Good morning, and welcome to the GeoPark Limited Conference Call following the results announcement for the first quarter ended March 31, 2024. 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 the company's business. All financial figures included here 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.

Good morning, and thank you for joining our first quarter conference call. Today, we're proud to report progress and very important results on all key elements of our business and strategy, with solid first quarter results coming from our improved base business, new significant share repurchases, a big and very attractive transformational acquisition, and impressive sustainability and decarbonization metrics. The underlying base business performance is continuing to deliver positive results. We had strong production in both the Llanos 34 and the CPO-5 blocks. In the Llanos 34, our core asset, the combination of our horizontal well program and increased water flooding project took gross production to a range of 56,000 to 57,000 barrels a day in early April, the highest level in the last 12 months. With the addition of the Indico-3 development well in April, the CPO-5 block production reached over 30,000 barrels a day, a new record. Our first quarter financial results were strong, generating over $111 million in adjusted EBITDA with a margin of 67%. During the quarter, we invested almost $50 million, and every dollar invested in the base business yielded around $2.30 in adjusted EBITDA. The return on capital employed for the last 12 months was 35%. The balance sheet remained strong as we ended the quarter with the highest cash position in the last 3 years, just over $150 million. Net leverage closed at 0.8x and remained well below our long-term target of 1 to 1.5x. We recently added an offtake and prepayment facility with Vitol that further improves our commercial terms and gives us access to up to $500 million of oil prepayment facility, providing immediate access to competitive and flexible financing. In the last 4 years, GeoPark has generated more than $475 million of net free cash flow, almost equivalent to our market cap, which was distributed to our shareholders in buybacks and dividends as well as to our creditors in debt repayment, proof of our commitment to maintain our capital discipline, a strong balance sheet while continuing to return value to our shareholders. This month, we successfully repurchased $43.7 million in GeoPark stock during the Dutch tender offer, reducing shares outstanding by approximately 8%. And our Board just declared a $7.5 million dividend to be paid on June 14. We have also recently published our SPEED Sustainability Report for 2023, which highlights that we reduced our greenhouse gas emissions intensity by 18% from 2022. At 10.6 kilos of CO2 equivalent per barrel, we're extremely proud to report that we have the lowest carbon intensity among our upstream Latin American oil peers. Our Llanos 34 block, which supplies close to 7% of Colombia's total oil production, had remarkably low intensity of 7 kilos of CO2 equivalent per barrel. With respect to our asset portfolio expansion, we announced on Monday a new transformational acquisition in Vaca Muerta in Argentina, a strategic asset in the world's fastest-growing unconventional play. The transaction includes high-quality assets with a combination of existing and fast-growing production and cash flow with a significant and tangible exploration upside. The Mata Mora Norte Block was producing about 3 years ago and is currently over 12,000 barrels a day from 26 wells in 8 pads, with a ninth pad of 4 wells already drilled and being completed now, expected to be put on production before the end of June. This production base is expected to grow to nearly 40,000 barrels a day within the next 4 years, an expected CAGR of 35% to 40% during the execution of the multiple remaining drilling locations. Upon closing of this transaction, we expect to add between 5,500 to 6,500 net working interest barrels of oil per day to our daily production, which is about a 15% to 20% increase to the first-quarter production. 50 million barrels of net 2P reserves represent a 43% increase versus our December 23 reserve certification, which includes also over $800 million of after-tax NPV10 at GeoPark working interest, equivalent to more than 4.5x the purchase price of Mata Mora Norte. An estimated annual net EBITDA of $90 million to $100 million in the full year 2024, which could grow by nearly 3x to $300 million at plateau production and at $70 Brent or more than 3.5x at current oil prices. Approximately 240 million barrels of gross 3C-certified contingent exploration resources in nearly 200 additional drilling locations, which could provide further significant growth even beyond the Mata Mora Norte plateau production. A significant part of this exploration upside is imminent as the first part has been built, and the first exploration well was spudded this month. We also have incorporated a new strategic partner, Phoenix Global Resources, which is part of the Mercuria Group, one of the world's leading energy trading companies. The technical and leadership teams at Phoenix have done an impressive job in bringing these assets to their current state, delivering significant production growth at highly competitive drilling, completion, and operating costs with further improvements being achieved on every new well. This team, both with Phoenix and at prior ventures, has more than a decade of experience in Vaca Muerta and have also taken part in the derisking of the entire Vaca Muerta oil and gas play in the earlier days. We're very proud and happy to be partnering with Phoenix and Mercuria in this new initiative. We have started a very busy year and have an exciting 2024 and beyond with some high-impact upcoming catalysts, both with drilling activity underway in our existing core asset base as well as the closing and drilling activity in our new Vaca Muerta assets. We look forward to reporting our progress to you. We remain committed to consolidating our leading position among Latin American energy companies producing sustainable hydrocarbons that guarantee energy security, reliability, and affordability in this rapidly changing world. We will now be happy to take any questions that you may have. Thank you.

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, how should we think about the balance between extra CapEx, free cash flow, and cash returns to shareholders over the next 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 on 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 to 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. 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 just announced the $7.5 million associated with the first quarter. And at the current price deck, we don't see any issue in maintaining that over time. At the same time, as you also noted, we performed the Dutch auction earlier in April. That's going to take our total shareholder returns this year to about $80 million, which is significantly above what we had last year. Last year, we had $61 million, for example. So all in all, what we're seeing with this deal is that it actually expands our capacity to maintain these returns over time. There is going to be a capital intensity associated. But given the returns that the asset provides, it doesn't affect our ability to provide an interesting yield to our shareholders. And lastly, I guess the other angle that needs to be covered when you're talking about shareholder returns, that's probably the cash component. We, of course, see with this deal that there is another angle, as I said, to the intrinsic value of the company. When you look at our reserves before this deal, we were talking about a 1P net asset valuation of about $1.1 billion and a 2P net asset valuation of about $1.8 billion. With this deal, the 1P net asset valuation goes to $1.5 billion, that's a 33% increase. And the 2P net asset valuation goes from $1.8 billion to $2.6 billion, that's a 46% improvement. So all in all, we believe that our shareholders are going to be benefiting from both sides, on one hand, from the direct cash yield angle, if you will, but also from intrinsic growth over time. On CPO-5, Martin? Martin, would you like to take CPO-5?

Absolutely. Alejandro, thanks for your question. As Andrés mentioned in his initial remarks, we are 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 at 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 delineation. When you look at delineation, as you were asking, you've got to remember we drilled 2 wells that were 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 is not producing as well. And as we continue delineating, 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. 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 throughout the full year.

Alejandro, this is Rodrigo. I'm going to tackle your question about Confluencia. Technically, what we see there is the continuation 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 the area, 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. What we are doing now, we are drilling 3 wells. We expect the result before the end of this year. 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 several assessments, we not only used the 26 wells that we have in Mata Mora, but we also examined the neighboring fields in these analog fields. We have a reserve report from DeGolyer and MacNaughton. At the end of the day, we see a range between 600,000 barrels per day and 1 million as most of the wells. However, what we see now is a clear learning curve, led by our operator and partner because most recent wells are outperforming. They are producing very good rates, you can see more than 2,000 barrels per day as productivity. Another example is that 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 we are also seeing that our partner and operator is improving every day. So that's why maybe this expectation is increasing with the recent results.

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. It would be great if you could share with us the IRRs so far that the company has seen per well. It would 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 a 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 would 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. 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 clear alignment around where we wanted to take the asset. 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. 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. That 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 with that. But in Mata Mora, it's actually quite firm and it's what essentially underpins the research numbers that you see us quoting. And how does that translate to actual activity? Essentially, we've committed with Phoenix to a 2-rig program over time. Currently, there's one rig. The second rig is going to come in the later part of next year. After that, we're seeing a sustained 2-rig drilling program indefinitely as more options arise. That's how we're thinking about it. The CapEx numbers that I quoted, Daniel, in the previous question are consistent with that. If you do the numbers of 350 wells, given the well cost, it's going to take you to that place. Let me cover now the average realized prices. Essentially, what we're seeing and what we are expecting, Daniel, is that there's 2 angles here. There is production that goes to international markets, and there's production that is sold domestically. Those ratios are going to change over time. If you look at history, that's been the case. So we cannot be too deterministic about it. But as a rule of thumb, what I would suggest is that we can sustain at least 30% of sales as domestic and about 70% can go to international markets. That's what we're seeing, I think that's going to change over time as the market evolves. This is a basin that is growing very quickly, and of course, that the commercial conditions around it as infrastructure matures and evolves are going to change as well. But generally speaking, that's the direction that we're seeing. What underpins that assumption, that 70% of the barrels can be exported, is that we are seeing a surplus whereby the needs of the refining sector in Argentina are very well met, so that allows for flexibility to export volumes. The sort of differentials that we're seeing are in the range of $10 to $12 versus Brent. That's the sort of discount that we are seeing and that we are modeling going forward as we look at this development. In terms of net leverage, you already reported, Daniel, the number that we're seeing, that kind of 1.1, that's not to exceed over the near term. I think what could change that is there's 2 angles that could change that. Leverage, I think that if we have a success case in Confluencia, possibly, our capital or possibly, no, our capital intensity will increase, but it will increase for the right reasons with substantial reserves, production, and EBITDA price associated with that. We modeled that at a very high level. Even in those scenarios, we are in the 1.2, we actually don't reach 1.3, even in those scenarios. So that gives you an idea of the profile that this development has. What that means is that we do have remaining firepower to engage in attractive inorganic opportunities. The way that I will frame this is that in the near term, clearly, our focus is on delivering our plan, our existing organic brand and now a high-quality incorporation of the assets into our portfolio. This is a big investment for GeoPark. We are going to get it right, and we need to get it right. In that sense, we're setting up a team that is going to work with Phoenix to progress this development plan as we've been discussing. We will be placing second deals. We're going to be securing the provincial approvals that we need to get the transaction closed within the next few months. We're going to set up performance management processes that allow us to have quality conversations with our partner and with the market regarding how this is evolving over time. And in the end, it's ultimately all about how can we efficiently and effectively collaborate with Phoenix to deliver the value promise that we're making with this deal. So that's clearly the priority. Having said that, our growth aspirations do not stop here. We will continue to be looking for strategic options that make sense for us. I think, Andrés, in the prior call, Daniel, when you asked about this, Andrés was very eloquent about our pan-regional aspiration. We are strong believers in the quality of Colombia, Brazil, and Argentina as world-class petroleum basins that we need to be in, and that's unchanged with this transaction. Actually, what I would say is that this transaction shows that and demonstrates that. But it's not the end. It's not the end. We will continue to look at options that make sense for us.

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. 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 look poorer than the recent wells that we are seeing. This 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 landing the wells. They have switched from C2, what we call a very specific definition, but they started to drill new wells in other landing zones in the area where we see better productivity. That's part of the learning curve that we are seeing. So if I had to summarize, 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 barrels per day. So that's great news for us. It's the reason we are talking about wells that have been producing for the last 3 months, but we definitely see this trend in most of the activity that we carry out in the field. 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 between $14.3 million, and we expect to finish the year close to $13 million per well. So that's what we are seeing in terms of productivity and well costs. You asked about the plan. As Jaime mentioned, we expect to develop the 150 wells in the area. That is the point that we have as a minimum plan with them. The IRR is a range, 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 you are 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? Additionally, what's the cash target after the acquisition?

Hello, Roman. I'm doing well, thank you. Regarding the Vitol deal, it's primarily about commercial performance, with financing flexibility being an added benefit. The deal ensures a competitive commercial discount for our Llanos 34 production, leading to better price realizations. We expect this to improve by about $0.60 compared to two or three years ago. Besides the commercial gains, the arrangement offers substantial financing options. Vitol has committed $300 million that we can access anytime in the near term, which is unsecured and comes with a favorable interest rate of SOFR plus 3.75%, approximately 9%. This compares favorably to our existing bond rates and current long-term financing options in the bond market. Moreover, we have a grace period until the end of this year with no payment obligations if we utilize the line, and repayments can be made at any time, keeping our long-term financing options open as conditions evolve. Looking at the broader picture regarding the Vaca Muerta deal, we have already paid $50 million from existing cash, with no financing involved. After that payment, we have a remaining balance of $110 million, and currently, we have that amount available. The next major milestone is the $150 million we need to pay at closing to fulfill the upfront requirements of the deal. It's also essential to note that the carry cost for the Confluencia wells will run parallel to this, which we estimate to be about $100 million this year. This means the total cost for the deal will exceed our initial plan by $250 million. To finance this, we expect to use a combination of the cash surplus we're accumulating at these prices and the Vitol financing facility. While this is flexible, I can indicate that we might utilize about $150 million from the Vitol facility this year for this purpose, with no interest due this year due to the grace period. Should we proceed this way, payments will begin next January, amounting to approximately $7 million a month. That’s the framework for thinking about our financial approach.

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 are 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, 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. This is what we referred to closing on this. There are 2 aspects. We need an approval in Neuquen for Mata Mora, and we need an approval in Río Negro for Confluencia. We are expecting that to occur within the next few months. When that occurs, that triggers the payments I mentioned previously of $150 million to things. Despite that or having said that, the effective date is going to be the 1st of July. We start to look at all the accounting of the deal on that 50-50 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 Q3, what you're going to see is that in the fourth quarter financial statements, you'll see this fully consolidated on a line-by-line basis. As an indication of that, in Q4, you'll see anywhere between 6,000 to 7,000 extra barrels a day of performance, of production. You'll see a share of costs. You'll see all the different lines this deal implies. On the EBITDA line, what you should expect for Q4 is an additional EBITDA of around $30 million. That's what we estimate at this time. The consolidation starts post-closing, but economic effects start on the 1st of July, regardless of closing date. That’s the bottom line.

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

Sure, Roman. Let me provide some broader context on this. The discussion revolves around the tax reform approved last year, which had two components. One was a surcharge linked to the price environment on the corporate tax that increased from 0 to 15%. This surcharge is currently in effect and is not under discussion. The other component involved the nondeductibility of royalties, which was declared unconstitutional by the Constitutional Court. The government has since requested a second hearing on this matter. The Constitutional Court has indicated its willingness to review the case, but the original decision still stands, meaning that the nondeductibility remains in place for now. This is particularly relevant as we are currently in tax season, and companies will need to decide how to approach the deductibility of royalties. For us at GeoPark, we will proceed under the assumption that the previous decision is unconstitutional. It's possible that the Constitutional Court may reconsider its ruling, which could affect future tax declarations. We estimate that the financial impact could range between $12 million to $15 million, depending on factors like timely royalty payments and fluctuating volumes. This figure is an estimate based on varying circumstances. Importantly, our guidance for full-year 2024 EBITDA remains unaffected by this situation, as it was established based on the previous plan announced back in November. If the decision is confirmed as unconstitutional, it would actually work in our favor. If the government's challenge proceeds, it would not pose a downside for us.

Okay. Awesome. Congrats again on the acquisition.

And our next question comes from Oriana Covault from Balanz.

Many of my questions have already been addressed, but I have a couple of follow-ups regarding the Vaca Muerta acquisition. First, about the development and completion costs you mentioned, I understand that local prices have been around $10 million to $11 million per well. Can you clarify if the difference between your targeted numbers is due to specific area factors? Also, could you provide additional insights on what you are observing? Furthermore, regarding the Vaca Muerta acquisition, could you discuss the regulatory landscape and the potential for repatriating profits once operations commence? Lastly, I would like to inquire about quality discounts. Congratulations on the commission agreement with Vitol. Can you share your perspective on how the start of operations at those refineries and the potential reduction in crude oil exports might affect you in terms of quality discounts? That would be helpful information.

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 you see them going through the remainder of the year.

This is Rodrigo here. It's important to note that the drilling costs two years ago were nearly $16 million per well. By the end of 2023, we reduced that to $14.3 million per well, which is a significant improvement. This reduction is due to both gained experience and the introduction of new technology, as well as lower service prices. We anticipate maintaining this cost of $14.3 million per well for the next two years. However, after 2026, with the addition of another drilling rig in the area, we are aiming for a target of $13.6 million per well. That's our base case. Honestly, we are observing a trend not only in Argentina but also in the Permian, with drilling efficiency continually improving. Therefore, we expect better performance and reduced costs in the future, which aligns with the costs we are using for our model.

Oriana, I guess, in terms of your benchmarking, I think there are several considerations, but the most important thing is to look at the trend. Regardless of who is the operator, what we're seeing in Vaca Muerta is a consistent trend where the 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 specific requirements of the locations and geographies where they operate that allow synergies or not. The $10 million to $11 million cost per well that you’re mentioning, we believe that is at the very low end. We prefer to use a more conservative assumption that ensures we can maintain the robust well designs that have characterized Phoenix so far. That’s something that attracted us to this deal, and it has to do with this alignment of ways of operating. Phoenix believes that you need to ensure certain integrity standards and quality standards around the well, and we’re comfortable with that. I think anything delivered on top of $13.6 million will be upside and that is, of course, great news. With regard to your other questions, Oriana, the regulatory challenges in Argentina, I would say the way we structured that transaction is that the transaction needs to fly under the existing regulatory environment. We are not banking on any 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 we looked into is capital controls, particularly those associated with money going into Argentina and coming out. I would say that our biggest consideration is that when you look at the profile of this program and the goals we talked about, we want to grow the asset quickly over the next 5 years, and it's not a big issue that capital controls because we actually expect that all revenues and EBIDTA generated will stay in the country to underpin that growth. I’m sure that over the medium and long term, options will arise if needed. But our priority now is making sure we can fully fund the growth of that asset, and we’re confident that we can do that under the existing regulation. Lastly, regarding the quality and discounts, I think it’s going to be very fluid. The important thing is the trend. What we’re seeing is that as Vaca Muerta grows, the surplus production relative to the requirements of domestic refining will just continue to grow. There is going to be a discussion between the regulator and between operators about how to distribute and allocate export capacities; surely, that’s going to develop over time. Even in a stressed scenario, where the need to alter that balance between exports and domestic sales exists, the quality of this asset will continue to allow for good returns, even in those scenarios. The extent we can have, if the market develops so there is a free market with perfect conditions, that will only represent upside for this deal.

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

Sure, thanks for clarifying, Oriana. I would start with a simpler view and then a broader market view. 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. What you're talking about is the remainder, a combination of CPO-5, Llanos 34 exploration, and Putumayo. The fundamentals for all of them are positive. CPO-5 is a super high-quality crude that is extremely attractive to the local Colombian refineries. We believe that we can maintain the existing differentials we are seeing, which actually are a premium. We're getting a premium on Brent of about $5 a barrel for that. So we're very optimistic about the commercial differentials we can get for CPO-5. On the Putumayo front, what we're seeing is an interesting development where several players are quite interested in getting those volumes because they're able to export them through the Pacific or create special blends associated with that. Overall, what I would tell you, Oriana, is that the differentials you saw in Q1, 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. 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 pipeline that provides us with a capacity equivalent of about 19,000 barrels per day. 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. By that time, which is when we are starting to near 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 capacities in Argentina. 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. 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 over the next couple of years.

We currently have no further questions. I will hand back over to Andrés Ocampo to conclude.

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.