GeoPark Ltd Q2 FY2023 Earnings Call

Good morning, and welcome to the GeoPark Limited conference call following the results announcement for the second quarter ended June 30, 2023. After the speakers' remarks, there will be a question and answer session. 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.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 Reforms 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 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, Shareholder Value Director. And now I will turn the call over to Mr. Andrés Ocampo. Mr. Ocampo, you may begin.

Good morning, everyone and welcome to our second quarter results call. We are joining with our team here in Bogotá, Colombia. We are advancing on our drilling program, which is already delivering results. We drilled 10 wells in the second quarter and have a busy schedule ahead of us with 10 rigs now in operation and two more coming this quarter. Our horizontal well drilling campaign in the Mirador formation in the Llanos 34 block is moving ahead at full speed with two wells already completed and on production, and the third one already started and about 30-days from reaching total depth. Besides some of the highest capital return projects in our company, the first horizontal well has already been paid off in approximately 3.5-months and continues producing over 2,000 barrels of oil per day. Our team is quickly taking advantage of the multiple wells campaign and applying new cost efficiencies to the next ones. The second well was drilled faster with 10% lower drilling costs and 32% longer lateral length. We expect to continue pushing these costs down to improve our payback and capital returns even more. Our exploration team has also delivered a new discovery in the Genos basin acreage that we acquired during the 2019 bid round. Saltador 1, our first well of the Llanos 124 block, is producing approximately 880 barrels per day with 5% water. In Ecuador, the Gen2 development well in the Perico block has encountered a new phase zone in the U-sand formation in addition to confirming its development potential in the OG information. Therefore, we expect to test this new zone before the end of this month. In the CPO-5 block, where our production has been down due to two very productive wells being shut in, the operator has advanced and completed most of the work requested by the ANH and anticipates that it will have the two wells back online before the end of the month. They also expect to spot the Halcon 1 exploration well in September, which contains the potential continuity of the Jacana play into the CPO-5 block. Following Halcon 1, the operator expects to drill another development well on the Indico field before the end of 2023. GeoPark continued to invest in our decarbonization efforts by installing a new photovoltaic solar power system in the OPA pipeline from our Platania block, which will help reduce our emissions and introduce efficiency gains by lowering energy and maintenance costs. We reinforced and extended our sustainability reporting with new submissions to the Carbon Disclosure Project, CDP, in both water and climate. These initiatives assess our ESG management performance and disclosures. Despite production being behind its full potential, GeoPark continues to record strong financial results in the quarter with revenues of $182 million and adjusted EBITDA of $104 million, representing an adjusted EBITDA margin of 57%, and profits of nearly $34 million or $0.59 per share. We invested $43 million during the quarter and generated $2.4 in adjusted EBITDA for each dollar invested, proof of GeoPark’s capital discipline and the quality of our assets. Additionally, the return on capital employed over the last 12-months reached 51%. Our financial expenses dropped by almost one-third to $11 million in the quarter following our debt reduction of $275 million during the last two years. After paying $88 million in cash taxes in the second quarter and returning almost $19 million to our shareholders through dividends and buybacks, we ended the period with more than $86 million in cash. Also, we completed a new $80 million unsecured committed credit facility for the next two years. Over the rest of this year, we will continue at full speed on our drilling program, adding more rigs and accelerating our activity. With 20 to 25 gross wells, we are targeting short-cycle exploration and development projects, including new horizontal wells in our core Llanos 34 block, exploration drilling in the CPO-5 block, the continued development of the prolific Indico field, and more exploration drilling in our operated Llanos acreage as well as our orientating acreage. In our two Eastern Llanos blocks adjacent to CPO-5, we have started preliminary activities to acquire over 650 square kilometers of 3D seismic, one of the largest 3D seismic onshore campaigns in the history of Colombia, which will significantly expand our exploration portfolio and inventory. We look forward to reporting to you the results of these activities. And we will now take any questions you may have. Thank you.

We have a question from Alejandro Demichelis of Jefferies.

A couple of questions, please. The first one is maybe you can walk us through the building blocks of the second half of the year to get to your production guidance? And then the second question is, how do you see the potential size of your new discovery from Llanos 123, please?

Good morning, Alejandro. This is Martin Terrado. Thanks for your question. In regards to the building blocks to making the guidance on production, it would largely depend on Indico wells getting back on production. We have been working closely with the operator on these two wells since the last call; all the civil works have been completed. That included building concrete decks and work is going on related to the flow lines that need to be welded. The operator has communicated to us that they will have that ready to go by the end of this month, and the national hydrocarbon agency has told them that with that, they will allow those two wells to be back on production. Those two wells have a gross production potential of 8,000 barrels, which is about 2,400 barrels net to GeoPark that we are expecting. As we are building, as you said, the blocks for the next quarters for the core number three, we are expecting partial contributions from those two wells because they will not be fully on stream for the full quarter, but they will be fully on stream for the last quarter. So that is a big contribution that we are expecting. The second one is related to our performance in the Llanos 34 block. For that block, we expect increased production compared to the first half of the year, which is mainly due to two things: our continuous production on horizontal drilling and improved downtime. We had about 7% downtime in the first half of the year, and we are expecting around 5%. These are the two main areas we expect to contribute to making our third quarter average around 38,500 barrels and the last quarter 40,800 barrels. We expect the exit rate to be between 40,000 and 41,000 barrels of production equivalent. This assumes that we don’t have major disruptions in our Llanos 34. And as always, it does not include additional production from exploration wells.

So with that, Alejandro, Andrés here, just to add to what Martin said. Obviously, with these numbers, roughly for the third quarter, we're looking at close to 38,000 to 39,000 and 40 to 41 in the fourth quarter. That would position us closer to the lower end of the range rather than the midpoint or the higher range. But we still believe that if the operator delivers on putting those two wells online before the end of this month, that is where we should be.

Hello, Alejandro. Regarding the Llanos 123, the Saltador discovery. So just to give you more context about the Saltador, the exploration well is located west of Llanos 34, that block was acquired in the 2019 ANH bidding round. The initial concept was to test the structural fault closure in that area. We did find hydrocarbons in the Barco Gadarupe formation with 29 feet of oil net pay. Today, we are testing around 900 barrels of oil per day with a 5% water cut. The testing will provide more information on volumes, reserves, and future developments. Additionally, the discovery of Saltador may extend to another prospect to the south called Visbita, which could hold more reserves. It is not yet decided, but there is clearly potential for this prospect to be completed at the end of this year or early 2024.

Our next question comes from Oriana Cobalt of Balance.

This is Serena with Balance. I had a brief follow-up with regards to the triggers for production in the second half and then I had a couple more if you could go one by one. So just I wanted to confirm where you are seeing the production? I think you mentioned 8,000 barrels per day of gross production potential for each Indico. Once they come back online, just curious how fast are you expecting for production out of these blocks to come back to levels seen before the shutdown during the most part of this year?

Thanks for your question. This is Martin Terrado. The current production for the CPO-5 block is approximately 17,500 barrels of oil per day. Comparatively, a year ago, we were without Indico six and seven, and we were probably around that same decline that you see is mainly in Mariposa, as the water has encroached into that well. The Indico field is producing flat production, so in addition to the 17,500 gross, we will be getting again 8,000 barrels from both Indico six and Indico seven production. These are flowing wells that have been tested. As soon as we get the green light from the national hydrocarbon agency, they will be contributing to the overall block production.

Andrés here, Serena. The expectation from the operator is to have those two wells back online before the end of this month. So the full production of the block should be on a gross basis back to over 25,000 hopefully in September or before the end of this month.

Perfect. Martin and Andrés, just keeping up with the CapEx and the exploration side of the business. Just wondering, in terms of the seismic acquisition that you are guiding for in the second half and it seems to be a very encouraging project from your end. So what are you targeting? What are the key areas? And what would be the main— how much of your CapEx budgeted for exploration with this seismic acquisition take up?

Thank you, Serena. I will go a little bit into the operations part, and then I will let Augusto go over what we are seeing on prospects. This is premium acreage. It is east of the CPO-5. As Andrés mentioned, we are going to be acquiring 650 square kilometers, which will be one of the largest acquisitions recorded. We have already received all the permits and completed the socialization. We are starting all the things related to building the camp so that we can start topography. After that, we will drill the wells to acquire some explosives, and the seismic acquisition will start in December of this year. It will take about two months to finish the acquisition, then we'll move on to processing, and after that, of course, building the pads and drilling the wells for those prospects that we expect to have. So that is a little bit on where we are from an operations perspective. From a capital perspective, the seismic is already in our budget, and we were able to get this seismic at a lower cost than expected, so we are acquiring it for less than our commitment. So that is a little bit on the operations perspective that we have. In terms of blocks and commitments on these two blocks, we only have one well commitment in each of the wells, so we are sure that we are going to find prospects to drill there.

Yes. Beyond the commitment that Martin mentioned, we really believe that these blocks, as mentioned before, are premium acreage. They are located next to the CPO-5, near important fields, for example, Caracara, and we have several leads defined that after the seismic, I’m sure that we are going to have new prospects and exploration opportunities.

The objective of acquiring 3D seismic over such a large portion of this part of the basin is to expand our exploration inventory and portfolio. In terms of how much of the CapEx was allocated to the seismic, as Martin said, it is already within our CapEx guidance and it is roughly at our working interest, around $20 million.

Perfect. That was very clear. And just one final one. Going through your filings, it seems that the EBITDA guidance using that same $80 to $90 per barrel was revised slightly downwards at the midpoint. I just wanted to know if you could share more insights on what the key drivers for this guidance revision are: is it in terms of wider discounts even though we have seen some timing recently? And/or where are you seeing OpEx cost—like total OpEx per barrel through the remainder of the year, and that would be very helpful.

Thank you, Serena. Veronica here. As you mentioned, we have adjusted our expected 2023 EBITDA range by about $40 million. Half of that is already realized impact during the first half from lower Brent prices and also wider Vasconia differentials that you mentioned. Going forward, in terms of the differentials, we really don’t expect further widening. We continue to use $4 to $5 for the remainder of the year. It is now pricing at $3.50, but we would expect that to revert to a 4% to 5% range, as I mentioned. The other half of the adjustment is related to higher OpEx. We have already been impacted by this in the first half, which has taken us to expect higher OpEx for the full year ranging between $10 and $11 per barrel on a consolidated basis. The drivers for this increase in OpEx are twofold. On one side, we have an appreciation of the currency in Colombia, which affects about 70% of our OpEx that is local currency-denominated, and on the other, higher energy prices stemming from weather-related effects due to the El Niño weather pattern in Colombia, where the power grid is mainly hydroelectric. These are primarily external factors. Our team will continue to focus on finding cost efficiencies and initiatives going forward.

We have received some text questions. Our first one is from Stephane Foucaud of Auctus. One question for me on Ecuador. The 40 net pay in a new formation looks good. How material is it? What are the implications for production and the development of the asset?

Stephane. Yes, we are very happy with the results of this well. The plan was to develop and investigate the potential upside to the U-sand, and as you mentioned, the Hanjin formation resulted with good hydrocarbon saturation and thickness, similar to the Jandia Hanjin wells with our 25 feet net pay. In the U-sand, we found about 40 feet of net pay, as you mentioned. According to our team and in line with our partner, we are going to complete this well, as it has better reservoir conditions. With this initiative, we will understand how the well behaves and what is the volume for future development. We have also had analogies of nearby fields that could indicate initial production between 900 to 1,300 barrels of oil per day. So again, we are really happy with the results, and we will be testing this well very soon.

It is important to mention that these are analogs, and this is information that our team uses to evaluate and test the wells. The reality is that we have good indications currently, and we will know much more once the well is tested.

Our next question comes from Roman Rossi of Canaccord. I have a couple, if I may. First, I would like to understand if the horizontal drilling was part of your original 2023 campaign and what is the estimated cost for each well? Second, can you give us more color on the derivatives loss and what is the strategy going forward? And finally, do you have any FX hedges?

Thank you, Roman. This is Martin again. I will cover the question about the horizontal well. So when we put together our budget, horizontal drilling was initially part of a pilot program with follow-up wells. Due to the very good results compared to our expectations, we adjusted our program, and we are now going into our third well. I will share a bit about our estimated costs and performance: the first well was drilled at around $11 million. For the second well, we drilled it with a longer length at around 10% cheaper, so at $10 million. Currently, we are drilling our third well, which we expect to be at around $9.5 million, and it is expected to be about three times the length of the first horizontal well. In summary, we have adjusted our program based on the promising results of the pilot well, and we expect to have about five to six wells by the end of the year. All of these wells are targeting the Mirador formation, which has an original oil in place of around 100 million barrels. Besides that, we are looking at other opportunities within the Llanos block and outside it, like Catania. We continue to work on improving efficiencies and believe we are learning and investigating what more we can do on the completion side. So we are excited about the results, and we will continue our journey on horizontal wells.

Roman, this is Veronica on your questions regarding derivatives. We continue to apply our hedging strategy for crude prices to protect against crude downside. We have done this consistently over the past several years. There has been no cash impact from the hedges year-to-date. As you know, the prices have remained between the floors and the ceilings, so there have been no gains or losses from those contracts this year. We did experience some of those losses last year that you may be referring to. Regarding the FX hedges, we have executed several FX hedges to protect the income tax payments that occurred in the second quarter of the year. Those transactions recorded about $3 million in gains year-to-date, and we will look for other opportunities to enter separate transactions as needed going forward.

Our next question comes from Daniel Guardiola of BTG.

I joined the call a little late, so I don’t know if some of my questions were already answered during the presentation. But first of all, I wanted to touch on reserves addition. Considering that this area has been one that the company has been struggling to add reserves or fully replace reserves in the last couple of years, I wanted to know if you can share with us what the most promising exploratory projects are currently being worked on and what your expectations are in terms of reserves addition for 2023? So that is my first question. If you want, we can go one by one.

Okay. Daniel, Andrés here. So we are, I would say, in the second half of the year, accelerating our exploration activity. We have already reported today the result of Saltador and the encouraging indications we have on the Genos basin. We also provided at least the list of all the prospects we are drilling in the second half of the year. There are some interesting prospects that we are going to be testing. We usually don’t give guidance on reserves, so it is really too early for us to say anything about our potential reserve replacement for this year. It will largely depend on the results of the two wells we are testing right now and on the six or seven wells we are going to be drilling from now until the end of the year. So again, we don’t usually provide guidance on reserves because that largely depends on the official views or certifiers on the discoveries.

And my second question was regarding the ease of operating in Colombia. It has been a year since Petro took office here in Colombia, and I wanted to know your thoughts. I want to know if you have perceived any material changes with respect to the process of environmental licensing and the procurement of a social license to operate. Is it becoming more difficult to operate in Colombia or is it business as usual?

Andrés here again, Daniel. I think it has changed a little in different locations. As Martin mentioned, we experienced some downtime in the Casanare area, for example, in the Llanos 34 block, which we hadn’t experienced in the past. In the Putumayo area, historically a more conflictive area, we have not experienced disruptions or blockages this year. I wouldn’t say it has dramatically changed or become significantly more difficult for companies to operate in the country, at least in the areas where we operate. There have been some changes, but not really significant. Compared to other countries, we still believe Colombia is one of the best regions in Latin America for oil companies to prosper and develop and execute their projects. We are investing more time and effort to maximize relationships with our neighbors. Recently, we completed the public audience for the Pure project where all communities participated. This was fully public and can be viewed on YouTube, illustrating the relationships and communications with stakeholders. So I think this is progressing well. We are pending final approval from the environmental authority and are still within expected timelines, so I wouldn’t say we’ve experienced delays or obstacles from these regulatory bodies.

And just a last question from my end. A very high-level question, maybe for you, Andres. In your view, what are the main challenges and opportunities that the company is facing right now?

Well, I can tell you that the biggest challenge we face today is bringing those two wells back online. That is obviously the top priority for the entire company and for myself. I know you are asking a more strategic question, but honestly, I wake up every morning just focused on those two wells. I want to ensure that the entire team is fully committed to bringing those back online very quickly. Beyond that, I believe that bringing the company back on the growth path is also a significant opportunity. We have been producing around 40,000 barrels a day for the last two years, and while that is a comfortable position, we don’t want to be complacent. We aim to be a much bigger and more relevant player in the market, so delivering results on our exploration campaign and achieving the company's growth trajectory is our biggest challenge and opportunity at this time.

With that, I will hand back to CEO, Andrés Ocampo, for closing remarks.

Thank you, everybody, for your interest and your support of our company. We are always here to answer any questions you may have, and we encourage you to visit our field operations or call us anytime for further information. So thank you, and have a good day.

Thank you. This concludes today’s call. Thank you for joining. You may now disconnect your lines.