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2026.10.08 | TB | Energy | Pluspetrol: Vaca Muerta Constraints

原标题：Pluspetrol – Argentina Operations & Vaca Muerta Development Constraints

#energy

Third Bridge · 2026-10-08

Analyst-led • 29 Sep 2026

Companies: CVX US

Roberto Diaz (RD) Independent Consultant

Curren Larson (CL) — Third Bridge Sector Analyst

Agenda

Key Insights

Introduction

CL [00:00:02]: Welcome to Third Bridge's Interview entitled Pluspetrol – Argentina Operations & Vaca Muerta Development Constraints. I'm Curren Larson, and I will be facilitating today's Interview with Mr Roberto Diaz, former COO at Pluspetrol.

Roberto, before we start today's Interview, please state I agree or I disagree to the following statement: You understand the definition of material non-public information and agree not to disclose any such information, or any other information which is confidential, during this Interview.

RD [00:00:39]: I agree.

CL [00:00:40]: Would you mind briefly introducing yourself before we jump in?

RD [00:00:44]: Roberto Diaz, petroleum engineer by background, MBA in oil and gas management from Dundee University in Scotland. More than 34 years in the oil and gas industry in Colombia, Peru, Ecuador, Angola, Russia and then Argentina. With Pluspetrol the last 11 years.

Questions

00:01:28] Could you walk us through Pluspetrol's upstream asset base, including its key basins and the relative importance of each asset to the overall portfolio?

RD [00:01:55]: Basically, right now, Pluspetrol is operating in three countries, Argentina, Peru and Ecuador. After several years of reshuffling, changing the portfolio, these are the three countries in which they are operating right now. Before that, it was operating also in Bolivia, Angola, Venezuela, the ones that I remember, but right now, it's focused on these three countries. Basically, I will start with Peru. Peru is a legacy asset, Camisea gas-rich asset. It's a world-class asset, a huge asset right now. It's producing around 1.8 BCF per day. Some of this gas is reinjected to the reservoir because there's not enough demand to consume that gas. It sells to the domestic market around 50% of the 1.2 BCF day that is produced and sell. The rest of the gas is exported through Pampa Melchorita LNG plant and the Peruvian coast, Pacific coast. It also produces liquids around 70,000 barrels per day of liquids, gas liquids and condensate. It's a very well managed and with a great performance reservoir.

It produces from around 20 wells, and it's located in the Amazon Cusco department in Peru. It was developed as an offshore inland concept. There are three or four well pads, with all of the production going to a CPF in the centre of the asset. Basically, it's a cash cow asset for Pluspetrol, very profitable during the last years. No huge investment remaining. Investment are foresee. It's in a declining mode operation. This is the one in Peru. Then Ecuador. Ecuador, they have there an asset, Block 10, Villano field. It's an oil asset, producing around 7,000 barrels per day. It's a very mature asset. It was not developed by Pluspetrol. It was bought 10 years ago through an acquisition from Eni. The asset also has an undeveloped oil field that is still waiting for environmental approval. With this asset, I estimate that the production of the block will go to 12,000-15,000 barrels per day.

Then is Argentina, which is the growth machine of Pluspetrol right now. It has changed in the last years from a conventional mature portfolio to Vaca Muerta shale portfolio. First, with the development of La Calera, a rich gas asset, which right now is producing around 500 million cubic feet per day and 30,000 barrels per day of liquids, and it's in the centre of the hub area of Vaca Muerta. Very profitable, very productive. Last year, Pluspetrol started the massive development of Bajo del Choique-La Invernada block in the northern hub of Vaca Muerta. As far as I know, right now, it's producing around 45,000-50,000 barrels per day in a very accelerated path development. The plan is to produce more than 100,000 barrels per day. It's a very large and productive play.

Then recently, it was announced a swap of areas with YPF. Pluspetrol used to have 50% of three, let's say, dry gas, rich gas, combination of assets in the south of Vaca Muerta, Meseta Buena Esperanza, Aguada Villanueva and the third that I don't remember, it was Las Tacanas. These three areas were swapped, this 50% of these three areas were swapped with YPF for, at the end, it was 20% of the asset. La Escalonada and Rincón de Ceniza assets in the northern part of Vaca Muerta, very close to the Bajo del Choique-La Invernada blocks. A lot of synergies will be developed in those developments. Then I think that they finally sold the Corcobo mature asset. Yes, it was announced that they finally closed that process with Pecom. I think this is all they have right now in Argentina.

CL [00:08:57]: How long do you think the production from the Peru asset can serve as a cash cow for Pluspetrol?

RD [00:09:14]: Liquid production is declining, like 8% per year as normal declining of the production. Of course, the gas will keep flowing at the same level for at least, let's say, six more years once the Block 56, I mean, Camisea is located in two blocks, Block 56 and Block 88. Those fields are smaller and the production will stay until, let's say, 8-10 years, no more than that. The other gas fields, Cashiriari and San Martín are larger. They will have production until end of the contract. Possibly, if there is no extension of the contract, once the contract finish, they will still have production from Block 88.

00:10:44] You mentioned an asset in Ecuador that's still waiting on environmental permitting. What is the stringency on permitting there? Would Pluspetrol need to get permitting before it can sell the asset?

RD [00:11:10]: As far as I know, the permit is very close to be on green light because, of course, the new government is pushing to increase production everywhere. I think the government is facilitating the process. The challenge is not the environmental part, rather than the social part. There are communities located within the area of influence and the process of conversation and defining commitments with the communities is what has been more difficult in Ecuador in general. This is not only for Pluspetrol. Everyone operating in Ecuador is having the same constraints as in Peru as well. Communities are the ones that give some challenges to operators.

00:12:44] Pluspetrol's Argentina asset appears very profitable, garnering lots of attention recently. How do you think about the break-even on that asset?

RD [00:13:01]: La Calera break-even, La Calera is a very special asset because it's in the transition of fluids window. There is a small part that is dry gas, but all the rest of the area is wet gas or condensate. The productivity of a well type is for the condensate area. It's very productive. I mean, in terms of break-even, I will say that is less than USD 1 per million Btu because of the liquids. In the wet gas zone, in those areas, the break-even for gas is around USD 2 per million Btu. Anyway, it's very competitive in comparison with the rest of the dry gas or gas developments in Argentina. Very, very competitive. It's very close to Tratayén, which is the gas node, the gas processing node and the location where all the gas infrastructure start in Argentina. It's in a very, very competitive position for gas development. For the liquid assets in the north, Bajo del Choique-La Invernada, the cumulative production, the expected cumulative production is larger. It should be around 1.2 million-1.5 million barrels. The break-even, as far as I remember, is around USD 35-37 per barrel. Very competitive, also.

00:15:38] Pluspetrol and YPF signed an asset swap agreement in January 2026. How do you think about the trade-off there? Why, in your view, does it make sense for Pluspetrol to do the swap?

RD [00:15:54]: It makes all sense because the three areas in the south were very gassy areas. Pluspetrol had enough gas in La Calera, plenty of gas to compete in the domestic market. These three areas in the south were more appropriate to export LNG project in which Pluspetrol has no interest because CAPEX is huge, risks are larger. Instead of that, what we saw was the opportunity to swap it with some liquid assets in the north, to find more synergies with the development of Bajo del Choique-La Invernada. That's why the option was La Escalonada. La Escalonada is a neighbour block from La Invernada and Bajo del Choique. A lot of synergies can be developed in terms of facilities, pipelines, rigs, frac spreads, everything. It's a huge opportunity for Pluspetrol being the operator in the north.

00:17:27] How do you think Pluspetrol compares operationally with YPF, Vista, Pampa and other Vaca Muerta operators? Where do you think the company is stronger or weaker?

RD [00:17:47]: It's very competitive. The level of scale of YPF provide them to some economies of scale larger than the ones that Pluspetrol can develop. Right now, YPF, as far as I understand, has around 21 rigs operating in Vaca Muerta. That makes a difference, but in terms of drilling performance, drilling times, number of stages of frac, and costs are not very different, are in the same average.

00:18:37] Pluspetrol targets 50,000bpd [barrels per day] at La Calera in 2026, up from 30,000 in 2025. How much of that growth do you expect to come from infill development within the proven core vs stepping out into less developed or even lower-quality portions of the acreage?

RD [00:19:10]: No, mostly is infill development because what happened in La Calera is that La Calera was developed first, more in the gassy areas because of the gas price resolution that provided some promotion to develop gas. The block was de-risked in the gassy areas, and then we started to develop the condensate and rich gas area. There is no uncertainty in terms of production. The asset is very well characterised in terms of productivity. No step-out areas remaining in La Calera. In addition, all the areas around La Calera have been developed. On the east, it has Loma Campana from YPF, which is in the massive development. North is Bajada de Añelo Shell, which has been developed. To the west is Fortín de Piedra and Aguada Pichana. It's an area very well developed, and there is no, let's say, de-risking issues regarding the asset. This is for La Calera. In Bajo del Choique, it's a bit different.

00:20:55] You mentioned that Pluspetrol's drilling performance is roughly in line with YPF. How long does it typically take to complete a well in La Calera today?

RD [00:21:17]: Drilled and completed, let's say, that on average, 18 days. La Calera is a bit less because La Calera is… Bajo del Choique is deeper, 500 metres more deep than La Calera. For La Calera, let's say, 15 days, for Bajo del Choique around 18 days, drilled and completed.

00:21:53] When I look at the amount of activity in Argentina, I start to wonder what services look like. Chevron is preparing a USD 13.8bn investment under Argentina's RIGI [Régimen de Incentivo para Grandes Inversiones; large investment incentive regime] to develop the El Trapial field in northern Neuquén, aiming to triple production at the 450-square-kilometre block over the next 10 years. How should we think about this competition for Pluspetrol's USD 12bn Bajo del Choique project? What are the implications for services with that increased competition?

RD [00:22:42]: I think that Chevron is behind Pluspetrol in moving into massive development stage. There are a lot of conversations between Pluspetrol, Tecpetrol and Chevron to develop synergies, to develop all the north portion of Vaca Muerta because they all know that they have to find ways to scale up opportunities and to make sense and reduce costs and optimise costs. In terms of facilities, I would say, pipeline capacity. I think the problem is already solved because the main pipeline from the north to the centre is Oldelval Norte, which is already sanctioned for expansion. Then once it goes to Allen, there will be the VMOS pipeline, which is already in construction stage. It will have enough capacity for all the developments in Vaca Muerta. It also has chances of expansion and using also drag reducers. It is very well planned in terms of pipeline capacity. I don't see any challenge or fight in terms of pipeline capacity between Chevron and Pluspetrol because actually they are both partners of VMOS and partners of Oldelval Norte, as far as I remember.

Then in terms of rigs and frac spreads, that should be a problem, but Pluspetrol made a movement years ago, having their own rig fleet. Pluspetrol owns three high-spec rigs. I think now, the two of them are drilling in Bajo del Choique and there is one in La Calera. In some moment in time, we were thinking to move all three rigs to Bajo del Choique and just keep one contracted rig in La Calera. Anyway, my point is that to drill the development wells in Bajo del Choique-La Invernada and La Calera, Pluspetrol will need four, let's say, maximum five rigs. They already have three secure rigs because they own those rigs. For frac spreads, Pluspetrol also moved ahead in the last two years because Pluspetrol, we bought the frac spread of Weatherford. Pluspetrol owns one frac fleet. As far as I know, because when I was working with Pluspetrol, the plan was to increase the pumping capacity, so buy new pumps to increase the horsepower capacity for frac spreads. They have secured the critical resources, rigs and fracs.

Then of course, there are some other critical issue, like sand, like water, but all of them are workable. As far as I know, those are the type of things that are discussing with Chevron and Tecpetrol, how to develop water supply from, let's say, in a common way, in a common view.

00:27:27] Would you be able to explain how the RIGI works? Are companies competing for capital or is this a very open initiative? I understand it essentially offers free export international prices and provides legal certainty, but you have to apply for it. How does that work?

RD [00:28:08]: In general terms, RIGI, it's a promotion of investments that at the beginning, it changed in the last year because at the beginning the upstream was not included in the law. It was more for midstream and LNG projects. Later on, once Milei government got into the executive, they changed the view because they saw the opportunity to increase the CAPEX, the investments in development of oil and gas. They changed the law and included the upstream. There is a differentiated minimum CAPEX for mining, for midstream, for LNG is USD 200m. It's the minimum CAPEX to apply for that regime. For upstream, the minimum is USD 600m. That's the difference. Then what is important is that, especially if you work in Argentina, it's been a country with no guarantee of anything in terms of stability of taxes, money change and dividend. How do you say that? When you can get your money out of the country.

What the regime is providing to operators is an instrument to guarantee their income tax, also 30 years of stability in terms of money exchange under some parameters and the income tax is a flat 25%, not changing withholdings and this type of changes that governments used to put in to create from time to time and also provide accelerated amortisation. They provided these type of conditions to promote those investments.

CL [00:31:03]: I wasn't sure if Chevron getting involved would have any implications for the ability of Pluspetrol to access the regime.

RD [00:31:15]: No, actually, everyone can apply, everyone can apply at the same time. You will notice that the LNG project from YPF, ADNOC already applied. Some mining developments also apply. TGS with the midstream project apply. In terms of upstream, I think YPF apply, Chevron apply, Tecpetrol was the first that applied for Los Toldos II Este, and then Pluspetrol. It is for new developments. This is important. For example, in La Calera, we didn't have the chance to apply because it was partially developed. You see, it was just for new developments, for new developments within a period of time since the law was issued. For previous development like Loma Campana, Bajada del Palo from Vista, La Calera from Pluspetrol, sorry, guys, you already developed those areas. There is no regime for you. It's just for new developments.

00:32:45] Going back to La Calera, you mentioned you're not really looking into step-out areas and it's all pretty much developed. What does the first-year decline rate look like for a standard La Calera well today? Do you expect that curve to flatten or steepen as we see more infill drilling and the development spacing tightens?

RD [00:33:15]: Yes, there will be some degradation because of the parent-child effect, but it's been already assessed and estimated. In some of the areas, that decline will be like 10-20% from the first well pads, but it's been assessed because La Calera already has a lot of production history. It is possible to simulate, to extrapolate and to understand that effect. There will be some degradation, but it doesn't compromise the plateau production that is expected. The production estimates already include that degradation.

00:34:21] Could you elaborate on the reservoir pressure at Bajo del Choique compared to La Calera? What might OPEX look like there over the next couple of years, given some more artificial lift requirements?

RD [00:34:42]: Yes. I'm trying to remember the numbers. I don't have the data, but the reservoir pressure in Bajo del Choique is higher because, of course, it's deeper. The reservoir is deeper and the reservoir conditions are better in general terms in Bajo del Choique. The landing zones, they have one or two additional landing zones than La Calera. In La Calera, the development plan is in some areas, two landing zones in the condensate-rich or wet gas area is three landing zones. In Bajo del Choique-La Invernada, it could be four or five landing zones. It's because the basin, the Vaca Muerta formation, gets thicker to the north. There are more landing zones for drilling. That means that you will have more drilling, more number of wells in the same area portion.

CL [00:36:38]: If it's above 7,000psi, you wouldn't necessarily suspect an intense need for artificial lift, would you?

RD [00:36:48]: You will need it. Yes, yes, of course. No, no, you will need it. You will need it because the pressure declines very steep once you start production. In the first two or three years, you produce 50% of the production and the production declines like 50% or 60%. No, no. You will need artificial lift after, let's say, in Bajo del Choique after maybe three years. Starting the fourth year, sure, you will need artificial lift. In La Calera, it's a bit different because you have gas. The gas acts like a natural gas artificial lift production system. In Bajo del Choique, gas production is not significant. You will need to put artificial lift. The one that we were considering when I was working there, when we start visualising the development plan for Bajo del Choique-La Invernada, we foresaw that we would need artificial lift. The one that makes sense for that asset is gas lift because they have gas. They have enough gas to use gas lift as an artificial system, which is very, very, very low in terms of cost maintenance. OPEX will be very fine. Instead of having rod pumping, which is you need energy, you need maintenance of the unit, a lot of things. Gas lift is a very more optimised artificial lift system.

00:39:03] How do you think about the remaining drilling inventory at La Calera? What does the runway there look like at a 3-5-rig cadence?

RD [00:39:32]: In La Calera, at the end of December, there were around 100 wells drilled and on production. The asset will be fully developed with between 500 and 600 wells. There is plenty of remaining wells and production to sustain the production plateau that is being planned. The difference is that we started development in La Calera with three rigs, but with time, there will be less rigs drilling well because you will not need to add inventory for production. You will need just to replace some of the production that goes declining. As far as I remember, you will go to one rig, then perhaps you have to move to two rigs once the new production plan, the new CPF expansion goes on production because you have to add inventory of wells to increase production, but then again, you go to one rig for at least, I would say that 8-10 years of drilling. In Bajo del Choique, it's different because it's still growing production. I think that they already reached the 45,000-50,000 barrels per day, but the plan is to go to 100,000 barrels per day. They need to increase inventory of wells. They will keep drilling with three or four rigs, for sure.

CL [00:41:33]: At La Calera, you're going from 30,000bpd to 50,000bpd, with two rigs and then one rig to sustain at that 50,000bpd. Is that right?

RD [00:41:45]: Yes.

00:41:53] Given the accelerated development at La Calera, what are the main operational constraints that you'd be keeping an eye on? Is it water or sand logistics? What, in your view, would be a constraint in going from 30,000 to 50,000bpd?

RD [00:42:14]: I'm thinking because La Calera is, I think in terms of resources, perhaps I would say that, yes, maybe rigs or because there will be some competition within Pluspetrol between Bajo del Choique and La Calera. We started to see that actually because when it makes sense to leave your own resources, I mean, your rigs and your frac because if you move everything to Bajo del Choique, La Calera will be the one needing to compete for those resources in the market. If the market gets stretched, you will have problems, but I'm not sure what is happening right now. If they move everything to Bajo del Choique, because that was something that was in their discussion when I was there, if we move all the resources that are available within Pluspetrol, but if it's not the case, if they keep, for example, the rig, perhaps as far as I know, the frac spread from SPI, which is the service company of Pluspetrol, has been moved to Bajo del Choique and will stay there for a long period of time.

Perhaps some challenge will be to have a frac spread available for one drilling rig campaign because you will be subject to on-call options, not a permanent contract. You see my point? You need at least three rigs for each frac spread because you need to add inventory, because drilling time is lower than frac time. If you don't have enough number of wells drilled and ready to complete, you don't need to have a contract for permanent exclusive frac spread. You have to go for frac time windows. If the market is constrained, you will need to negotiate with the service company, but also with the operator that is giving you the time for a window. It start to make difficult. This is the one issue that I see for La Calera. Reducing the level of the drilling campaign and the well inventory will make more difficult to secure resources, especially fracs. Then for water, for water and sand, I would say that La Calera is in a better position than Bajo del Choique because La Calera is in the centre of Añelo.

Añelo is in the heart of Vaca Muerta development, where all the companies already deploy resources and everything. La Calera is closer to the river from which all the operators in the southern hub get water supply. It's very close, I don't remember, but it's like 20-25km, in average, from the river to the centre of the block. In terms of water supply, La Calera is very well positioned, very well located. In terms of sand, also because all the service companies that provides sand and last-mile logistics are already located with equipment and everything in Añelo. It's closer to La Calera. This is what I see. In terms of production facilities, I would say that the risk will be the CAPEX expansion. The facilities expansion. We suffered a little bit when we built the first Central Process Facility, but it was in a difficult time for Argentina because it was when the Kirchner government was in place, Alberto Fernández, a lot of problems, a lot of restrictions to import things. We had delays and overruns in those CAPEX facilities.

I don't see those problems right now in Argentina, but perhaps the problem is that companies, service companies, construction companies are over-demanded. Perhaps they have to compete with resources from project to project. You can get some overruns or delays in your facility if your contractor start to delay. This is the other issue that I see for increasing production in La Calera.

00:48:21] You mentioned drilling times are around 15 days at La Calera. Do you see that shortening? If it's just bottlenecked by the frac times, what do frac times look like?

RD [00:48:41]: No, there is always opportunity to optimise well drilling time. I think in terms of well design, Pluspetrol is one of the best companies. We optimised from the beginning. We changed the logic that all the rest of the operators had with four casing strings. We reduced it to three casing strings, controlling the difficult section in Quintuco Formation, which produced some problems for some operators. We didn't have any well lost and abandoned in the whole 100-well campaign. Perhaps the one that we struggled a little bit and we saw opportunity was directional drilling. Temperatures in Vaca Muerta are higher than in Permian, Eagle Ford and directional drilling tools that are provided by Baker, Schlumberger, Halliburton didn't work very well in those temperature conditions. They fail a lot rather than in USA. That is an issue that all operators had in mind and were working with the service providers to increase reliability of the directional drilling tools. I would say that that's the most important, maybe some logistics, moving time, working with the local companies, it's always an issue with the union, the labour union.

There is always some issue around that that you can improve, but I would say that an ideal drilling time in Vaca Muerta should be like 12-15 days. That would be ideal. This for conditions like La Calera. Of course, I'm talking about normalised 3,000-metre lateral. It changed because in La Calera we were drilling also already wells with 3,800-metre lateral, horizontal well. In that case, it takes more time, but the well has more productivity. It depends, but normalising in 3,000-metre lateral well, I would say that right now is in La Calera is around 15 days. Ideally, it should be go to 13.

00:52:34] You mentioned that securing an additional rig could be a potential bottleneck, given the internal trade-off between La Calera and Bajo del Choique. How long do you think it would take to secure one today?

RD [00:52:52]: I would say that I'm not sure. My last conversation when I was in Argentina, discussing the issue with some of the rig providers, were like, they will need around 4-6 months. Bringing a rig from United States, but I don't know if it changed, because, one, with the current oil price, I would expect that the drilling will maybe increase in Permian, in Eagle Ford because with these prices, a lot of acreage is attractive. The US market is very elastic. Once price goes up, they start to drill more. It goes down, stop rigs. Maybe changed, I'm not sure but I read in a paper from Welligence, I think, or Rystad, I don't remember, one of these information solutions that right now there are, in theory, 30 high-spec rigs in Argentina. In order to develop the whole acreage in well manufacturing mode, they will need like 50 high spec. There is a gap of 20. I don't know if those rigs are available. In Argentina, there are not available. Perhaps you will be able to convert some conventional rig to high spec. I don't know how it will take in terms of cost and time.

It's not an easy solution, converting a rig, but I don't know. I'm not sure, really, but months ago, it was like a window of 4-6 months when I had that conversation with Nabors, for example. I sat down with guys in some people in Nabors, Houston, and they told me, "If you want a rig coming from USA to Argentina, right now, it's like 4-6 months."

00:55:36] With Pluspetrol looking to grow its production alongside broader production growth from Vaca Muerta in Argentina, where do you see the greatest downside risk to the company actually executing on that production growth?

RD [00:56:14]: I will not see on the operational side because I think they have everything in place. The resources, the people, the talent, maybe financing because, of course, Pluspetrol is financing everything with money from the market. Maybe the highest risk is how the Argentinian economy goes on. If it goes well, the market will continue supporting Argentinian companies for finance, but if the government start to have issues, there is elections. Next election time will be critical. Election time. Yes, election time/financing because the rock, the subsurface is already proved. The main core areas in Vaca Muerta centre hub and in the north are producing at better productivity rates than Permian, which is the premium acreage in USA. Subsurface is proved.

Execution capacity is proved. You have to secure resources like the ones that we were discussing, rigs, frac spreads, but let's say that you can find it, but then it goes to Argentina's macroeconomic conditions and political issues. For me, operating in Argentina, Vaca Muerta, the constraint or the concern will be always related to political and economical stability and how this situation impacts on financing the programme or if the government start to make moves different that open the market to operators, more centralised type of politics and everything.

CL [00:59:10]: I think that's about all we have time for today. I'm going to leave it there. I just want to say thank you for joining me and sharing your insights on Pluspetrol and the broader Argentina build-out.

RD [00:59:23]: It was a pleasure.

Transcription ends at 00:59:26 of the recorded material