Canacol Energy Ltd (CNECCL.SN) Earnings Call Transcript & Summary

Welcome to the EPM contract and Medellin Pipeline Project Conference Call. [Operator Instructions] Please note, this event is being recorded. I would now like to turn the conference over to Carolina Orozco, Vice President, Investor Relations. Please go ahead.

Good afternoon, and welcome to Canacol's EPM sales contract and Medellin Pipeline project conference Call. This is Carolina Orozco, Vice President of Investor Relations. 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's senior management team 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 our President and CEO, Mr. Charle Gamba, who will provide background to the Jobo-Medellin pipeline project in order to provide context for our announcement of the new sales natural gas contract with EPM and an update on the pipeline project. Mr. Jason Bednar, our CFO, will then discuss financing considerations for the project as well as adjustments to our pre-existing bridge term loan that supports the project. A Q&A session will follow. Mr. Gamba is joining us on the line from Bogotá and Mr. Bednar is joining us on the line from Calgary. I will now turn the call over to Mr. Charle Gamba, President and CEO of Canacol Energy.

Thank you, Carolina, and good afternoon or good evening to everyone, and welcome. I want to talk to you about why the new sales contract we signed with EPM as well as the Jobo to Medellin pipeline project, which that sales contract was a part of, marks an important strategic step for us here at Canacol. For those who haven't followed our story from the beginning, we began building our gas business with the acquisition of Shona Energy in 2012. At that time, we operated one gas field selling 12 million standard cubic feet per day of gas to a single user, the Cerromatoso ferro-nickel mine, who, by the way, we continue to sell gas to, to this day. That represented approximately 1% of Colombia's natural gas demand. We recognize that we could grow the business by firstly proving up the significant gas resources we believe could be discovered on our lands via exploration drilling; and secondly, by connecting those discovered gas reserves with a growing gas market on Colombia's Caribbean coast. We negotiated entry to that market at a time when we could see that the Guajira gas fields, which had traditionally been supplying over 80% of the coastal market, were entering into terminal decline. As a result, we were able to provide the market with a critical supply of gas at exactly the right time when it was needed. Fast forward now to 2021, where our gas now supplies over 50% of the gas consumed on the Caribbean Coast, with the majority of our sales being sold under take-or-pay fixed gas price contracts. That's approximately 25% of Colombia's entire national gas demand. Having those contracts allow us to have reliable and predictable revenues, which has helped reduce our financing costs and also allowed us to weather unexpected market disruptions like the COVID pandemic, which had a very negative impact on some of our oil and gas-producing peers globally. The Caribbean gas market has and continues to be important to us, and we expect that to remain the case going forward. Our next strategic initiatives was to access the market in the interior of Colombia, which currently represents approximately 60% of Colombia's gas demand. This strategic initiative has now been realized with the signing of the gas sales contracts with EPM. Gas demand in the interior of the country is more stable than that of the Caribbean market as most of the interior demand is related to residential, industrial and commercial use. Gas demand in the Caribbean market is dominated by thermoelectric power generation, which is very sensitive to rainfall, which, of course, can be somewhat unpredictable. The main reason we launched the initiatives by gas to the interior of Colombia was exactly the same reason we acquired Shona 9 years ago in 2012. Ecopetrol's Cusiana and Cupiagua gas fields located in the Llanos Basin, which supply a majority of the interior market currently, are set to enter terminal decline in 2 to 3 years' time. So we saw an opportunity to repeat what we did in the Caribbean market 9 years ago, that being to provide new gas supply just as consumers in the interior need to replace supply from Ecopetrol's mature decline in fields in the Llanos Basin. As you can see in the chart in the bottom right of this slide, which shows a recent supply forecast from the Colombian gas market authorities, local supply in the interior market is expected to decline by a lot more than the 100 million cubic feet per day that our pipeline project is planned to bring to the market began in late 2024. Without new gas volumes from Canacol's field to the interior of Colombia, we'd likely either have to reduce gas consumption significantly or become increasingly reliant on reverting to more polluting sources of energy such as coal and petroleum. Our project to connect to the interior market is, therefore, not just aligned with the Colombian government's commitment to transition to a cleaner energy matrix, but by ensuring a long-term affordable and stable supply of clean burning natural gas. This project is critical to the government's energy transition plan. I now want to briefly provide context as to why connecting to the interior market isn't feasible without the Jobo to Medellin pipeline project. In short, the gas from Jobo would have to travel 1,500 kilometers to a sub-optimally routed network of existing pipelines with transportation fees alone in excess of $5 per 1,000 standard cubic feet. After providing for an adequate return on investment for the new Jobo to Medellin pipeline, we expect transportation fees to be less than half that level, allowing us to offer gas to the interior market on attractive terms to both us and our consumers. Beyond Medellin, the pipeline will make Canacol's gas available to consumers in Bogotá, Cali and other regional markets within the interior of the country. The new gas sales contract will see us deliver gas to EPM and Medellin starting in December 1, 2024, with an initial minimum volume of 21 million standard cubic feet per day, escalating to 54 million cubic standard feet per day on December 1, 2025, and remain at this level until the sales contract expires on November 30, 2035. We won't be providing exact guidance relating -- related to expected pipeline transportation costs or sales pricing, but I can say that as currently designed, we expect the pipeline project to yield returns that will be very attractive to potential partners in the project. And we expect our sales in the interior market, including those under the new contract with EPM, to generate netbacks in line with those we have proven we can achieve in the Caribbean market. It's important to note that the Jobo to Medellin pipeline will also allow us to move gas to Bogotá and Cali via the existing Transmetano and TGI gas pipeline networks. Current demand in Bogotá is approximately 200 million cubic feet per day, and that of Cali is approximately 60 million cubic feet per day. I strongly believe this is a win-win for Canacol and gas consumers in the interior of Colombia, in particular, in Medellin and Antioquia. To deliver the gas, a new 20-inch pipeline will be built between Canacol's gas treatment plant at Jobo to the city of Medellin located approximately 285 kilometers to the south. The pipeline will have an initial transportation capacity of approximately 100 million standard cubic feet per day, which can be subsequently expanded to 200 million standard cubic feet per day via the installation of additional compression capacity. Total CapEx for the project is anticipated at approximately $450 million. In the near term, as it relates to this project, we will now focus on the following activities, all of which are anticipated to complete -- to be completed by the end of first quarter 2022: one, finalize work on the environmental permit to submit to the national environmental permitting authority, the ANLA, for approval prior to end of 2021; secondly, finalize the selection of the construction company that would be responsible for building and operating the pipeline; thirdly, arrange the necessary financing as required to execute the project; and fourthly, continue to negotiate and execute an additional 45 million standard cubic feet per day of gas sales contracts with consumers in the interior to fill the initial 100 million standard cubic feet per day capacity of the pipeline. I will now turn the presentation over to Jason Bednar, our CFO, who will discuss financing considerations for the project. When he's done, I'll make a short closing statement. Thank you.

Thanks, Charle. I will also start by providing some background. Just over a year ago, we announced that a subsidiary of Canacol had entered into a $75 million senior unsecured bridge loan with the syndicate of banks. The bridge was entered into by the Canacol subsidiary that we intend to use to construct and own the Medellin pipeline with Canacol being the guarantor throughout the outstanding term of the bridge. As required under terms of the bridge loan, we made an initial $25 million draw during August of 2020. The initial draws to be used for expenditures, such as engineering and environmental permitting. The other $50 million is available under the bridge loan is budgeted to order long lead time items needed for construction, such as pipe. Under the original terms, the remaining $50 million was to be available to be drawn at any time up to 12 months from the closing dates, and all amounts drawn were to have a initial 2-year term ending in July of 2022. What we announced today is that the bridge loan has now been amended to extend both the bridge term and the available period on undrawn amounts to July 31, 2023. I'd like to thank the banking syndicate for this amendment as it gives us increased flexibility on timing to utilize the bridge loan. Detailed discussions are ongoing with respect to Medellin pipeline with interested equity partners and the syndicate of banks interested in providing debt finance. Once equity partners and bank syndicate agreements have been signed and any applicable conditions precedent have been met, we anticipate that long-term funding will be advanced and the bridge will be repaid, thus bring Canacol of its guarantees on the bridge. I'll also mention that 25% is the maximum permitted ownership level in a gas pipeline for a gas producer under Colombian law. Note that the process of Canacol leading development of the project through its initial phases but then divesting of our interest is a process we have been through before, albeit with a smaller project, our Sabanas pipeline, which we completed in 2019. We have seen strong interest from both local and international equity partners as well as interest from national and international banks to finance it. With what is clearly a cornerstone infrastructure project for the Colombian economy and the government's ambitions to transition its energy matrix, we are positive about the level of interest and terms we can obtain. At this point, I will hand it back to Charle. Thank you, everyone.

Thanks, Jason. I'd like to close by thanking our counterparts at EPM for their persistence over the many years that we have worked together negotiating this important contract. Our ability to advance the project was delayed by a number of issues beyond our control, including a global pandemic, but I'm grateful that our team as well as that of EPM chose to persist. We're now ready to answer any questions that you might have.

[Operator Instructions] Our first question comes from Luiz Carvalho with UBS.

And congratulations. I remember discussing Shona almost 10 years ago, so congratulations on this one. Basically, I have, if I may, 3 questions here. The first one is after the signature of the contract or in the meantime, if you guys receive any contract from other cities in Colombia requesting additional gas or, I don't know, potential additional demand. So that's the first one. The second one, pretty much straightforward. When do you expect you'd see the sell-down or the 75% to be sold? I mean any expectations in terms of timing that we can expect? And the third one, maybe I missed this one, but I didn't see in the press release. I'm trying to get the presentation right now. If you can share a bit more details about the total CapEx of the project and more details about the gas prices.

Yes. I think with respect to your first question, Luiz, yes, we have been actively negotiating additional gas sales contracts with other consumers in the interior, particularly within Bogotá and Cundinamarca where current gas demand is about 200 million cubic feet per day. So we have made progress on additional take-or-pay contract negotiations with the objective being to fill the entire 100 million cubic feet per day of transportation capacity. Secondly, with respect to the 75% sell-down, we will participate in up to 25% in the equity of the project. We have been in negotiations with other equity partners for the other 75% for which we have received various offers, which we will now, of course, move forward with to close on. And thirdly, with respect to total CapEx, as I mentioned and as I mentioned before, the total CapEx for the project is estimated to be about $45 million. Our thoughts with respect to the financial structure would contemplate 70% debt, 30% equity. And our share of the equity, of course, would be 25%, which -- up to 25%, which would be the maximum allowed by the Colombian regulators. So that would translate to approximately at 25% equity interest, approximately $35 million up to $35 million on Canacol's part, which is a relatively small amount of capital to be spent over the next 3 years. So thank you for your question, Luiz.

In terms of the natural gas prices, sorry?

In line with our -- as I mentioned in our presentation, the netback for this contract as well as other contracts we're currently in negotiation is in line with our netbacks.

The next question is from Ezequiel Fernández with Balanz.

And it is great to see such transformational project for Canacol and Colombia going forward, so I join in the congratulations. I have questions on pricing, the pipes permitting and the related drilling efforts. I would like to go one topic at a time if you don't mind. Going first with pricing. I imagine that you cannot comment a lot, and you already said that the netbacks are similar to those in the Caribbean. But I wanted to know how much, if you have that information available, the average residential consumer is right now paying in Medellin for gas. And I'm talking about just the molecule, not including transport and distribution.

Ezequiel, yes, so I don't unfortunately have that type of information at hand.

Okay. Great. And maybe if the price you agreed with EPM includes transport or not? Or -- and how are you going to -- the split between the gas price and the transport, how are you going to handle that?

Yes. We -- as you realize, we don't discuss the details of any particular sales contract, neither pricing or transportation. So I have no comment with respect to that.

Okay. Great. I understand. My second question regarding the pipe permitting. I wanted to know if there is already something filed at the ANLA, at what stage it is, how long the whole process would take.

Yes, we will -- we've been working on the environmental permits for the past -- for quite some time. Our plan now is to finalize the permit application, and we hope to have that submitted to the ANLA prior to year-end this year. Typically, pipeline permits take between 12 to 18 months. We are, however, going to be applying for a special consideration with respect to this permit, which is a document referred to as a PINES, which is a project of strategic national accordance to the government, which will cut the environmental permitting time line down to around 12 months if that classification or status was given to this project. So to answer your question with respect to permitting, we expect 12 to 18 months from submission by the end of this year.

That's great then. And following up on the permitting side, 2 questions more. Is the pipe expected to go through hot areas like natural reserves or indigenous communities? And also, how are you working around securing the -- all the strips of land needed if you have a certain percentage already and if there is an instance in which the government on the basis of public interest can help you with that?

Yes. We analyzed 4 different routes between Jobo and Medellin, and we analyzed each routes from the perspective of topography, communities, environment and security. So with those 4 categories and analysis of those 4 routes, we settled on the route that essentially has the fewest number of indigenous communities located along it, which means that the process of consulta previas, which are the community consultations, will be minimized. There will be a minimum of communities along that route. The topography along that route is slightly more challenging but not insurmountable. And security and environmental, there are very strict protocols with respect to environmental, which, of course, are embedded in the environmental permits. So the study of alternative routes, et cetera, all of which go into that process. So we really focused a lot on trying to avoid as much as possible sensitive community areas, areas where there are a lot of communities and a lot of complicated negotiations. The process that I mentioned, the PINES, the status of the project as a project of strategic national importance, if the project achieves that status, it will greatly reduce the time line with respect to having those community negotiations to a much shorter period of time with the assistance of the Ministry of Interior.

Great. Is it supposed to be mostly underground or above ground?

Yes. The entire pipeline will be underground. So the entire pipeline route will be underground.

Okay. That's great. And my final question is relating to drilling. I guess depending on how the rest of your contract portfolio evolves, you will need to ramp up more or less output. So do you expect to drill outside of Jobo for these volumes? Or do you expect to be contained there still?

Yes, we will focus the majority of our drilling in the next 3 years in and around the Jobo area as we've been doing in the past 7 or 8 years. As we approach the start date for the pipeline in December of 2024, we will probably start to accelerate, particularly development drilling in 2023 and 2024 to ensure that we have more than enough productive capacity to meet our obligations for our sales to the interior as well as to the coast. But the majority of our drilling will be focused in the current area where we've been active for the past 8 years.

The next question is from Josef Schachter with Schachter Energy Research.

Congratulations on moving this major project forward. I have 2 questions. First, on the 25% ownership, do you have to be down to that level on the date when the pipeline is approved to have volumes? Or is there some date -- or is it when it gets up to $100 million? Do you have some flexibility in there? Or is it the minute you start putting volumes though, you have to be down to 25%?

We would have to be down to 25% if the pipe is transporting gas, and our expectation is to have the project completely farmed out with the award of the construction contract to our equity partners.

Okay. And the second question, in the contract with the buyers of your natural gas, do you have some requirements for certain levels of 1P or PDP reserves for different time lines to meet those new contract requirement specs?

Yes, we presented our current reserve reports to the buyers for analysis and new agents. So yes.

And do you need to increase production significantly in there? Or do the volumes and the reserves you have to date meet that need?

Well, as you know, we're continually increasing our reserve base. We have 5.7 Tcf of prospective resource identified in over 165 identified prospects to drill over the next 10 years. So our reserve replacement rate, 2P basis, has been over 200% a year. So we expect that to continue. So we expect our drilling programs to continue to add new reserves from resources as we drill along. So we're not particularly too worried about replacing and expanding our reserve base given the history doing that.

And again, congratulations.

The next question is from Román Rossi Lores with Balanz.

Congratulations on the transformative deal. I have 3 questions, and I'd like to ask them sequentially if I may. So the first one, regarding the contract. Can you confirm, is this take-or-pay modality?

That's correct. Yes, it's a take-or-pay contract.

Okay. And then looking at the map, the pipe is only 100 kilometers away from the TGI network. So are you already thinking about an interconnection there, perhaps a deal with Transmetano to make the pipe to be directional? And if so, if you have anything in mind in terms of work, investments or permits.

Yes, the plan is to connect into the Transmetano pipeline, which is currently transporting gas from Sebastopol, the TGI pipeline, to the city of Medellin. So the idea would be to connect into that pipeline. At that connection point, the EPM volumes, at the very least, would flow west along the Transmetano to be delivered to EPM and Medellin, and additional volumes would flow east along the Transmetano to be injected into the TGI pipeline in Sebastopol.

Okay. Great. And how big is the free customers' gas market that you could tap in Antioquia? I'm referring to those medium and large industrial and commercial customers that are not directly dealing with EPM, if you have any figures in million cubic feet.

It is approximately just over 70 million cubic feet per day of total demand in Medellin and another 10 million or 15 million in the remainder of Antioquia. So that's -- the market is fairly sizable there. So we are looking at additional sales contracts to other customers in Antioquia, in Medellin as well as the environments of Medellin. But for the remainder of the majority of the sales, we're looking more into the interior in the markets of Bogotá, in particular Bogotá and Cundinamarca where current demand is 200 million cubic feet per day, all of which is currently coming from Ecopetrol's fields located in the piedmont of the Llanos basin.

Awesome. And just -- this is the last one. Considering the increase in volumes, we know that you need to increase treatment capacity. So where are you doing this investment? And what are the CapEx needs that you're anticipating?

So our current treatment capacity at Jobo, we have 3 treatment plants currently operating there, is about 300 million cubic feet per day would be the current treatment capacity. So our plan is in 2024 to install an additional 100 million cubic feet per day of treatment capacity, which is identical to what we installed 3 years ago at Jobo, so the Jobo 3 train. And that costs about $30 million, $30 million to install an additional 100 million cubic feet per day of additional treatment capacity. So we would probably start that work late 2023, so that it will be ready by December of 2024.

[Operator Instructions] The next question is from Luiz Carvalho, a follow-up from UBS.

Charle, just a follow-up. How feasible do you think is to get the additional 200 million cubic feet in the next 5 years in take or, I don't know, pay given the size of the, say, of the market currently around $600 million? I mean what's the feasibility that you think here?

I think if you look at that graph on Slide #1 in the low right, which I referenced a little earlier in the presentation, you can see that starting in mid-2024, the supply and demand curves for the interior across. And of course, that's all related to Ecopetrol's production in Cusiana-Cupiagua declining. So you can see, for example, that by 2027, there's approximately 200 million cubic foot a day current shortfall in the interior market from those fields. So the way we're looking to design the pipeline is sort of a Phase 1, which is the -- to install 100 million cubic feet per day of initial capacity. And then within 2 or 3 years after that, to evaluate the installation of Phase 2, which is simply the installation of additional compression stations along the pipeline route. And given the projected decline in the interior, I would say that it's a very good option to have, to be in a position to make the call 1 or 2 years after the startup of our pipeline project in December of 2024 to add an additional 100 million to supply additional gas to the interior.

Okay. Now I'm going to be reading some questions that we have received through the webcast. The first question is from Ricardo Nasser from JPMorgan. He said, how should we think about CapEx in the coming years given the additional reserves required to supply the EPM contract and the Medellin pipe?

Yes, I can probably add to that. I've mentioned on a few conference calls recently that we're working through some tail end of some 6-year strategic model. So we've got a pretty good handle on what will be required. For context, our drill program this year is up to 12 wells and approximately $120 million worth of CapEx. Moving forward, of course, we'll have heavy drilling in 2023 and 2024. I'd expect 2022 levels will also potentially be ramped up from this year, but it's certainly something that our cash flow can support. And of course, there's the $30 million Jobo expansion that Charle had mentioned. But we give up healthy cash flow. We still have a revolver that's untouched, et cetera. So it's -- and debt levels of less than 2x EBITDA even on these decreased EBITDA levels due to COVID with our production levels recently ramping up. So it's nothing that's concerning, and it certainly will be an exciting time as we drill forward.

The next question is from Sofía Rojas from BD Capital. When do you expect to draw the remaining $50 million of the bridge loan? When do you anticipate a prepayment?

Sure. Okay. So the bridge loan, as I went through, has been extended to essentially -- the term is 2 years from now. So as Charle mentioned, the environmental permit will likely take between 12 and 18 months. Our expectation is loosely approximately 6 months before receipt of that permit. And as you can understand, we'd be in constant communication with the government on that. Approximately 6 months ahead of that receiving the permit, we would expect to draw the last $50 million. So if it's 18 months from now with the outside, and about 12 months from now, we draw the last $50 million. We spend it on long lead time items, for example, pipe. So it's well on its way to Colombia by the time the environmental permit gets received. And then, of course, we had repay it back when the conditions precedent are met, and the long-term funding for both debt and equity partners is received. Now one of those long -- one of those CPs that have been discussed with the partners logically would be the environmental permit itself. So we'd probably draw it in 12 months and we repay it back in 18 months when we receive the permit.

Thanks, Jason. The next question is from [ Eric Pool ], a private investor. The local opposition to fracking in Colombia is well known. Is there any opposition to the use of the natural gas similar to what one finds with some climate change activists in North America?

Great. Thanks, Eric. Yes, there is quite a bit of opposition to frac in Colombia. We know that -- about that particularly for oil in the middle Medellin Valley. With respect to the use of natural gas and its role in the transition, not so much. There's very little in the way of renewable power here in Colombia, solar and wind. And a lot of that -- a lot of the projects that are planned with respect to solar and wind have quite long time lines, 5- to 10-year out there. In the meantime, a lot of people in Colombia are cooking with wood and charcoal. So the Colombian government has made it very clear and has communicated very well that natural gas will first and foremost be a transition fuel essentially to eliminate or reduce as much as possible the use of coal and wood and charcoal for domestic sources of energy and the burning of oil to generate power. So gas has a very significant and well-publicized role in the Colombian -- in Colombia and is accepted essentially as a cleaner fuel. That's an important part of the transition. But of course, the Colombian government's objective ultimately, as the objective of most governments in the world, is to completely eliminate the use of fossil fuels, including gas when the matrix will be entirely renewables, but that's not anticipated to occur within at least 50 years ago. So in the meantime, gas remains a very important part of the government's plan to essentially clean up the environment, especially the use of coal and wood and charcoal as well as petroleum.

We have one question from Andres Duarte from Corficolombiana. What is the current unexpected import gas price in Colombia?

I can tell you that I was just reading a Fitch report, who, of course, is one of our rating agencies for our bond. And they said the price in 2020 was USD 5.83 plus another $2 to $3 to regasified and transported. So that was the average price in 2020 according to Fitch. I have no more color on the current price, perhaps Charle does.

Yes. Thanks, Jason. I can add that there's very little gas being important to Colombia at the moment, very little LNG. The last load that came out of the Gulf Coast, I believe, in April or May of this year was loaded at about $8. So we could expect landed prices of $9. The forecast for landed LNG in Colombia for the next 3 to 4 years is between $10 and $14 an MMBtu. And as you know, LNG prices worldwide have escalated significantly from last year's lows. So LNG landed in Colombia continues to be a relatively expensive option, and the prognosis or the forecast looks like it's going to remain that way.

Thank you. With this, we conclude the presentation today. Thanks all for attending. Please do not hesitate and contact us should you have any further questions. You may now disconnect. Thank you.