Canacol Energy Ltd.

Good morning and welcome to the CannaCall Energy first 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 telephone keypad. 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 CannaCalls first 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 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 uncertainty 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. Charles Gamba, who will summarize highlights from our first 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 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 Canacol Energy.

Thank you, Carolina, and welcome everyone to Canacol Energy's first quarter 2023 conference call. In the first quarter of 2023, we realized natural gas sales of 184 million standard cubic feet per day, which is just above the midpoint of our annual guidance of 160 to 206 million standard cubic feet per day. Our relatively stable production and operating conditions allowed us to report a quarter with the highest sales prices and netbacks prior to COVID. An operating margin of 78%, record EB DAX of $61 million, and a relatively high return on capital employed for the quarter on an annualized basis. With respect to our drilling activity, we were largely focused on production testing of the Saxophone 1 and DIVI-DIVI 1 gas discoveries. With Saxophone 1 testing at a combined rate of 15 million standard cubic feet per day and DIVI-DIVI testing at a rate of 5 million standard cubic feet per day. Saxophone is currently being tied into the whole facility and a commercialization plan is currently being worked up for the DIVI-DIVI discovery. Subsequent to the first quarter, we announced the discovery at LULO 1. which is located on a 100% operated VIM21 exploration and production contract. LULA 1 encountered 207 feet of net gas pay within the primary Cienaga de Oro sandstone reservoir. And once we finalized production testing, which commenced last night, in various zones, the well will be tied into permanent production directly to the whole gas treatment facility located only 50 meters from the well. Lula One is part of our 2003 exploration program and has opened an area of deeper potential in and around our main producing area that we're planning to pursue aggressively in the short term. I'll now turn the presentation over to Jason Bednar, our CFO, who will discuss our first quarter financials in more detail.

Thanks, Charles. The first quarter was another very good quarter with strong netbacks from our producing operations. Our gas operating net back was $4.01 per MCF in the three months ended March 31, 2013, which is 12% higher than in the same period in 2022, 8% higher than the prior quarter, and approximately 5% above our guidance of 381 to 384 on average for 2023. These high netbacks can be attributed to spot market pricing that was significantly stronger during the quarter than we had assumed it would be for the whole year of 2023 on average. As such, our total realized gas price of $5.13 per MCF was relatively strong. We're encouraged by the persistence of robust pricing for interruptible gas sales despite somewhat subdued demand in terms of volumes. Recall that the majority of our guidance is based on sales under fixed take-or-pay contracts with an average fixed price of $5.09 per MCF. Off-ex was $0.25 per MCF in Q1, down from $0.30 in the fourth quarter, as we were undertaking less maintenance. In percent terms, our gas royalties increased slightly to 17% of revenue due to higher production at the VIM-5 block, which is subject to higher royalties. I'll also note that our recent LULO discovery as well as its planned development wells will only have a 9.4% royalty. Return on capital employed was 17% for the quarter on an annualized basis and 12% on a trailing 12-month basis. We reported 74 million of revenue net of royalties in transportation, which represents a 12% increase from Q1 of 2022. This increase was driven by a 3% increase in sales volumes, combined with a 10% increase in realized prices, slightly offset by higher royalties. $33 million in adjusted funds from operations, which represents a 3% decrease from the same period in 2022. EBITDAX of $61 million, which represents a 23% increase from the same period in 2022. And finally, net income of $17 million, being 31% lower than the same period in 2022. The significantly different trend in adjusted funds flow from operations and EBITDAX is mainly attributable to an increase in cash taxes relative to the same quarter in 2022. The $26 million of current taxes this quarter has several factors impacting that relatively large number. First of all is the increased taxes on the company's record EBITDAX, which was $11 million higher than in the same quarter of 2022. Secondly, the recent tax reform made royalties non-deductible beginning in 2023 and also added an additional surtax on our relatively modest oil operations. And lastly, as you may recall, in Q4 of 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, which is still expected to provide benefits over the next 10 years. The final steps of that reorg are currently being completed, and as such, this quarter's tax provision recognizes some associated trailing costs. As mentioned, EBITDAX of $61 million was the highest we have ever reported, and I think the long-term trend of steadily growing EBITDAX over the last seven-plus years is worth highlighting briefly. We do anticipate this trend continuing, and as such, our high-case 2023 EBITDAX guidance of $263 million remains unchanged. This concludes my comments. I'll now hand it back to Cheryl.

Thanks, Jason. Our results for the first quarter once again demonstrated high and stable operating margins, as well as a very respectable rate of return on capital employed. Our guidance and plan for 2023, which I discussed on our year-end results conference call in March, remain largely unchanged. Forecasts realize contractual gas sales for 2023, which include downtime, are anticipated to range between 160 and 206 million standard cubic feet per day. Our gas sales averaged 185 million standard cubic feet per day for the first quarter and 180 million standard cubic feet per day during April of this year. So we have started the year around midpoint of our guidance. The corporation's firm 2023 take or pay contracts alone averaged 160 million standard cubic feet per day, net of 2023 contractual downtime. optimistic we will continue to see demand and related sales volumes and pricing remain strong particularly heading into what is expected to be a very strong el menial the second half of this year 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 our capital program has flexibility to adjust spending as new information is obtained and opportunities present themselves. An example of this is our decision to immediately drill the Lulu 2 well following the discovery of Lulu 1 to praise the extent of this important discovery. We're now ready to take questions.

We will now begin the question and answer session. To ask a question, you may press star then 1 on your telephone keypad. 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 is from Oriana Kovalt with Balance. Please go ahead.

Hi, thanks to all the chemical team for the material team. Congratulations for the quarter. This is Serena Colt with Balance, and I had three questions. If I may go one by one, that would be great. The first one has to do with this lowered maintenance activity that you recorded during the quarter and that actually drove lifting costs down. So if maybe you could mention how should we think of upcoming scheduled maintenance activities and in terms of lifting costs impact, should we think these are some new sustainable levels? That would be the first one.

Yeah, I can answer that question. You know, due to various, you know, timing issues, et cetera, you know, the maintenance or the OpEx by quarter sometimes gets a little lumpy. I would not consider this 25 cents as the new go-forward norm. Our budget is for 32 cents on average for the year, and we still do expect to see 32 cents on average for the year.

Perfect. Thank you. And maybe just moving on to the second one. In terms of the RCF, we noticed that you used $75 million during the quarter, $40 million additional on the $35 million you had initially used for debt repayment. So just to understand if this 40 million is in connection with the tax payment that you had already anticipated, that you had already mentioned during your last earnings call, and if you're seeing perhaps revisions in the additional amount that you plan to tap from this RCF in the following quarters.

Yeah, I'm going to tie that in with a written question I already have from Christian Calderon. where he's basically asking, you know, this similar schedule of the tax payments. So these financial statements show that we paid $18 million of tax cash payments physically out the door during Q1. Of course, that initial tax restructuring bill, if you will, of $65 million, that will be paid, the balance of that will be paid this quarter. With respect to the use or how much we may use of the $200 million, I will say that today we are drawing $130 million of that. That amount, of course, has been upsized from the $75 to the $130 amount in order to pay that last $65 million of the restructuring cost. But I will also state at this point in time, As of today, we do have $85 million in the bank. We do not intend, anticipate to draw any more of that revolver during the remainder of the year. And on a debt to EBITDA ratio, we expect to end the year at approximately 2.4 times. I think this quarter we ended at 2.31 times. And to refresh everyone's memory, Our bond covenant is at 3.25 times and the revolver is at 3.5 times. So we're well inside those covenant restrictions.

That's very clear. Thank you. And just one last one with regards to sales that are coming up from Tesorito. So just to, maybe if you could provide additional quarters in terms of availability, if you saw any improvement during the quarter and how much of the total sales that you're reporting are coming in from Tesorito. That would be helpful. Thank you.

Charles, would you like me to answer that?

Sure. Go ahead, Jason.

Sure. So during Q1, Included in our numbers was 21.9 million cubic feet a day on average for the 90 days of Q1 that were sold to Tesarito at a healthy price of $5.66. Perfect.

That's very helpful. Thank you very much, guys. And again, congratulations for good results during the quarter.

Thank you. The next question is from Joseph Schachter with SER. Please go ahead.

Good morning, everyone, and thanks for taking my questions. Jason, back to you. With the increase, as you mentioned, on the RCF to 130, is that for our modeling going to be the high point for debt and that you expect debt to be lower by the end of 2023?

That will be the high point for the year. At this stage, you know, according to the budget, you know, which could conceivably have some upside left on them, but according to the budget, we would also end the year at that $130 million. Now, you know, I said earlier, and I'll re-note here, that our current cash balance is $85 million. So, you know, it's been adding to the current cash position, not just simply being a Spencer drilled into the ground at this stage.

Just to follow up, net debt at the end of December 22 was 573 million US. Do you expect to be below that at the end of this year?

Let me just look on the screen here. The net debt at the end of the year we anticipate to be... Just over $600 million.

Okay, super. And Charles, you mentioned in your... Right around 600 mil. Okay, yeah, I made that note. Thanks very much. Charles, you mentioned in your commentary about El Nino, is that going to affect the hydro and is that going to open up the ability for more spot sales? Maybe if you can give us your thoughts of how El Nino might affect operations in Colombia. so that we can get an idea of the impact of that.

Yeah, two things. El Nino, the forecast from NOAA for El Nino is now at 93% probability, according to the last update this week from NOAA, starting in July of this year and extending potentially through mid-year 2024. So typically, that would indicate that by... third quarter this year, we'll start to see reservoir levels here in Columbia at very low levels. And that, of course, will require the use, the addition of, spare one moment, And that will essentially necessitate the use of thermoelectric power plants to make up for the shortfall in electrical power. So that will translate into two factors related to us. First, we will increase overall volumes. We have a productive capacity now, a fairly healthy productive capacity to meet anticipated demands. And the second factor will be pricing. So typically we tend to see much higher pricing on the spot market during El Ninos. If we go back to 2016, during the last El Nino, we saw spot pricing in the $12 to $14 per MMBTU. We also anticipate that Tesorito, the 200 megawatt power plant that we're connected to, will be dispatching at 100%, and the capacity of that plant is 40 million cubic feet per day. So yes, we expect higher volumes and better pricing on interruptible prices and Tesorito pricing.

Okay, super. That would be fabulous if that occurs and really help cash flow and maybe knock that debt down a little further. You mentioned that you're following up on the exploration success. Does that mean that POLA 1 gets moved into 2024? Maybe if you can give us some guidance on how you see the exploration program and any issues related to equipment or whatever, and if POLA needs to be pushed further into the future.

Yeah, two things. With respect to the success at Lulo, which is a deep Cienaga de Oro play in and around our production facilities, we've identified several other prospects to drill in the area. It's about a five-kilometer square area in and around our producing facilities. So after we drill Lulo 2, we're going to be drilling the Piña 1 and the Ceresa 1 exploration prospects, which are very similar, identical to Lulo, and then possibly a fourth exploration prospect. With respect to POLA, we're currently negotiating a 3,000-horsepower rig. We expect that if we successfully negotiate that rig, we will be spotting POLA mid-September to mid-October of this year. With that date in mind, we could possibly have results by year-end, but it's likely we would have results in the first quarter of 2024. Okay.

Okay, that does it for me. Thank you so much for taking my questions, and congratulations on the improved quarter.

Thanks, Joseph.

Again, if you have a question, please press star, then 1. While we wait, I'd like to turn the call back over to Carolina Orozco for some web questions. Please go ahead.

Thank you. We have one question from Ricardo Sandoval from Bancolombia. Can you explain how did you accomplish a reduction of 27% in operating costs?

can we expect the margins like first year 2023 for the whole year um yeah i think i partially answered that i mean our our operating expenses you know as a quantum are relatively low this quarter it was you know five million dollars uh which equaled the uh 25 cents so you know even an additional one million dollars of maintenance activities which would have been in the original budget, you know, would bring that 25 cents up to the 30 cents. So, you know, as I think I already stated earlier, we do expect to catch up on those maintenance activities, whether they occur in Q2 or Q3, with those quarters, you know, having higher than the annual budget of 32 cents. But, you know, overall as a whole, Our look through till the end of the year, we still believe the year will average approximately 32 cents of offense.

Thanks, Jason. We have another question from Cesar Orozco. Which one is your expectation of net sales according to the dry climate is coming in Colombia? Do you keep expecting to make investments outside Colombia according to the new political risks? And how are they going, especially in Bolivia or other locations?

Okay, I think I covered our expectations with respect to El Nino and the increase we expect in volumes and interruptible pricing on the question with Joseph. With respect to our activities outside of Colombia, we continue to negotiate several exploration and production contracts in Bolivia. We expect that process to conclude shortly, at which time we'll be making a decision with respect to proceeding in Bolivia. And that, of course, would be gas as well.

Yeah, Caroline, I'll just note here also the numbers that I gave out. with respect to net debt at the end of the year and net leverage ratios at the end of the year were based on, there is zero upside put into those numbers with respect to El Nino. Those are simply just based on our actual quarter to date and the remainder of the year averaging that 206 number.

Our next question. Excuse me, our next question is from Nikos Manolios with Ingalls and Snyder. Please go ahead.

Good morning and congratulations. I have some more exploration-related questions. The DBDB one, well, what was the drilling cost and what are the potential development costs for the options you're considering, the pipeline connection or a CNG plant? And also, could you give us an update on the status of the Kimela one, well, that you drilled back in January and the Natila well, Natila 1 well.

With respect to Divi Divi, that was a very shallow well, 5,600 feet vertical depth. I believe the final drilling completion cost came in at about $3 million because it's quite shallow, of course. With that particular discovery, we're looking at a plan. In that area, we are unable to shoot seismic, 3D seismic. It's a fairly wet area. So the first thing we're going to do later this month is commence a very long-term production test of the zone, the Sikuku limestone we encountered, to see what the potential reserves might be associated with that. A long-term production test can give us some idea. Upon the completion of that long-term production test, we will formulate a commercialization plan, which has two options. Either tie it into the TGI pipeline, 35 kilometers to the east if it's sufficiently large, or to install a liquefication plant at Divi Divi and sell liquefied natural gas to some of the surrounding areas. Population centers, one of the largest ones would be the city of Cucuta on the Venezuelan border, which has a consumption of about 8 to 9 million cubic feet per day of natural gas, which is not connected to any pipeline system. So that consumers in Cucuta are using compressed natural gas at fairly high cost. So we should have a commercialization plan worked out for Divi Divi after that long-term production test. With respect to Chimila, we plan to initiate production testing here at the end of this month. We're testing several of the oil zones we encountered there. And if the test results are good, we will immediately commence temporary production of those wells and truck the oil to local transportation points. And with respect to Natia, we do not have an update to provide at this point in time. I see.

One more follow-up on the DBDB. What would be the minimum reserve size to justify a pipeline connection? Would we be looking at something at least a minimum of 50 BCF to justify a pipeline connection?

Given the distance and the cost of the pipeline connection, probably 25 BCF. would be sufficient to construct a six-inch flow line, a six-inch flow line which would be capable of transporting about 20 to 25 million cubic feet per day. So that's the transportation option via pipeline. The LNG option, you know, based on the production test that we currently have completed, the LNG option is commercial at this point in time.

Okay, thank you very much.

The next question is from Chen Lin with Lin Asset Management. Please go ahead.

Hi, Charles. Congratulations for the good quarter. I did probably miss a little bit. I think a lot of people were asking about Omnino. I know we discussed that last time we were in Bogota. So the question is, right now you're producing about 185 million cubic feet a day. So what's the actual maximum capacity you can provide? in terms of amino. And I understand that right now the 160 is the contract price. The rest will be at the spot price. Is that correct?

That's correct, Chen. So anything above 160 is essentially offered as spot price. And our current productive capacity at the moment is about 240 million cubic feet per day. LULO and LULO2 should boost that significantly.

Would Lulu already in time of this amino season, this surge of the natural gas demand?

Lulu is already connected into the hobo production facility. We're flowing the well as we speak into the hobo production facility. Okay, great. Thank you, Chen. Great. Thank you, Chen.

At this point, I'd like to turn the call back over to Carolina Orozco.

Thank you. We have a question from Agustin from Pine Bridge. Can you provide some update on the next option for new thermal capacity if you can share the strategy and update on timeline? Many thanks.

Yes, the UPME has initiated a new bid round for energy, both thermal and renewable. We are currently evaluating couple of projects. With respect to that, those would both be thermal projects, very similar to the Tesserito project we're currently partnered with Celsia and ProElectrica on. With respect to the timing, that bid round, bids will be due in mid-August currently. So we are working with a number of different parties to look at participating in that bid round with the objective of participating in at least one or two new power projects. And these projects would come online in 2026 or 2027.

Thank you, Charles. We have one more question from . In the light of your strong exploratory activity, if you were to keep the current pace, how many years of exploratory activity will your current portfolio of exploratory licenses last?

On our current 11 EMP licenses that we currently have under contract with the regulator, we've identified about 175 remaining exploration prospects that we could drill. under the current contractual terms. So, that's probably at least 10 years of portfolio on the expiration side.

Thank you, Charles. With this, we don't have any questions, any more questions. Thank you all for participating in CanonCold's first quarter conference call. We hope you all have a great day.

The conference is now concluded. Thank you for attending today's presentation. You may now disconnect.