Good morning, and welcome to the GeoPark Limited conference call following the results announcement for the first quarter ended March 31, 2023. [Operator Instructions]. If you do not have the copy of the press release, it is available at the Invest With Us section of the company's corporate website at www.geo-park.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 developments and risk factors listed from time to time in the company's SEC reports and public releases. Those lists 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 herein were prepared in accordance with the IFRS and are stated in U.S. dollars unless otherwise noted. Reserve figures corresponding to PRMS standards. On the call today from GeoPark is Andrés Ocampo, Chief Executive Officer; Veronica Davila, Chief Financial Officer; Augusto Zubillaga, Chief Technical Officer; Martin Terrado, Chief Operating Officer; and Stacy Steimel, Share Value Director. And now I'll turn the call over to Mr. Andrés Ocampo, Mr. Ocampo, you may begin. Andrés Ocampo: Good morning, and welcome, everyone, to our first quarter results call. We're joining with our team here in Bogota, where we just…

[Operator Instructions]. Our first question comes from the line of Stephane Foucaud of Auctus Advisors.

I've got a few. The first one is around -- so CPO-5 is the restart of the 2 wells is now being pushed back to July. And I was wondering any particular context. My biggest, obviously, the question would be -- my question is there is not any stronger stance being taken by the government and whether you expect that the July is -- there could be some further delays compared to the new date of July. That's my first question. The second one is around the CapEx reduction. I was wondering what activities have been taken out from the program? If you could comment on that. Is that exploration? Is that development or otherwise? And lastly, it's an accounting question. It's around the royalty and the economical right, that's medical and economic rights in Q1. I see that $1 million, the value has dropped a lot compared to I think Q1 2022. Of course, oil price is a bit lower, but it doesn't seem to justify such a big drop. So I was wondering what was behind the drop and whether there would be a catch-up at some point or not. Andrés Ocampo: Good morning, Stephane. Thank you for your questions. I'll address the question on CPO-5. Obviously, this is a very important element of the business for us. It's 1 of the most important blocks for GeoPark. So the main reason for the delay is typical delays in executing the operations or the constructions that were needed. So effectively, the reason why those 2 wells are shut in is because the ANH has requested the operator after a long time of being producing under temporary facilities, temporary testing facilities to build definitive facilities with -- which require some civil works and facilities construction. . So when the operator…

Thank you, Andrés. Good morning, Stephane, and thank you for your question. As you mentioned, we have reduced our CapEx guidance for 2023 to $20 million shifting it to $180 million to $200 million total from $200 million to $220 million before. It's a project of -- constant looking for cost efficiencies and streamlining of our projects. In particular, there's a combination here of those 2 factors, cost efficiencies and adjustment to projects. About half comes from cost savings in the execution of seismic that will be happening in the blocks Llanos 86 and Llanos 104 that are to the east of Llanos 34 and the result from cost savings in the contracting process of these activities. About 25% also comes from savings in the drilling and completion in Putumayo and in some infrastructure projects to be carried out in Llanos 34. And the remaining 25% comes from an adjustment to the drilling schedule that is getting pushed out mainly in Ecuador and to a lesser extent, in CPO-5. For Ecuador, particularly, originally -- our original guidance included 2 to 4 wells in the first half of the year, and our current guidance is including 1 to 2 wells in the second half. And then moving on to your question on royalties. As you well mentioned, the royalties are lower in the first quarter. And it has the impact of prices that you mentioned, so at lower prices, you get a lower royalty component and also from the shifting of some of the royalties that are paid in cash to being paid in kind. This second impact, net-net, doesn't have an EBITDA adjustment to it, right? But you will see, as royalties have shifted from cash to in kind is that the revenue line, the top line will drop, but the production and operation cost where the royalties have included will drop for similar amount. Going forward, the definition of royalties get paid, in cash or in kind is the decision made jointly with the regulator. And we would expect to still have more royalties shifted to in kind during the year. So you could see a continuation of these numbers going forward.

Our next question comes from the line of Alex Demichelis of Nau Securities.

So to follow up on the CPO-5 situating, Andrés. So just to be clear, you don't have people seconded to the ONGC team. It's Martin and his team kind of overseeing things and going to the field. Is that the situation? Andrés Ocampo: Yes. I mean, we do have people seconded in the operations, and that's how we maintain the flow of communication with the field operations on a daily basis. But on top of that, we have Martin and his team and our asset managers dedicated to CPO-5 that work all the time and continuously supporting and providing any help that may be required by the operator. But actively we cannot execute some of these activities ourselves. There is an operator that is responsible for these works.

Okay. But just to be clear, there were -- that was supposed to take 2 months, it's taking like 6 months. Andrés Ocampo: That's absolutely right.

Okay. That's clear. And then the second question is more on the exploration front. When we look at your exploration charges over the past kind of 9 manihots, it has been almost $40 million. So I'm trying to understand the plan going forward. Are you changing the approach? Are you having some lessons learnt from those, kind of, let's say, less successful wells that we have seen over the past few months?

Alejandro, good morning. Zubi here. So just to give more context regarding your question. We have in our exploration plan to dill between 13 to 15 wells this year. In this first part of this year, finished drilling of 7 wells, 4 unsuccessful and 3 wells with positive results. 1 is the [indiscernible] Llanos 34 that we already announced and commented in the last call. The well is on production. The other 2 wells are under evaluation and testing in Llanos 87 block. They are the Tororoi that is tested in the middle of formation with more than 200 barrel of oil per day without water. The other well is the Zorzal that we are developing, the work over plan to be able to test the light oil that showed in the initial test. In both wells, working in work plans and volumes for a possible future development plans. For the rest of the year, we have at least 6 to 8 more wells, exploration welled that we are going to drill. We want to do well in Llanos 124, 2 wells in Llanos 123, both blocks to in geographical contest are located to the west and neighbor of Llanos 34 block. So in CPO-5, we're going to drill 1 to 2 wells. 1 of those. You know that we are -- will be the first well in the targeting the continuation of Tigana Jacana geological trend. We also want to drill 1 to 2 wells in Llanos 34. And we also -- we have an evaluation 1 well in Ecuador in the Perico block. So Alejandro, we are optimistic about our plan and we are sure -- I'm sure that we'll give you news in the next operational update. Andrés Ocampo: And to complement what Zubi is saying, Alejandro, to your point, of course, every well that we drill provides new information that is factored into our model to recalibrate the new prospectivity of the area. So that continues, and there's also new 3D seismic that comes in almost every 3 or 5 months because we are registering seismic in many places. So [Technical Difficulty] recalibrate and remap new prospectivity areas or remap again, existing prospectivity areas where we had prospects before. So yes, the campaign on the second half of the year does factor in the results of the first half of the year.

Our next question comes from the line of [indiscernible].

This is [indiscernible] [Technical Difficulty] has to do with the persistently wider differentials for Colombia and crude despite expectations for compression, I noticed that they started compression in late March, April. But I'd like to understand better what is driving this? And where do you see differentials heading? Are we under like a new normal "situation" and just to get a sense from you guys on what are you observing?

Thank you, . Good morning. As we mentioned, the Vasconia differential has been volatile and has been wider, especially during the first quarter. It's now trading about $6 below Brent, averaging $7.5 year-to-date versus $5.5 for the full year of 2022. And during the quarter, we even saw a loss of $9. So your point is absolutely right, we've seen volatile and wide differentials. The drivers behind this are a few, but I would highlight, one, increased crude out of Venezuela coming to compete with our Vasconia grade specifically and the sustained affluence of Russian barrels into the market at discounted prices. Additionally, we've seen increased flows of Canadian crudes into the U.S. Gulf Coast market, which also affected the competitiveness of Vasconia. But if you look forward, and you have already seen it in the compression thus far of the differentials. A key factor going forward is the impact of the Chinese reopening in the demand for our crude, and we expect that to continue easing the differentials as the Chinese demand picks up and the appetite for our crude increases. We would expect a recovery in the differentials for the remainder of the year, closer to the long-term historical averages about $4 to $5 versus Brent.

Perfect. That's very clear. Maybe just moving on to a process of relinquishing of exploration licenses in Putumayo area, I believe that headlines came up 2 days ago. So if you can comment on this process? And do you have like an estimate of impairment loss that you book in connection with this? Any rationale behind this as well. Andrés Ocampo: Good morning, Oriana, Andrés here. Yes, thank you. Not sure why these headlines are coming out right now. But just to be clear, when we acquired Amerisur end of 2019, early 2020, we picked up about 12 blocks in the Putumayo basin. And from these blocks, we started between 2020 and 2021. We started some different processes for relinquishment of some of these areas because they are in either less prospective areas or more difficult access areas or more sensitive environmental areas. So -- which were in places where we have no intention to -- real intentions to go. So we've started the relinquishment of all these blocks a long time ago. And some of them have been completed, I think out of the 6 that we were relinquishing, 2 of them have already been completed, and thus 4 more to be completed. There's no impairment associated to those because we have not allocated any capital to any of these blocks in the past. So it's just following the normal due course of any portfolio management of the company. That's all that it is.

Our next question comes from the line of Roman Rossi of Canaccord.

I have a follow-up on the royalties. You mentioned that you are changing the amount of royalties you pay in time. Just wanted to have more clarity around that. Is that affecting the tax rate you are paying with the new tax reform?

Thank you, Roman. As I mentioned, yes, we're shifting those royalties in conjunction is the process that we do in coordination with D&H, with the operator. But as you well mentioned, right, as the tax reform has different treatment for royalties paid in cash and relative paid in kind in terms of the deductibility. Moving royalties to being paid in kind would have a positive impact on our income tax numbers.

And I have another one regarding the issues you are seeing in Chile. You're only considering ENAP as the possible offtake? Or are you considering others? And do you have any clarity on when are you signing a new agreement?

In regards to Chile. So in the first quarter, we've had commercial headwinds in the operation. We've been in negotiations with ENAP, our offtaker, but it's led to the shedding of crude production in the -- in our assets, about 400 barrels a day remains shut in and the asset is currently producing gas and condensate. We continue to work in different alternatives, commercial alternatives for the assets, not only to conscribe to ENAP. And we will continue to work on those and report on them as they come forward. In terms of expectations, we -- it is uncertain when we will be able to renew our contract or finalize other commercial alternatives and that's why we've taken the approach of including this production as being shut in, in our guidance.

Our next question comes from the line of Phil Skolnick of Eight capital.

Just want to follow up just on the Ecuador deferral. Is there anything specific to cause that?

Good morning, Phil, and thank for the question. This is Martin. Specifics are basically out of the comments from Vero and Zubi in a sense that from a exploration perspective, we had a total of exploration and development 3 to 4 wells for the year in the first half, and now we're moving to 1 to 2 wells in the second half. This is based also on our CapEx adjustment. And as you know, we had an 8-well commitment in those 2 blocks. We have already drilled 5 wells. So we're looking at the performance of the wells, water cut, decline rate. We also finished the seismic. So we decided to move further activity in the second half of the year so that we get more information from the subsurface. And we also align it with our CapEx for the rest of the year.

Okay. So I mean, were there any kind of surprises then? Or is it just more -- just -- you just want to look at the data and just progress based on that?

Yes. No big surprises, it's basically looking at performance and continue evaluating how the wells behave.

So our next question is a tech question. And it's from the line of Andrew De Luca of T. Rowe Price. And it says, on horizontal drilling, can you please let us know how many additional horizontal wells do you plan to drill? What is the CapEx associated with the horizontal well, lifting costs increased in Q1? Can you please specify what drove the increase and where you see this in 2023?

Thank you, Andrew. I will take the horizontal well questions and let Veronica then go over the lifting cost. But absolutely, we're really happy and excited about the first horizontal well that was drilled in Llanos 34. This well is targeting to the Mirador formation. It has around 1,500 feet in the horizontal section, and it's performing according to plan and slightly above it. Right now, the well is producing 3,000 barrels of oil per day with no water and a very low drawdown. Mirador is a formation with a very active aquifer and this was one of the opportunities that we saw to optimize the recovery factor of that formation. The cost of that well was around $10 million, within budget and within time, as Andrés mentioned. And of course, after well #1, we learned from it. And we're looking forward to drilling the wells cheaper in the -- starting on well #2 and so forth. We are expecting to drill 1 minimum to 3 wells in the remaining of the year in Llanos 34. Also, like Andrés mentioned, we will spud well #2 in the month of June. And from a cost perspective, again, we expect to be obviously below the $10 million for the next wells.

Thank you, Martin. Moving on, Andrew, to your question in terms of OpEx. As always, our team works very diligently in our cost management, working to keep our costs tight -- as tight as possible. And this is reflected on the fact that we keep cost per BOE flat at $8 per BOE consolidated year-on-year in 2022. In the first quarter of 2023, we've seen higher OpEx, about $10.1 per BOE on a consolidated basis. This came from an increase in Colombia, which registered a total of $9.6 per BOE and also in Ecuador, while it was in line for other assets. But the main factors pushing or higher OpEx in Colombia were transitory in nature. We accelerated well service activity. It was already planned that was executed in the quarter. And we also faced higher electricity costs, especially in Llanos 34, but those were a function of weather factors. Being these factors transitory, we expect our operating cost to drop from this level of the first quarter, expecting $7.5 to $9.5 on a consolidated basis for 2023 with Colombia about $7.5 to $8.

As there are no additional questions at this time, I will hand the conference back over to Mr. Andrés Ocampo for closing remarks. Andrés Ocampo: Thank you, everybody, for your interest in and support of GeoPark, and we're always available to answer any questions you may have. We encourage you to please visit us and our operations and call us any time for more information. Thank you, and have a good day.

Ladies and gentlemen, this concludes the GeoPark First Quarter 2022 Results Conference Call. Have a great day ahead. You may now disconnect.