Canacol Energy Ltd.

Good day and welcome to the Canticle Energy year-end 2024 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. We will only be taking questions from the webcast side today. 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 fourth quarter and fiscal year 2024 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 may not constitute any commitment as to future results, nor take into account risks or uncertainties that could materialize. As a result, Canacol assumes no responsibility in the event that future results are different from the projections shared on this conference call. Please note that all finance figures on this call are denominated in U.S. dollars. We will begin the presentation with our President and CEO, Mr. Charles Gamba, who will summarize highlights for the corporation's fiscal year 2024 results. Mr. Jason Bednar, our CFO, will then discuss financial highlights for the fourth quarter of 2024. Mr. Gamba will close with a discussion of the corporation's outlook for the remainder of 2025. At the end, we will have a Q&A session. We will now turn over the call to Mr. Charles Gamba, President and CEO of Canaco Land.

Thanks, Carolina, and welcome everyone to CannaCall's fourth quarter and fiscal year-end 2024 conference call. We're pleased to report that this past year was a record-breaking one for CannaCall Energy, with EBITDAX reaching a new high of $296 million, 25% higher than the EBITDAX recorded in 2023. Our realized natural gas prices for the year were $6.99 per 1,000 standard cubic feet, which generated net banks of between $5.41 per 1,000 standard cubic feet, 32% higher compared to last year, all the while maintaining a strong operational margin of 77%. In 2024, we averaged 165 million standard cubic feet per day equivalent of gas and oil sales, which included an average of 157 million standard cubic feet per day of natural gas. Through our disciplined approach to capital management, we will continue investing in key projects focusing on increasing our EBITDA generation and reserves base, as well as reducing our debt. During 2024, we invested $122 million in capital, 43% lower compared to the previous year and lower than our 2024 guidance of $138 million. This reduction is attributed to drilling and cost efficiency efforts during the course of the year. These capital efficiencies, combined with our strong financial performance, enable us to close the year with a cash position of $79 million. Strong commodity pricing, combined with our focus on cost reduction and production optimization, have been essential to maximize our response to market dynamics and achieve these strong results. From a drilling perspective, we drilled a total of five exploration wells and five development wells, with four out of the five exploration wells and all of the development wells being successful. We're also releasing our oil and gas reserves and deemed volumes for the fiscal year ending December 31st, 2024. Through our exploration and development drilling efforts, we achieved a 2P reserve replacement ratio of 85% with 53 billion cubic feet in new discoveries. This brings our total 2P reserves to 599 billion cubic feet of gas equivalent. The net present value of the future net revenues from our 2P reserves, discounted at 10%, is now estimated at U.S. $2.6 billion before tax and U.S. $2 billion after tax. These figures represent an increase of 21% and 13% respectively compared to 2023 year-end. The before tax value translates to Canadian dollars $109 per share of reserve value and $79 Canadian dollars per share of 2P net asset value, highlighting the strong intrinsic value of our reserve portfolio. Furthermore, with a reserve index of 10.2 years, our 2P reserves will sustain long-term production, supporting our ongoing development and future exploration projects. Finally, we're pleased to share the results of the corporate sustainability assessment conducted by S&P Global. In this rigorous evaluation, we achieved a total score of 75 points, ranking us as the fourth best company out of 165 participants in the global oil and gas business, upstream and integrated sector in the entire world. We achieved an eighth place in the environmental dimension, improving three positions from last year. Fourth place in social dimension, improving eight positions from last year. And for the second consecutive year, we ranked first in governance. I'll now turn the presentation over to Jason Bednar, our CFO, who will discuss 2024 fourth quarter results.

Thanks, Charles. The fourth quarter of 2024 was another very strong quarter for us with record EBITDAX generation and netbacks. Our realized natural gas price net of transportation reached $7.81 per MCF during the three months ended December 31st, 2024, with operating expenses averaging $0.45 per MCF, 26% lower compared to the same period in 2023. Building on this cost efficiency and supported by our strong realized pricing, we achieved record natural gas operating netbacks of $6.12 per MCF, which is 39% higher year over year and being the highest quarterly net back in the corporation's history. Our emphasis on operational efficiency continues to strengthen our financial results, enabling us to keep costs and capital expenditures in check while preserving strong operational and financial metrics. At the same time, as Cheryl noted, Columbia's tight natural gas supply reinforces our solid commercial approach which balances stable long-term take or pay contracts with healthy, interruptible sales exposure. During the fourth quarter of 2024, we generated total revenues, net of royalties and transportation expenses of $98.3 million, which were 23% higher compared to the $79.7 million for the same period in 2023. Adjusted funds from operations for the quarter totaled $52.1 million, a 68% increase from the $31 million in the same period of 2023, largely driven by higher EBITDAX. Adjusted EBITDAX rose significantly by 43%, reaching $76.1 million for the three months ended December 31st, 2024. compared to $53.1 million for the same period in 2023. This increase was driven primarily by higher operating netbacks for natural gas. The corporation realized the net loss of $25.4 million for the three months ended December 31, 2024, compared to a net income of $29.9 million in the same period of 2023. The net loss for the three months and year-ended December 31, 2024, as a result of a non-cash deferred income tax expense of $28.9 million, as compared to a non-cash deferred income tax recovery of $31.7 million in 2023, offset by an increase in EBITDAX. Q4 2024 deferred tax expense is mainly driven by the foreign exchange impact on the corporation's unused tax pools and capital pools. Our accrued capital expenditures for the three months ended December 31st, 2024 was $28.6 million, 60% down from $72.2 million in Q4, 2023. This reduction reflects lower spending on warehouse inventory, drilling, completion, workovers, and related costs, and land and seismic acquisition aligning with the corporation's commitment to capital efficiency. Our strategic investments and operational efficiencies have allowed us to achieve a return of capital employed of 18% for the fourth quarter, a significant improvement compared to 11% reported in the same period of 2023. This reflects our disciplined approach to prioritizing high return projects and optimizing capital allocation, ensuring that each investment contributes meaningfully to our financial performance. As of December 31st, 2024, the corporation had $79.2 million in cash and cash equivalents, marking its strongest cash position since Q3 of 2022, along with a working capital surplus of $45.5 million. Further, as announced on February 24th alongside our guidance, the cash position at that date still remained at $79 million. And I'm pleased to provide an update that as of today, the cash position remains at approximately $80 million. With this strong liquidity, the corporation is well-suited to address both current and future operational requirements, while preserving the financial flexibility needed to seize strategic opportunities and sustain long-term growth. I'd also like to highlight our declining leverage ratio, which was approximately 2.9 times at both year end 2023 and March 31st, 2024. That leverage ratio fell consistently throughout 2024 and at December 31st, 2024 stood at 2.31 times as a result of both record EBITDA and a very strong cash position. and indeed lower than the 2024 guidance we issued at the start of the year of between 2.4 to 2.8 times. One of the corporation's 2025 objectives is to reduce our debt levels. The Macquarie two-year term loan remains drawn at $50 million and begins terming out in four equal quarterly installments of $12.5 million, with the first of such payments scheduled for December 2025. In addition to that, the corporation will continue to monitor its prospective free cash flow throughout the year with the goal of potential further debt repayments or bond buybacks while balancing its capital programs and successful exploration developments. As of the end of the fourth quarter, we are fully compliant with all financial covenants, which include the following. First, the consolidated leverage ratio of 3.2 times in current and 3.5 times maintenance-based. Our current leverage ratio of 2.31 is well inside this covenant. The second covenant is a minimum consolidated interest coverage ratio of 2.5 times. Our current coverage ratio is at 5.1, which is well above the minimum required. And finally, a consolidated current ratio requirement of minimum one times. and we currently stand at 1.7 times. As such, we're well inside all of our financial restrictions. This concludes my comments. I'll hand it back to Charles now.

Thanks, Jason. In 2025, our focus is fivefold. Firstly, maintaining and growing Canada's EBITDA generation and reserves through higher commodity pricing and investment in drilling, work over and new facilities projects. Secondly, drilling high impact gas exploration opportunities in both the lower and middle Magdalena valleys. Third, reducing our debt. Fourth, laying the groundwork to be able to commence operations in Bolivia in 2026. And fifth and finally, continue the corporation's commitment to its ESG strategy. We published our 2025 guidance in February, announcing a capital program ranging from $143 to $160 million. Throughout the year, we expect to average natural gas and oil sales between 146 and 159 million standard cubic feet per day of gas equivalent, with natural gas sales projected to be between 140 and 153 million standard cubic feet per day. We expect commodity prices to remain strong throughout the rest of this year and into next year, and hence lowered our take or pay volumes to 111 million standard cubic feet per day in order to maximize our exposure to the higher price spot sales market. We anticipate well-head natural gas prices, including both take or pay and interruptible volumes, net of transportation to range between $7.33 and $7.65 per thousand standard cubic feet. By maintaining disciplined capital allocation and operational efficiencies, we expect to sustain netbacks between $5.81 and $6.19 per thousand standard cubic feet, resulting in an EBITDA forecast of $264 to $312 million for 2025. It's important to note that a $1 change in the cost of interruptible gas pricing impacts EBITDA by $9 to $14 million, highlighting our ability to capture opportunities in the market under higher pricing. In 2025, we also plan to increase our exploration activities in both the lower and middle Magdalena Valley basins as part of our long-term commitment to maintain and growing the corporation's reserves and production base. We intend to drill up to 11 exploration wells, including 10 new wells in the lower Magdalena Valley and one in the middle Magdalena Valley. High-impact wells include the Natia II well, where we plan to penetrate the primary CDO target shortly, having found significant reserves already in the overlying Porqueros formation. A second high impact well would include the Valiante well located in the middle Magdalena Valley. Additionally, we will continue to optimize output by installing more compression, processing facilities, and executing workovers in key producing areas. Through this multi-tiered drilling approach, which includes high-impact exploration, near-field tie-ins, and ongoing development work, we expect to continue positioning ourselves as the largest independent supplier to Colombia's natural gas market for the long term. Looking ahead, we see significant exploration potential with over 7.5 trillion cubic feet of risk perspective resource on our current exploration portfolio spread across the lower and middle Magdalena valleys of Colombia. Through our disciplined capital approach to capital management, we will continue investing in key projects focusing on increasing our EBITDA's generation and reserve base, as well as reducing our debt. Outside of Colombia, we are progressing with our strategic entry into Bolivia. We have signed three exploration contracts, the Arenales, Ovalle, and Florida Este, and one field redevelopment contract, TITA, all located in the prolific gas-producing sub-Andean basin of Bolivia. These contracts are pending congressional ratification and formalization to establish the effective dates which we anticipate to achieve in September of this year. We're currently preparing to apply for the environmental permit for Tita and developing our plans for the field's redevelopment with the intention to begin investments and field reactivation activities in 2026. Although the South Andean Basin is underdeveloped in terms of resource, it benefits from an existing export pipeline network into Brazil, creating a very favorable environment for commercialization of any gas we can bring back onto production or find. By leveraging our technical expertise and proven ability to commercialize gas, we aim to expand our regional footprint and diversify our resource base. Thank you for your attention, and we look forward to updating you on our progress in the coming months. We're now ready to take questions.

We will now begin the question and answer session. Once again, we will only be taking questions from the webcast. At this time, we will pause momentarily to assemble our roster. Please stand by.

Thank you. The first question we have today is from Omar from Oppenheimer. How will the company replenish its PDP reserves and how easy or how fast can you currently not producing 1P reserves turn into production?

Thanks, Omar. The way we typically increase our PDP reserves, generally through infield work, such as workovers of existing wells, which open new producing zones in the well, currently producing wells. The installation of compression in the field, which lowers the dry down pressure on the reservoir so we can suck more gas and push more gas out of the well. These two activities are always ongoing in our operations and always result in increases of PDP reserves from existing wells. The second way to increase PDP, of course, is to bring on new production from new wells and new discoveries, which we have done so far this year in the example of Siku 2, for example, Lulo 3, and hopefully bringing Natia 2 on by year end. So through those two activities, infield work related to working over existing wells and the installation of compression, as well as bringing on new wells, we managed to increase and replace our PDP reserves on a yearly basis.

Thank you, Charles. The next question is from Peter Bowley from Jefferies. You have $12.5 million in short-term debt under the senior term loan with Macquarie. Can you remind us the amortization profile of this loan? And can you confirm production levels have been sufficient to not trigger an accelerated amortization event under the TL Accredited Agreement?

Sure. Thanks, Carolina. So the Macquarie loan, $50 million, was taken out in September of 2024. There is no debt repayments for the first 12 months. As such, the first quarterly installment, as I mentioned earlier, is in December of 2025, and it's four equal quarterly installments of the $12.5 million, with the last one being in September 2026. uh production levels sufficient yeah there is the production levels have not dipped below any form of accelerated amortization for for any month uh since inception to date um and for those that aren't aware you know should it trigger which once again we do not expect that to happen it would simply pay out in six payments beginning in October 2025. So essentially it paid over the final six months instead of the final 12 months, but we're not anticipating that.

There's another question from Peter. Can you share an update on Natilla 2 and when you target knowing results?

Yes, Peter. We're currently running casing in the well to isolate the gas that we have already discovered within the shallow porcaro formation. And once we've completed that casing operation, we will commence drilling again to deepen the well through the primary target, which is the Cienaga de Oro. These operations should take between four to five weeks. Okay.

The next question is from Alexander Emery from S&P Global Platts. Can you provide more color on your plan for your Bolivian blocks this year? We understand Canacol signed the four contracts with Bolivia's energy ministry in January.

Yes. In Bolivia, we are waiting for the ratification of the four contracts by Congress. We anticipate that to occur in September of this year. In the meantime, we are preparing the environmental, all the paperwork to submit for environmental permitting of the TITA block. so that we can start operations in Tita next year. And those operations would include workovers of existing wells, testing of existing wells, the construction of early production gas treatment facilities, and the construction of a short flow line to tie those wells into the export line to Brazil. So that's the status of Bolivia. We're aiming to have production from Bolivia, hopefully exiting 2026.

Next question is from Alejandra Andrade from JP Morgan. On the tax side, can you remind us the expected cash payment for 2025? To clarify, you do not need to get rebates from the government, but simply will make a lower payment, correct?

Yeah, as our guidance press release roughly a month ago stated, the tax installment that we will pay in Q2 total $18 million, of which $12 million is a prepayment related to 2025 tax. And of course, we have roughly a million dollars a month comes off our revenue checks, you know, being like two or two and a half percent. So it's not a big number. And no, we don't expect any rebates. Anything we have overpaid essentially just rolls into a credit for the next year and thus lowers that year's taxes too.

Thank you, Jason. The next question is from Oriana Cobalt from Balance. In your reserve reports, we see your price forecast for the next five years with revisions to close to 40% versus 2024 report. Can you shed additional color on what are you seeing behind your expectations? And if you're using any benchmark reports for forecasts,

Yes, this, um, this reflects the, um, not only the current market dynamics in Columbia, where there is a shortfall of, of gas supply, but also the cost of imported, uh, and regasified LNG into Columbia. So essentially the benchmark that, uh, that applies to Columbia, specifically the, the landing point of the spec terminal located in Cartagena. parallels that of Brazilian imported LNG pricing at a premium of about 10% to 15% given the relatively small votes that Colombia can accept. So that forecast going forward reflects current market conditions, which are being driven by the shortage of gas and the relatively high cost of imported LNG into Colombia tied to Brazilian import benchmark.

Thank you, Charles. We have a question from Alexander from Sonaris Investment and Management. When it comes to reducing debt, what is your priority, buying back bonds or reducing the RCF?

Well, first of all, as I mentioned, we do have some scheduled Macquarie payments, which is not dissimilar from the RCF, perhaps. Obviously, the quickest way to To deliver post that would be to buy back bonds at a discounted rate. So that's certainly on the radar. And, you know, any excess cash flow, you know, I suspect will be allocated to a mix of both, whether it's the RCF or the bond buyback. It's entirely possible and perhaps likely that we will be extending the term of the RCF also.

We have a question from Bernardo Carvajal from Farallones Capital. Thank you for the webinar. Are you considering any sale of assets to help the leverage?

No, we are not.

The next question is from Andres Castillo from Kratos Capital Partners. Please talk us about how you see pricing of natural gas evolving vis-à-vis the price of imported LNG via Cartagena or Buenaventura?

Yeah, I mean, the only practical, in the mid to near term, and that's the next five to six years, the only potential source of new imported volumes of LNG would be through the expansion of the SPEC terminal in Cartagena. That's a fairly limited capacity terminal at the moment. So there's not a lot of potential in the near to midterm to significantly increase imports of LNG into Colombia. So we expect, again, as I mentioned in an earlier question, that imported LNG pricing in Colombia will certainly be at a premium to Brazilian imports. benchmarks and international benchmarks in general, given the relatively small volumes that are involved and the smaller ships that are used at higher cost to import gas into Colombia. With respect to the Buena Ventura terminal on the Pacific coast, that project has now been on the books for at least 15 years. Technically extremely difficult to achieve given having to cross the Western Andes with a gas pipeline. So that project remains very distant in any terms of potential outlook, certainly well beyond 10 years.

Once again, we are going to pause momentarily while we gather more questions from our webcast side. Please stand by.

We have one last question from Ezequiel Fernandez from Balance. How will Caneco fund the expansion into Bolivia? Would this require an equity injection or does Caneco plan to raise more debt, possibly non-recourse?

Yes, as I mentioned in response to the earlier question, the only activity we have planned next year is some some reactivation activities associated with the Tita gas field. And that would involve essentially the work over of up to five existing wells, the installation of some production treatment facilities and a relatively short flow line to tie the facilities into the export line. We anticipate that that will cost approximately $12.5 million in total. And the result of that investment would be commercializing gas production. So certainly in the near term, 2026, relatively small investment into Bolivia simply to reestablish production from that existing gas field. Going forward, 2027 and beyond, we would start drilling new wells in both that existing gas field as well as start exploring some of the three other blocks over the next five years. We expect cash flow from TITA as a result of next year's activities and essentially relatively minimal amounts of new cash into Bolivia once TITA is up and cash flowing.

Thank you, Charles. This was the last question. Thanks everyone for joining us today. We appreciate your time and interest and we look forward to connecting with you again on our next call. Have a great day.

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