Canacol Energy Ltd (CNECCL.SN) Earnings Call Transcript & Summary

Good morning, and welcome to the Canacol Energy Fourth Quarter and Full Year 2022 Financial Results Conference Call. [Operator Instructions] Please note, this event is being recorded. I would now like to turn the conference to Carolina Orozco, Vice President of Investor Relations. Please go ahead.

Good morning, and welcome to Canacol's Fourth Quarter and Year-End 2022 Financial Results Conference Call. I am with Mr. Charle Gamba, President and Chief Executive Officer; and Mr. Jason Bednar, Chief Financial Officer. Before we begin, it is important to mention that the comments on this call by Canacol's senior management can include projections of the corporation's future performance. These projections neither constitute any commitment as to future results nor take into account risks or uncertainties that could materialize. As a result, Canacol assumes no responsibility in the event that future results are different from the projections shared on this conference call. Please note that all finance figures on this call are denominated in U.S. dollars. We will begin the presentation with our President and CEO, Mr. Charle Gamba, who will cover the operational highlights for the fourth quarter. Mr. Jason Bednar, our CFO, will then discuss financial highlights. Mr. Gamba will close with a discussion of the corporation's outlook for 2023 and beyond. And finally, we will have a Q&A session. I will now turn the call over to Mr. Charle Gamba, President and CEO of Canacol Energy.

Thanks, Carolina. Good morning or good afternoon, and welcome to Canacol's 2022 Year-end Conference Call. In 2022, the corporation achieved several important goals with respect to creating value for our shareholders and other stakeholders, including an increase in realized natural gas sales year-over-year in line with guidance and a 13% return on capital employed. We also generated high and stable operating margins averaging 77%. We continue to report strong and stable financials, which allow us to continue to return capital to shareholders in 2022 via our quarterly dividend program and share buybacks. In addition to announcing our financial results yesterday, we also announced our year-end reserves the week prior. Discoveries we made in 2022 are estimated to have added approximately 93 billion cubic feet of new proven plus probable gas reserves, replacing production in 2022 by more than 150%. We also made an interesting oil discovery at Chimela in the Middle Mag Valley that we are currently evaluating. All 7 exploration wells that we drilled in 2022 were successful. Our gas exploration drilling results over the past 9 years have yielded an industry-leading 85% hit rate of commercial discoveries. Looking ahead to 2023, we are excited to be in a position to continue drilling a combination of low-risk development and exploration wells, some of which will be targeting newly developed prospects based on seismic acquired in 2022 as well as some higher impact exploration wells we plan to drill outside of our core producing area. With respect to our ESG achievements, we continue leading the industry as one of the cleanest oil and gas producers in both Colombia and North America, with Scope 1 and Scope 2 greenhouse gas emissions that are 80% lower than our oil-focused peers and 50% lower than our gas-focused peers on average. During 2022, through the continuous and successful implementation of the corporate ESG strategy, we obtained several achievements, such as the Equipares Silver Seal from UNDP and Gender Equality. We were accepted as an engaged corporate member of the Voluntary Principles Initiatives and achieved significant and outstanding upgrades in several of the most important ESG ratings and rankings internationally. I'll now turn the presentation over to Jason Bednar, our CFO, who will discuss our fourth quarter financials in more detail. When he is done, I'll provide a detail on the outlook for the remainder of 2023.

Thanks, Charle. 2022 was a good year financially for Canacol and its stakeholders as we continue to execute our plan and develop our growing natural gas business. We reported approximately $213 million in adjusted EBITDAX for the full year of 2022, a 9% increase from -- sorry, in 2022, a 9% increase from 2021 and roughly in line with the 10% increase in net revenues. Adjusted funds flow from operations would also have been up, which is 4% at $159 million, if it weren't for a corporate restructuring that we undertook in the fourth quarter in order to better optimize our business, which caused the onetime $65 million current tax expense. However, the corporate restructuring also increased our deferred tax asset by $202 million. Net income, for which we reported a very large increase, would have been lower at around $10 million if it weren't for the restructuring. Looking past the decline in funds flow from operations that was purely due to the restructuring, these are strong financial results that allowed us to maintain our quarterly dividend, paying out $27 million to shareholders and applying over $13 million to the repurchase of shares during 2022. To preempt potential questions, given that our 2023 guidance announcement did not provide cash tax or after-tax cash flow guidance, I will mention that in the high-end case in which we guided to EBITDA of $263 million, we would expect to pay $42 million in cash taxes. Our dividend payment per share, after adjusting for recent 5:1 share consolidation, has also remained unchanged since before the pandemic and currently represents an annual yield of approximately 10%, with the last quarterly dividend paid in January and the next one due to be paid on April 17, 2023. The resilience and growth in our key financial metrics also allowed us to recently close a new and expanded revolving credit facility, which is providing significant financial flexibility as we plan for continued investment and growth in our business. Looking at our operational results on a quarterly basis. Our operating netback was unchanged at $3.73 per Mcf in the fourth quarter of '22 compared to the third quarter, but up 4% relative to the same quarter in 2021. These results again highlight the stability and high-margin nature of our business. To further highlight the strength and stability of our business and financial results, we want to highlight the return on capital employed implied by our financial statements over the last 4 years. This has remained above 10% for the fourth year in a row and at 13% for 2022. A significant event subsequent to year-end was a closing of our new $200 million U.S. revolving credit facility. We replaced 2 facilities with total debt capacity of $121 million that were set to expire this year, with the new facility that is very similar terms, but doesn't require any repayments until February 2027, giving us increased flexibility over the medium term. I'll note that the revolvers expiring 2027 should be well after. The company had significant additional corporate cash flows realized from additional gas sales coming from the Medellin Pipeline and its associated take-or-pay contracts. The revolver also simplifies our capital structure as we immediately paid out $10 million of bank debt that was outstanding in Colombia as well as paid off the $25 million that was outstanding on the Medellin bridge loan. These actions did not affect the fact that Canacol will still be reimbursed by SETCO for the $25 million or any other amounts that Canacol will spend on the pipeline prior to the environmental permit being released by the government, which triggers the SETCO reimbursement. All said and done, Canacol now has 2 debt components: the new revolver expiring in 2027 and the bond expiring in 2028. Given the interest rates have been increasing, I'm very happy that we were able to secure the terms for this facility that were very similar to what we previously had set for an extended period of time. In closing, our 2022 financial results were strong and relatively stable. We have significant financial strength in cash, debt capacity and stable high-margin operations. As a result of which, I foresee us being able to maintain a return of capital to shareholders while maintaining flexibility to ramp up investment levels when we think it makes sense to do so. At this point, I will hand it back to Charle. Thanks, everyone.

Thanks, Jason. Our results for the fourth quarter and the year showed the positive impact of our investments in long-term growth and demonstrate the stability of our gas business. For 2023, we're optimistic that we will continue to see demand and related sales volumes and pricing gradually strengthen. A relatively strong dry cycle related to El Niño is predicted to commence in June of this year and last through to April of 2024. As a result, we expect interruptible gas demand related to thermoelectric power generation to be very strong for the second half of 2023. Interruptible pricing is also anticipated to be strong during this period. During the last El Niño in 2016, we saw pricing for interruptible volumes reached $14 per MBtu. Forecast realized contractual gas sales for 2023 are anticipated to range between 160 million and 206 million standard cubic feet per day. Our gas sales have averaged 188 million standard cubic feet per day for the first 2 months of 2023. So we're starting off the year above the midpoint guidance. The corporation's firm 2023 take-or-pay contracts alone averaged 160 million standard cubic feet per day. We expect to have sufficient capital and operational resources to execute on our key objectives for the year, which include: the drilling of up to 10 exploration and development wells; the acquisition of 280 square kilometers of new 3D seismic on the VIM-5 contract to expand our exploration prospect inventory; continuing to progress the new gas pipeline from Jobo to Medellin; continuing our return of capital to shareholders in the form of dividends and share buybacks; and finally, continuing with our commitment to continuous improvement in our ESG processes. I'd like to thank the entire Canacol team as well as our contractors, partners and clients for their support and hard work during 2022. It is our team, partners and clients that allow us to continue operating safely, sustainably, reliably and profitably while investing for the future. We're now ready to answer any questions that you might have.

[Operator Instructions]

Thank you. We received one first question from Daniel Guardiola from BTG Pactual. What is the current progress of the drilling of Pola? Can you share with us the expected time line, CapEx expected EUR, IP and potential reserves?

Yes, I'll take care of Pola, and Jason can cover the second half. So the Pola-1 exploration well will be the first deep test we drill in the Middle Magdalena Valley. We're targeting a conventional deep basin-centered gas play within the Cretaceous our reservoirs there. Last year, we had planned to drill that well. However, we were unsuccessful in sourcing a drilling rig this well as it will be drilled to around 19,000 feet, will require a 3,000-horsepower rig, and there were none available within Colombia or even South America last year. That situation has changed. Ecopetrol, who contract the majority of the 3,000-horsepower rigs for their drilling programs in the Piedemonte and the Llanos Basin, are starting to drop those rigs. So we're currently negotiating a 3,000-horsepower rig, which we assume we will have contracted by June of this year. And with that in mind, we've already completed the civil works to drill the well from, and we anticipate to spud the well in third quarter of this year.

Thanks, Charle. We have a few follow-up questions from the same analyst. What is the expected free cash flow generation for 2023? Are you considering to raise additional debt to fund the CapEx expected to be deployed in 2023? And do we have a maximum threshold or covenant in terms of EBITDA?

Sure. Thanks, Carolina. So our free funds flow, net of CapEx, the free funds flow will approximately be enough to pay our $27 million dividend, leaving us post dividend essentially neutral in terms of cash generation or what goes out the door. With that said, and given this additional $65 million tax bill with respect to the corporate restructuring, I do expect to draw on the $200 million revolver to pay that particular bill midyear. And once that is all said and done, I expect our -- sorry, EBITDA to debt-to-EBITDA ratio, rather, to be at approximately 2.5x. And that compares with our bond covenant, which is 3.25x, and the $200 million revolver has a bit more room at 3.5x. So at 2.5x, we're well within those covenants.

Thanks, Jason. The next question is, can you share with us how is progressing the environmental license related to the construction of the Medellin pipeline? When do you expect to secure all required licenses to kick off construction?

We expect to obtain the required licenses by August of this year, and we anticipate commencing the construction process in Q4 of this year.

And we have one last question from Daniel, which is what are your overall thoughts on the current administration view on the gas industry? Do you consider Venezuela to be a realistic threat to your business in Colombia?

I think with respect to the current administration in Colombia, they are very supportive of the gas industry. Both the upstream, midstream and downstream, given that it plays a very key role with this current administration, is planned for the energy transition towards renewables. So the current administration is very focused on the elimination of the use of oil and coal in the power generation acreage in Colombia and the substitution of those fossil fuels with gas. So very optimistic with respect to the current administration's view on the gas industry. With respect to Venezuela, I don't consider Venezuela to be a realistic threat to our business model here in Colombia, given the fact that, firstly, Venezuela has no excess gas to export currently. All gas in Venezuela is either consumed domestically or flared. Nobody is drilling any gas wells or building any infrastructure related to gas transportation in Venezuela. And thirdly, the situation in Venezuela remains fairly, fairly slow with respect to investment. So no, I do not consider the importation of gas from Venezuela to be a short or midterm rent to our business for those reasons.

Our first question from the phone will come from Oriana Covault from Balanz.

This is Oriana Covault with Balanz. I had 3 questions -- 2 questions, sorry. If we may go one by one, that would be great. First, having to do with El Tesorito, with operations now fully running, if perhaps you could share more color on how have you seen volumes evolve and utilization factors at the plant?

Thank you, Oriana. With respect to Tesorito, that plant entered operation in September of last year. Generation, the plant has been generating on average about 50% of the time, but half time. We've been selling volumes up to 40 million cubic feet per day, which is the capacity of the plant to generate 200 megawatts, at prices ranging up to $7.60 at the wellhead. So Tesorito is working out very well. It has the advantage of being able to dispatch at a lower price, given that there's no transportation costs associated with getting the gas to the plant. There is -- the government here has announced another bid round for the Cargo por Confiabilidad. They expand by power generation, and we are currently registered to participate in that bid round for another 200-megawatt plant. We expect that bid round currently scheduled for July of this year. So we are very happy with gas sales and pricing to Tesorito. We see Tesorito generating upwards to full capacity during the second half of this year related to the El Niño, and the dry season being particularly hard this year. And we also anticipate to participate in another Tesorito-like project for another 200-megawatt standby plant in the field.

Perfect. Maybe just taking your last comment on participating in a new bidding round for Tesorito-like plant. Is it already embedded perhaps in your 2023 budget? And how would those incremental volumes would be met?

Yes. This project -- you recall that we were awarded the test -- the consortium or part that was awarded the Tesorito project in 2018. So these projects are 4 years in duration, and the new project as well is planned for 2027 vendor operations. So these are quite long-term projects. We will maintain a relatively low working interest in the new project as we did in Tesorito. And our main objective, of course, is to sell gas to these power projects. So any gas sales associated with the new project will not commence until 2026 or 2027, when the plant -- the new plant enters operation.

Perfect. That's very clear. And finally, with regards to your 2023 exploration program, if you could share more color on which areas will be at the core of your strategy, minding that Pola-1 is expected for the third quarter. And is there any exploration commitments that maybe will drive you to exploring areas that are may not be as profitable as suggested by your seismic? How are you planning to balance this?

Yes. So we have 3 types of exploration program we're executing this year. The first is a very near-field exploration program, which consisted 3 wells, Lulo, [ Pina and Seresa ]. These are 3 wells that will target the CDO reservoir, which is our main producing reservoir at deeper levels. So we're drilling the upper part of the CDO in the near-field area around Mobil, have been exploited by previous operators that did not drill all the way down to the bottom of the CDO. And we know that there is gas throughout the CDO. So those 3 near-field exploration wells will target sort of lower gas within the lower part of the CDO. We're looking at that the 3 wells have [ accum ] target of about 60 Bcf on risk resource. And the value of these near-field prospects, they can be tied into production immediately. One of the wells, Lulo-1, is actually being drilled from our production facilities at Jobo. So we're drilling right underneath the Jobo processing plant for deeper gas in the CDO. So that's the first type of near-field, very low risk, very rapid commercialization exploration we're doing. The second is on the VIM-5 contract where we shot a significant 500-square-kilometer 3D seismic program last year. So we've identified about 20 prospects of that 3D. These are all prospects within the CDO, the conventional producing reservoir. These prospects all have amplitude anomalies associated with them, and we'll be drilling 2 or 3 of those this year. So exploration, but at least 2 of them this year, part of [ Mono ] and another one who's name [indiscernible] and that movement of freight. So these are relatively large new prospects based on the 3 seismic that we acquired last year. And finally, in the Middle's Mag, as I mentioned earlier, we plan to drill the Pola-1 well starting in the third quarter of this year. So those -- that I think calculates our exploration program, generally low risk, certainly very low risk in our near field operations, relatively low risk in the new area that will be shot 3D and then, of course, the high-risk Pola-1 well.

Okay. Okay. Perfect. So that would take about 6 or 7 of the total 10 exploration wells? Am I doing the math correctly, just to understand the areas that you plan to target. The other would be commitment, exploration commitments. Is that correct?

That's correct.

Our next question will come from Josef Schachter with SER.

Charle and Jason. Two questions for me. The first one on -- you guys had a very good year, as you mentioned earlier in your opening remarks, on adding reserves, 191 million for 3P and you've got 59 for 1P or for proven. How do you move those 3P reserves into 1P and PDP? Is there any specific drilling that you need to do? Is it hooking the wells up? How do we see that big movement up into the 1P category and into the PDP category going forward?

Josef, thanks for the question. With respect to the 1P reserves or the reserves we added in 2022, 3 of those wells -- 3 of the 7 wells were drilled very late in 2022. Those being the Dividivi well, the Dividivi discovery, the Saxofon discovery and the Chimela discovery. So we were not able -- given that those wells, we really just had lag results from those wells. So we're only able to book a lag-based pay. So what we need to do and what we're doing right now is we're production testing those 3 wells. And with production tests, we can move more of the probable reserves into the proven category. So a little late on proven reserves based on the fact that we drilled those 3 wells right at year-end, and we're not able to production test them in time for booking, which is what we're doing now. And with that, we expect to see a good bump in 1P reserves. One of the wells, in particular, Saxofon, we drilled in the Southwest corner of our VIM-5 block, very close to some recent discoveries made by Hocol and NG Energy. As a matter of fact, Saxofon might actually be within the same field in general. So we're very keen to quickly move Saxofon onto production. We're currently working on the tie-in of that well into Jobo, which is about 7 kilometers away to bring that well on production. And with that, we can book additional 1P reserves there, Joe.

Okay. Wonderful. And the second one is you mentioned, of course, August, you hope to get the government permitting, and then they can start construction of the [ SETCO ] construction in Q4. Any issues with any of the lead time items, pipe, compression issues where some of the environmental areas are tougher? As you know, in Canada with TMX coastal gas pipeline, the cost have just gone nuts and way, way out of line with the original budgets. Is there anything that you're concerned about or anything that needs to be done by a certain date to take that risk down?

No, the key factor right now, Joe, is receiving the environmental permit, which we expect in August, as I mentioned a little earlier. With respect to cost, this was awarded as a turnkey contract, the BO -- BOOM. So we are not exposed whatsoever to any cost overruns. Those are borne by the consortium, which was awarded the project. Obviously, with any pipeline project and this is a 300-kilometer pipeline project, it's not particularly big. But obviously, there are always issues with communities. There are physical issues with some of the terrain, but all of that has been taken into account. The community issues via the consulta previa we've executed as part of the environmental permitting process to the government satisfaction and the community satisfaction. And the technical challenges will be addressed by having construction being performed or executed on 5 separate fronts basically. so that will move things around relatively quickly. So I think the consortium that was award the project is managing in a very good way the engineering and planning to execute the project.

Can I ask one more then? The tariffs that you're going to be paying, do they have any escalators if the cost overruns are? Or do you have a firm price going forward on transportation?

Yes. The price is firm, escalated at inflation. There are no contingencies related to cost overruns whatsoever. So the price is firm.

Our next question will come from Peter Hitchens with Edison.

Most of my questions have been answered. I was just intrigued by the timing of all these events that are coming through. What are the key times that we should be concentrating on over the next 6 months?

I think with respect to the drilling program, the only well -- we have all of the permits in hand to drill wells. We have the rigs contracted to drill these wells, with the exception of the 3,000-horsepower rig to drill Pola, but we anticipate having that rig contracted in June. These things can always slip a little bit. Fortunately, drilling activity in Colombia is decreasing from last year, particularly on the oil side, given the higher tax rate now for corporate tax rate for oil producers. So that's seen an impact -- the direct impact on the pace of drilling. A lot of the oil producers here in Colombia, including Ecopetrol, scaling back their drilling programs appropriately to cover the additional tax they have to pay. And that's good for us, and that rig availability is better, particularly for the 3,000-horsepower. So June is a key date to secure that particular drilling rig. Another key date, as I mentioned a little earlier, related to Oriana's question, is the new bid round for power generation, standby power generation. That bid date is scheduled for the third week of July. So that's another key date for us in that a week after the bids are due, the projects will be awarded. So we'll know whether we're going to be participating in a new thermal electric power plant project. So key date there, mid to late July. And then finally, with respect to our Jobo-Medellin project, as I mentioned, we're expecting the environmental permit to come out in August. There is always risk with that in that, that is a government process. And there's always the potential for delays associated with the receipt of the environmental permits. So I think those are the key -- 3 of the key bids we're looking forward here over the next 6 months, Peter.

Our next question will come from Luis Serrano with Goldman Sachs.

Just 3 very quick questions. I guess the first one, if I understood correctly, you've drawn about $35 million of the credit line. You probably plan to draw another $65 million for the tax bill. So that leaves you about $100 million available. Given how the market has turned and with your bonds now in the 80s, would you consider sort of drawing a little bit more on the credit line and buying back some of those bonds in the secondary market? That would be the first question.

Yes, to take the questions one at a time, I think it's unlikely that we would do that. We have another year and a bit until the Medellin pipeline comes on, which would provide us more financial flexibility to do things -- to consider things like that at a later date. But I think at this point in time, it's unlikely we do that. I will also mention that we actually had a visit from a rating agency, who basically warned us not to do things like that because they would consider a sign of stress, which sounds a bit counterintuitive. But all things considered, I don't believe that's something we'll be doing in the near term.

Okay. Understood. Then secondly, there's been, over the last few weeks, a lot of talk about potentially the nondeductibility of royalties part of the fiscal reform, which is the only thing that -- the only part of it that's actually impacting you potentially being rolled back or declared unconstitutional. Has there been any update to that?

I have no update as to if or when anyone has challenged that as unconstitutional at this point in time. And I could be behind on that particular topic. It's conceivable that someone already has, but not to my knowledge.

Yes. I'll just add to that, Jason. There have been 7 [ lots ] in trial by the industry against the Ministry of [ ASEAN ]. So those are currently -- they've been accepted by the Judge in charge, and those are currently going to be moved through the court. And that's related to both the nondeductibility of royalties as well as the surcharge on taxes for oil producers.

Got it. That's helpful. And then the very last question, you've already answered a lot of it in a previous question, but just on the reserves on the PDP and the 1P. I understand it's mostly -- so that decline that we're seeing in the reserve report is mostly a timing issue. Can you just help us sort of understand the magnitude of that timing issue? Like, for example, I see about 8% decline in 1P and like 30%-plus decline in PDP year-over-year. Should we expect, if we correct for that timing to be sort of flattish or still down or a little bit of growth? Sort of the order of magnitude would be helpful.

Yes, there's 2 factors associated with that. The first is we had some wells shut in related to production volumes in December. So shut-in wells are immediately moved from PDP to E&P basically. So that's just the matter of bringing those -- many of those wells have been brought back on as we listed production up to 200 million cubic feet per day this first quarter. Second, as I mentioned a little earlier, was related to the fact that 3 of our exploration discoveries were made in December of last year. So we were not able to production test those wells in time to book. We are currently doing that production testing now. So we expect to see some of those probable reserves that were booked in 2022 as so, those wells moved to P -- proven category. And finally, with respect to your overall question, we typically experience a decline rate of about 10% per year, which, of course, we offset through the drilling of new well. So we typically add more 2P reserves than we produce per year. And then it's just a timing issue of getting those 2P, particularly probables, into the proven category, as I mentioned a little earlier.

I'd now like to turn it over to Carolina Orozco for additional questions for the webcast.

We received a couple of questions from Roberto Paniagua from Casa [ Wisa ]. The first one is please explain better Canacol's corporate restructuring process and motives.

Sure. I can take that. So back in 2008, when Canacol started until about 2012, the company was -- Canacol was an oil producer. Approximately 2012, we acquired Shona and entered the natural gas business. With that said, we've grown by several acquisitions. And as such, have an overly complex organization structure. So the restructuring allowed us to simplify that. We've essentially taken 4 companies out of the organizational chart, consolidated some assets into other existing companies. And that offers administrative, logistical and cost efficiencies for us.

NThank you, Jason. The next question from Roberto is which are the exploratory success rates in 2021 and 2022?

Yes, I can -- go ahead, Charle. Sorry.

So in 2021, we drilled 8 exploration wells with a success rate of 75%. And in 2022, we drilled 7 exploration wells with 100% success rate.

Thanks, Charle. The next question is from Matt Bundschuh from Oaktree Capital Management. Is the $65 million tax bill this year in addition to the $42 million cash taxes assumed under the high-end guidance for 2023, which assumes an EBITDA of $263 million?

Right. So the $65 million tax bill associated with the restructuring was a 2022 tax event. So if you looked at our 2022 financials, which were filed yesterday, you'd see that our current tax on the P&L was $111 million. So $65 million of that would relate to this restructuring, leaving the additional $46 million, as I'll call, regular tax. As at December 31, 2022, on the balance sheet, you'll see that there is a $75 million tax bill -- or sorry, taxes payable at December 31. And $65 million of that $75 million would be as a result of the restructuring process. With respect to 2023, on that $263 million of EBITDA, it would now generate only $43 million of current tax.

Thanks, Jason. We have another question from [ Nicolaus Monarios ] from [ Ingelsson Schneider ]. When will Dividivi-1 flow test results be available? And how long would it take to connect to pipeline, if successful? Is production from this well in 2023 guidance?

Thank you. We are currently testing the Dividivi well under a long-term test. We will release those results when that test is completed in April. And we're currently evaluating development options for that discovery, which would include tying well into the TGI gas pipeline located approximately 30 kilometers to the East of the discovery. We are also looking at possibility of installing liquefication, up to 15 million cubic feet per day, on that discovery to transport the gas and liquid form to various commercial options. So we should have post-production -- long-term production test results out sometime in April.

Thank you, Charle. We have one last question from Julio [ Elga ]. Are you still evaluating potential opportunities in Peru and Bolivia? If so, is there any update or scheduled for us to follow?

Yes, we continue to evaluate natural gas exploration and production opportunities outside of Colombia, and that is still very much ongoing. We are not, at this point in time, in a position to disclose any of the current opportunities we're looking at. But yes, we are evaluating natural gas exploration and development opportunities outside of Colombia.

This concludes our question-and-answer session. The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.