Good morning, and welcome to the Canacol Energy fourth quarter and Full Year 2022 Financial Results Conference Call. All participants will be in listen-only mode. Should you need assistance, please signal a conference specialist by pressing the star key followed by zero. After today's presentation, there'll be an opportunity to ask questions. To ask a question, you may press star then one on your touch-tone phone. To withdraw from the question queue, please press star then two. Please note this event is being recorded. I would now like to turn the call over 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 risk 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 US 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. 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, 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 continued 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. The 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 Magdalena Valley that we are currently evaluating. All seven exploration wells that we drilled in 2022 were successful. Our gas exploration drilling results over the past nine 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 in gender equality. We were accepted as an engaged corporate member of the Voluntary Principles Initiative 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's 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 continued to execute our plan to develop our growing natural gas business. We reported approximately $213 million in Adjusted EBITDAX for the full year of 2022, a 9% increase in 2022, a 9% increase from 2021 and roughly in line with a 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 one-time $65 million current tax expense. The corporate restructuring also increased our deferred tax asset by $202 million. Net income, for which we've 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 our purchase 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-to-1 share consolidation, has also remained unchanged since before the pandemic. 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 17th, 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 net back was unchanged at $3.73 per Mcf in the fourth quarter of 2022 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 four 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 the closing of our new $200 million revolving credit facility. We replaced two facilities with total debt capacity of $121 million that were set to expire this year with the new facility that has 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 expire in 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 two 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 and cash, debt capacity and stable high margin operations. As a result of which I foresee us being able to maintain our 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 show 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 pricings gradually strengthen. A relatively strong dry cycle related to El Niño is predicted to commence in June of this year and last through till 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 reach $14 per MBTU. Forecast realized contractual gas sales for 2023 are anticipated to range between 160 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. We're starting off the year above the midpoint guidance. The corporation's firm 2023 take-or-pay contracts alone average 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. We will now begin the question and answer session. To ask a question, you may press star then one on your touchtone phone. If you're using a speakerphone, please pick up your handset before pressing the keys. To withdraw from the question queue, please press star then two. At this time, we will pause momentarily to assemble our roster. 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 timeline, CapEx expected, EUR and potential reserves? Yes, I'll take care of Pola and Jason can cover the second half. 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 center 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 contracts the majority of the 3,000 horsepower rigs, for their drilling programs in the Piedemonte of the Llanos Basin, are starting to drop those rigs. We're currently negotiating a 3,000 horsepower rig, which we assume we will have contracted by June of this year. 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? Do you have a maximum threshold or covenant in terms of EV-EBITDA? Sure. Thanks, Carolina. Our free funds flow, net of CapEx, the free funds flow will approximately be enough to pay our $27 million dividend, leaving us, you know, post-dividend essentially, a neutral in terms of cash generation or what goes out the door. With that said, 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 mid-year. Once that is all said and done, I expect our EBITDA to debt to EBITDA ratio rather, to be at approximately 2.5 times. That compares with our bond covenant, which is 3.25 times. The $200 million revolver is a bit more room at 3.5 times. At 2.5 times, 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. We anticipate commencing the construction process in Q4 of this year. Thank you. 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's plan for the energy transition towards renewables. The current administration is very focused on the elimination of the use of oil and coal in the power generation matrix in Colombia, and the substitution of those fossil fuels with gas. 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. Thirdly, you know, the situation in Venezuela remains fairly slow with respect to investment. No, I do not consider the importation of gas from Venezuela to be a short or mid-term threat to our business for those reasons. Our first question from the phones will come from Oriana Covaci from Balanz. You may now go ahead. Hi. Thanks for taking my question. This is Oriana Covaci with Balanz. I had three questions. Two questions, sorry. If we may go by 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. 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, about half the 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. 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 cost associated with getting the gas to the plant. The government here has announced another bid round for the Cargo por Confiabilidad, the standby 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. We're 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. We also anticipate to participate in another Tesorito-like project for another 200 megawatt standby plant in the field. Perfect. Maybe just to taking your last comment on participating in a new bidding round for a Tesorito-like plant. Is it already embedded perhaps in your 2023 budget? How would those incremental volumes be met? This project, you recall that we were awarded the Tesorito, the consortium we're part of was awarded the Tesorito project in 2018. These projects are 4 years in duration and the new project as well is planned for 2027 to enter operations. 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. Any gas sales associated with the new project will not commence until 2026 or 2027 when the new plant enters operation. Perfect. That's very clear. 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. Is there any exploration commitments that maybe will drive you to exploring areas that may not be as profitable as suggested by your seismic? How are you planning to balance this? We have three types of exploration program we're executing this year. The first is a very near field exploration program, which consists of three wells, Lulo, Piña and Cereza. These are three wells that will target the CDO reservoir, which is our main producing reservoir at deeper levels. We're drilling the upper part of the CDO in the near field area around Jobo had 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. Those three near field exploration wells will target sort of lower gas within the lower part of the CDO. We're looking at about for the three wells have a cum target of about 60 Bcf unrisked resource. The value of these near field prospects, so they can be tied into production immediately. One of the wells, Lulo-1, is actually being drilled from our production facilities at Jobo. We're drilling right underneath the Jobo processing plant for deeper gas in the CDO. 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. We've identified about 20 prospects off 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 two or three of those this year. Exploration wells, at least two of them this year, part of Momo and another one whose name escapes me right now, I'm afraid. These are relatively large new prospects based on the 3D seismic we acquired last year. Finally, in the Middle Mag, as I mentioned a little earlier, we plan to drill the Pola-1 well, starting in the third quarter of this year. Those that encapsulates our exploration program. Generally low risk, certainly very low risk in our near field operations. Relatively low risk in the new area where we shot 3D. Of course the high risk Pola-1 well. Okay, perfect. 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. Perfect. Thank you very much, and thanks for the material. Thank you. Our next question will come from Josef Schachter with Schachter Energy Research. You may now go ahead. Thank you very much. Good morning, Charle and Jason. Two questions from me. The first one on... You guys had a very good year, as you mentioned in your opening remarks on adding reserves, 191 million for 3P, and you've got, you know, 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 then, and into the PDP category going forward? Hi, Josef. Many thanks for the question. With respect to the 1P reserves or the reserves we added in 2022, three 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. We were not able. Given that those wells, we really just had log results from those wells. We were only able to book log-based pay. What we need to do, and 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. A little light on proven reserves based on the fact that we drilled those three 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. With that, we expect to see a good bump in one P 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, that Saxofon might actually be within the same field in general. We're very keen to quickly move Saxofon onto production. We're currently working on a tie-in of that well into Jobo, which is about seven kilometers away, to bring that well on production. With that, we can book additional one P reserves there. Josef? Okay, wonderful. The second one is, you mentioned, of course, August, you hope to get the government permitting. Then they can start construction of the SETCO construction in Q4. Any issues with any of the lead time items, pipe, compression, you know, issues where the, you know, some of the environmental areas are tougher? You know, in Canada, with TMX and Coastal GasLink Pipeline, the costs have just gone nuts and 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, a BOOT. We are not exposed whatsoever to any cost overruns. Those are borne by the consortium which was awarded the project. Obviously, you know, with any pipeline project, and this is a 300 km pipeline project, it's not particularly big. You know, obviously, there are always issues, you know, with communities. There are physical issues with some of the terrain. All of that has been taken into account. You know, the community issues via the consult that previously we've executed, as part of the environmental permitting process to the government satisfaction and the community satisfaction. The technical challenges will be addressed by having construction being performed or executed on 5 separate fronts, basically. That will move things along relatively quickly. You know, I think the consortium that was awarded 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? The price is firm, escalated at the inflation. There are no contingencies related to cost overruns whatsoever, the price is firm. Super. Thank you very much for your response and congratulations. Thanks, Joe. Our next question will come from Peter Hitchens with Edison Group. You may now go ahead. Good morning, everyone, or afternoon here. 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 six months? I think with respect to the drilling program, you know, we have all of the permits in hand to drill these wells. We have the rigs contracted to drill these wells, with the exception of the 3,000 horsepower rig to drill Pola-1. We anticipate having that rig contracted in June. You know, these things can always slip a little bit. Fortunately, drilling activity in Colombia is decreasing from last year, in particular on the oil side, given the higher tax rate now for corporate tax rate for oil producers. That's seen an impact, the direct impact on the pace of drilling. A lot of the oil producers here in Colombia, including Ecopetrol, are scaling back their drilling programs appropriately to cover the additional tax they have to pay. That's, you know, that's good for us, and that rig availability is better, particularly for the 3,000 horsepower. You know, the 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. 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 gonna be participating in a new thermoelectric power plant project. Key date there, mid to late July. 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 permit. I think those are the key, you know, three of the key dates we're looking forward here over the next six months, Peter. Brilliant. Thank you. If you have a question, please press star then one. Our next question will come from Luiz Carvalho with Goldman Sachs. You may now go ahead. Hi guys. Thank you for the call. Just three 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. That leaves you about $100 million available. Given, you know, 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. Yeah. To take the questions one at a time. I think it's unlikely that we would do that. You know, we have another year and a bit till the Medellin pipeline comes on, which would provide us, you know, more financial flexibility to do things, to consider things like that at, you know, at a later date. I think at this point in time, it's unlikely we'd do that. I will also mention that we actually had a visit from a rating agency, you know, who basically warned us not to do things like that because they would consider it a sign of stress, which sounds a bit counterintuitive, but, you know, all things considered, I don't believe that's something we'll be doing in the near term. Okay. Understood. Secondly, there's been, you know, over the last few weeks, a lot of talk about potentially the non-deductibility of royalties, part of the fiscal reform, which is 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. I could be behind on that particular topic. It's conceivable that someone already has, but not to my knowledge. Yeah. Yes, I'll just add to that, Jason. There have been seven lawsuits filed by the industry against the Ministry of Hacienda. Those are currently. They've been accepted by the judge in charge, and those are currently going to be moved through the courts. That's related to both the non-deductibility of royalties, as well as the surcharge on taxes for oil producers. Thanks, Charle. Got it. That's helpful. Thank you. 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 one B, 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 one B 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. Yeah. There's two factors associated with that. The first is we had some wells shut in related to production volumes in December. Shut-in wells are immediately moved from PDP to PDNP basically. That's just a matter of bringing those many of those wells have been brought back on as we lifted production up to 200 million cubic feet per day this first quarter. The 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. 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, so those wells move to PPF, you know, proven category. Finally, with respect to your overall question, you know, we typically experience a decline rate of about 10% per year, which of course we offset through the drilling of new wells. You know, we typically add more 2P reserves than we produce per year. Then it's just a timing issue of getting those 2P, particularly the probables, into the proven category, as I mentioned a little earlier. Got it. Thank you very much, guys. I'd like to turn it over to Carolina Orozco for additional questions from the webcast. Thank you. We received a couple of questions from Roberto Paniagua from Casa de Bolsa. This first one is: Please explain better Canacol's corporate restructuring process and motives. Sure, I can take that. You know, 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. You know, with that said, we've grown via several acquisitions and, you know, as such have an overly complex organization structure. You know, the restructuring allowed us to simplify that. We've essentially taken four companies out of the organizational chart. Consolidated some assets into other existing companies. You know, that offers, you know, administrative, logistical, and cost efficiencies for us. Thank you, Jason. The next question from Roberto is: Which are the exploratory success rates in 2021 and 2022? Yeah. I think that... Go ahead, Charle. Sorry. In 2021, we drilled 8 exploration wells with a success rate of 75%. In 2022, we drilled seven exploration wells with a 100% success rate. Thanks, Charle. The next question is from Matthew 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. The $65 million tax bill associated with the restructuring was a 2022 tax event. 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. $65 of that would relate to this restructuring, leaving, you know, the additional $46 million as I'll call, you know, 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. You know, $65 million of that $75 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 Nikos Monoyios from Ingalls & Snyder. When will Dividivi 1 flow test results be available, and how long would it take to connect to pipeline if successful its 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. We're currently evaluating development options for that discovery, which would include tying the well into the TGI gas pipeline, located approximately 30 kilometers to the east of the discovery. We are also looking at possibility of installing liquefaction up to 15 million cubic feet per day on that discovery, to transport the gas in liquid form, to various commercial options. We should have post-production, long-term production test results out sometime in April. Thank you, Charle. We have one last question from Julio Delgado. Are you still evaluating potential opportunities in Peru and Bolivia? If so, is there any update or schedule for us to follow? Yes, we continue to evaluate natural gas exploration and production opportunities outside of Colombia. 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. 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.