Pampa Energía S.A. (PAM) Q1 2026 Earnings Report, Transcript and Summary

We would like to welcome everyone to Pampa Energia's First 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 to Lida. Thank you, Lida.

Thank you, Raquel. Hello, everyone, and thank you for joining us. I will make a quick summary, so we can spend more time on the Q&A with the senior management. Today, we have our CEO, Mr. Gustavo Mariani; our Head of Oil and Gas, Mr. Horacio Turri; and our CFO, Mr. Adolfo Zuberbuhler. In Q1, production exceeded 100,000 barrels of oil equivalent per day, reaching a new quarterly all-time high, driven by the sustained ramp-up at Rincon de Aranda and higher gas output under the new power generation framework. Rincon de Aranda, which began ramping up a year ago, is now producing approximately 25,000 barrels of oil per day as of today. With the new regulatory framework, we also had a positive impact on our Power Generation segment as our non-PPA CCGTs benefited from stronger spot margins, dispatch margins. Also leveraging our solid balance sheet, in April, we successfully issued $200 million in 3-year bullet notes at a highly competitive rate of 5.49 fixed rate. Adjusted EBITDA amounted to $325 million. This is 48% up year-on-year. As mentioned before, Rincon de Aranda gas operations and power generation were the main contributors. Rincon de Aranda alone represented 17% of the quarter's total EBITDA, increasing 8x versus Q1 last year. Quarter-on-quarter, EBITDA grew 41%, supported by synergies between gas and power businesses as Loma De La Lata and Genelba CCGTs self-supply gas for thermal dispatch, enhancing spot margins. The CapEx rose 36% year-on-year to $242 million during the quarter, of which $163 million were invested in the development of Rincon de Aranda. Moving on to Slide 4. The Oil and Gas adjusted EBITDA was $104 million in Q1, 2.5x last year, driven by Rincon de Aranda, higher gas production for self supply to our thermal power plants, exports and industrial demand. These factors were partially offset by lower realized crude oil prices and higher royalties, transport and treatment costs associated with the production growth. Rincon de Aranda contributed 54% of the segment's EBITDA in this quarter, up from the 15% last year. Quarter-on-quarter, EBITDA increased by 36%, mainly due to higher gas demand for CCGT self-supply and exports to Chile. As we mentioned before, total production averaged more than 100,000 barrels equivalent per day, primarily contributed by Rincon de Aranda and Sierra Chata, partially offset by lower output from our non-operated blocks and in El Mangrullo. The production mix continued to diversify with oil accounting for 19% of total production, entirely driven by Rincon de Aranda. Lifting costs averaged $6.1 per BOE. This is down 11% last year and 23% sequentially, explained by higher oil and gas output outpacing a stable cost base and the divestment of mature non-operating – non-operated oil assets. Gas lifting costs decreased 10% year-on-year to $0.90 per million Btu and 23% quarter-on-quarter lower. This is supported by higher gas output. Oil lifting costs declined sharply to below $10 per barrel from $41 in Q1 last year, thanks again to Rincon de Aranda's ramp-up and the divestment of mature fields. Focusing on crude oil, output multiplied by 6 year-on-year to 19,500 barrels per day as Rincon de Aranda ramp up following the commissioning of the Duplicar trunk pipeline last year's April. Realized prices averaged $58 per barrel in Q1. This is 15% lower than last year due to the oil hedge. Without the hedge, realized prices will have been more than $69 per barrel, resulting in approximately $21 million of additional revenue. Exports accounted for 55% of total volumes sold in Q1. At Rincon de Aranda, the ramp-up continues to progress as planned. Average production during Q1 reached 18,200 barrels per day across 43 producing wells, up 7% quarter-on-quarter. In Q1 last year, production was below 1,000 barrels per day. During Q1 this year, 6 wells were drilled and 15 wells were tied in, of which 7 came online last March, bringing the quarter's exit rate to more than 21,000 barrels per day. For the remainder of the year, we expect to tie in an additional 20 wells and reach 28,000 barrels per day milestone by mid this year, mid-2026, supported by the second temporary facility that was commissioned in late March. We target a production plateau of 45,000 barrels per day once the central processing facility and the Vaca Muerta Oil Sur pipeline are online. It is worth noting that Rincon de Aranda completed its first full-year of operations with clear efficiency gains already visible. Drilling performance improved from 200 meters per day on the first pad last year to nearly 330 meters per day on the most recent pad. This is more than a 50% improvement. Completion activity also improved from almost 7 to 9 stages per day, an increase of over 30%. This improvement reflects the team's consistent execution and shorter cycle times across the development program. Also, on March 9, we submitted the project's application to the RIGI incentive program, which is expected to accelerate the development in the northern area of Rincon de Aranda support a fast ramp-up and sustain plateau production for a longer period. The estimated investment under the project amounts to $4.5 billion, including new shale oil wells and associated infrastructure. Approval remains pending. Moving on to the gas. Production grew 17% year-on-year and 28% from Q4 to almost 14 million cubic meters per day, driven by gas sales supply to our CCGTs under the new power market framework, higher exports to Chile and stronger industrial demand. Exported volumes increased 65% year-on-year from 900,000 cubic meters per day to 1.5 million, yes. We expect these levels to continue throughout the remainder of the year. El Mangrullo and Sierra Chata, our 2 operated blocks accounted for 88% of the total gas production. No new wells were connected during the Q1, although a new path tied in during the Q4 at Sierra Chata explains the 70% % year-on-year growth, while El Mangrullo just dropped slightly 7%. During the quarter, Sierra Chata drilled 3 new wells, so completed the 4-well DUC pad. For the second half of the year, the plan includes drilling 2 additional pads and tie in 1 pad before the winter aligned with the seasonal gas demand from our power generation business. At El Mangrullo, the plan is just to drill a 6-well pad, which will remain as a DUC inventory. Gas prices averaged $2.9 per million BTU, flat year-on-year due to the lower export prices, offset by higher retail prices as tariffs increased above peso devaluation. In Q1, 47% of our gas was sold under planned gas GSAs through CE and retailers, down from the 82% exposure last year following the transfer of set GSAs to our CCGTs. As a result, Interco consumption -- actually intersegment consumption increased to 32% of total sales compared to just a marginal 2% last year. Under the new framework, we expect approximately 40% this year's production to supply our own power generation assets. As for power generation in the Slide 7, we posted adjusted EBITDA of $144 million in Q1. This is 11% year-on-year and 30% quarter-on-quarter increase, mainly driven by stronger spot margins at our CCGTs under the new guidelines in the wholesale electricity market, which operates under a marginal pricing system that benefit efficient units. Total availability fell, though to 90%, mainly due to the ongoing outages in Willes [] since January last year and the outage that we had in the gas turbine #4 in Loma De La Lata. This is not a CCGT, which is expected to return in service in next month in June and a scheduled maintenance at Barragan. However, Pampa's thermal availability continues to outperform the peers in the national grid, as you can see in the chart. In addition, 32% of our installed capacity was contracted in the B2B market, whether it's PPAs with CAMMESA or in the maps, covering the levels before the implementation of the framework. Regarding the expansion of the Perito Moreno gas pipeline and its final sections toward Buenos Aires Metro area, on April 15, TGS awarded the tender's first tranche corresponding to 4.8 million cubic meters per day out of the 12 meters per day of expansion in the transportation capacity. This is 40% of the expansion. Pampa secured 3.2 million cubic meters per day, representing 27% of the expansion capacity and 2/3 of the first tranche tender. The transportation contract is for 35 years under take-or-pay or in this context, it is cheap or pay and requires prepayment of the first 15 years of tariffs, which in our case, amounted to approximately $330 million VAT included, payable in 4 installments with final maturity in next year, April. The expansion is expected to begin operations during the winter of 2027. Participation in this gas pipeline expansion is underpinned by a clear economic rationale Under the new power market framework, electricity generated using gas transported through new infrastructure such as the Perito Moreno and its final sections expansion captures the full dispatch margin when sold in the spot market with an FRA of PAA equal to 1. Therefore, a new deregulation guidelines creates 2 key drivers of profitability for Pampa. We secure additional transportation capacity for additional gas produced from our upstream operations for self supply, enable further modernization of our reserves. Second, it enhances the profitability of our power generation assets, particularly our CCGTs. Turning on to the cash flow on Page 8. We show the parent company figures aligned with the bond perimeter. Free cash flow was negative $404 million in the Q1, explained by collateral requirements related to the oil hedge, intensive CapEx at Rincon de Aranda. On top of that, we have the payments associated with last year's CapEx and a slightly higher days of sales outstanding, offset by strong EBITDA generation. As a result, cash and cash equivalents stood at $677 million at the quarter end, $414 million less than Q4. Finally, on the balance sheet, gross debt as of March was nearly $1.9 billion, similar to the end of 2025, but the net debt rose to $1.2 billion, representing a net leverage of 1.5x to the last 12 months EBITDA. Well, so this concludes our presentation. Now the floor is open for questions.

[Operator Instructions]. Guido Bizzozero from Allaria. Considering the awarded 3.2 million cubic meters of gas capacity in the Perito Moreno pipeline expected for May -- well, winter 2027, how much annual revenue and EBITDA contribution do you expect from this? Can we forecast a similar award? Well, first, how much do you expect?

How much -- just to -- how much do we expect? It's not an easy number to provide because it will depend basically on what will be in the winter of 2027 and in future winters, what will be the prices -- the marginal cost of the system. That will be dependable on prices of LNG and prices of diesel oil. How many days during the winter, those fuels will be setting the marginal price in the system. To give you a rough idea, we think it could be in the -- but again, this is dependent upon many estimates, but could be in the range of $100 million. That is basically what we are expecting because of, as Lida explained, with this firm capacity of gas, we will be able to capture the full margin, not only the 15% margin, the 15% that the current regulation allow us to capture.

This year.

This year, yes. This 15% increases up to 35% by year 2028. No, think 2030. That is the rough estimate for power generation, and there is an additional increase in the EBITDA coming from the E&P segment because of -- I don't know if you have the figure in.

There, as Lida and Gustavo mentioned, additional gas being dispatched into the market, and that would represent approximately around EUR 50 million to EUR 60 million of additional EBITDA for the E&P business.

Very conservative, yes. Conservatively. Of course, from our affiliate, TGS.

Yes. That's right.

That's the 27% of that, right?

That's right.

That's the package. Yes.

On the other hand, we are prepaying for this transportation capacity. In 4 installments in the next 12 months, we will be paying to TGS, prepaying the transportation tariffs to TGS for the next 15 years, and that amounts to $330 million, $280 million-plus VAT is the exact figure.

Can we forecast a similar 30% award for the second tranche of 7.2 million cubic meters per day next June?

Gas distribution companies has a preference over A priority over power generators. Gas distribution companies decided not to participate in the first tranche of the auction that was this -- you have to prepay the tariff. That's where we were very aggressive on securing this gas transportation. In this second tranche, the gas distribution companies have a priority over us. It will depend on the level -- the amount of gas that they need to secure. On whatever is left from the distribution companies, then we can we may be able to secure a similar percentage as we secure in the first tranche.

All right. Should we expect any results -- nothing to do with it. Any results for the expiration of the Loma De La Lata hydropower plant concession, if we have any money?

No, nothing.

Likewise, for Rincon de Aranda.

Yes.

Both concessions is like we shake hands and that's it.

Basically.

Basically. We noticed a decrease in power generation EBITDA margin. It is explained by the sub-procurement gas and the new tariff scheme. How do you expect to evolve in the coming quarters?

Can you repeat the question?

Its EBITDA margin reduced in power generation. I know why. Let me tell you, now with the new regulation, we have more sales because we are selling gas on E&P through the electricity, right? Before we didn't, before it was a pass-through. It's like kind of like -- it was very low sales, but the EBITDA normal. You know what I mean? Before it wasn't like apples-to-apples, we have a bunch of things. Now it's like what it should be, like you are selling electricity with the associated fuel, the right price, no longer something like a cost-plus situation. Then, of course, the EBITDA represents that. It's not like we are losing profitability. It's just now it's more apples-to-app like-for-like.

No. Actually on the contract, the margins have increased.

Increased, yes. That's right. The EBITDA, what it matters is that the EBITDA.

Nominal margins are increased, but the total sales have increased significantly more because now you have to deduct the cost of fuel. Nominal numbers are better. The ratio is worse.

It's more comparable to another utility in the world.

Yes.

I hope -- if not, let me know. Could you give some color about the increase in the working capital in the quarter? We saw an increase in trade receivables of around $500 million. No. Let me tell you. The working capital, as you can see, mostly of this $343 million, like $250 million is for the oil hedge collateral requirements that you -- well, you can -- Horacio and Gustavo can tell you us better. Then 75% of -- $75 million of payments of last quarter's -- last year's actually CapEx. We increased the PPA last year, and then we are paying it this year. Then very little, $20 million of higher DSO, days of sales outstanding, small delays on the payments. Now it was last year's December, it closed at 6 days of delays. This quarter, it closed at 12 days. It's a 6-day deterioration, just nearly 6 days. Now it's back to 7 days of DSO. Now it's back to normal, putting in this way. You want to add something? Well, let's move on. How do you expect to evolve the free cash...

I would say very normal with the increase in sales that we have to have a higher working capital.

That is correct. How do you expect to evolve the free cash flow in the following 12 months, considering the installments to be paid to TGS, the CapEx plan for Rincon de Aranda and any other divestments for projects like CESA and Urea in the future?

Vito, do you want to answer that?

Sure. Good morning, everyone. As you can perfectly see, we are undergoing record investments. This was reflected in our net leverage that increased to 1.5 as we expected. Going forward, EBITDA is growing as well. In fact, this is our record quarter. We are very thrilled that our investments are paying back. The base case is if we continue with our base plan or base scenario is that EBITDA keeps growing, so the company will naturally deleverage. In fact, if we don't pursue new projects, net leverage will go to 0 in 2 or 3 years. That being said, we will probably need to increase gross debt to finance this high CapEx and for example, the TGS expansion. The growth of debt will go in line with the growth of EBITDA. We expect net leverage to keep around 1.5 this year and gradually go down as Rincon de Aranda starts to ramp up and all the investments start to profit to deleverage again. Going forward, and that is why that going forward, we're going to have no leverage. We are pursuing or we are starting new investments and new alternatives to apply our future free cash flows.

Next, [indiscernible] from Allaria. Could you give us some color about the urea project future deployment of CapEx and expected sales and EBITDA contribution beyond the year 2030?

Let me say this about the urea project. As you know, we have been working for a while, and we continue working on several fronts. That includes engineering of the plant, negotiating the EPC with potential suppliers, environmental permits, the project finance. All of this takes a lot of time. The reason why the project had a lot of publicity lately was we engaged IDB and IFC for project finance. They needed -- they published the environmental permits in their websites, and that gave publicity to -- but they need to -- this is part of the process. They need to have this public for at least 6 months before being able to move forward. That's why it was published a couple -- I think like a month ago. All in all, the decision is not -- has not been taken yet. This will be such an important move for Pampa that obviously, the moment that we decide to move forward, we will do an IR Day to fully explain why we are moving forward with this project. To give you some color why an urea project, I think we already went through in previous call about this. Probably Argentina is one of the few gas producing countries in the world that imports urea. 65% of the cost of producing urea is natural gas, another 10% or 15% is electricity, 2 products were Argentina and Pampa, it's very competitive. Developing urea is a way to monetize our very competitive gas reserves. The other rationale is that not only Argentina is importing from the Middle East and from Russia and from the whole South America. South America has a deficit of 10 million tons of urea per year that we are importing. The plant that we are envisioning is 2 million tons per year of urea. In terms of sales at normal historical prices, that would be sales for around $1 billion today because of the disruption in the Middle East, at current prices of urea would be almost twice that much. Again, it's a project that makes a lot of sense for Pampa that we are working on several fronts, and we hope to take the final investment decision by the end of the third quarter or at some point in the fourth quarter of this year. Once we do that, you will be fully informed about all the details.

As we always do. Could you give us some color about the RIGI application for the northern area of Rincon de Aranda? What means this $4.5 billion investment about the already $1.5 billion plan for the area. Could you clarify that? How do you expect this may accelerate and sustain the plateau in the future?

Okay. The full field development for Rincon de Aranda, it's in the range of $4.5 billion. That takes into account both the drilling and completion of our wells and all of the midstream infrastructure. needed through the life of the project. Basically, that investment will develop both the south of Rincon de Aranda, which is so far the most productive rock we've seen in the area and also the northern block of Rincon de Aranda, which will enable the production plateau to be sustained for approximately 6 to 8 more years.

Then the next question from Santiago is regarding Transener. Can you give us a dimension of what is power transmission grid expansion represents for the country? For Transener, if it was awarded regarding CapEx revenues or EBITDA, do you expect a significant change in prices versus the current framework scheme? If you feel like with the current framework scheme, the wholesale prices of power will increase a lot or not?

Regarding grid expansion, high-voltage grid expansions, I don't think there's anything new other than some press nothing has been published lately by the Secretary of Energy, as I believe. We are expecting the government to do an auction for new power lines basically to strengthen the supply of energy to the Amba area to the Buenos Aires metropolitan area. That will be the first auction to be launched. Transener could participate as any other. The difference for Transener is even if not awarded the construction of the line, Transener regulatory-wise has the supervision of -- so it collects 3% of the total cost of the new line constructed. Obviously, Transener has very good competitive advantage to be awarded the operation and maintenance. Again, we are still awaiting and nothing has been decided yet by the Secretary of Energy on power transmission.

Until then, we are still curtailed in the power generation, right? There is not much we can do.

A few hours or days in a year that there are some restrictions.

There's the next question coming from Alejandro Demichelis from Jefferies. We're growing CapEx at both Pampa and the subsidiaries, could you please indicate how do you see financing for the projects and for the group and the level of leverage do you see Pampa getting into the next 2, 3 years?

Well, it's going back to the question I answered before. In 2, 3 years, if we don't pursue any other new projects like urea plant, we will have no debt, okay? In the meantime, when we grow, we have opened all the pockets for financing. Our bonds are trading greatly in the international market, so we can tap that market if needed. Also, we have the local market that recently we issued $200 million at 5.49%, which is a very competitive rate. As I explained before, we probably will increase our gross debt. However, in terms of leverage, we will keep deleverage because our EBITDA is growing fastly. As you can see, this is our record quarter. You will see us issuing more debt, but keeping leverage levels in this area of around 1.5 and going down to 0 in the coming years. That being said, if we pursue a new project like the we have plant, this might change, but as Gustavo explained, this is very early still to give any guidance. We have to define the financial structure of the project and see how that will impact in the short-term leverage naturally will impact, but we have to have more clarity on the numbers to give any guidance. It's early to say.

Next question comes from Matias Cattaruzzi from ADC. He's asking, well, other questions are already answered. Net debt leverage ratio, answer. The first question, though, is Medanito rent spread tighten material with the premium now or. Passes Hormuz. Is there room to capture this improved spread in the remaining quarters? Or does the hedge effectively cap realization for the full-year?

The hedges is related to the market to Brent. Any premium on top of Brent will be captured by Pampa.

Next question comes from Gustavo Faria from Bank of America. He asks, power sector new framework, how are the discussions with the clients, I guess, in the math, right, or in the B2B market to fulfill the energy generation capacity available for PPAs, B2B PPAs. Are you being able to fulfill all the capacity available? Or is there any some spare capacity?

Yes. The new regulations separated the market into energy and capacity. For energy, for legacy capacity, generators are allowed to sell up to 20% of the expected energy production on B2Bs. We have already completed that very fast, very efficient, thanks to the strong commercial team that we have and something that we have always been used to because of our participation in the former Energia Plus market and the matter market. We have always been very active. We have a huge several hundred clients that we provide energy. I think we were the first one in Argentina to complete the sale of the 20% of energy available to sell. Regarding capacity, we can sell all our capacity. I think we've sold around 30% or 30-something percent of our total capacity. That will take more time to be completed. Once we sell the capacity, it provides us an additional market to -- an additional margin to the price that we sell capacity to CAMMESA. That will take time because it's a larger number.

That was expected.

Yes.

Next question from Gustavo Faria, which it partially answers about the fertilizers plant, but it's associated with you, Horacio, which he asks how much CapEx comes from the higher gas production at the gas fields associated from the fertilizers project?

How much will be the additional CapEx? The urea project will come in line in 2030. That will be after the planned gas ends. Therefore, we still need to understand what's going to be our mix of sales by 2030. Eventually, it will -- and that's why I'm mentioning because the amount of CapEx needed will depend on how much additional demand Pampa would like to engage to service. If we decide eventually to reduce our sales to the, let's say, residential market and keep that gas to feed our urea project, then the CapEx is completely different as -- on the other hand, we decide to supply the urea on top of all of our additional demand.

The next question is for you, Gustavo. What will be the commercialization strategy for the fertilizers? In 2030?

Okay. Argentina currently consumes about less than 2.5 million tons per year of urea and approximately half of that is locally produced by Profertil. The first option will be local prices, local demand, but given the restraints on the project finance that require us to sell -- to export a higher percentage in the first few years, probably we'll be exporting to the neighboring countries. All our neighbors consume urea from Middle East, Russia and exactly the opposite side of the world. Again, too soon to tell what will be our commercial strategy, but it will be domestic and export sales.

The people from Latin Securities, Alejandro Christensen and George Gasztowtt ask, how is the treatment plan Rincon de Aranda progressing? In which quarter do you expect it will COD?

Okay. It's progressing with no problems at all. Some minor delays on the desalinization modules that were scheduled to come from the OEI. To answer your question, the plant will be commissioned by the month of March 2027.

Have you hedged any production beyond first quarter '27 so far this year? Or do you plan to?

Basically, we have 1 year forward. Yes, we probably we will continue with the hedging strategy moving forward, probably not so aggressively as we've done this year. During the ramp-up, we wanted to ensure the stability of the results. That's why we decided to hedge 100% of our production. Going forward, and as production continues to grow, we will be reducing the percentage of the quantity hedge to probably around 50%.

Next question in the gas supply for the intersegment procurement structure, is it structured as a fixed price contract? He's asking how much power generation is buying the gas from E&P?

How much -- what amount of gas?

No, prices.

Prices are regulated by CAMMESA. There is a maximum price, which is linked to the, let's say, LNG FOB Argentina, it's 55% of that. That's the price at which we sell, quote our gas to our own power plants.

Yes. During the summer, it's just like the plan gas.

The summer is the plan gas.

Iner segment-wise, it will be like very similar to what is planned gas, right?

No, no, no. It's significantly higher. The plan gas has a price for the summer and another price for the winter is approximately, let's say, 2-point-something and 5. Today, with the markers that we are looking at for the month of May, we are looking at prices that are around $10 per million BTU for the generation segment.

That we are capturing.

Almost twice the plan.

We are capturing all of it.

We're capturing right now.

It's just to allocate.

Who gets that?

Revenues or margin between the power segment and the E&P segment is not that.

Then he says, should we expect the variable cost component known as CVP recognized by CAMMESA to remain broadly stable over time, given this structure? Actually, the CVP is not stable because as what Horacio was saying, the seasonal winter CVP shoots up because of the cost of gas, right?

I would say that it's the first time in many years that Argentina is showing the correct price signal in the gas market. This means that the price significantly escalates during the winter and is very, very cheap during the summer. If this continues, this should be reflected in the gas market.

Is there a positive spread between the CVP you declare to CAMMESA and what your intercompany gas procurement costs? Actually, no. In order to be competitive, no. He said can we have like a spread against what we declare before CAMMESA. In CAMMESA, what the real CVP is actually.

It's part of our commercial strategy, the declaration of the CVP. That's something that we do every 2 weeks. That's part of the commercial strategy, declaring your CVP, not necessarily the real CVP -- there is a margin included in the CVP that you declared to CAMMESA, yes.

Yes, it's the 25%.

Well it depends every week is different.

Different. Yes. CAMMESA does calculate theoretical CVPs. You cannot go very different from what you declare. What you declare, you can go very different from what theoretically CAMMESA calculates for you. You cannot say $1.

If you declare expensive, you are not dispatch it. If you declare the cost, sorry, I don't understand this. I think we answered that. Let's move.

How should we think about the release timing from collateral post against the oil hedges? Has Pampa had to post any additional margins since March 31?

I think not today because -- but eventually, at one point during this time, we had to post higher collateral, then we -- as prices came down, we recovered. I think today, we are more or less at the same level.

[Lisa Williams] from Morgan Stanley, she asks one of the easy one. Could you give me some color from the gas export perspective in the coming quarters, Horacio? There's any sales to Brazil? How is Chile evolving?

Okay. Our exports are basically to Chile, all of them, both through the Gas Andes pipeline and the Gas Pacifico pipeline. We are hitting 1.5 million of exports, and it's been pretty stable, and that's what we foresee for the rest of the year.

Well, this is a very -- like I think we didn't answer this. Do you expect RGII for Rincon de Aranda to be approved in the next few weeks?

I don't think so. If you take a look at -- Initially, RIGI were approved in 2, 3 months, the first few RIGIs that were approved. Then for other RIGIs, it took 6 to 7 months. Although we are pushing and trying to get the approval as fast as possible, I think it will take a few more months.

Once approved?

No. Just one clarification on what Gustavo said is that even if we get approved, let's say, 2 months from now, the benefits will apply for the pads #14 and #15 that have already been drilled and completed after the date of our presentation of the submittal of the request for RIGI.

Once approved, what's the next steps from there? Nothing. It's just working, right?

Enjoy.

Enjoy it. Well, no. [Francisco Caparo from Don Cap], he's asking my question will be regarding the OCI or other comprehensive income results in the pesos balance sheet. We have also dollar balance sheet as well. Can you explain the loss approximately of -- I don't know how much 300 billion, but there's in dollars. Is it related to the losses not perceived for the production hedge for the rest of the year?

Yes, it's reflected in the.

Other comprehensive income.

Exactly. That will be offset with future physical sales of oil at higher prices. That's why it is an unrealized Yes, but it's not reflecting in the P&L. It's reflecting the -- and it will compensate with future higher sales of the physical oil.

Also, can you give us an explanation of the $184 million jump in financial derivatives instruments on current liabilities, is exactly that, right? It's a mark-to-market. All right.

What price is Pampa hedged for the year going forward?

The average price until April next year is $65 million. Of course, this is the Brent marker.

Agustin Pacheco from Banco Mariva. Power gen CapEx, just $2 million in Q1 versus $35 million quarterly D&A. Is this a 1Q timing effect? Or should we recalibrate our maintenance CapEx assumption lower going forward? What normalized annual level do you consider appropriate for the current asset base?

I think it's in the range of $70 million, $70 million, $80 million average annually per year. There are some years that it's significantly higher and some years that is lower. That depends on the major maintenance that the turbines need to go through every -- several years. Average around $80 million. That's why it's just a coincidence that this Q was so low, but this year, it should be in the average range.

$70 million budget. The quarterly D&A or the D&A actually is because we are a functional currency in dollars. We are increasing PPE, and we are doing the D&A. That's why -- and we have increases in the past few years. It's a normal amount.

Probably the $35 million that he mentioned in previous year, it's not only maintenance, but it's probably the end of the PPI, the wind farm, I think it was in the first quarter of this year, payments related to the last wind farm that we built.

Alvaro Leva from BTG. He's asking what are the expected losses from the hedging strategy in 2026 and 2027.

Again, we don't consider that losses. The goal when we decided the hedging policy was to ensure stability of results, especially during the ramp-up and the first phase of the development of Rincon de Aranda at the level that we hedge, we secure a very good profitability and IRR for the project. Obviously, now that prices are higher, it's something that -- we knew it could happen, it could go the other way as it did last year, and we profit from this strategy. Again, the strategy is to provide stability to the results. That was the goal. Let's see.

It's 12:00. We have like 3 pages of questions, like a lot of questions.

Different questions. different subjects.

Yes. Can you imagine? Daniel Guardiola from BTG. He's asking main benefits on the deregulation, we already covered that, but he's asking when the first PPAs with CAMMESA are expiring and what is expected the impact in EBITDA? The first PPAs, the first one is expiring in July this year. It's a very small one, 75 megawatts. Next year, it's another 300 megawatts. Then until 2035, we have the 400 megawatts of CCGT in Geneva. I will say, roughly speaking, the most important amount is next year's 300 megawatts. In total, they represent roughly 400 megawatts together, they roughly represent $100 million EBITDA today. With the deregulation and the fact that the east side of the country will get more gas transportation, and we don't know what's going to happen in a long time and depends on the international prices and so on. The impact because of the deregulation is smoother than before. It's like it's lower EBITDA, of course, but it's not like a sharp drop like we used to preview before with the regulated peso spot market. Urea business, what's the IRR lever in dollars?

I think we already covered urea.

Yes. If shares continue trading at these multiples, why not prioritize aggressive share buybacks instead of pursuing even organic growth? What inorganic?

Urea, I think is mentioned.

That's organic.

Organic?

Okay. You are doing it by yourself, so it's organic. M&A is inorganic. We have a lot of things to do.

Yes. It's a question that has many answers. I think we've been very aggressive when there was an opportunity to be very aggressive. In the future, if there is another opportunity to be very aggressive, we will be very aggressive again. On the contrary, exactly, one point to take into account is liquidity of the stock. Definitely, the buyback that we did had an impact on the liquidity of the stock. There are several issues to take into account. Obviously, the attractiveness of the investments that we are doing, we think are competing extremely well with the possibility with the buyback of shares.

All right. Gamze Alpar from Impera Capital from Turkey. She's asking what's the well inventory of Rincon de Aranda, including the north? Can the production go over 45,000 barrels per day?

Okay. The total inventory, it's more than 300 wells, out of which 2/3 is in the South, 1/3 is in the north. Obviously, the production can go up to more than 45,000 per day, but that's what we consider a reasonable plateau because that's what we dimension our CPF for. How many years? She asked? How many years of production?

No, no. As she says, if he stays at 45,000, how many years can you keep up the plateau? Taking account the number.

Okay. So taking into account the size of our processing facility, we expect approximately 15 years of production at 45,000.

Daniel has more questions. He's asking, what's the expected EBITDA and free cash flow generation for 2026? Let me give you a disclaimer here. We don't give guidance. This is Argentina, but we can share with you what our forecast of the budget it is, right? What's the expected EBITDA and free cash flow generation for 2026. Actually, no generation outflow for 2026, right? We don't give guidance, but we can share with you the budget, which is the EBITDA for the parent company, it's around $1 billion, composed by $600 million from E&P and $400 million something from power generation. Be aware that this is not including the JV with Barragan, a little bit over $1 billion, of course. Then corporate and petrochemicals are negative. That's why it's rounding it $1 billion. In the consolidated level, it's including the TGS and Transener's equity share, it's around $1.3 billion. Then in the free cash flow, this is including the prepayments of TGS, SESA, San Matias and Bemos, it's around an outflow of around $400 million free cash flow outflow. Have you considered to grow inorganically in the oil window of Vaca Muerta? This question he always asked -- but he asks good. How is an inorganic Vaca Muerta oil project ranking in terms of risk-adjusted IRRs against the urea project or the San Matias pipeline? That's a good question, though.

Good question. We are permanently looking at opportunities in oil, in the shale oil window. It's very hard to give an IRR because it will very much depend on the quality of the asset. I would say that for a good asset, definitely, we will be tempted to go ahead into inorganically operation.

Regarding San Matias, it's not a project itself. It's part of the investment of the floating LNG project and is done by the same shareholder structure of SESA of the whole project.

Another question from -- I don't know how it pronounced, sorry, but I guess it's Gergolet from Scarlet Macaw Capital. The first question about the hedge is answered, but the second question is very funny. It's worth asking is with abundant gas potential in Argentina, what about petrochemicals? It is barely profitable? Or does it make sense to keep it? Or would you consider selling it to simplify the company like you sold the mature oil fields.

We are looking for alternatives, but nothing is on the table at this point.

Edward Palma, he's asking, given the negative cash flow generation, are you planning to raise additional debt? Or is a focus on improving working capital management? A little bit was by.

Well, we always have to like to have high liquidity to keep all our options open. Yes, it could be the case that we decide to continue tapping the market in the medium term.

Okay. Ignacio Lopez from Puente. He would like to ask the outlook for gas segment, particularly considering the increase in production and the lower exposure to Plant gas. Could you share your expectation for local gas prices this year, especially for volumes traded outside Plan gas? I guess he's asking about the industry.

He's asking about the market in an overall view. As we mentioned before, it's the first time in many years that they are giving the right signal to the market. Our view is that the gas prices for 2026 are going to be higher than last year.

Now with the war.

With the war and with -- particularly in the domestic market with the possibility of selling your gas at an alternative -- at least a percentage, but the alternative import parity.

Armando Moretti, he's asking, do you plan to pay dividends?

No.

Thank you very much. I don't know if you would like to add some comments.

We covered all.

Next earnings is on August, okay? Thank you very much.

Thank you very much. Thank you for your attendance.

Thank you.

Thank you.

Thank you. Have a good day.