Good morning, and welcome to the GeoPark Limited Conference Call following the results announcement for the first quarter ended March 31, 2024. [Operator Instructions] If you do not have a copy of the press release, it is available at the Invest with Us section on the company's corporate website at www.geopark.com. A replay of today's call may be accessed through this webcast in the Invest with Us section of the GeoPark corporate website. Before we continue, please note that certain statements contained in the results press release and on this conference call are forward-looking statements rather than historical facts and are subject to risks and uncertainties that could cause actual results to differ materially from those described. With respect to such forward-looking statements, the company seeks protections afforded by the Private Securities Litigation Reform Act of 1995. These risks include a variety of factors, including competitive development and risk factors listed from time to time in the company's SEC reports and public releases. Those risks are intended to identify certain principal factors that could cause actual results to differ materially from those described in the forward-looking statements but are not intended to represent a complete list of company's business. All financial figures included here and were prepared in accordance with IFRS and are stated in U.S. dollars unless otherwise noted. Reserves figures correspond to PRMS standards. On the call today from GeoPark is Andrés Ocampo, Chief Executive Officer; Jaime Caballero, Chief Financial Officer; Augusto Zubillaga, Chief Technical Officer; Martin Terrado, Chief Operational Officer; James Deckelman, Chief Operational Officer; Rodrigo Dalle Fiore, New Development and Portfolio Director; and Stacy Steimel, Shareholder Value Director. And now I would like to turn the call over to Mr. Andrés Ocampo. Mr. Ocampo, please, you may begin. Andrés Ocampo: Good morning, and thank you for…

[Operator Instructions] And our first question comes from Alejandro Demichelis from Jefferies.

Three questions, if I may. Maybe the first one, Andrés, is now that you're having more CapEx going to Vaca Muerta, so how should we think about the balance between extra CapEx, free cash flow, and cash returns to shareholders over the next kind of couple of years? That was the first question. Second question is, could you please provide us an update on the delineation and appraisal program that you have been conducting on CPO-5? And then the third question is on the new acreage in Vaca Muerta where you're doing the exploration, what do you see at the risk of the oil getting much heavier on that side of the basin, please?

Alejandro, it's Jaime. I'm going to address your first question, if you will, and it kind of tackles 2 angles as I understand it, which is how does this entry into Vaca Muerta and its capital profile and production profile affect shareholder returns? So I'm going to first talk a little bit about the CapEx profile and give you a little bit more detail what we already announced previously. When you look at the base case for Vaca Muerta and Mata Mora in particular, our goal is to reach 40,000 barrels of production around 2027. And we expect to retain a plateau of possibly 2, 3 years around that time. In order to get there, the CapEx exposure that we see to get there is going to be around $1.3 billion over the next 10 years, right? It's going to gradually escalate. We see this year, it's going to imply an incremental CapEx of about $100 million. Next year, about $160 million, $170 million, getting to a peak of $280 million around 2026. So that's what it's going to take in order to get there. Now we obviously need to put that in context, that getting there is going to have a significant EBITDA contribution to the company. This is a clearly value-accretive deal where we're seeing an incremental EBITDA for the company of between $360 million to $400 million per annum at $70. So in that context, what we are seeing is that over time, this deal is paying off by itself with its own cash generated, and it's going to allow us the cash flexibility to sustain our shareholder return strategy. So specifically, in the near term, what we're seeing is we are expecting to maintain our existing policy of $30 million in dividend distributions per annum. We…

Absolutely. Alejandro, thanks for your question. like Andrés mentioned in his initial remarks, we're really happy with CPO-5 performance. We keep breaking records. I kind of remember that in November 2018, '19, when we acquired Amerisur, that block was 8,000 barrels of oil per day, and like Andrés mentioned, we're at 30,000 [ now. ] We have put on production the well, Indico-3, and it's producing good rates, around 3,700 with no water. The rig continues drilling in the [indiscernible] when you look at delineation, like you were asking, you've got to remember, we got 2 wells that we drilled delineating the Barco formation. They were Halcon and Perico. Perico is delivering more than 900 barrels of oil per day with very low water cut. Halcon had completion challenges, so that well, it's not producing as well. And as we continue delineating [indiscernible], we are drilling the well Cisne. This is part of the Barco delineation that we're doing. We expect to be completing that well by late May. And after that, the rig will go and drill another exploration well called Lark. So that's kind of where we are on delineation. We expect to have that rig work in the full year.

Alejandro, this is Rodrigo. I'm going to tackle your question about Confluencia. Technically, what we see there is a continuation -- the continuity of Mata Mora to the east part. Of course, we know that there are certain regional trends like the heavy, for example, how it's going to affect the API and the gravity of the oil. But there are always good things that we can mention here because during the evaluation period, we saw really good results from, for example, [ Vista ] and Pan America in [indiscernible], where they are producing very good wells in the same trends where we are in confidential. So that's, from the technical point of view, what we see there, of course. And also, we have a robust report from DeGolyer and MacNaughton where they say that we have more than 200 million barrels as resources in the area. But to be honest, we have to deal with the block. And what we are doing now, we are drilling 3 wells. We expect the result before the end of this year. And also, we had just finished 234 square kilometers of [ seismic ] to complement this information. But we are optimistic and we expect a range of productivity in this area in line with the same rates that we see in Mata Mora.

And could you please confirm the rates that you see in Mata Mora Norte then?

Yes, we can go to Mata Mora Norte. During the evaluation period, we ran [indiscernible] we not only used the 26 wells that we have in Mata Mora, we also see the neighborhoods in these analog fields. And also, we have a reserve report from DeGolyer and MacNaughton. And at the end of the day, we see a range, a range between 600,000 barrels per day and 1 million as most of the wells. But what we see now is a clear learning curve, leading by our operator and partner because the most recent wells are outperforming. They are producing very, very good. You can see more than 2,000 barrels per day as a productivity. And another example, a good example that you can take is in February, the Mata Mora, 2,073 was the best producer well in the basin. So that's why we believe that the rate is adequate at the moment, but also we are seeing that our partner and operator is doing the things better every day. So that's why maybe this expectation is increasing in -- with the last results that we are seeing.

Our next question comes from Daniel Guardiola from BTG.

I think most of my questions are in Argentina. It would be great if you could share with us additional details on the acquired assets. I'd like to know, I mean, I know Jaime just talked about the expected CapEx for the upcoming years. But I don't know if Jaime, maybe you could share with us the total size of the development plan agreed with Phoenix for the development of Mata Mora Norte and what percentage of the total identified wells or drilling locations is this plan forecasting to cover? That would be my first question. The second one will be additional details on the Mata Mora Norte already drilled wells. So it would be great if you could share with us the IRRs so far that the company has seen per well. It'd be great to see the EURs of the type curve that you're seeing and the average realized prices at which Phoenix is basically selling its oil flowing out from Mata Mora Norte. And the third question and the last question is on future growth opportunities. I mean, my understanding is that after the closing of this transaction, your net leverage is now going to surpass 1.1x net debt to EBITDA, which is still very low, very healthy level. So I would like to know your thoughts on additional acquisitions similar to this one. And if you're thinking about it, what will be the main features you will be looking at when doing another acquisition? That will be all.

Daniel, it's Jaime here. I'm going to try and cover a number of the questions that you made, and I'm going to then pass it over to Rodrigo who is going to give us a little bit more color around Mata Mora Norte to date. So let's start first with your first question, which is essentially around our development plan philosophy. And I would start with this notion, which is that one of the key reasons why we decided to partner with Phoenix and why Phoenix decided to partner with us, frankly, was that a clear alignment around where we wanted to take the asset. And there is here a joint vision where we want to take the Mata Mora development to 40,000 barrels a day. In parallel, we want to fully explore Confluencia and hopefully add to that. And what we're seeing is 4 blocks that over time are going to have massive economies of scale and of development pace and even commercialization. So that's what we're aiming to do, right? And that vision that you can extract from our release takes us to anywhere between 40,000 barrels to 60,000 barrels a day within 5 years. The work program budget that we've agreed with them essentially reflects that. So the numbers that you've seen, we quoted about 150 remaining drilling locations, that's what we've identified with Phoenix, and that's what we want to pursue together with them. Same thing applies for Confluencia in the success case. Obviously, Confluencia is further behind, if you will, in terms of its maturity so those are not firm numbers. There's a derisking component associated to that. But in Mata Mora, it's actually quite firm and it's what -- essentially, it's what underpins the research numbers that you see us quoting. And how does…

Thank you, Jaime. Hello, Daniel, this is Rodrigo. We set that range between 600,000 barrels and 1 million as an average in the Mata Mora Norte area. But let me put this in a frame, in a time frame because what we see is a clear learning curve here. Most of the first wells in the area looks poor than the recent wells that we are seeing. So that means that the operator is doing a great job in order to improve not only the operational aspect but also the way that they are at least landing the wells because they switch from C2, what we call it, is a very [indiscernible] definition, but they started to drill new wells in other landing zones in the area where we have or we see better productivity. So that's part of the learning curve that we are seeing. So that's why if I had to summary this, the initial estimation that we see for the area is a well that can produce between 1,000 and 1,500 barrels a day as a peak at least in the first 2 months. Now we are seeing most of the wells producing more than 2,000 wells -- 2,000 barrels per day. So that's a great news for us. It's the reason because we are talking about wells that are producing for the last 3 months, but definitely, we see this trend in most of the activity that we carry out in the field. So that's a great news for us and for a deal, of course. Another thing that we see with optimistic eyes is the well cost. They were able to reduce the cost of the well more than $15 million at the beginning. Now they are drilling before -- between $14.3 million, and we expect to finish the year close to $13 million per well. So that's what we expect. That's the intention of the operator and, of course, our intention, too. So that's what we are seeing in terms of productivity, well costs. And of course, you asked about the plan. As Jaime mentioned, we expect to develop the 150 wells in the area. And that's the point that we have as a minimum plan with them. Andrés Ocampo: I think IRRs -- he also asked about IRRs expected from the wells.

The IRR is a range, of course, but we are seeing between 30% and 70%. Thank you for reminding.

Our next question comes from Roman Rossi from Canaccord.

Congrats on the results and the acquisition announced. So just wanted to get a sense regarding the facility with Vitol. I would like to understand how much are you expecting to use for the acquisition? And what are the terms beyond -- you mentioned it's SOFR plus 3.75%, but does it have an undrawn fund cost associated? And additionally, what's the cash target after the acquisition?

Hello, Roman. How are you? Let me cover the Vitol question. So I would start saying that the Vitol deal, it starts with being about commercial performance. Financing optionality is a plus. It's an upside, but the underpinning, it's commercial performance. So this deal covers and secures a very competitive commercial discount for our Llanos 34 production. That improved commercial differential is something that we're actually going to see coming across as better price realizations. I think we've quoted in the statement that this represents a $0.60 improvement over what we were seeing 2, 3 years ago. And that's a prime motivator for engaging in this type of deal. The nice thing is that beyond the commercial performance that this deliveries, it does provide significant financing optionality. So the key terms are we have -- Vitol has committed $300 million that we can draw at any time in the near term. It is unsecured. It has a very competitive interest. It reported SOFR plus 3.75% that's about 9% interest, which compares very favorably even with our own existing bond and the sort of interest that you would get in longer-term financing in the bond market today. It also gives us a grace period that extends until the end of this year without making any payments if we draw on the line, and it can be repaid at any time. So it actually keeps our longer-term financing options fully available for us if we believe that's the convenient thing to do and if the market conditions adjust to that. So that's kind of like the general framework. In terms of our plans with that line, I think the way that we think about it is, let me stand back and talk more broadly about how we are actually approaching this deal,…

Great. And maybe a follow-up on the acquisition. Do you say that you expect to close in Q3 so that will be impacting your fourth quarter financials, right?

Yes, Roman. So basically on this, I think there's 2 things, 2 key milestones you need to consider. I think there is an effective date and then there is the closing date. So regardless of closing, and let me define closing. So for the purposes of this deal, the private deal between Phoenix and GeoPark are fully complete. So that deal is complete, it's irrevocable. We have an agreement between us. Now when we talk about closing, we're really talking about the regulatory approval that the provinces in Argentina need to provide so that we are, if you will, the equivalent of a leaseholder, right? So that we come through in the public bid as a leaseholder. That's what we referred to closing on this. And there are 2 aspects. We need an approval in Neuquen for Mata Mora, and we need an approval in río Negro for Confluencia. So we are expecting that to occur within the next few months. When that occurs, that triggers the payments that I mentioned previously of $150 million to things. So that's what closing refers to. Despite that or having said that, the effective date is going to be the 1st of July. So the economic aspects of this deal are already effective starting on the 1st of July. So we start to look at all the accounting of the deal on that 50-50 basis, the 50% basis. Well, how is this going to translate into accounting? What we see is that subject to closing date, and let's assume that we close by the end of the 3Q, what you're going to see is that in the fourth Q financial statements, you're going to see this fully consolidated on a line-by-line basis, right? As an indication of that, in 4Q, you're going to see anywhere between 6,000, 7,000 extra barrels a day of performance, of production. You're going to see a share of costs. You're going to see all the different lines what this deal implies. On the EBITDA line, what you should be expecting for 4Q would be an additional EBITDA of around $30 million. That's what we are estimating at this time. So it's going to be fluid from here to there. But if I would have to give you a message is that consolidation starts post closing, but economic effects start the 1st of July, regardless of closing date. That's the bottom line.

Awesome. And just one last question on Colombia. So a couple of days ago, there was a public hearing at the Constitutional Court regarding the nondeductibility of royalties. So do you have any comments on that front? And say that they want to keep the nondeductibility valid for 2023, which is one of the alternatives that the government is trying to get. So will you need to pay more taxes or how that will work for GeoPark?

Sure, Roman. So let me provide some kind of broader context on this. So really, what's in discussion is that as part of the tax reform that was approved last year, the tax reform had 2 components. It had a surcharge linked to price environment on the corporate tax. That surcharge went from 0 to 15%. That's that's in place, it's not in discussion. The other component was the nondeductibility of royalties, which was declared inconstitutional (sic) [ unconstitutional ] by the Constitutional Court at the time. What has happened is that the government presented a recourse whereby they requested like a second hearing on that by the Constitutional Court. What the Constitutional Court has communicated is not a final decision on it but the willingness to perform that review, willingness to perform that review. While they do that, the prior decision still stands. So this does not suspend the decision that the Constitutional Court had already made of declaring that unconstitutional. What that means is that for -- we are actually in May, which is tax season, right? So we are in tax season. Companies are going to make a decision around how are they calculating the deductibility of royalties. What prevails at this time is that decision that, that is unconstitutional. So at least for GeoPark, we are going to act on the basis that, that's unconstitutional, right? And now what could happen later on is that the Constitutional Court decides to reconsider its previous decision, this will have an effect on next year's declaration, right? And there could be some form of a recognition of what was not paid in 2024. While we have estimated the impact, as I stated to that, we have estimated it between $12 million to $15 million. That's the rough estimate that we have associated to that. It is a range because it depends on things like royalties paid on time, fluctuating volumes. There are some moving pieces around that. So we estimated in the $12 million to $15 million range. Importantly, in the guidance that we have provided to you guys around our full year 2024 EBITDA, we actually -- this actually doesn't have any impact on that because the way that we provided that guidance, it assumed at the time, remember that this was the plan that we announced back in November. At the time, we were operating under the existing tax reform. So for us, this is an upside. If this is -- ultimately, this is confirmed as inconstitutional (sic) [ unconstitutional ]. it is an upside to our case, right? And if the government's idea of contesting this and timing this goes forward, it's not going to represent the downside.

Okay. Awesome. Contracts again on the acquisition.

And our next question comes from Oriana Covault from Balanz.

Many of them have been answered already, but I have one -- a couple of follow-ups on the Vaca Muerta acquisition. First, regarding the development and completion costs that you shared, it's my understanding that local [ prices ] have been in the $10 million to $11 million per well. So just to understand if this difference between the numbers that you're targeting, it's because of area specifics? And/or if you could share additional color on what you're seeing on your end. And also related to the Vaca Muerta acquisition, if you could comment on any, from the regulatory side of things, right, how are you seeing the landscape in terms of the possibility of repatriating profit of the operations once they are ongoing? And one last one regarding quality discounts. Congratulations on the commission agreement with Vitol. But just to understand if you're expecting any potential -- what are you seeing from the entry into operations of those refineries and kind of lower exports of crude oil? Could this potentially benefit you in terms of quality discounts? That would be a helpful color to have. Andrés Ocampo: Oriana, this is Andrés. Your line comes a little bit noisy. Let me repeat, if I am to see if we understood your questions correctly. Your first question is with respect to the drilling and completion cost of the wells that we are estimating for these assets?

Yes. It has to do with the drilling and completion costs compared to what local peers have been reporting in the same area. Our understanding is that it is closer to perhaps $11 million per well. So just to understand whether the difference is something area-specific or if you could share additional color on what you're seeing. And also on the Vaca Muerta transaction, the additional follow-up has to do with the regulatory challenges that you may see to the potential of taking profits from the operations. And the last one has to do with quality discounts and where do you see them going through the remainder of the year. Andrés Ocampo: So the second one is related to capital controls in Argentina and the last one to quality discounts on the crude sales, correct?

Yes. Sorry for the trouble with the line. Andrés Ocampo: No, no, that's okay. That's okay. So Rodrigo?

This is Rodrigo here. It's important to remind that the drilling costs 2 years ago was close to $16 million per well. Now the last -- in '23, the end the year with $14.3 million per well, so that's a tremendous improvement. Of course, this is because they learn but also they introduced technology and the services prices getting down. So that's the trend that we see for the future in the model we used for the next 2 years, $14.3 million per well. But after '26, with an extra drilling rig in area, we are talking about $13.6 million per well. So that's the base case that we have. But to be honest, what we see is it's a trend not only here in Argentina, but at the same time, you can see the same trend in Permian, the trend in efficiency in terms of drilling wells is continually improving. So that's why we expect better performance in the future and lower cost. But that's the cost that we use for the model.

Oriana, I guess, in terms of your [ DeGolyer ] around benchmarking, I think there's several considerations here. But I think the most important thing is to look at the trend, right? Regardless of who is the operator, what we're seeing in Vaca Muerta is a consistent trend where your cost per well is improving over time. I think as you would expect, there are differences from operator to operator. That's always the case. It depends on the standards that we use. It depends on a specific requirement of the locations and geographies where they are operating that allow synergies or not. The $10 million to $11 million cost per well that you're mentioning, we believe that is in the very low end. We prefer to use a more conservative assumption that ensures that we can maintain the robust well designs that have characterized Phoenix so far. That's something that actually attracted us to this deal and it has to do with this alignment of ways of operating and everything. And Phoenix is of the view that you need to ensure certain integrity standards and quality standards around the well, and we're comfortable with that. I think anything that can be delivered on top of the $13.6 million is going to be upside and that is, of course, a great news. With regards to your other questions, Oriana, the regulatory challenges in Argentina, I'd say the way that we structured that transaction is that the transaction needs to fly under the existing regulatory environment, right? So we are not banking on any type of positive developments in the regulatory environment, even though there are clear winds of change that could suggest that those upsides are possible. In the near term, the biggest consideration that we've looked into is capital controls…

Yes. Just one follow-up because maybe I wasn't fully clear, but I was referring more on the Colombian side of quality discounts. Just to understand how are you seeing the evolution of potentially fewer exports out of [indiscernible] because of the entry into operations of those [ low-cost ] refinery having a potential upside into your heavy crude [indiscernible]. That was more of the angle of this.

Yes, sure. Thanks for clarifying, Oriana. So I guess in Colombia, I'd say I'll start with a simpler view and then kind of a more broader kind of market there. In our case, the bulk of our production, which is Llanos 34, we've already secured commercial conditions for those to the Vitol deal. That covers about 20,000 barrels of production, give or take. And then what you're talking about is really the remainder, which is a combination of CPO-5, Llanos 34 exploration and Putumayo. The fundamentals for all of them are going in a positive direction. CPO-5 is a super high-quality crude that is extremely attractive to the local refineries in Colombia. We believe that we can maintain the existing differentials that we're seeing, the existing commercial differentials that we're seeing for that, which are actually a premium. We're actually getting a premium on Brent of about $5 a barrel on that. So we're very optimistic about the commercial differentials that we can get for CPO-5. On the Putumayo front, on Oriente front, what we're seeing is an interesting development where a number of players are actually quite interested in getting those volumes because they're able to export them through the Pacific or make blends, special blends associated to that. So overall, what I would tell you, Oriana, is that the sort of differentials that you saw in 1Q, we believe we can sustain them over the medium term.

And our next question comes from Alejandra Andrade from JPMorgan.

Mine is a quick one. I know you said you already have some existing infrastructure for transportation in Argentina, but just wondering because you said that there was a pipeline still that needed to be built in order to have all the proper infrastructure for exports and transportation. So just wondering if you could comment a little bit more on that.

Alejandra, this is Jaime. So yes, effectively, as part of this transaction, we secured the access to the midstream capacity that we need to make the deal work. Essentially, we've secured an entry into the [indiscernible] pipeline that provides us with a capacity of -- the equivalent of about 19,000 barrels per day. Of that, about 5,000 barrels a day are already in place, and the pipeline is under construction and is expected to be fully delivered by April 2026. So by that time, which is when we are starting to -- we're going to get near to the plateau production, we are expecting to have that capability fully in place. There's also open market access to redundant capacity in that pipeline where there's the ability to access that. And there are other projects in place to construct additional capacity in Argentina. But with respect to this deal, in particular, what we have secured is that 19,000 barrels a day that I mentioned. That covers essentially 50% of the plateau, right? So the way to think about it is that we have secured transport rights to export ports for about 50% of the production already. And there's optionality for other infrastructure that's going to come about over the next couple of years.

We currently have no further questions. I will hand back over to Andrés Ocampo to conclude. Andrés Ocampo: Thank you, everybody, for your interest and your support of our company. We're always here to answer any questions you may have. We encourage you to visit us in our field and our operations or call us any time for further information. So thank you, and have a good day.

And this concludes today's call. Thank you for joining. You may now disconnect your lines.