GeoPark Limited

Q1 2023 Earnings Conference Call


spk02: Good morning and welcome to Geoparks Limited conference call following the results announcement for the first quarter ended March 31st 2023. After the speaker's remarks there will be a question and answer session. If you would like to ask a question at this time press star 1 on your telephone keypad. If you would like to withdraw your question press star 2. 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 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 report 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 statement, 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 the US dollars, unless otherwise noted, reserved figures corresponding to PRMS standards. On the call today from Geopark is Andreas Ocampo, Chief Executive Officer, Veronica de Villa, Chief Financial Officer, Augustas Zubilaga, Chief Technical Officer, Martin Torredo, Chief Operating Officer, and Stacey Stimel, Share Value Director. And now I'll turn the call over to Mr. Andreas Ocampo. Mr. Ocampo, you may begin.
spk07: 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 CP05 due to matters that are beyond our control. We lost approximately 2,400 barrels a day of production from Indigo 6 and Indigo 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 38, a range of 38 to 40,000 bars 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, and following that, maintain 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 Janus 87 block and the successful drilling of the first horizontal well in the Tigana field in our core Janus 34 block. This first horizontal well was a great success, executed within budget and within time, and now flowing about 3,000 barrels a day with barely no 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. Next one is expected to start in June. The base business continues generating solid financial results with revenues 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 45 cents 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 0.7 times. 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 26th, 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 six to eight exploration wells, including exploration prospects in the Janus 123, 124, and CPO5 blocks, in addition to continue developing 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.
spk02: Thank you. If you'd like to ask a question, please press star followed by one on your telephone keypad. If for any reason you'd like to withdraw your question, it is star followed by two. As a reminder, if you're using a speakerphone, please remember to pick up your handset before asking your question. Our first question comes from the line of Stefan Burkhardt of Oxford Advisors. Your line is now open. Please go ahead.
spk04: Hi, guys. Thank you for taking my questions. I've got a few. The first one is around, so CPO5 is the restart of the two wells is now being pushed back to July. And I was wondering, in any particular context, my biggest, obviously, the question being my question is, there is not any stronger stance being taken by the government and whether you expect that 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 otherwise? And lastly, it's an accounting question. the royalty and the economical right, I think it's called economic right, in Q1. I see that million dollars, the value has dropped a lot compared to, I think, Q1 2022. Of course, the 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. Thank you.
spk07: Hi, Stefan. Good morning, and thank you for your questions. I addressed the question on CP05. 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 delays is typical delays in executing the operations or the constructions that were needed. So effectively, the reason why those two wells are shut in is because the ANH has requested the operator after a long time of being producing under temporary testing facilities to build definitive facilities which require some civil works and facilities construction. So when the operator gave us the May deadline to put those two wells back online, the actual work progress was barely zero. It hadn't been started, so this is when we gave the information before in March. Today, the advance in the works is in about 60 to 65 percent. And Martin Terrado was there just a couple of weeks ago overseeing the works and making sure that everything was advancing. So the works are being completed. Today, the estimation is to be end of June or July by the operator. That is being said to us with a 65% advance in the operations or in the facilities. So 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 request or anything like that that is working here. It's really just the typical that sometimes it happens, there's delays. when executing some of these civil works in the facilities. That's all. So 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. And 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, as I said at the beginning, this is a major production for our company. It is also part of the future and our upside. So we dedicate as much time and effort as we possibly can. And then I will let Evedo to answer the other two points that you mentioned, Stefan.
spk00: Thank you, Andrés. Good morning, Stefan, and thank you for your question. As you mentioned, we have reduced our CAPEX guidance for 2023 in $20 million, shifting it to $180 to $200 million total from $200 to $220 before. This is a product of constant looking for cost efficiencies and streamlining of our projects. In particular, there's a combination here of those two 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 Janus 86 and Janus 104 that are to the east of Janus 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 Putumajo and in some infrastructure projects to be carried out in Janus 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 CPO5. For Ecuador particularly, Originally, our original guidance included two to four wells in the first half of the year, and our current guidance is including one to two 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 doesn't have an EBITDA adjustment to it. What you will see as royalties get shifted from cash to in kind is that the revenue line, the top line, will drop, but the production and operation costs where the royalties are included will drop for a similar amount. Going forward, the definition of how royalties get paid, in cash or in kind, this definition is 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 this in our numbers going forward.
spk03: This is great and very clear. Thank you very much for taking my questions. Thank you, Stefan.
spk02: Thank you. Our next question comes from the line of Alex Dimitris of North Security. If your line is now open, please go ahead.
spk08: Yes, good morning, guys. Thank you very much for taking my questions. Just to follow up on the CPO5 situation, Andreas, so just to be clear, you don't have people seconded into the ONGC team. It's just Martin and his team overseeing things and going to the field? Is that the situation?
spk07: Yes, we do have people seconding the operations and that's how we maintain the flow of communications 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 CPO5 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's an operator that is responsible for these works.
spk08: Okay, but just to be clear, the work that was supposed to take two months is taking like six months now, yeah?
spk07: That's absolutely right.
spk08: 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 nine months, it has been almost $40 million. So trying to understand the plan going forward, are you changing the approach? Are you having some lessons learned from those kind of, let's say, less successful worlds that we have seen over the past few months?
spk06: Hello, Alejandro. Good morning. Zuby here. So just to give more context regarding your question, we have in our exploration plan to drill between 13 to 15 wells this year. In this first part of this year, finishing drilling seven wells, four unsuccessful, and three wells with positive results. One is the Waco Zuri that we already announced and commended in the last call. The well is on production. The other two wells are under evaluation and testing in the Janos 87 block. They are the Toloroid that is testing in the Mirador Formation with more than 200 barrels of oil per day without water. The other well is the Sorsal X1 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 six to eight more exploration wells that we are going to drill. One to two wells in channels 124, two wells in channels 123. Both blocks, to put you in your graphical context, are located to the west and neighbor of channel 34 block. So in CP05, we're gonna drill one to two wells. One of those, you know that we are, will be the first well in the block targeting the continuation of Tigana-Hakana geological trend. We also wanna drill one to two wells in channel 34. And we also have another evaluation, one well in Ecuador in the Perico block. So Alejandro, we are optimistic about our plan, and I'm sure that we give you news in the next operational update.
spk07: And to complement what Zub 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. the continuous and there's also new 3D seismic that comes in almost every three or five months because we are registering seismic in many places. So all this new information is factored into the model to 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.
spk08: That's great. Thank you very much. Thank you.
spk02: Thank you. Our next question comes from the line of Oriana Cobalt of Balance. Your line is now open. Please go ahead.
spk01: Hi. Thanks for taking my question. This is Oriana Cobalt with Balance. I had a couple of questions. If we may go one by one, that would be great. First, and it has to do with the persistently wider differentials for Colombian crude. despite expectations for compression. I noticed that they started compressing 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 quote-unquote situation? And just to get a sense from you guys on what are you observing?
spk00: Thank you, Oriana. Good morning. As you well mentioned, the Vasconia Differsion 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 lows 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 Basconia grade specifically, and the sustained affluence of Russian barrels into the market at discounted prices. Additionally, we've seen increased flows of Canadian crude into the U.S. Gold Coast market, which also affected the competitiveness of Basconia. But if you look forward, and we've 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, Close to a long-term historical average is about $4 to $5 versus Brent.
spk01: Perfect. That's very clear. Maybe just moving on to a process of relinquishing of exploration licenses in Putumayo area. I believe that headline came up. two days ago, so if you can comment on this process and do you have like an estimate of impairment loss that you broke in connection with this, any rationale behind this as well? Thank you.
spk07: Hi, good morning. Oriana Andres here. Yes, thank you. Not sure why these headlines are coming out right now, but just to be clear, when we acquired AmeriSUR, you know, 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 environmentally areas so which were in places where we have no intention to real intentions to go. 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 six that we were relinquishing, two of them have already been completed and there's four 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 path. It's just following the normal due course of any portfolio management of the company. That's all that it is.
spk01: Perfect. That's great. That would be all from my end. Thank you.
spk07: Okay. Thanks very much, Adriana.
spk02: Thank you. Our next question comes from the line of Roman Rossi of Canaccord. Your line is now open. Please go ahead.
spk10: And good morning, and thanks for taking my question, guys. I have a follow-up on the royalties. You mentioned that you are changing the amount of royalties you pay in kind. Just wanted to have more clarity around that. Is that affecting the tax rate you're paying with the new tax reform?
spk00: Thank you, Roman. Good morning. As I mentioned, yes, we're shifting those royalties in conjunction with the process that we do in coordination with the INH, with the operator. But as you well mentioned, as the tax reform has different treatment for royalties paid in cash and royalties 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.
spk10: Awesome. Thanks. And I have another one regarding the issues you are seeing in Chile. You are only considering EAMP as the possible off-taker or are you considering others? And do you have any clarity on when are you signing a new agreement?
spk00: In regard to Chile, so in the first quarter we've had commercial headwinds in the operation. We've been in negotiations with ENAP, our off-taker, but it's led to the shutting of crude production in our asset. About 400 barrels a day remain 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 circumscribed to ENAP, and we will continue to work on those and report on them as they come forward. In terms of expectations, 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.
spk10: Okay. Thank you very much for the answers.
spk02: Thank you. Our next question comes from the line of Bill Skolnick of Eight Capital. Your line is over. Please go ahead.
spk09: Yeah, thanks. Good morning. Just want to follow up just on the Ecuador deferral. Is there anything specific to cause that?
spk05: Good morning, Phil, and thank you for the question. This is Martin. Specifics are basically out of the comments from Vero and Suby in a sense that from a Exploration perspective, we had a total of exploration and development three to four wells for the year in the first half, and now we're moving to one to two wells in the second half. This is based also on our CAPEX adjustment. As you know, we had an eight-well commitment in those two blocks. We have already drilled five 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 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.
spk09: 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, you know, progress based on that?
spk05: Yes, no big surprises. It's basically looking at performance and continue evaluating how the whales behave.
spk09: OK, thanks. That's it for me. Thank you, Phil.
spk02: Thank you. So our next question is a text question. And it's from the line of Andrew DeLuca. of T-Row Price and it says, 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?
spk05: Thank you, Andrew. I will take the horizontal well question 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 channels 34. This well is targeting to the middle 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 Andres mentioned, Of course, after well number one, we learned from it, and we're looking forward to drilling the wells cheaper starting on well number two and so forth. We are expecting to drill one minimum to three wells in the remaining of the year in channels 34. Also, like Andrés mentioned, we will spot well number two in the month of June. And from a cost perspective, again, we expect to be obviously below the $10 million for the next wells.
spk00: 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 as tight as possible. 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 our higher OPEX in Colombia were transitory in nature. We accelerated well service activity that was already planned, that was executed in the quarter, and we also faced higher electricity costs, especially in Janus 34, but those were a function of weather factors. Being this factor's transitor, we expect our operating costs to drop from this level of the first quarter, expecting $8.5 to $9.5 on a consolidated basis for 2023, with Colombia about $7.5 to $8.
spk02: Wonderful, thank you. As there are no additional questions waiting at this time, I will hand the conference back over to Mr. Andreas Ocampo for closing remarks.
spk07: Thank you, everybody, for your interest in and support of Geopark. 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.
spk02: Ladies and gentlemen, this concludes the Geopark First Quarter 2023 Results Conference Call. Have a great day ahead. You may now disconnect.

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