approximately $1 billion. Brazil, which currently imports between 7 million and 8 million tonnes of urea per year, together with the rest of the Southern Cone, which has an annual deficit of about 2 million tonnes, will be the project's primary market. Moving on to the project details. The plant will be located in Bahia Blanca, on a proprietary site, strategically positioned next to the Argentina's -- one of Argentina's main export ports, Bahia Blanca, with direct connection to Vaca Muerta pipelines, feeding pipelines and close to Pampa's thermal and renewable power generation assets. This is a $2.7 billion investment to build, on a turnkey basis, a 2.1 million tonne per annum plant, consuming 3.3 million cubic meters per day average year and 75 megawatts of power, again, supplied by Pampa. The plant is scheduled to be completed by the end of 2029. Now that we have reached the FID, so the next milestones are obtaining the RIGI and the Buenos Aires RIGI approvals, which are essential to the development of the project. Last Friday, the evaluation committee of the RIGI cleared Fertil Pampa's presentation. So we are waiting for the formal approval to be published in the official gazette. Thus Pampa continues to strengthen its industrial profile further through the several projects presented under the RIGI framework. You see, we are currently participating in 7 projects across oil, gas, midstream, LNG, fertilizers, NGLs. Last June, following the FID at TGS, our affiliate filed an application for the $3 billion investment in an integrated NGL project. Also TGS's private initiative, which consists in expanding the Perito Moreno pipeline, the San Matias dedicated pipeline for the LNG project and Rincon de Aranda. All those RIGI applications got approved. Overall, these projects provide a clear road map for Pampa's long-term growth, supporting Argentina's export expansion and enable 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 our quarterly all-time high production of 107,500 barrels of oil equivalent per day due to the sustained ramp-up at Rincon de Aranda and gas self-supply. The new regulatory framework also had a positive impact on our Power Generation segment, which benefited from the strong spot margins and as high fuel costs impact and drove the marginal cost up of the system. So that helped. And also, we have more B2B PPA sales. To the lesser extent, increase in international prices also boosts the petchem business, which recorded its highest quarterly EBITDA since 2023, 3 years ago. Quarter-on-quarter, EBITDA grew 28%, supported by gas seasonality, stronger spot power margins and increased petchem prices. So CapEx dropped 21% year-on-year to $279 million during the quarter, of which $165 million were destined to Rincon de Aranda. It is worth noting that we already invested last year $900 million in Rincon 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. So moving on to the Slide 7. The Oil and Gas adjusted EBITDA was $182 million, more than double last year, driven again by Rincon 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 increase. These factors were partially offset by lower realized crude oil prices due to the hedge. Quarter-on-quarter, EBITDA increased by 74%. This is mainly explained by gas seasonality. Total lifting costs grew 30% year-on-year. This is primarily driven by Rincon de Aranda ramp-up, partially offset by the divestment at El Tordillo and lower activity at El Mangrullo gas block. Cost per BOE, however, remained broadly flat at $7.7 on average as production growth offset the increase in lifting costs. If we do double-click, oil lifting cost per barrel actually declined 28% to $15 in Q2. However, it increased quarter-on-quarter following the commissioning of the second EPF at Rincon de Aranda that increased the treatment, the crude oil treatment from 20,000 barrels to 28,000 barrels per day. Gas lifting costs also decreased 13% year-on-year to $1 per million BTU, but slightly decreased 6% sequentially due to the maintenance cost at El Mangrullo. So focusing on crude oil only, production increased 3x year-on-year, purely explained by Rincon 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. Rincon de Aranda contributed 1/3 of oil and gas EBITDA, up from 6% last year. So last year was only 6% and this year is 1/3, this year's quarter. This is continuing to diversify the production mix, now oil accounting 22% of the total output. At Rincon de Aranda, the ramp-up continues. As you can see, the performance is comparable to the best blocks in the core hub, reaching a new record of 27,000 barrels per day of May 21 actually, specifically. Since March, we have not tied in new wells, just producing from 43 wells. Even so Rincon de Aranda averaged 22,000 barrels per day, up 22% quarter-on-quarter. The quarter's exit rate was 16,000 barrels, temporarily affected by chokes on certain wells while we completed other neighboring pads, so we avoid the frac hit. These 10 wells in said pads -- said 2 pads were completed in July and will be tied in, in August, now, which will support a rebound in production. In Q2, we also drilled another 10 wells from -- for 2 pads. Currently, we have 2 high-spec rigs and 1 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 plateau, production plateau of 45,000 barrels per day once the CPF and the Vaca Muerta oil pipeline are online next year. Regarding RIGI, well, as we said previously, the application was formally approved on July 21 as long-term strategic export projects. The application includes the drilling and completion of 259 wells for now from July 21 on and the construction of the CPF, we are already building oil and gas pipelines and water treatment plants facilities to treat the flowback, the water flowback. 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 Rincon de Aranda, providing a stable framework for tax, customs and FX incentives for 30 years. Long-term strategic export projects are also eligible for specific benefits, in particular, the exemption, the waiver on export duties starting in the second year of operation after the enrollment. In this sense, Pampa expects to export all of Rincon de Aranda's production through 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 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 pipelines -- gas pipelines. During Q2, we tied in 4 new wells at Sierra Chata, bringing production to a new all-time high. At El Mangrullo, there were no new development activity with production supported by the existing well base. At Rio Neuquen, 4 new tie gas wells were drilled and 2 were connected. For the second half of the year, we -- our plan includes drilling activity in Sierra Chata and El Mangrullo. This is aligned with our 2027 activity production plan, which considers the recently awarded transportation capacity at Perito Moreno pipeline in which gas transported through new infrastructure is able to capture the full margin -- the full spot margin. In Q2, 56% of our gas was sold under Plan Gas GSA through CAMMESA and retailers, down from the 80% last year following the transfer of the 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 prioritize self-supply demand and which is priced at a higher price because of the higher pass-through allowed by CAMMESA. This is seasonal. And the regulation guidelines. Gas prices averaged $4.6 per million BTU. This is 15% higher than last year. This is reflecting fuel -- 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 Energia Plus contracts, the outage of Loma La Lata's gas turbine #4 that is under a PPA, which is remunerated under the PPA and the PPA wind farm's underperformance. As you know, the new guidelines we introduced marginal costs as part of the spot pricing methodology, which that marginal cost overshot during the quarter, especially during the winter season, reflecting higher fuel prices, in particular, using LNG and liquid fuel oil, diesel oil. 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're using new infrastructure such as a gas pipeline, which that's the case for Perito Moreno pipeline that will be online next May 2027. This full margin thing is not only benefiting power generation, it's also benefiting E&P, which will be producing more gas that now has security to be transported for this Perito Moreno expansion. So full capture of this FRA, that the FRA equals to 1 instead of 15%. Pampa was awarded 3.2 million cubic meters per day in the Buenos Aires bound tranche. So it goes to -- it will be used to procure the gas needs of the legacy Genelba CCGT, right? And we are -- we also participate in the second tender for the remainder of the Perito Moreno. We are waiting for the results. If the regulator grants the clearance, we should add another 0.7 million cubic meters per day to the Buenos Aires tranche, plus another 1.3 million cubic meters per day in the Bahia Blanca tranche. Total availability fell to 88% during the quarter, mainly due to the ongoing outage in [indiscernible] which now is -- currently since July 31st is no longer part of Pampa. And we had some outages also in Guemes and in the mentioned Loma La Lata TG #4. Barragan also has some scheduled maintenance. Even though it's 88% availability, we continued to outperform the peers in the national grid. 35% of the capacity was contracted, slightly higher than Q2 last year. This is reflecting the new guidelines that boosted the B2B PPAs. 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 Rincon de Aranda and receivables due to the better collection, though this is impacted by higher winter sales. Quarter-on-quarter improvement is explained by the release of collateral on our Brent hedge as oil prices declined. As a result, cash and cash equivalents stood at $1.3 billion at the quarter end, $604 million more than Q1. Finally, on the balance sheet, gross debt as of June was $2.6 billion. This is mainly because of the retap of 2037 notes priced at the lowest spread to the T-bills, U.S. T-bills in Pampa's debt issuance history and corporate history, I must say, Argentine corporate history. Net debt rose to $1.3 billion, representing a net leverage of 1.4x to the last 12 months' EBITDA. So it concludes now this presentation. The floor is open for questions.

If you have a question, please send it through the Zoom chat. If you have -- we will read it first in, the first receives, first served. Make sure your name and your company is there. Otherwise we can't just read it, and so we can also introduce you the audience. Should any participant have assistance, just send us a chat through the platform. Thank you. Wait for -- while we poll for questions. Should we start? With the new expansion projects that -- Alejandro Demichelis from Jefferies is asking, do you see -- what do you -- how do you see CapEx in the next 2 to 3 years? At what level do you expect debt to leverage to peak?

Thank you for the question. Yes, evidently, we're facing challenging CapEx deployment, especially with urea project. But also bear in mind that EBITDA looking forward should increase as well, right, once we achieve maturity of the Rincon de Aranda investment and the Southern Energy and San Matias pipeline investments by 2028, cash flow generation will be increasing and stable. So what we foresee is that net leverage should increase from current levels up to a maximum of around 2x. And this -- and the ratio should vary between 1.5 and 2x for the next 2 to 3 years until we finish the investment in the urea project.

Right. But the CapEx this year is basically is around $1 billion, right?

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

A little bit lower.

Yes, it's lower separating urea project, it will be around $700 million CapEx next year, again, mainly Rincon de Aranda project. And after that, Pampa, 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 Fertil Pampa, yes.

[Indiscernible] they're asking, after this '23, jump in EBITDA for the first half of '26, how do you expect to evolve the second half and '27 on power generation? And considering in '27 that the second half starts rolling -- starts rolling out the PPAs, we want to know.

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

And power demand.

And power demand. Bear that in mind, always the last quarter is a little bit weaker. But it will be partially offset by the increase in the production of Rincon de Aranda. So the oil business will keep growing, but remember, the seasonality in the other segments.

Well, 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 is...

Q4 always is.

Yes, yes. So first half is $299 million of EBITDA. We expect $600 million for this year. Yes, a little bit -- yes, $600 million for this year. So basically, it jumps up in Q3 if winter allows and then goes down and specifically because El Nino, right, there's more water. So it means lesser thermal power demand. So in '27, it's -- yes, it's a combination. Second half starts rolling out PPAs, but we also have the TGS' private initiative that, hello, we have 3.2 million confirmed that we will inject it through Genelba's legacy CCGT. That -- and actually, it's going to start before the winter. 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 million, 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, it goes down. So it's a combination that in '27, the PPAs rollout doesn't much reflect because it's towards the end of the year. But in '28, you should see that it's a little bit lower. It's $40 million less because the PPAs rollout, but at the same time, they join the spot market. Loma La Lata, out of the PPAs that roll out, 2 of them are at Loma La Lata. Loma La Lata is highly competitive because it doesn't require any gas transportation. So they -- and they are a very efficient machine. So they kind of rank senior among the thermal units in the system. I hope that explains -- answers the question. How do you expect to increase the stake of gas used and sold to power generation since we noticed an increase from 3% to 31% year-on-year basis? Well, basically, as I said in the call, we -- the average of this year is around 40%. It will pick up -- it should pick up in Q3. And actually, it peaks more -- it's highly reliant on self-supply on Q4, even though the 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 Barragan. 10 million cubic meters per day, of which 8 goes to the CCGTs, 8 Loma La Lata CCGT and the 2 CCGTs at Genelba. So the CCGTs are the flat consumption of gas for self-supply. That's what you should expect going forward. Third question from [indiscernible] people. How do you expect petrochemical business to evolve in the future, considering the 5% contribution to the consolidated EBITDA this quarter when it usually is negative or slightly or breakeven, what it is, right?

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

Yes. It was something like circumstantial.

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

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

Yes, 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. In that -- with that in view, we started in February a very thorough due diligence. So we've been working in 6 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 final -- to 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's a big, big spike of -- the CapEx is concentrated mainly on 2028. I will say 1/3 of the CapEx is on 2028 and the rest is evenly distributed on the remaining years. So I will think that we start contributing capital to the project this year. The financing will be closed by the last quarter of the year, probably. And the big contributions, both of debt and capital, will be on 2028. I think that covers the question.

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

Yes. Well, the revenues, I think we already disclosed that on, where?

1 billion. Yes, yes, 1 billion.

Yes, 1 billion. So the math is pretty simple, is depending on the price of urea you take, but you multiply 2.1 million tonnes 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. And again you have to factor in the price and the netbacks, whether you sell to Brazil or to Argentina or what combination, but those are the big numbers that you can easily compute. And what was the rest of the question?

No, how much impact on Pampa's E&P and power? Very good question.

Very good question. Yes. 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.

Assuming.

Assuming it's around -- if 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 3 years.

The price is around $3.

The price is $3.

$3 is our internal GSA.

Internal GSA, yes. Consumption is 3.3 on average, year average.

Yes, it picks up in winter.

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.

We will.

And again, the power contribution is marginal.

Marginal.

The big contribution here is gas.

Yes. But imagine like -- well, today, we are selling B2B PPAs at 65 monomic price, right? This is considering capacity, $65 to $70. Well, we were talking about the B2B PPAs boost in this quarter, basically because people are seeing the prices in the spot. If you go to the spot, the prices are really high. That's why when this deregulation started, the industrials didn't start to get into the B2B market. And now they're getting into because they seem highly seasonal that are 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.

Yes, it's around $68 and the consumption is 77 megawatts hours. But again, it will be additional energy capacity rather than replacement of.

I imagine myself using our renewable wind power.

That's the plan, yes.

Yes. And backup with our thermal.

Exactly.

Yes. Well, another question from [ Hilaria ] people saying, considering the current production levels at Rincon 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?

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

Well, Bruno Montanari from Morgan Stanley. He asks, how can we think about Pampa's long-term peak gas production, considering the volumes to CESA to the project, the self-procurement for power generation?

So -- yes.

Well, that's flat actually.

Yes. So what we foresee, and this is not a projection. It's not a projection. It's a budget, if you like. Imagine that we can procure to our own power business around 10, 10.5 million cubic meters of gas per day, another 3.5 million to our urea plant, another 6 million to the floating LNG to CESA to floating energy project.

1.5 for exports.

1.5 for exports, you would add up.

A little bit, during the peak is around 20.

So it's around 20 million -- between 20 million and 22.

Peak.

Peak.

Peak. Flat is -- average is 20 million.

Yes. So it's around 20 million cubic meters of gas per day. Quite constant because we are selling intercompany. So we avoid the seasonality. But yes, that is what we foresee for the next -- in the next 3 to 4 years when all our projects are online.

So as you can see here, no retail, assuming no retail.

Yes, assuming no retail.

No CAMMESA power source contention during the winter.

Yes, it's 10 to our plants, 3 to our urea plant, 6 to our floating energy plant.

Yes, 10 is assuming all the plants.

Yes.

CCGTs only is 8.

Yes.

Which is the baseline, right?

Yes.

Bruno also asked a very good question, how much -- once we reach this peak, how can we -- 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 it very conservative, assuming 20 million cubic meters per day of annual production and with the current -- not saying resources, but 2P reserves is around securely 25 years of average life. This is only 2P, not even including the 3P, yes, the resources and so on. How much required CapEx? Well, if we're doing the math and assuming the average well type of our shale gas blocks is around $250 million to $300 million -- and obviously, considering also the CapEx to maintain the treatment plants, it's around $250 million to $300 million of CapEx per year. Okay. Can you talk about the funding strategy of urea? We talk about it, right? The funding of urea project, the strategy, we talk about it. Yes.

Yes. Well, it's what Lida presented. On the one side is to monetize our gas reserves, which is a perfect fit. On the other hand, urea business per se, which, as Lida explained, the region needs a lot of urea and it's coming from 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 don't depends 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're 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 4 main angles of the project.

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

Yes.

Bruno is also asking, well, about the debt, can you share something about the tenor, interest costs?

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

Well, the last question on Bruno is about lifting cost of oil, obviously. Can you expect a normalization following the recent increase driven by the new TPFs? Actually, well, 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 choke some wells, so we avoid frac hit in the fracking of other pads. But now that everything is fracked, everything, it's done, we can connect all the pads and resume the choke ones and connect the new ones, right? So right now, we expect an exit rate of lifting cost of around $10 per barrel with the 2 TPFs. But once the TPF is online and also considering the fact that the production will ramp up, we're 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 cost 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, this is -- it is highly seasonal. It's becoming more -- we are flatting 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 Rincon de Aranda? And what are your initial expectations for the productivity there?

It's a good point. I would like to clarify something because we read a report stating that we were closing wells and holding back the completion of wells for the RIGI approval. And I want to clarify, this is not the case, okay? The RIGI, only new drill wells will enter the RIGI. So all these wells that we were -- that we explained, the 10 wells that we were fracking and are completing now, they are not in the RIGI project. They are from before, okay? 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...

Not to complicate.