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spk02: Good morning and welcome to the CannaCall Energy second quarter 2023 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 will be an opportunity to ask questions. To ask a question, you may press star then one on your touchtone phone. Please note this event is being recorded. I would like now to turn the conference over to Carolina Orozco, Vice President of Investor Relations. Please go ahead.
spk01: Good morning and welcome to CannaCall's second quarter 2023 financial results conference call. This is Carolina Orozco, Vice President of Investor Relations. I am with Mr. Charles Gamba, President and Chief Executive Officer, and Mr. Jason Bednard, Chief Financial Officer. Before we begin, it is 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 finance figures on this call are denominated in U.S. dollars. We will begin the presentation with Mr. Charles Gamba, President and CEO, who will summarize highlights for our second quarter results. Mr. Jason Bednar, our CFO, will then discuss financial highlights, and Mr. Charles Gamba will close with a discussion of the corporation's outlook for the remainder of 2023. At the end, we will have a Q&A session. I will now turn the call over to Mr. Charles Gamba, President and CEO of Canacal Energy.
spk00: Thanks, Carolina, and welcome everyone to Canaco's second quarter 2023 conference call. In the second quarter of this year, we realized natural gas sales of 185 million standard cubic feet per day, just above the midpoint of our annual guidance of 160 to 206 million standard cubic feet per day. We continue to report strong and stable financials, which allow us to continue to return capital to shareholders via our quarterly dividend program. Our relatively stable production and operating conditions allowed us to report a quarter with high sales prices, net backs and operating margins, EBITDA acts of $61 million, and a relatively high return on capital employed on an annual basis of 16%. Last week, we announced our July sales averaged $197 million standard QVP per day, which is the highest monthly average so far this year. On the drilling front, we announced a successful test of the Chimela oil discovery in the mid-mag that we had previously announced in January, with an average rate of 353 barrels of oil per day from the base of Lisama. With this test data now in hand, we're progressing development plans for this discovery. This is in addition to the testing of the saxophone and DVD gas discoveries, which was also announced in early May and which was discussed in our last conference call. With respect to our drilling activity for 2023, we've been primarily focused on exploration of the Cienaga de Oro prospects, situated close to our hobo gas processing facility, which can be commercialized very quickly. We announced the discovery of LULO-1, located on our 100% operated VIM-21 E&P contract, which encountered 207 feet of net gas pay within the primary Cienaga de Oro sandstone reservoir and tested 17 million standard cubic feet per day. We followed this up by drilling the Lulo 2 appraisal well, which encountered 230 feet of net pay and tested 24 million standard cubic feet per day. Both Lulo wells have been tied into our facilities and are currently on production. Last week, we announced that we had plugged and abandoned the Pina Norte 1 exploration well located on our 100% VM21 EMP contract after encountering an overpressured zone in a very shallow reservoir. Fortunately, we were able to move very quickly to drill a twin offset well, which we are now completing and preparing to bring on production next week. With a total of three drilling rigs, we are planning to continue our drilling activity with the Malfadine and Ceres exploration wells and the Aguas IV development well, all located on the VIM 21 E&P contract. The Malfadine Exploration Well is situated approximately 1.5 kilometers to the northwest of our hobo production facility, and the Cereza Exploration Well, which spud two days ago, is located approximately 500 meters to the north of Hobo. I anticipate we will be providing results from our drone activity in our regular monthly updates. Here at Canacol, we understand the crucial role of natural gas in addressing climate change and global challenges and remain committed to supporting Colombia's objective of achieving a 51% reduction in emissions by 2030. In line with this, we have published our 2022 ESG report and long-term decarbonization goals, whereby we aim to achieve zero methane emissions by 2026, and reduced Scope 1 and 2 emissions by 50% in 2035 and achieved carbon neutrality by 2050. For 2022, we reported Scope 1 and 2 GHG emission intensities that are an average 80% lower than our oil-producing peers and 50% lower than our gas-producing peers in North and South America. Our emissions intensity is lower than the average for many broad equity indices, including some with constituents selected for having low carbon emissions. Our progress has driven us to the top 10th percentile of upstream oil and gas companies in the CSA S&P assessment, and we have received an A rating from MSCI, affirming Canaco's leadership in ESG. I invite all of those interested about our ESG achievements during 2022 to read our report, which is now available on our website. I'll now turn the presentation over to Jason Bednar, our CFO, who will discuss our second quarter financial results in more detail.
spk04: Thanks, Cheryl. The second quarter was another very good quarter with strong netbacks from our producing operations. Our gas operating netback was $3.94 per MCF in the three months ended June 30, 2023, which is 8% higher than in the same period of 2022. and slightly above our guidance for 381 to 384 on average for 2023. As was the case in the first quarter, these high netbacks can be attributed to strong pricing under our firm contracts at $5 per MCF on average during Q2, combined with interruptible market pricing that was significantly stronger during the quarter than we had assumed it would be for the whole year of 2023 on average. A realized gas price of $5.13 per MCF net of transportation was exactly the same as we reported for the first quarter, demonstrating a new stable and higher level for our realized prices. We remain encouraged by the persistence of robust pricing for interruptible gas sales. Recall that the majority of our guidance is based on sales under fixed price take or pay contracts with an average price of $5.09 per MCF for 2023. OPEX was $0.35 per MCF in Q2, up from $0.25 in the first quarter, as we had previously indicated that we would likely return to doing more maintenance spending in the second quarter. This brought the first half of 2023 OPEX to $0.30, which is slightly less than our internal budgets of $0.32 for 2023 on average. In percentage terms, our gas royalties were roughly in line with prior quarters at 16.5% of revenue. Return on capital employed was 16% for the second quarter on an annualized basis and 12% on a trailing 12-month basis. We reported $75 million of revenue net of royalties in transportation, which represents a 6% increase from Q2 of 2022. This increase was driven by an 8% increase in realized prices, slightly offset by a 2% decrease in sales volumes, combined with slightly higher royalties. $34 million in adjusted funds from operations, which represents a 14% decrease from the same period in 2022. This $5.4 million decrease in adjusted funds flow from operations is solely attributable to a 9% increase in current taxes relative to the same quarter in 2022. We also reported EBITDAX of $61 million, which represents a 10% increase from the same period of 22. And finally, we reported net income of $40 million with the change from a net loss in the same quarter of 2022 being due to a deferred tax recovery this year when we had deferred tax charges in Q2 of last year. As you hopefully recall in Q4 2022, we initiated a corporate reorganization in order to better optimize our business, alongside of which we also increased our deferred tax asset by $202 million. The most important steps of that reorg as it relates to our ability to make use of our tax assets were completed by the end of the second quarter. As a result, our expectation is that the relatively high current tax expense in the first two quarters of 2023 will not continue going forward. So I expect significantly less current tax expense going forward than we have reported for the first two quarters of 2023. EBITDAX of $61 million in the second quarter was just a few hundred thousand dollars short of the new record we set in the first quarter, so I will again highlight the long-term trend of steadily growing EBITDAX over the last eight years. We do anticipate this trend continuing and are optimistic with regards to the pricing and demand outlook for the second half of 2023, and as such, our high-case 2023 EBITDAX guidance of $263 million remains unchanged. Before I hand the call back to Cheryl, I'll make some comments on capital spending to date and the outlook for the remainder of the year, as well as debt levels. Our cash capital expenditures of $99 million for the first six months represents approximately 60% of our unchanged high case capital budget guidance of $163 million for 2023. The $99 million of first half CAPEX does include $17.5 million of warehouse inventory at June 30th as required under IFRS, including a wellhead and casing materials for POLA and other upcoming wells. If we adjusted for these amounts as traditional inventory items, the CAPEX levels for the first half of 2023 would be exactly 50% of the annual $163 million budget. As such, I do anticipate that we can continue significant drilling activity, despite anticipated lower spending in the second half of 2023. During the second quarter, we drew an additional $70 million on our revolving credit facilities, such that we've now drawn $145 million in total on this $200 million facility as at June 30th. As a reminder, the main reason for the additional draw during the quarter was to pay a $65 million one-off cash tax bill incurred as part of the corporate restructuring that we had discussed earlier and in detail on prior calls. Our net debt to EBITDA leverage ratio was 2.7 times on a trailing 12-month basis at June 30, with the increase from prior quarters caused mainly by the restructuring tax payment. How this ratio evolves going forward will depend on a host of factors, including gas demand as a key driver of revenue and hence also EBITDA levels. With our one-off cash tax payment now behind us, my expectation continues to be that our leverage ratio will decrease to approximately 2.4 or 2.5 times a year end. To refresh everyone's memory, our bond covenant is at 3.25 times and the revolver is at 3.5 times. As such, we're well inside those covenant restrictions. That concludes my comments, so I'll now hand it back to Charles.
spk00: Thanks, Jason. Our results for the quarter once again demonstrate high and stable operating margins as well as a very respectable return of capital employed. As Jason just outlined, our guidance and plan for 2023 remains unchanged, and we're continuing to progress a steady exploration drilling program targeting exploration prospects located close to Hobo that can be commercialized very quickly. We're doing this in order to build productive capacity to meet the anticipated high demand of natural gas associated with the upcoming El Nino phenomena. Forecast realized contractual gas sales for 2023, which include downtime, are anticipated to range between 160 to 206 million standard cubic feet per day. Our gas sales averaged 185 million standard cubic feet per day for the first half of this year and were 197 million standard cubic feet per day during July. The corporation's firm 2023 take or pay contracts alone averaged 160 million standard cubic feet per day, net for 2023. We are optimistic that we will continue to see strong demand in related sales volumes and pricings, allowing us to report continued growth in sales volumes, revenues, and funds from operations. We therefore expect to remain well-positioned to continue returning capital to shareholders while investing for growth. We're now ready to take questions.
spk02: We will now begin the question and answer session. To ask a question, you may press star, then 1 on your touch-tone phone. If you are using a speakerphone, please pick up your handset before pressing the keys. To withdraw your question, please press star, then two. At this time, we will pause momentarily to assemble our roster. Our first question comes from Arianna Kowalt of Balance. Please go ahead.
spk05: Hi, good morning. Thanks for taking my question. This is Arianna Kowalt with Balance. I have three questions. If we may go one by one, that would be great. First, with regards to drilling for POLA 1, I just wanted to confirm if you could share any insights on how are negotiations going to bring the rig for POLA 1 drilling and when do you expect activities to begin?
spk00: Hi, Marianne. Thanks. With respect to drilling Polo 1, we are planning to target the drilling of the well for the last quarter of this year. Rig availability is very good. Rig availability in Columbia has been increasing as drilling activity has decreased about 33% in terms of drilling activity this year. So rig availability for the 3,000 horsepower we need is very good. So we're again targeting to spot that well sometime in Q4 this year.
spk05: Perfect. And just following up with additional traders for the next quarter, just thinking of the Medellin pipeline, I just wanted to confirm on what are the next steps or the steps that are missing to – to continue on to start construction works and what are the strategies that might be on the table for chemical to avoid being exposed to spot markets if there are any delays with the pipe?
spk00: The next step in the process for Medellin would be the receipt of the environmental permit, the EIA, which will allow for construction. So we're waiting for the Ministry of the Environment to issue the EIA.
spk05: Sorry, just one follow-up there. What is the expected timeline for this?
spk00: This year.
spk05: Okay. And just one last one. You had mentioned in the last earnings call the UPM bidding process that had started and the potential of having something similar to El Tesorito. So just wanted to confirm that now and how is this process ongoing and if there are any updates that you could share in this regard?
spk00: Yes, with respect to the the bid round for the Cargo de Confidabilidad, which is the additional standby power generation. The original date proposed by the UPME was August 24th, I believe, to submit bids and the UPME delayed that process by three months to November 24th. So we remain very actively engaged in in planning our proposal with our consortium members, and we await the November 24th date to make any bids.
spk05: All right. Thank you. That will be all from my side. Thanks.
spk02: Our next question comes from Josef of Schachter Energy Research. Please go ahead.
spk03: Good morning, Charles and Jason. Jason, a question for you. I see, you know, the nice bump up 10% on the adjusted EBITDA cash flow, though, down negative 24 versus 35 million comparable quarters. Is that related to that restructuring and tax? And can you kind of walk through a little bit more detail and give us some more color on that?
spk04: Yeah, sure, Joseph. So, you know, the restructuring plan is quite complicated as things of, you know, this magnitude are. It includes close to 20 steps. And although the, you know, the major steps such as the transfer of the blocks, et cetera, were done by year end, some of the trail on steps that have tax impacts, you know, did not get done until the end of Q2. As such, you know, we do see that additional $9 million in income tax and thus, you know, the free funds flow is down by, $5.4 million, you know, once again, as I said directly, as a result, the additional $9 million in tax. So now that the bulk of those things are completed, and envision things like, you know, you need to get the companies December 31st audited, and, you know, that typically takes till March, then you do the paperwork post that, etc., Now that those are largely completed, we do anticipate seeing the decrease in our current taxes, beginning in Q3 and trailing downwards from there. I'll reiterate, as I think I did, whether it was the year-end call or the Q1 call, we do anticipate seeing the benefit of the $202 million of the new deferred tax asset to be realized at approximately $40 million a year for the next five years, and then some additional trailing benefits beyond that.
spk03: So when we get into Q3 data, when we have the next conference call, cash flow should be very close to funds flow going forward?
spk04: Agreed.
spk03: Thank you. Thanks for the clarification.
spk02: As a reminder, if you have a question, please press star, then one. I will now pass it over to Carolina Orozco to read questions from the web.
spk01: Thank you. We have one first question from Roberto Paniagua from Casa de Bolsa. Please give us a deeper explanation of the increases in financial expenses and the deployment of the $105 million in debt.
spk04: So the first one, if I understood it correctly regarding financial expenses, I assume it's the financing costs, i.e. interest, etc., which would be largely attributable to the increase in the revolver balance, right? So we would have started the year at zero-ish and, of course, now have 145 million drawn, hence the extra interest expense. The second question, the increase in the debt was 70 million, drawn the revolver as I alluded to, he's probably including a change in cash on that to get to 105 million if I assume he did the math right. The first 65 million of that, related to, of course, the $65 million that we paid in May relating to the restructuring. The other components to that would be working capital changes. Our payables ended in Q2 less than they did in Q1. I think off the top of my head, $8 million less, despite us having increased capex of approximately $4 million. Those would be the major components. related to the change in net debt.
spk01: Thank you, Jason. The second question from Roberto Paniagua is, has Canacol perceived an increase in gas demand by thermoelectric plants due to the El Nino?
spk00: We're seeing overall demand in Colombia for gas has remained relatively stable. El Niño is the full effect of El Niño is anticipated to start in October and November of this year. So El Niño is still a little ahead of us here. But so far, you know, overall gas demand in Colombia has been very stable. to this point and normal. But we expect that to see an uptick in gas demand as the effects of El Nino settle in here in October, November later this year. And that will last for between six to nine months, depending on how strong El Nino will be.
spk01: Thank you, Charles. We have one last question from Roberto Paniagua, which is, are you expecting to keep the average gas price over $1.50 per MCF in the second half of 2023 and the operative net back near the $4 per MCF?
spk00: Yeah, so 160 million cubic feet per day of our gas sales are sold under take or pay, which is prices fixed. So there'll be no change in price related to the majority of our production. And the variable in increased price occurs in the interruptible spot sales we do. We did about 37 million cubic feet per day in July of spot above that. And we expect to see pricing remain very strong for the rest of the year and building in terms of demand. value through the last part of the year in the El Nino.
spk01: Thank you. We have now a question from Ricardo Sandoval from Bancolombia. Could you please give us the Henry Hub price, $2.48 per MBTU equivalency in MCF, please, to compare with the $5.30 you reported?
spk00: I don't understand that question, and we have nothing to do with respect to Henry Hub pricing.
spk04: I'll take a stab at it because I have it on my screen. It's BTU compared to MCF, so it's right around a one-to-one level. BTU just has the energy content in it, so depending on how rich your gas, it might be 101%, but it's essentially one-to-one equivalent, meaning, of course, that we get more than double the Henry Hub price.
spk01: Perfect. Thank you. We also have a question from Diego Espinoza from BTG Pactual. I believe you already answered, Charles, but just in case you want to add something. Regarding El Niño effect, do you see any increasing demand? How will you face it?
spk00: As I mentioned, we expect to see gas demand in general increasing, especially through October and the remainder of this year into next year. And as I mentioned in our presentation, we're very focused on drilling close to our producing facilities. All the exploration, the majority of exploration wells we're going to be drilling for the next two months will be located within several hundred meters of our production facility. And the reason for that, of course, is to be able to bring those wells on stream very quickly in order to commercialize into the higher expected demand for gas in the fourth quarter.
spk01: Thank you, Charles. And a similar question coming from Aman Badhar from Pender Fund Capital Management. Can you please elaborate on the potential for additional sales as a result of El Niño in second half 2023 and the potential higher price impact? If demand for gas is much higher in the back half of the year, what is the cap in terms of access to market pipeline capacity and gas production capacity? How will each of these trends into 2023?
spk00: Yeah, we expect, as I mentioned a couple of times, we expect to see increased demand for gas, certainly starting in October this year. And we expect that to be all thermoelectric power driven. And of course, we have our Tesorito 200 megawatt project situated seven kilometers from From our hobo facility, that 200 megawatt power plant consumes up to 40 million cubic feet per day if it's running flat out, and it's connected to our facility by a private pipeline, so there's plenty of transportation capacity. So I expect we could see up to an additional 40 million cubic feet of sales related to sending gas to that project in order for that project to generate during the El Nino.
spk01: Thank you, Charles. This was the last question we received. So with this, we finish our call. Thank you all for participating in CannaCold's second quarter conference call and hope you all have a great day.
spk02: The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.
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