Hi, good morning.
Oi.
Hi, good morning, everyone. Pardon for my voice. My name is Lida Wang. I'm Investor Relations Manager of Pampa Energía. Thank you for joining us today in our Investor Day here in New York. I'm gonna just kick it off. Our chairman and co-founder, Mr. Marcelo Mindlin, is here, so he will start off, and we expect by 9:30 A.M. to finish the session and start the Q&A. Thank you so much.
Good morning. Oh, good morning, everybody. Thank you for coming. As you know, we are here in New York because yesterday we celebrate the thirtieth anniversary of TGS listed in the New York Stock Exchange. So we were in the bell ringing ceremony, it was very nice. Since we were all here, we decided to visit shareholders, investors, and do this investor day for Pampa. We founded Pampa almost twenty years ago. In those almost twenty years, we were able to build a unique portfolio of energy assets, diversified across all the subsectors of the energy world. And we have created one of the most liquid stocks in the capital markets in Argentina, and we think that we have one of the best credits in the corporate world of Argentina.
Our bonds are yielding the lowest spread in our history, yielding 7.5%. So, we have built that fantastic credit. As you can see here, and we're going to be further describing the sectors and the opportunities, we have 15% of all the power generation in Argentina with 5.5 gigawatts of power capacity. We have developed our gas and oil business, and today we have 9% of the market of natural gas. And as Horacio is going to be describing later, we are now focusing to develop also our shale oil reserves. We have the co-control of the two backbones or infrastructure backbones. We have the co-control of Transener, that transport 86% of all the electricity in the country.
We have the co-control, together with the Sielecki family, of TGS that transports 60% of the gas in Argentina. But more important than that is that TGS has the treatment and processing plants that are the entry of Vaca Muerta gas to the rest of the system. So every gas, almost all the gas that comes from Vaca Muerta should go through our treatment and processing plants and pipelines, of course. And in petrochemicals, even though it's very small, we have 100% of several markets. And even though it's not a critical part of our portfolio, we it produce a nice EBITDA every year. One of the transforming moment of Pampa was when in 2016, we bought Petrobras Argentina.
And with Petrobras Argentina, we received many, many assets, the most important of which were the power and the fields, the oil fields in Neuquén. That later on, we realized that was very important because was covering 8% of all Vaca Muerta. So that transformational, that key moment of Pampa in 2006 was critical for us. Since then, we have been growing, as I said, the power from 3.8 thousand megawatts to 5.5 gigawatt. In gas, we almost more than double our production of gas, becoming or representing today 9% of all the gas, natural gas supply for Argentina. How did we fund this growth? Basically, by issuing shares.
We issue up to 85 million, 83 million ADRs, especially to consolidate all the assets that we were acquiring or developing. And since 2019, we started our buyback programs, and we were able to repurchase 35% of the outstanding ADRs using our cash flow. So today, we have 54.5 million ADRs listed in New York, of course. And on top of this program of repurchasing shares to consolidate the financial position of the company, we were able, with our positive operating cash flow, to reduce our net debt 50% from the peak we had when we bought Petrobras, to only $700 million at present. I think that today is more than 400.
So every quarter that as we produce cash flow, we are reducing our net debt. So that allows, together combined with our very strong cash position, gives us the potential to continue growing in the different sectors that my colleagues are going to describe in the next minutes. So, Gustavo, if you can?
... Take the microphone now. Thank you so much.
Thank you, Marcelo. Good morning, everybody. Thank you all for being here. I will go quickly through power generation, and as requested by many of you, give the prime time to my colleague, Horacio, to explain the E&P business that will be the start of the bright spot of Pampa in the coming years. So I'm sure you all know this because we've been in this segment from the very beginning. We are the leading IPP in Argentina, not in terms of installed capacity, but in terms of energy that we provide to the system. And this speaks well about the relative efficiency of our power plants.
Also, we have a high. So, stay for another second here, please, Raquel. We have hydro and wind farms and thermal capacity, and a consistently along the years with very outstanding availability, well above our peers. So doing all the proper maintenance of the equipment. To next slide. This is how the business is split. We have in total a capacity of 5.4 gigawatts that is split between the new cap- what we call the new capacity. That is everything that had been, has been installed after 2012, and the legacy capacity, both thermal and hydro capacity. The new capacity generates almost 75% of the EBITDA of the segment. These are the PPAs.
These are PPAs with CAMMESA, which is basically a state-owned entity, and B2Bs with large industrial users in a split, roughly 80-20. These PPAs have an average maturity of seven years, so they will provide very stable cash flow throughout the following years. Going slightly up next year because we just finished our sixth wind farm of 140 megawatts of capacity. That will add $35 million of EBITDA on an annual basis. So it's starting right now, but it will impact fully in 2025. The other 68% of our capacity, that's about 3.7 gigawatts of installed capacity, is the legacy part. That generates only, despite being 68% of our total capacity, generates only 25% of our EBITDA.
As we will see in the following slide, this is the segment that is subject to the impact of the new deregulation that we are expecting in the sector. The PPAs, for several years down the road, contribute a very stable cash flow for the company and some upside potential on the legacy or spot market energy. Another relevant thing to say about this segment is that maintenance CapEx for all these 5.4 gigawatts of capacity is around $80 million per year. This segment will contribute for the company a very strong free cash flow, north of $300 million pre-tax every year, the following years, so contributing to the health of the company. What are we expecting on the deregulation and on power generation?
Here, let me say that I'm sure you know this. We have the privilege of having in the room not only Ex-Minister Domingo Cavallo, which is honestly, for me, it's an honor being presenting in front of him, but also Carlos Bastos, who was his former Secretary of Energy, and the person responsible of putting in place during the nineties all the regulatory framework that lasted several decades, and that we all want to go back to something similar to that. I'm not sure if I should say this, but current Secretary of Energy Eduardo Rodríguez Chirillo was a former under. Was in his staff, was a.
I would say people from Carlos, so they share the view. So probably, after the end of the meeting, you can talk with Carlos to give you his view about the potential deregulation. What we expect here is that, the government wants to eliminate the role of CAMMESA, that CAMMESA has been having in the past few years as a central planner of the system, deciding all the expansion and managing all the fuel of the system. The idea is to recreate a competitive system among the IPPs, giving the price signals that the system need in order to become, for the power generators to become the off-takers of the needed infrastructure, that the country needs to lower the cost of producing electricity.
So that is the basic idea behind the expected deregulation. More in details, what do we expect for what we call the new capacity, the PPAs. We don't expect any change. It will remain as they are until those contracts mature. For the legacy and spot remuneration, we expect a marginal price system. Initially, we see that it's going to be easier for that free market between large users, IPPs. Later on, distribution companies can join that market. The third very relevant thing for Pampa is fuel procurement.
Today, CAMMESA centralize all the fuel of the system, and for Pampa, an integrated company, is extremely important or will be extremely beneficial to manage and to be able to source its power generation plant with its own natural gas plant. To give you an idea, our power plants consume, on average, two-thirds of the total production of natural gas of Pampa, and in terms of for future expansions, today they are all decided by CAMMESA or by the Secretary of Energy. In the future, we expect CAMMESA to maintain a role of organizing the market, but that large users and distribution companies will be the ones demanding and contracting directly with the IPPs.
So one reason that why this is quite important for us is, as I explained, self-procurement of our fuel, being able to consume our natural gas production on our power plants. The other thing is that our CCGTs, we have four CCGTs, a total capacity of 2.6 gigawatts, and they rank among the best and most competitive in the industry. Not only for they are all, and I'm comparing CCGTs, so they are all very efficient in terms of consumption of fuel. But ours have the peculiarity that they are very well located in terms of they are on top of the Neuquén Basin, so we don't require gas transportation.
That is basically the, we are very competitive, even assuming our power plants, well, most of them, consume natural gas all year round, while several others today, they need to consume, diesel oil because there is lack of infrastructure to reach the power plant with gas during wintertime. Even thinking of a moment when all the infrastructure, all the new pipelines are built, and all the power generators consume natural gas, our power plants will remain very competitive because we have very cheap transportation - no transportation need or very cheap transportation cost. Next. It's ... I am done. Horacio? Your time.
Okay, good morning to everybody, and thank you for coming to our Investor Day. We will be explaining the E&P business and, most importantly, the unique opportunity of unlocking a shale oil block that we recently acquired, that's called Rincón de Aranda. First of all, we've heard many times about Vaca Muerta. Just a few words about it. It's a massive geological formation. It's a blessing for Argentina as well. The total resources are in the range of sixteen billion barrels of oil and three hundred TCF of natural gas. That accounts for ninety years of consumption of oil and approximately a hundred and fifty years of consumption of natural gas for Argentina. So definitely, in both cases. The international market is a way out. There's no way Argentina can consume that, okay?
So everybody's focusing today in exporting those surpluses as quickly as possible. We can see that the increase in oil production in Argentina surged in the past years. Vaca Muerta, six, seven, 10 years ago, was non-relevant in terms of production. Currently, it accounts for approximately more than 30% of the total growth of Argentina's oil production, with a share of 60% in our total output, while the conventional reservoirs are declining. One just one word about its productivity. If you look at the right of the slide, you can see the different performances of the different shale plays in the U.S. vis-à-vis Vaca Muerta, and we can see that it's extremely productive and very competitive.
So, having said so, it's important to point out that in the U.S., more than two hundred thousand wells have been drilled, and in Argentina, only two thousand three hundred. The learning curve that the Americans had to pay in the past twenty, twenty-five years we are taking advantage of that and quickly catching up on productivity. Now, all of this export potential that we have needs a lot of infrastructure, both in natural gas and in oil. Let's take a quick look at the oil infrastructure that is needed in order to have these exports going on. We are currently building a new pipeline from Neuquén to Ayacucho that's called Duplicar. That accounts for three hundred thousand barrels per day, approximately.
There is a project in which we are taking part as well for building a big pipeline, a new big pipeline, going from Neuquén to the province of Rio Negro, at a site called Punta Colorada, that will increase approximately 500,000 barrels per day. If we add up the Duplicar with the new pipeline, the Vaca Muerta Sur, Tramo 2, we will end up with approximately 800,000 barrels per day of additional oil production. All of it is gonna be facing the export market. Argentina will become a net exporter of oil with figures that will range 1 million barrels per day. Investments required to do so will be in the range of $5 billion in the next three years. Next, please. In terms of natural gas, something similar happened.
Argentina was importing significant amounts of natural gas in the past five, six years. A new pipeline was built, the Néstor Kirchner Pipeline, reducing considerably the imports of Argentina, and also the participation of Vaca Muerta in the overall production of the country. We went from almost nil participation of Vaca Muerta to currently about 60% of the natural gas being produced in Argentina comes from that formation, and in the coming years, probably more than 80-85% will be so. That has a significant and very important impact on our trade balance. We are reducing around $4.5 billion in 2024, and we are raising our exports, particularly to Chile so far, and eventually to Brazil in the coming future, in around $1 billion per year.
Now, how are we going to become a net gas exporter? What we are seeing there is our gas pipeline infrastructure that the most important portion of it is owned by our colleagues of TGS. In orange, you can see the new pipeline, the Néstor Kirchner pipeline that accounted for approximately 30% increase in our total output production and reduced considerably our imports. We are currently producing, for the year 2024, 4.6 billion cubic feet per day, and there are two major gas LNG export projects online. One that's in the range of 2.5-6 million tons per year, and a big one that is led by YPF, with 10-30 million tons per year.
If we take that into account, by 2030, we will have the first project going on, and that will boom and/or boost our production to approximately 6.3 billion cubic feet per day. Eventually, in 2035, with the second project online, we will be producing and exporting 6.5 additional billion cubic feet per day. Just to have in mind, the impact that this will have is around $20 billion per year of net exports. If you add up that to the 1 million barrels per day of oil, which is an additional $20 billion, you will end up with approximately $40 billion of additional exports for Argentina in the coming six to seven years. Now, where are we positioned in this new game of Vaca Muerta? We own key assets in Vaca Muerta.
We are partners with Exxon in Sierra Chata, almost 50-50%. As you probably know, Exxon is going or undergoing a spin-off process, which is not yet finished. We are operators in Sierra Chata. We also own fully 100% El Mangrullo, with 48,000 acres. Sierra Chata is massive, with 214,000 acres. We recently acquired, we will go into that detail, a shale oil block, shale oil lease, that's called Rincón de Aranda, around 60,000 acres, that we are in the process of developing. As Marcelo mentioned before, we are the third unconventional gas producer in Argentina. It accounts for 10%, approximately, of the national gas output, and the figures have already been shown.
We produce approximately six hundred million cubic feet a day during the winter peak. Next, please. Now, what was the story behind our natural gas output? If we look back only at two thousand and twenty-one, we were producing two hundred and fifty, and as I mentioned recently, we are now producing six hundred. So we were capable of multiplying by two point four our gas production in only three years. It's an impressive growth, and we will try to show you why it happened. This is a curve that represents. It's a histogram. It represents the cumulative probability of the wells, of all of the gas wells drilled in Vaca Muerta.
Vaca Muerta, as I mentioned before, has 2,300 wells being drilled, out of which 70%, around 1,600, were drilled to oil, and 1,100 were drilled with a gas target. Out of those, our Sierra Chata wells are the orange spots there. You can see that we range in the top 10% of all of the gas wells that were drilled in Vaca Muerta. So Sierra Chata is an outstanding reservoir. It has a lot of potential, and we were capable of developing the techniques that are convenient for developing that well, that reservoir as it should. And now we will go particularly into Rincón de Aranda. I will show a very, very short video, and we will just start with the project.
For those of you that have a lot of expectations about Rincón de Aranda, this is to show you that there we have almost nothing yet being built or constructed. It is. We are starting right from scratch. That is very good news, because we can try to do things well done from the very beginning, and this is what we're trying to do. The story behind Rincón de Aranda is that we acquired a 45% of the block from TotalEnergies. Actually, we traded the 45% for our windmill farm that we had, the Parque Mario Cebreiro.
It was a very interesting transaction that has implicit a price of $1,650 per acre, when the historical average is around $6,000. So it was a pretty convenient deal for us in order to acquire new acreage in the shale oil window. Next. Rincón de Aranda has 60,000 acres. Our estimation on resources is around 400 million barrels, so it's quite impressive. What is interesting about Rincón de Aranda is that it's located very, very close to different developments that had already been taking place. Around more than 300 wells have been drilled south of Rincón de Aranda by different companies, Vista, YPF, Pan American Energy.
Those, if we again, if we draw the histogram of those wells being drilled, and it's not a small amount of observations, 330 wells, you can see the curve on the right, and the green spot is where we are positioned with our well, our exploratory well, the RDA-2001, that performed pretty well in the 70% top of the curve. Next. Where are we going with Rincón de Aranda? Our expectations are to reach a plateau of 45,000 barrels per day by 2027. We have an inventory of around 300 wells, a total investment of about $5 billion in the coming years. We are planning to develop this new field with three rigs and one fracture fleet.
We expect to keep the 45,000 barrels per day for 15 years. Some things to take into account is that if you look at the distribution of our pads at the left of the slide, you can see that they're pretty well concentrated in two, like, in two blocks. One of the things that we have in mind, if the figures show right, is to try to reduce as much as possible the carbon footprint by the use of electricity for moving not only the drilling equipment, but eventually the frac equipment. This is something that we have on top of our minds, and we are looking at constantly. Next.
Now, the key issue on any shale oil or shale gas development is the operational excellence and the permanent reduction of costs. So, we see here three stages, both in terms of the operational cost and the CapEx associated with the project. Currently, during 2024, we are working with extended well testing equipment, particularly for the well that we already are producing, which is the RDA-2001. And the coming wells that we are already drilling and will be completing by the beginning of 2025, but only until May, in which we'll be finishing the construction of our temporary facilities, plus a pipeline for the evacuation of the oil. That will reduce considerably our lifting costs from $22 per barrel to approximately $7 per barrel.
With the construction of our final central processing facility by mid-2026, we will be in a position to reduce additionally two more dollars per barrel and go to a $5 per barrel target, which is pretty competitive in the industry. In terms of the CapEx per well, we are currently at around $18 million per well. We are planning, and we aim to get that down to $15 million per well in the development stage. Many things have to be done to achieve so, particularly the signing of large-scale contracts, the use of close sand. We currently have a mixture of 70-30 sand that comes far away from the field.
We are trying to move together with the other operating companies into using what we call Arena de Cercanía or close sands. So all of these small steps will allow us to reduce the CapEx per well from $18-$15 million in the coming three to four years, approximately. This is our production ramp-up curve. Currently, we are producing around 1.2, well, 102,000 barrels. By the end of 2025, we'll be producing 20,000 barrels per day. By the end of 2026, and this has to do with the coming up of our transportation and our treatment facilities, we will be reaching almost 40,000 barrels per day. By the end of 2027, we will be reaching our plateau of 45,000 barrels per day.
The ramp-up CapEx for the period 2025-2027, on average, will be a little bit more of $600 million per year. Our maintenance CapEx going forward from 2028, when the plateau's already been reached, forward is around $250 million per year, at an estimated EBITDA of $700 million per year by when we reach the plateau, of course. Now, in order to achieve this production increase, we definitely need to secure our evacuation capacity, because all of the new oil being produced in Rincón de Aranda will be exported.
What we do have now are 8,000 barrels per day secured through the Oldelval Duplicar, and we have additional agreed capacity agreements with other operators in order to move approximately 2,000 barrels per day. That adds up to the 20,000 barrels per day that we showed by the end of 2025.
We are currently working on a total guaranteed pipeline capacity in the Vaca Muerta Sur, that's the blue one going to the south, together with a consortium in which we have YPF, PAE, Vista, Chevron, Shell, and other big majors, working of 25,000 barrels per day by half, first half of 2026, and an additional 25,000 barrels per day by the end of 2027. That we end up with more than that we need for the 45,000 barrels per day. In a nutshell, what's our estimated growth in production, both for gas and oil? That's where we're standing... where we were standing in 2020, 46 equivalent barrels per day.
By 2024, we are doubling almost that figure to 82, and by the end of 2027, we will be producing, hopefully, 122 million barrels per day. Sorry, 102,000 barrels per day. Our revenues for year 2024, almost $800 million, and that will boost up to 1,727 - 1,700 million dollars by the end of 2027, with a very important combination that we will be exporting out of the 1,700, 1,100. That will be the world as a market, and we will be selling crude oil, hopefully, to companies all around the world.
That will have an impact in our EBITDA, that will go from $370 million, our estimation for 2024, to more than $1 billion by the end of 2027, tripling our EBITDA in the coming three years. So, that's what we aim to do with Rincón de Aranda, and thank you very much for your attention.
Three more slides before going to Q&A. As explained through the presentation, we have these two segments of our business, power generation and shale gas production, that are ... In the near future, they have potential to continue growing, but in the next couple of years, they will remain more or less about this same size. So, there are two segments generating about $400 million of EBITDA each, and each of them around $100 million of maintenance CapEx going forward. So each of them generated significant free cash flow that we will use to fund the development of Rincón de Aranda, as Horacio just explained. Just one clarification, in this slide, Horacio mentioned $5 billion of total CapEx for the development of Rincón de Aranda.
That is, that is throughout the fifteen years of development of the area. In the next two years, we are investing about $100 million this year, and we will be investing $600 million each, 2025 and 2026. So, that is going to be basically financed by the free cash flow generation of the other two segments that will not grow in the next couple of years. Apart of that, and we can show that in the following slide, we have a very robust balance sheet. Those figures are as of June, if I'm correct. If you look at our numbers today, gross debt is about the same, but cash and equivalents are north of $1.3 billion.
An extremely comfortable situation with net debt today at this point of about 0.5x EBITDA. As you can see, our debt profile very well spread throughout the years with no significant or no year with a significant maturity that will put any stress on our financial position. This giving us the chance to continue growing as we have been. Final words that I will relay from Marcelo. Pampa for the next five years. Almost 20 years ago, we had nothing on power, nothing on shale gas, nothing on shale oil. Today, we are a key player in Argentina.
As we said, the largest IPP, almost 10% of the total production of natural gas in the country, and developing Rincón de Aranda, that will. We will become a key player as well. Twenty years ago, being an investor in Pampa was a bold decision. But I think we are very proud of what we have achieved in these two decades, not only in terms of production, but the team that we have put in place. The team in power generation, our capacity to build new plants on budget, on time, with excellent performance.
The team that Horacio has put together, to do the kind of growth that we have seen on our, E&P business, and that we'll see, in the coming years. These three segments have, as explained, upsize in the near future. The deregulation on power generation, further monetization of our, I would say, unlimited, gas reserves, and the best gas reserves, the most competitive, that has been so far discovered, in the Neuquén Basin with Sierra Chata. We have several projects that we are studying in order to monetize these reserves. We are studying as Horacio explained, LNG projects.
We are studying now, and we will do so throughout the next year, an urea project that will be potentially an important off-taker of natural gas. We are starting to study the possibility of data centers for AI consuming natural gas. So there are several opportunities down the road in the country to monetize our unlimited and excellent gas reserves. Shale oil, what Horacio has just explained, in the next two years, reaching a plateau of 45,000 barrels of oil production. That eventually could go even higher as we learn about the area further. And also, there could be eventually M&A opportunities in Argentina down the road that we may take, thanks to our strong financial position, take advantage of.
So currently, about $1 billion of EBITDA, with exports of $300 million. Looking forward in the next few years to double our EBITDA generation and exporting a significant portion of our total revenues. So this concludes the presentation, and now we open for Q&A.
All right. Everybody, if you have any questions, just raise your hand, and I will go gently by your side and bring the microphone. Yes. Please introduce yourself.
Hi, good morning, everyone. My name is Andrés Cardona from Citigroup, and of course, the question goes to Horacio. Two questions about the assumptions you have for the development plan. What is the oil price? I see a footnote. I think it's $60 per barrel, but just want to confirm. What is the EUR assumption for each of the wells? And maybe a third one is, how was the process to contract the rigs? Because what we have been reading is, there is low availability and maybe demand to import incremental equipment. So if it's local equipment that was already there, and how easy is to bring new equipment? And what is the type of technology that you are being able to get to develop the project?
So the first one is the price?
Yeah.
Okay. Yeah, price is $60. Our expectation is the future curve. Sorry. Our expectation is a future curve that it's around $60. Okay? So that was the first question. Second question was the EUR. EUR for these wells is around 1.2 million barrels. 1.2 to 1.5. And regarding the drilling equipment, we secured already two high-performance drilling rigs. One from the Ensign company and the other one from H&P. The high spec that we use are the 1,700 PSI standard drilling rigs for this type of horizontal wells. There is availability today in Argentina. There is a lot of availability in the US.
There are a lot of idle equipment, drilling equipment, idle in the U.S. currently. We don't foresee a major problem or a constraint in procuring these rigs. All of them are working rigs, and they are the type of rigs that will eventually bring those CapEx costs down from $18 million to $15 million in the coming years.
Thank you, Horacio. Next question. Please introduce yourself and go to the camera.
Sure. Thank you so much. I'm Alejandra Andrade from JP Morgan. I cover you guys on the credit side. Two questions for me. First, in terms of the competitiveness of LNG, we've obviously seen a lot of headlines of international companies perhaps shying away from Argentina because of the competitiveness of some of the LNG projects. So just some comments on that. And then secondly, obviously, you're very comfortable from a cash and debt position. Could there be opportunity to do something additional in international capital markets, considering the success you had this year? So we can start.
Who want to start?
Okay. Regarding the competitiveness of the LNG projects, as you know, they are very big projects, very big CapEx and long-term, like four to five years. So we are currently studying different projects. The one is the YPF Petronas one. That is a very big one. And the other one is a floating liquefaction plant that has been brought to Argentina, the project by Pan American. We are studying both of them, and at this moment, we cannot say whether it makes sense from a rate of return perspective to come into these projects.
...Together with that, as Gustavo was saying, we're starting the urea project. That is a big off-taker of gas, of natural gas. And as you know, Brazil and Argentina are importing, like, 10 million tons per year, so that would be another way to, like, to export gas, through the urea and monetize our reserves. And then about capital market, no, as Gustavo was saying, we are producing a strong cash flow, and we have a very strong cash position, so we are not expecting to go to the market except for advance, to replace maturities. The same way we issued the bond a few months -- a few weeks ago, was to replace the two thousand and twenty-seven bond.
So that's the only, you know, scenario where we would be tapping the market, just to renew in advance. Next.
Hi, I'm Lily from HSBC. Just for a quick change, I would like to ask about the power business. You mentioned your 2030 ambitions to reach $2 billion EBITDA by then. I see most is coming from the Rincón, the new field. But what could be the upside on the power business you mentioned about deregulation? So in a normalized scenario, right, how could the EBITDA, the power business grow and mature? Thank you.
Thank you for the question. Now, we are in a stuck situation, no? Because this administration doesn't want the government or CAMMESA to be the off-taker of PPAs, which I think is a healthy decision, but they haven't yet deregulate the market in order to free the forces so that private sector can contract among each other. So we need to see this deregulation happening, and after that, there might be opportunities to build new power plants, but... And, regarding renewables projects, that is the only segment where there's still a free market, where you build a renewable wind farm or solar farm, and you sell it to large industries. That's been...
I don't think that's going to continue in the near future, because thermal capacity is more competitive with the cheap gas that the country has. It's more competitive than renewables. Renewables have been always a low IRR project. That in the past few years, why we were doing them, because taking advantage of the spread between the official dollar and the Blue Chip Swap. For example, this wind farm that we are finishing now, 140 megawatts of capacity, that cost us $240 million official dollars. Real dollars were half that amount. So when measuring official dollars, the IRR is not very attractive. Now that the spread between the official and the Blue Chip Swap has compressed significantly, it provides a good IRR.
But going forward, that there is no chance to take advantage of this, because there is no longer that spread. I'm not sure it will make sense to continue building renewables in Argentina.
Hi.
Hi, thank you for the presentation. Guillermo Infante, JP Morgan. I wanted to understand the strategic rationale of the petchems business. Seems to be a little bit different from the other areas where you guys are at. The other question is, there are some articles in the press about Loma Negra potential interest. I don't know if this is something you guys can comment on. Thank you.
Petchem is a -- and you notice that we hardly mention it, because it's almost an insignificant part of our portfolio. It's a segment that in the past has generated small positive EBITDA. Down the road, in a more open economy, it's a tougher environment for the segment, but we expect it to remain cash flow positive. We are studying M&A alternatives for the segment. It's not easy, but we are on that.
Yeah, just to remind that petrochemical is part of the inheritance with Petrobras Argentina. When we bought Petrobras Argentina, those assets came with the company, so they were never strategic, and they are not now, so and not significant. So, if we could divest that, we should do it, so it's just to focus on the main business of Pampa. And regarding Loma Negra, as the, we never wanted to mix it with Pampa. Pampa, we want to keep it 100% focused in energy. The partners of the, our partners, we are, as individual, we were taking, we were participating in the process. We presented an offer that I understand that Mover that is the controlling shareholder of Loma Negra, is going through another route.
At this time, we are not having any kind of conversation. We did present offer.
I'm Carlos Moraes from Morgan Stanley. I have two questions on the generation side. Can you explain us a little bit how is it going, the transmission, the tariff review for the transmission companies? And could you give us a little bit of timing about the generation, the legacy generation capacity remuneration change? And for gas, how you're seeing the, the possibility of Argentina exporting gas to Brazil, to Bolivia?
Thank you. For the internal tariff review for yesterday, there was news that the public audience will be postponed, so you see that the government is concerned about the impact of inflation. But it's important to keep in mind that early this year, both for on the natural gas, on the electricity, for transportation and for distributors, there was an initial price adjustment with that put the companies in a comfortable situation. For example, for Transener, being in a very tight situation, now with this initial increase or temporary increase, is with an EBITDA of $170 million. It's able to wait until the government defines when to go ahead with the internal tariff revision. I don't have any clarity, just being postponed yesterday.
I don't have any clarity on when they will move ahead.
Yeah. Regarding gas exports to Brazil, there is now a project that's being completed. That's the reversion of our north pipeline, that will enable to export gas from Neuquén, eventually to the north of Chile, or alternatively, to Brazil through the pipelines in Bolivia. What we need to negotiate yet is the tariff, the transportation tariff, both in the Bolivian territory and also from Bolivia to São Paulo. So that's what we are negotiating right now. But there are many Brazilian companies that have already contacted us for bringing Argentinian gas to São Paulo.
Good morning. Thank you for the presentation. I'm Anne Milne from Bank of America. First question is on the oil and gas side. By the way, I'm waiting for that $1 billion EBITDA number to come through, so I'm hoping it'll come soon, but on the upstream side, are you just talking right now about organic growth. Could you talk a little bit about inorganic growth, M&A, and maybe in particular, comment on Exxon, who is a partner with you in one of the fields, and if you would entertain options there? And then just a small question on the side of, what do you see as the future of the hydroelectric concessions that keep getting extended going forward? Thank you.
Yeah, I'm also looking forward to see the $1 billion EBITDA.
No, we are very confident.
About ExxonMobil. ExxonMobil, we participated at the beginning of the process. It's a very long, complicated, tiresome process that is being undertaken by ExxonMobil and Qatar authorities, so was very long. Like a few months ago, we were out of the process because we understand, taking rumors from the market, that the price they are offering now is around $1.7-$1.8 billion for the area, and at that price, we consider that's not attractive or very expensive. On top of that, they have to invest another $1.7 billion or something like that, because it's an area totally undeveloped. So that is a really significant amount of money.
When we compare the Exxon area with Rincón de Aranda, for Rincón de Aranda, we paid for the total part, an implicit value of $200 billion. Comparing, it doesn't make any sense. I understand that there are two groups competing, and it's a, as I said, it's a very unclear, not very organized process.
Regarding hydro concessions, as you said, they have expired, and they are renewing. The government is deciding whether to give some kind of a PPA and so in order to try to obtain money throughout the new concessions, or just do a process where the one offering the least tariff, the smallest tariff to do the operation and maintenance of the plant, gets the extension of the concession. They haven't yet decided which way they go. I think in the next six months, and I think that they even publish a resolution that within the next six months, they need to.
... to decide on this and move forward with re-privatizing or extending the concessions of the hydro facilities.
Did they ask for some bids that there were not acceptable prices?
No, no. They haven't asked for anything.
They haven't asked anything.
They just extended the concession for another year.
Thank you. Hi, Orlando Muci , Elena Partners. I had a question about the, you mentioned about the regulation, the electricity regulation. Just curious how that could evolve and how it could impact the legacy energy, 'cause I was not as familiar with the regulation, the original from the '90s. Love to hear just about that. And also, just one other question. On Sierra Chata, you said that there's pretty much unlimited inventory, so that's just a matter of finding the offtake for that gas, basically, that you have?
Yeah. Regarding the deregulation, we are comfortable and we are optimistic, more than comfortable, because what I explained about the competitiveness of our CCGTs.
Yeah.
But implementing this regulation is a hard thing to do. We've been 20 years of complex regulation. We have a contractual inertia, because gas producers have contracts until the end of 2028 with CAMMESA. So there are several things that makes this deregulation complex, and probably will happen in stages, and it, it will take time. And certainly, it needs a strong team in the Secretary of Energy that... They are putting it together, you know, so that's why it's, it's taking time. So I don't know when it is going to materialize. I think that the sooner the better, because the, the system needs new, additional capacity, and as I explained, government doesn't want to be the offtaker of the PPA, so they need to deregulate in order to for these expansions to, to happen.
That is the power generation question. And the-
Sierra Chata.
Sierra Chata
The scale of it, it's just-
Sierra Chata is a massive block. Our estimation of our at the working interest resources are more than 12 TCF. That's 6 years of Argentine consumption.
Sorry, to complement the question about the. Today, the market is fulfilled in Argentina. Now, there is excess production during the summer. During the winter, we continue importing LNG and diesel oil that we consume in power plants, but we lack the infrastructure, the pipelines, to be able to use local gas to eliminate the import, so if the pipelines are extended, and we are counting on TGS to do the expansions of the pipelines in the next couple of years, there is going to be an opportunity for our gas production to increase just in the wintertime, then marginal export to our neighbor countries, but it's not significant, and the LNG project.
So, the market, the demand in Argentina is constrained until the big LNG projects appear. And despite our competitiveness in the market with our colleagues, until 2028, because of the contractualization of the market, there is no chance for us to gain market share. That's why we explain that the growth on natural gas production, besides having the reserves, is going to be limited until these big infrastructure projects materialize.
Hi, good morning. I am Marina Mertens from Latin Securities. I want to know what do you expect on the natural gas segment after the Plan Gas expires, both in terms of pricing and also if you expect some kind of deregulation, similar to what you are seeing in the generation segment?
Okay, as Horacio mentioned, until two thousand and twenty-eight, there is not much room for new demand, other than the expansions of the infrastructure. Regarding your question, two thousand and twenty-eight onwards, what we used to do is to look at the marginal cost of providing natural gas in Argentina. And, although there will be significant amounts of associated gas with the oil production that we already showed, it is true also that in order to fulfill the country demand, you will also need dry gas to be in place. We hold one of the most competitive fields in that area, which is Sierra Chata. But, even with Sierra Chata working at 100% and taking into account other projects like the Urea project and the export of...
We will need additional fields to fulfill the Argentinian demand. That marginal cost of the fields that are not Sierra Chata are not very far away from what you saw during the Plan Gas bids. That's the range of price that probably we will see in the future, even if it is deregulated. At the end of the day, you will have to look at the marginal cost of producing that dry gas.
Hi, good morning. Thank you for the presentation, and congratulations for all the growth that you are posting. I have two questions, one on the E&P and one on the power generation. If I can start on the power generation, how do you see the power prices evolution in Argentina for the legacy remuneration? Because if we convert the legacy remuneration, it is at $10 per megawatt hour, and the marginal cost of expansion, in Argentina, is around $60-$70 per megawatt hour. So how do you see the evolution of the power prices in Argentina? And the second question on the E&P: you mentioned $60 per barrel in the business plan of Rincón de Aranda, which, in our view, is a very fair assumption.
But is there any level of Brent that you can revisit the Rincón de Aranda development, like for the upside or for the downside, to delay a little bit the business plan?
I don't have a straight answer to your question. The $10 you mentioned is just is not considering fuel, you know? So it's not comparable those with the. On average, on the system, I don't expect a significant changes. I think we will be able to take advantage of our relative competitiveness in the market. But I don't expect marginal prices of the system, the $50-$60. Current prices are gonna go down in the following years as more gas becomes available to the system, and then the system stops using LNG and stops using diesel oil, costs will go down, probably $55, in the $55-$60 range.
So that is the price that we are seeing with the market, that those most efficient will be able to take advantage of the spread, those least efficient, less. But that's... I hope I have answered your question.
Regarding the oil prices, two things. What we are looking now and trying to understand a little bit more is how convenient will be to hedge some of the production of Rincón de Aranda, at least until we reach a very good competitiveness in terms of CapEx per well and operational cost.
Wells?
Regarding the legacy production on crude, the conventional one, is it still a core asset? We have seen some peers divesting it or consider to divest it, so any update there?
Yeah. Our conventional assets in oil are not core for us. We are very open to consider divesting in those areas. It's not significant at all. We are talking around 5,000 barrels per day.
Yeah, and non-operated by us.
We are not operating, so.
We are studying the M&A alternatives to focus on Rincón de Aranda.
Hi. Jonathan Suarez, Deloitte. On Sierra Chata and the gas output, is it your general strategy to try to use the natural gas from Sierra Chata and other of your wells for, quote, unquote, "domestic consumption," meaning the power plants, urea, et cetera, or more towards the LNG export market? And also probably for Gustavo, when you say that you are expecting to get more EBITDA out of the legacy projects, that implicitly assumes a higher tariff, not tariff, so remuneration, which would be contrary to the system trying to lower the cost. So how do you balance those?
Okay. Let me start with the last one. That's why my answer to him is that I don't expect the total cost of the system to go up. Actually, I expect it to go down from current level because of more use of natural gas and less use of LNG and diesel. But we expect, in this deregulation, that because of the competitiveness of our CCGTs, basically Loma La Lata, our CCGT, is probably the most. It's a combined cycle on top of the gas field, so no cost of transportation of natural gas. So makes that CCGT very competitive or the cheapest one in the curve of supply of energy in a deregulated market.
Also, Genelba, where we have 1.2 gigawatts of combined cycle capacity. Genelba, fortunately, has transportation capacity for one of the combined. To fulfill, to supply to one of the, the, to half of the 1.2 gigawatts of capacity. Of existing transportation capacity, which has-
... lower tariff than the new transportation capacity that will be built. So the transportation capacity of Genelba will be cheaper than the colleagues, even the location is similar, because the other CCGTs are lacking transportation capacity, and will need to hire the new one. So that's why we expect our EBITDA on the legacy in a deregulated market to grow. And it's related to how competitive we see our asset vis-a-vis our colleagues.
But just you, it's not-
No, exactly. As a whole, we don't expect any significant change.
Regarding your question on Sierra Chata, it's important to understand that the Argentine market is a seasonal market. So actually, exporting and the local demand are in a way complementary. They're not necessarily collide with each other. So we will be looking at both markets, because in many cases, they will be complementing each other as well.
Sorry, follow-up. How do you balance that you have a working interest from another company that might not be necessarily as inclined to invest as you are?
Y- yeah.
That's why I'm asking.
Yeah. Usually, the contract structure under which you develop and the block has what is called sole risk. If the other company is not interested in investing together with you, they have to give you the way out to do it on your own. Eventually, they can re-enter if they decide to do so, but you would be able to go ahead with your own plans.
Thank you.
I have a question, another question on Rincón de Aranda. In case the evacuation capacity expansion gets delayed, do you have a plan B to evacuate the oil from Rincón de Aranda?
There has been an increase already. It's on the way, the construction of the Duplicar Oldelval, which is what we mentioned, three hundred thousand barrels per day. And we don't see the industry fulfilling that capacity. So we think that particularly during two thousand and twenty-five, at least, there will be opportunities of buying spot transportation capacity from those companies that secured the capacity but don't have the production to fill it.
So, and also, Oldelval, the one that is doing the Duplicar project, may have additional expansion.
Additional, yeah, additional expansion for the year 2026.
That may be even before the Vaca Muerta-
The Vaca Muerta.
As what YPF is projecting, so.
I don't know if there's any questions in the audience present, in person in here, but if you want, we can do some that are virtually connected, if that's all right for you. So the first question comes from Francisco Casarone, from TPCG. He asks: When do you expect an answer on the TGS plan? Which I don't know which one of the plans, I guess, the investment plans.
Yeah, I understand that is the answer to the private initiative that we presented to the government. Just a very short summary. TGS presented a private initiative to invest around $700 million to expand the transportation capacity of the pipeline for around 14 to 15 million cubic meters per day. The government is now studying the initiative, and they have to launch a bid. In the bid, of course, TGS is going to participate. There are going to be other potential participants, and we, TGS, as the initiator, has a 10% margin to win the initiative. So we are expecting that to happen within the next 30 days.
Another question from Francisco Casarone says: Around what price are the gas contracts as of today? When do these contracts mature? What dynamic of prices do you expect going forward?
I think we covered that question, but the current prices are around 3.5 on average. They mature in 2028, and we already explained five, yeah.
Alejandro Demichelis from Jefferies is asking: What should be Pampa's total CapEx requirement in 2025, 2026 and 2027, including the investments in the new export pipelines and LNG project?
We don't have those calculations, because at this time, there are only projects that we are analyzing. What are investment that are being undertaken right now, like the Rincón de Aranda or the CapEx that Horacio showed, so we don't have those estimates, because again, they are at the analysis level.
All right. Next question comes from Agustín Coscio. I don't know where he works, but what about investments in Ecuador?
One of the assets we inherited when we bought Petrobras Argentina in two thousand and sixteen was a little participation in OCP, that is, the second largest pipeline in Ecuador. Since then, we have been able to acquire 100% of the pipeline. And the concession for this pipeline has ended. The government has extended the concession and is entertaining conversations to give a new longer-term concession. So if that happens, Pampa, that is today owner of 100% of this OCP pipeline company, will have a concession for the next X years to continue operating this pipeline.
All right. There is no more questions virtually. So in the interest of time, we thank you. We appreciate very much for you to come here and to hear my voice. So thank you. If you have any questions, please do not hesitate to contact us. Here are the senior management, if you want to approach. Thank you.
Thank you.
You, you could do that. Thank you so much.