Good day, and welcome to the Canacol Energy third quarter 2022 financial results conference call. All participants will be in a 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 will be an opportunity to ask questions. To ask a question, you may press star then one on a touchtone phone. To withdraw your question, please press star then two. Please note this event is being recorded. I would now like to turn the conference over to Carolina Orozco, Vice President of Investor Relations. Please go ahead. Good morning and welcome to Canacol's third quarter 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's important to mention that the comments on this call by Canacol 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 financial 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 summarize highlights from our third quarter results. Mr. Jason Bednar, our CFO, will then discuss financial highlights. Mr. Gamba will close with a discussion of the corporation's outlook for the remainder of 2022 and looking out to 2023. At the end, we will have a Q&A session. I will now turn the call over to Mr. Charle Gamba, President and CEO of Canacol Energy. Charle, we cannot hear you. Hello? Yes. Yes, we can hear you now, Charle. Can you hear me now, Carolina? Yes. Hello? Yes, Charle, we can hear you now. It appears we've lost connection with our speaker, Charle. Please wait as we reconnect. Pardon me, ladies and gentlemen. We've reconnected with our speaker. Charle, please go ahead. Good morning, everybody. I apologize for the delay I had connecting. But anyway, good morning, good afternoon, and welcome to Canacol's third quarter 2022 conference call. In the third quarter of 2022, we realized natural gas sales of 184 million standard cu ft per day, which is above the midpoint of our annual guidance of 160 million-200 million standard cu ft per day. Tesorito, the 200 MW thermoelectric plant in which we hold a 10% equity interest and for which we are the sole supplier of gas, began generating electricity in mid-September. I would like to again congratulate Celsia, our operating partner, for the successful conclusion of the construction process and look forward to this investment contributing to continued growth in our business, both through our equity investment and of course, through increased demand of our gas. Our relatively stable production and operating conditions allowed us to report another quarter with high netbacks, an operating margin of 78% and a relatively high return on capital employed of 17% annualized for the quarter. We continue with the execution of our drilling program planned this year with a total of nine development and exploration wells, drilled to date, which includes four successful exploration tests. Finally, subsequent to quarter end, we signed a strategic agreement with SETCO to build, own, operate, and maintain the Jobo to Medellín pipeline project, which I will discuss in more detail when I talk about the outlook for the remainder of this year and beyond. I'll now turn the presentation over to Jason Bednar, our CFO, who will discuss our third quarter financials in more detail. Thanks, Charle. We continued to execute our plan and develop our natural gas business in the third quarter. We reported the following for the third quarter of 2022. $70 million of production revenue, net of royalties and transportation, which represents a 6% increase from Q3 of 2021. The increase was driven by higher realized prices, more than offsetting slightly lower sales volumes. We reported $39 million in adjusted funds from operations, which represents a 1% increase from the same period in 2021. We also reported EBITDAX of $56 million, which represents a 4% increase from the same period in 2021. Finally, we reported a net loss of $5 million compared to a net profit of $9 million in the same period in 2021. As I've explained on many previous conference calls, a big driver of our net income each quarter is unrealized foreign exchange gains and losses that can impact the valuation of our tax pools, which are in Colombian pesos. In the third quarter, we recorded a deferred tax charge of $11 million, the majority of which was due to a deterioration in the value of the Colombian peso versus the US dollar, and without which we would have reported substantial positive net income. In the event that the peso strengthens against the US dollar in the future, the corporation would realize a deferred income tax recovery. Our gas operating net back was $3.73 per Mcf in the three months ended September 30, 2022, which is 7% higher than in the same period in 2021, 2% higher than the prior quarter, and 4% above our guidance for $3.60 on average for 2022. Our realized gas price of $4.76 was the highest we've achieved since prior to COVID and was above our guidance for the year of $4.61-$4.74 per Mcf, thanks to stronger interruptible prices. We're encouraged by the persistence of robust pricing for interruptible gas sales despite lower absolute demand. Recall that the majority of our guidance is based on sales under fixed price take-or-pay contracts with an average fixed price of $4.74 per Mcf. Opex was $0.28 per Mcf in Q3, down from $0.36 in Q1 and $0.31 in Q2, as we were undertaking less maintenance and benefiting from a lower Colombian peso when measuring our local costs in U.S. dollars. We continue to anticipate very little maintenance in the second half of the year and expect 2022 average OpEx to be approximately $0.30 per Mcf. In percentage terms, our gas royalties were again 16% of gross revenue, which is in line with the average for the preceding two years. I will highlight again the return on capital employed implied by our financial statements over the last 15 quarters, averaging 16% over the last 12 months. That concludes my comments on our third quarter financial results. I'll now hand it back to Charle. Thanks, Jason. Our results for the third quarter once again demonstrated high and stable operating margins as well as a very respectable return on capital employed. Our guidance for 2022 remains unchanged. We anticipate production and cash flow to near the high end for our guidance, which was based on 200 million standard cu ft per day of average gas sales, with CapEx coming in closer to the lower end of our guidance at $170 million. Our exploration drilling program will continue at an increased pace through the remainder of this year and into early 2023, with four relatively high-impact exploration wells either spudded or due to spud within weeks at Saxafón, Chimela, Dividivi and Natilla. This will allow us to meet our guidance for drilling 12 wells in 2022, with a 13th well, Natilla, reaching TD in early 2023. In late October, we issued an update on our Jobo to Medellín pipeline project. Specifically, we announced the successful execution of agreement with the Shanghai Engineering and Technology Corp. Consortium, or SETCO, to build and operate the pipeline project. SETCO is a Chinese-based construction and pipe fabrication consortium with experience in building major gas pipelines in Asia and the Middle East. Recall that this is the 3rd time in Canacol's history that we have initially championed and funded a gas pipeline project, which a different corporate entity has subsequently taken on and then built, own, operate, and maintain. The prior two projects with Promigas allowed us to grow pipeline takeaway capacity from our Jobo facilities from less than 50 million standard cu ft per day in 2016 to 200 million standard cu ft per day today. This Jobo to Medellín pipeline project will increase total pipeline takeaway capacity to over 300 million standard cu ft per day when it is completed in late 2024. Consistent with what we did for those prior projects, we won't be committing or we won't be commenting on the cost of this project beyond stating that Canacol has agreed to pay a fixed fee for a certain volume of gas to be transported through the pipeline to Medellín over a certain period of time. In combination with long-term sales contracts we have signed, we expect to achieve attractive effects at a slight premium to what we're currently achieving, selling exclusively to consumers in the Caribbean coast. Our recent update on the Medellín project highlighted that we now have two 12-year take-or-pay gas sales contracts for a total volume of 75 million standard cu ft per day going to Medellín through the pipeline, when it commences operation in 2024, late 2024. This project has significant strategic value for Canacol and for Colombia as Canacol pursues its mission of improving the lives of millions of Colombians by supporting the Colombian government's vision of transitioning to a future with cleaner but no less abundant energy, using natural gas as a key transition fuel. More specifically, this project will allow consumers in the interior of Colombia to maintain or grow gas use through the middle of this decade, despite expected declines in production from the largest producing gas fields operated by Ecopetrol in the interior of Colombia. The project will also allow Canacol to increase our gas sales and net backs by accessing what is a new market for us and doing so in a cost-effective manner. I'd like to thank everyone at Canacol and SETCO that worked so hard to bring us to this point, and I look forward to updating you over the coming quarters and years as SETCO works to complete the project. As in prior years, we'll be announcing our 2023 guidance in the first half of December. In summary, we are continuing to deliver financial results within our previously stated guidance, and we continue to both return capital to shareholders, at the same time investing for growth. We're now ready to take your questions. 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 are using a speakerphone, please pick up your handset before pressing the keys. If at any time your question has been addressed and you would like to withdraw your question, please press star then two. At this time, we will pause momentarily to assemble our roster. The first question today comes from Oriana Koval with Balanz. Please go ahead. Hi. Good afternoon. Thanks for taking my question. This is Oriana Koval with Balanz, and I have two questions. If I can go one by one, that would be great. First, with regards to the Jobo to Medellín pipeline, just wanted to understand if these contracts with EPM include any fines and/or penalties associated with delays of the entry and operations of the contract. If so, if these events are caused because of construction delays on the EPC side, are they covered by Canacol or passed through the contractor? That was my first question. Thank you for that question. As with any of our gas sales contracts, we cannot comment on any of the particular details associated with the contract, including those. Okay, understood. Just perhaps following up on the exploration plans, if you could share any updates around the deep gas wells, particularly Pola-1 that I understood was part of the schedule for the last quarter, and how are these coming along? Thank you. Pola-1 is the first deep La Luna target gas well we're drilling in our new acreage position in the Middle Magdalena Valley of Colombia. We are using a 3,000 hp rig. The well is quite deep, up to 19,000 ft in terms of total vertical depth. We had some delays with respect to the contracting of that rig. We initially intended to spud that well the last quarter here of 2022, but we anticipate spudding that well now the first quarter of 2023. The civil works for that well have been constructed and the site is prepared and ready to accept the 3,000 hp rig that will arrive here in the first quarter to drill that well. That well will take approximately five months to drill and complete then test. We expect the timing of that well in the first quarter of 2023. Okay, perfect. That's very clear. Thank you. The next question comes from Josef Schachter with SER. Please go ahead. Good morning, Charle and Jason. Good to talk to you. First question. In your Note 18 of the results, it shows that where you're talking about the SETCO deal, it talks about the reimbursement of the $12 million of costs. Is that something that's going to be paid to Canacol before year-end, or is that something that will happen in 2023? Hi, Josef. Yeah, that payment will be made upon the receipt of the environmental permit for the project, at which point SETCO will reimburse all costs up to that date to Canacol. That's anticipated in August of 2023. I see. August 2023. Okay, good. Next question from me. The four wells that you're drilling, Saxafón, Chimela, Natilla, and Dividivi, two of them should be finished before year-end. Are we looking at 10-20 Bcf targets? Are they bigger than that? You know, do you expect that they will be included in your reserve report at year-end if they're finished and you get to test them before year-end? Yeah. Three of them, Chimela, Saxafón and Dividivi will be completed and tested prior to year-end. Only Natilla, which is a much deeper well, about 15,000-16,000 ft on SSJN-7, that will be finished drilling towards the end of January, early February. We expect that should any of those three wells, which would be Saxafón, Chimela and Dividivi, prove up gas. We will be booking those as reserves on our 2022 reserve balance. Correct. Okay. Chimela, when I look at the map, is in VMM-45, just in the area of Pola-1. Are you drilling this one to de-risk Pola-1, or is this a totally different structure? Yeah, this is Chimela targeting sandstones, conventional sandstones of the Tertiary Lisama formation. This formation is very productive in the area. Gran Tierra produces from the same sandstones immediately to the west of Chimela from their Acordionero field. This is a little deeper, however. Deeper than there, about 2,000-3,000 ft deeper than their targets there. We're expecting that the base of Lisama here will contain primarily natural gas as opposed to primarily oil. It's a separate target. It's a Tertiary sandstone target. We expect it to be gas-charged along the same fault systems that connect it to the deeper La Luna Pola target. That's where all the gas is expected to be coming from. It's a shallower test. Okay. As you go down to these zones, are these also zones that you expect to find in Pola so that if Pola doesn't have the success at the lower zone, then the upper zones could be successful? Is that what you're looking at here, or is it totally different structurally? Yeah, we view it as certainly de-risking the Tertiary section associated with Pola, which also has Tertiary targets. The presence of gas as well will be very important. It somewhat de-risks the deeper Pola location, even though Pola is a La Luna exploration target. Okay. Last one for me. Your CapEx budget is so large and of course, you know, you're also having the capital requirements on the dividend. Have you thought of having a DRIP, so that people, you know, who see the stock is quite cheap, could get in with using the DRIP format that's available, you know, for the company? Is that something you guys are considering, as a way of rewarding shareholders without doing cash and then having more cash for other company needs? I can answer that. It is indeed something the board has considered and is considering. Thank you for bringing it up and expressing your interest in that. Okay. I'll leave it there. Thanks. I hope you guys, you know, do move to consider the DRIP because I think that for retail shareholders it might be something that would be of great consideration. With that, thanks very much for answering my questions. Thanks, Josef. The next question comes from Chen Lin with Lin Asset Management. Please go ahead. Hi. Thank you for taking my questions. Actually, just continue for the DRIP. For us, United States based in United States, there is a tax withholding. Do you intend to offer that DRIP to Canadian only or, you know, or open to potentially to, you know, investor like me in the United States? Yeah. Thanks, Chen. You know, one of the reasons we started examining this was for, you know, exactly the reason you bring up. My expectation, if it's offered, is that we could offer it to all shareholders. Oh, good. But for us, we will have to have a tax withholding first, or is this not taxed? I don't know. I mean, I'm not expert in the tax law, international tax law, so. Yeah. If you wanna give me a call, after this conference call or any time next week. I am not the resident tax expert either, but I know we have worked through this situation. Okay, great. Thank you. The other question I have is with this new government, you know, they are not open for new concession, my understanding. On your existing concession, you basically can continue to do all the exploration. Is that correct? Just want to confirm with you. Yes. With respect to the existing exploration and production blocks held by operators in Colombia, activity will continue as normal under those contracts. There will be the ability to drill exploration, appraisal, and development wells on all existing contracts. With respect to new exploration bid rounds and the availability of new exploration areas, initially, the position of the government and of the Ministry of Mines and Energy, the Ministry of Mines and Energy was not to award any new contracts, as they viewed there being sufficient contracts already to explore during the next four years. However, in recent weeks, the president of the republic has indicated that they are currently assessing the possibility of offering up new exploration and production areas sometime during the next four years. It seems like they're backing a little off that position, but nothing definitive in either direction currently, Chen. Oh, thank you. Hopefully, the EU energy crisis is a wake-up call for the government. Do you foresee any royalty changes, you know, or coming, you know, going forward in the country? Again, there's gonna be no changes to existing E&P contracts, which means that the royalties that are associated with those contracts will not be changed. No, there's no prospect, you know, on any changes in royalty. Those will remain as they are in existing contracts. Okay, great. Thank you. Hopefully, this will discourage your competitor from exploring well, while you grow your production. Just to confirm, your Pola-1 is due for drilling next year, right? We should hear something by mid-year. Is that correct? Yes. We will, we'll be publishing our guidance for 2023, including our drilling program in by mid-December. The plan right now, Chen, is to initiate the drilling of Pola-1 in Q1 of 2023, and that well will take approximately five months to drill, complete, and test. Great. Thank you. Can you just remind us what's the target risk and unrisked target of this, Pola-1? The target is the La Luna. For Cretaceous La Luna, it's gas. We have unrisked gross recoverable resource mean resources of around 500 Bcf, with risked prospective resource of around 200 Bcf. It's a very large target for us, a very important well. Of course, this is the first deep well we'll be drilling into our La Luna position in the Middle Magdalena. We have just under 1 million net hectares under license there for the La Luna, with some 15 Tcf of gross mean unrisked prospective resource identified in the La Luna by our third-party auditors. Great. Thank you. Good luck. Thank you. Thank you, Chen. The next question comes from Christina Ronac with HSBC. Please go ahead. Hi. Thank you. Question on the new tax royalty, and I know it's not finalized yet. It's gonna happen next week. Remind me, I think your corporate tax rate of 35% does not go up like it does for the oil companies. Wasn't sure if you just don't have any step up like the oil producers. Then if you don't have a tax royalty tax deduction anymore, I just take whatever you have been deducting times your royalty times 35%. I'm getting roughly like $20 million that wouldn't even be paid until 2024. If I'm just at all roughly close, that'd be great. Thank you. Okay. Thanks, Christina. I can handle this. I see on our email questions that we've got multiple on the exact same topic, so I'll try and make this fulsome. First of all, to my knowledge, the reform is not yet passed. As it currently stands in front of Congress, gas, natural gas is not subject to the income surtax, so you're correct on that. Royalties will not be deductible. When we go down this last path, once again, our income tax rate of 35%, we do not expect that to change as it sits now. We will not be able to deduct royalties, which is the same as oil, which will be the same effect that oil companies will also have, right? That effect would be our 35% tax rate on the base royalty of 6.4%. Not to make this too complicated, but some of our blocks have royalties of 20%, some have a 6.4%. What's the delta? The delta is generally an X factor that people bid on when they first, you know, bid on the block from the ANH. The non-deductibility, as we currently understand it, is on the base royalty of 6.4%. It would be the effect would be 35% of 6.4% of revenue. I will now pass the conference over to Carolina Orozco for more questions from the webcast. Thank you. The first question that we have is from Andres Duarte from Corficolombiana. Andres is asking, can you please brief us on the difference between gas input prices and local contract prices currently and on the near future? Yeah, importation prices compared to domestic, correct? Correct. Domestic wellhead pricing this year in 2022 has averaged between $4.50-$5.50 from gas producers. Imported LNG loads delivered in Cartagena have been very few this year. There were some loads imported earlier on in 2022 at landed prices of $14-$16 not regasified. The LNG loads that have landed here in Prices in Cartagena this year have been approximately three times the price prior to being re-gasified and commercialized as domestic wellhead prices. Thank you, Charle. The next question is from Roberto Paniagua from Casa de Bolsa. Roberto's asking: What is the impact on shareholder value creation with Canadian proposal to impose 2% tax on stock buybacks as of January 2024? Yeah, I can answer that. I mean, our share buybacks this year totaled approximately $13 million. Two percent, of course, would be. I think that's $260,000. I mean, it's, you know, I don't think any corporate company is in favor of this. Having said that, it's, you know, at $260,000 for us, I don't think it's going to impair any value creation. Thanks, Jason. We have another question from Thierry Gronier. Thierry's asking: I would like to know more on the company's rationale on the proposed consolidation mentioned in October 24th press release. Our share price, you know, has slid a bit. Our you know, some of our peers have higher share prices. That's it. You know, that's not the motivation. The thought process here, many corporate accounts have discussed trading fees with us. We believe that alongside trading fees, meaning, you know, the price they pay on a per share basis, and they can lower their trading costs, perhaps attract more interest. You know, I think it's important to note that, you know, we decided to do this consolidation alongside the SETCO pipeline announcement, which we think will be transformational to the company in you know, a year or two's time. You know, took the opportunity to, you know, address some of the concerns raised by some of our shareholders alongside this monumental announcement for us. We have another question from the. Thanks, Jason. Yes, please go ahead, Corinne. The next question from the audio side comes from Steven Bodzin with REDD Intelligence. Please go ahead. Hi, thank you very much. All right. There's been some news reporting about the possibility of reopening that Venezuela pipeline and reversing it, bringing some gas imports. Not a lot of details so far. I don't even know if it's realistic. I'm curious if you have any thoughts about it or whether that could pose any challenges over the next 5 -1 0 years. Yes. Yes, thanks for that question. Yeah, there has been some speculation earlier on in the summertime about the possibility of importing gas from Venezuela. Of course, Venezuela contains a variety of gas reserves, and there's plenty of gas in Venezuela. Most of the current gas production there is being used for internal consumption, of course. So there's sort of three issues associated with the possibility of importing gas from Venezuela into Colombia. There's infrastructure. There is a pipeline between Venezuela and Colombia that was built back in 2008. That pipeline used to be used to transport gas from Colombia to Venezuela. Venezuela uses quite a bit of gas in the Maracaibo area for reinjection into oil-producing reservoirs to maintain reservoir pressure. That pipeline went into disuse in 2014. The pipeline has a capacity of about 300 million cu ft per day. The pipeline is essentially being shut in for almost eight years. There's quite a bit of uncertainty with respect to what investments are required to make into that pipeline, which is about 350 kilometers long to repair it, as well as install the correct new compression equipment and reverse the flow. There is an investment of uncertain magnitude required to be made in that pipeline. The pipeline, I should add, is owned and operated by PDVSA, the Venezuelan national oil company. The second question is the availability of gas. As I mentioned, the majority of produced gas in Venezuela, particularly in western Venezuela, which has access to that pipeline, is currently used in the domestic market. There is not much of a surplus of gas in the Venezuelan market currently to export to Colombia. The third question, of course, is price. The price of that gas sent from Venezuela to Colombia. Naturally, PDVSA and the Venezuelan government is thinking about exporting gas, in particular to the European market, in liquefied form, where pricing, of course, is much better. As I mentioned on the call here to a question just a little earlier, wellhead prices in Colombia are $4.50-$5.50 per MBTU. Of course, gas prices in Europe are as high as $40. With respect to exporting gas, you know, it's very likely that the government of Venezuela and PDVSA would focus on liquefying and exporting gas to Europe, instead of, you know, for much higher pricing as opposed to Colombia. Having said that, you know, those are sort of the three main elements associated with that possibility of importing gas from Venezuela to Colombia. Sounds like you're not especially concerned about the competitive threat. Not in the near term, no. Certainly not within the next, you know, 2-5 years. Again, I think that realistically and very sensibly, I would imagine the Venezuelan government will be more focused on exporting that gas to much higher value markets. Sure. I guess the reason I ask about the 5-year+ timeline is just looking at the, you know, timeline for the bond maturity and thinking long term. It sounds like you're just keeping an eye on it. Not an immediate issue. No, it's not an immediate issue. Again, the prices, you know, I don't think anyone's expecting, you know, Venezuela to give away its gas. Yeah. I think that there will be a price associated with that, and it'll be closer to international prices than to Colombian domestic prices. Yes, sir. Thank you. This concludes our question and answer session and concludes the conference call. Thank you for attending today's presentation. You may now disconnect.