Good morning, and welcome to the GeoPark Limited conference call following the results announcement for the first quarter ended March 31, 2023. If you do not have a 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. These statements are subject to risks and uncertainties that could cause actual results to differ materially from those described. 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. All financial figures included herein were prepared in accordance with IFRS and are stated in U.S. dollars unless otherwise noted. Reserve figures correspond 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.

Good morning, and welcome, everyone, to our first quarter results call. We're joining with our team here in Bogota, where we just celebrated our 10th anniversary in Colombia and our 20th year as a company. We're proud of our accomplishments so far. Today, we are the second largest operator in Colombia, with about 8% of the country's oil production, and are excited about the future in Colombia and in Latin America as well. During the first quarter, we suffered some temporary production shortages, particularly in CPO-5, due to matters that are beyond our control. We lost approximately 2,400 barrels a day of production from the Indico-6 and Indico-7 wells and have been working on assisting the operator to get those two wells back online as soon as possible. As a result of these shortages, and as previously announced, with the operator's new expectation that these wells may not be back online before July, we had to revise our full year production guidance down to a range of 38,000 to 40,000 barrels a day. Despite these challenges, we were able to adapt quickly, streamline our capital allocation, and continue reducing our cost base to maintain our cash flow generation guidance. Following that, we maintained our shareholder return program unchanged. During the first quarter, we invested $45 million to drill 12 wells, all in Colombia, including wells in new exploration acreage in the Llanos 87 block and the successful drilling of the first horizontal well in the Tigana field in our core Llanos 34 block. This first horizontal well was a great success, executed within budget and on time, and is now flowing about 3,000 barrels a day with barely any water. In less than two months, the well has accumulated 50% of the production needed to recover the investment, encouraging our team to define multiple new drilling locations going forward. The next one is expected to spud in June. The base business continues generating solid financial results, with revenue topping about $182 million and an adjusted EBITDA of almost $115 million, a 63% EBITDA margin. Cost and capital efficiencies were a highlight of the quarter once again. And despite inflationary pressures, we were able to reduce our structured costs, G&A, and G&G by 6% compared to the first quarter last year. Every dollar invested generated $2.50 in adjusted EBITDA, which showed both the efficiency of our capital investments and the profitability of our assets. Over the past 12 months, we have generated a 62% return on capital employed. Bottom line in the quarter, we generated $26 million of net profits or $0.45 per share during this quarter. Following our debt reduction of $275 million during the last two years, our interest payments in the quarter were down by 30% to $13.5 million. We ended the quarter with $145 million of cash in hand and a net leverage ratio of just 0.7x. We continue to deliver on our increased program to return more value to shareholders. Share buybacks increased by 142% to $7.5 million, and cash dividends increased by 55% to $7.5 million, approximately a 5% dividend yield. On April 26, GeoPark published its 2022 SPEED ESG report, from which I would highlight our 34% carbon intensity reduction, which is a big step towards meeting our near and mid-term goals, as well as the positive impact that we were able to have on 240,000 people that benefited from the company's social and environmental programs in 2022. Looking forward, we're executing the multi-year drilling program in our core and surrounding blocks in the Llanos basin. For the remainder of 2023, we're targeting the drilling of 6 to 8 exploration wells, including exploration prospects in the Llanos 123, 124, and CPO-5 blocks, in addition to continuing to develop our core asset base. We look forward to reporting results on these activities in the upcoming quarters. Thank you, and we will be happy to answer your questions.

Our first question comes from Stephane Foucaud of Auctus Advisors.

I have a few questions. The first one is regarding the CPO-5 restart of the two wells, which is now delayed until July. Can you provide any specific context on this? My main concern is whether the government plans to take a stronger stance and if you anticipate any further delays beyond the new July date. My second question relates to the reduction in CapEx. Could you clarify what activities have been removed from the program? Are these related to exploration, development, or something else? Lastly, I have an accounting question regarding the royalties and economic rights in Q1. I noticed that the value has significantly dropped to $1 million compared to Q1 2022. While I understand that oil prices are lower, this drop seems excessive. Could you explain the reasons behind this decline and whether there is a possibility for a recovery in the future?

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 one 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. Effectively, the reason why those two wells are shut in is that the ANH has requested the operator after a long time of being produced under temporary facilities to build definitive facilities, which require some civil works and facility construction. So when the operator gave us the May deadline to put those two wells back online, the actual work progress was barely 0. It hadn’t been started. So this is when we provided the information before in March. Today, the advance in the works is about 60% to 65%. Martin Terrado was there just a couple of weeks ago overseeing the works and ensuring that everything was advancing. The works are being completed. Today, the estimation is to be the end of June or July by the operator. That is being said to us with a 65% advance in the operations. Therefore, the degree of confidence we have on this new date is higher than the one we would have had on the May date we gave before. So that's the reason. There's no new government requirements or any unreasonable requests; it's really just the typical delays that sometimes happen when executing some of the civil works in the facilities. We hope we can meet that date in July, and we are working and assisting the operator as much as we can. I took two trips to New Delhi this year already. We spent time with the management team of ONGC, as we always do. As I said, Martin visited the operation and is in constant daily conversations with the ONGC crew to make sure that all these activities are completed as soon as possible. Obviously, this is a major production for our company. It is also part of the future and our upside. We dedicate as much time and effort as we possibly can. I will let Vero answer the other two points that you mentioned, Stephane.

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 our projects. In particular, there's a combination of those two factors: cost efficiencies and adjustment to projects. About half comes from cost savings in the execution of seismic that will happen in the blocks Llanos 86 and Llanos 104, which 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. 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, 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. Regarding your question on royalties, as you mentioned, the royalties are lower in the first quarter. This 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, but you will see, as royalties have shifted from cash to in kind, that the revenue line, the top line will drop, but the production and operating costs, where the royalties have been included, will drop for a similar amount. Going forward, the definition of how royalties get paid, in cash or in kind, is a decision made jointly with the regulator. We would expect to still have more royalties shifted to in kind during the year. Hence, 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 situation, Andrés. Just to be clear, you don't have people seconded to the ONGC team. It's Martin and his team overseeing things and going to the field. Is that the situation?

Yes. 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. On top of that, we have Martin and his team and our asset managers dedicated to CPO-5 that work all the time, continuously supporting and providing any help required by the operator. But we cannot actively execute some of these activities ourselves. There is an operator that is responsible for these works.

Okay. But just to be clear, that was supposed to take 2 months; it's taking like 6 months.

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 months, it has been almost $40 million. 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. Just to give more context regarding your question. We have in our exploration plan to drill between 13 to 15 wells this year. In the first part of this year, we finished drilling 7 wells, 4 unsuccessful and 3 wells with positive results. One is the Llanos 34 well that we already announced and commented on in the last call. The well is on production. The other two wells are under evaluation and testing in the Llanos 87 block. They are the Tororoi that is testing in the middle of formation with more than 200 barrels of oil per day without water. The other well is the Zorzal that we are developing, the workover plan to be able to test the light oil that showed in the initial test. In both wells, we are working on work plans and volumes for possible future development plans. For the rest of the year, we have at least 6 to 8 more exploration wells that we are going to drill. We want to do well in Llanos 124, 2 wells in Llanos 123, both blocks located to the west and neighboring Llanos 34 block. In CPO-5, we’re going to drill 1 to 2 wells. One of those will be the first well targeting the continuation of the Tigana Jacana geological trend. We also want to drill 1 to 2 wells in Llanos 34. Additionally, we have one well in Ecuador in the Perico block. Thus, we are optimistic about our plan, and we're sure that we'll give you news in the next operational update.

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. That continues, and there's also new 3D seismic that comes in almost every 3 to 5 months because we are registering seismic in many places. So this allows us to recalibrate and remap new prospectivity areas, or remap existing prospectivity areas where we had prospects before. Yes, the campaign in the second half of the year factors in the results of the first half of the year.

Our next question comes from the line of an unidentified analyst.

This has to do with the persistently wider differentials for Colombia 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 a new normal situation and just to get a sense from you guys on what you are observing?

Thank you. Good morning. As we mentioned, the Vasconia differential has been volatile and 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. During the quarter, we even saw losses of $9. 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 competing with our Vasconia grade and the sustained influx 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. However, looking forward, you've already seen the compression thus far of the differentials. A key factor going forward is the impact of the Chinese reopening on 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 of about $4 to $5 versus Brent.

That's very clear. Maybe just moving on to a process of relinquishing exploration licenses in the Putumayo area, I believe that headlines came up 2 days ago. Could you comment on this process? Do you have an estimate of impairment loss that you booked in connection with this? Any rationale behind this as well?

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 in late 2019, early 2020, we picked up about 12 blocks in the Putumayo basin. From these blocks, we started between 2020 and 2021 various processes for relinquishing some of these areas because they are in either less prospective areas or more difficult access areas or more sensitive environmental areas. We started the relinquishment of these blocks a long time ago. 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 with those because we have not allocated any capital to any of these blocks in the past. It's just following the normal due course of any portfolio management of the company.

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. I just wanted 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 with the process that we do in coordination with D&H, with the operator. But as you mentioned, the tax reform has different treatments for royalties paid in cash and relative paid in kind in terms of deductibility. Moving royalties to being paid in kind would have a positive impact on our income tax numbers.

I have another one regarding the issues you are seeing in Chile. Are you only considering ENAP as the possible offtake? Or are you considering others? Do you have any clarity on when you will be signing a new agreement?

In regards to Chile, 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 our assets. About 400 barrels a day remains shut in, and the asset is currently producing gas and condensate. We continue to work on different commercial alternatives for the assets, not only to conscribe to ENAP. We will continue to work on those and report on them as they come forward. In terms of expectations, it's uncertain when we will be able to renew our contract or finalize other commercial alternatives, which is why we've included 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 on the Ecuador deferral. Is there anything specific causing that?

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

Okay. Were there any surprises then? Or do you just want to look at the data and progress based on that?

Yes. No big surprises; it's basically looking at performance and continuing to evaluate how the wells behave.

So our next question is a technical question. It's from the line of Andrew De Luca of T. Rowe Price. 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. We're really happy and excited about the first horizontal well that was drilled in Llanos 34. This well is targeting the Mirador formation. It has around 1,500 feet in the horizontal section and is 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 we saw to optimize the recovery factor of that formation. The cost of that well was around $10 million, within budget and on time, as Andrés mentioned. After well #1, we learned from it and are looking forward to drilling the wells cheaper, starting with well #2 and so forth. We're expecting to drill a minimum of 1 to 3 wells in the remaining year in Llanos 34. Additionally, as Andrés mentioned, we will spud well #2 in June. From a cost perspective, we expect to be below the $10 million for the next wells.

Thank you, Martin. Moving on, Andrew, to your question regarding OpEx. Our team works diligently on keeping our costs as tight as possible. This is reflected in the fact that we kept the 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 was in line for other assets. However, the main factors pushing higher OpEx in Colombia were transitory in nature. We accelerated well service activity, which was already planned, and we also faced higher electricity costs, especially in Llanos 34, but those were a function of weather factors. Since these factors are transitory, we expect our operating costs to drop from the first quarter level, 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.

Thank you, everybody, for your interest in and support of GeoPark. We are 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.