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

Good day, and welcome to the Canacol Energy Third Quarter 2021 Financial Results Conference Call. [Operator Instructions] I would now like to turn the conference over to Carolina Orozco, Vice President of Investor Relations. Please go ahead.

Good morning, and welcome to Canacol's Third Quarter 2021 Financial Results Conference Call. I am with Mr. Charle Gamba, President and Chief Executive Officer; and Mr. Jason Bednar, Chief Financial Officer. Before we begin, it 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 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 cover the operational highlights for the third quarter. 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 2021 and beyond. A Q&A session will follow. Mr. Gamba is joining us on the line from Bogota 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.

Thanks, Carolina. Good morning or good afternoon, and welcome to Canacol's Third Quarter 2021 Conference Call. In the third quarter of 2021, we realized natural gas sales of 191 million standard cubic feet per day, the highest level of quarterly gas sales we recorded since the start of the COVID pandemic and approaching the level of just over 200 million standard cubic feet per day that we had prior to the pandemic. October gas sales averaged 192 million standard cubic feet per day, further confirming that we're achieving full year average sales towards the top end of our guidance of 153 million to 190 million standard cubic feet per day. Increased natural gas sales during the third quarter were achieved, thanks to an increase in the interruptible market sales as a result of the COVID-19 pandemic restrictions gradually being lifted and an increase in firm contract sales due to certain offtakers taking less contractual downtime and less undelivered nominations. We expect the natural gas demand in Colombia will continue to rise throughout the remainder of 2021 and return to pre-COVID levels in 2022. Thanks to increased gas sales, we reported another quarter of strong and relatively stable operating margin of 79% as well as a noteworthy return on capital employed of 21%. We remain committed to a return of capital to shareholders with the payment of the eighth consecutive quarterly dividend of CAD 0.052 per share, $7.5 million in total, which at the current share price represents an annual dividend yield of approximately 5.5%. We also repurchased 1.8 million shares under our normal course issuer bid, taking advantage of what we perceive as weakness in our share price. During the quarter, we reported an important strategic step for the signing of a new long-term sales contract with EPM in Medellin, which underpins our Jobo to Medellin pipeline project. We held a conference call focused specifically on that announcement in August, so I won’t elaborate in detail on that project on this call unless there are questions. I will, however, give a quick reminder of the significance of this project. The new gas sales contract will see us deliver gas to EPM in Medellin starting in December 2024, with an initial volume of 21 million standard cubic feet per day, escalating to 54 million standard cubic feet per day in December 2025 and remaining at this level until the sales contract expires on November 30, 2035. This contract allows us to proceed with our Jobo to Medellin pipeline project, knowing that we have a contract for approximately 50% of the pipeline's design capacity so that we can now focus on permitting contracting for detailed engineering construction firms, secure financing for the project and ultimately divesting the 75% of the project while retaining transportation rights that will allow us to grow our production and sales volume over the long term. In the meantime, we are currently negotiating additional new long-term take-or-pay contracts with other clients in Bogota and Cali, so that we can ensure that the pipeline will be full to capacity when it enters operation. During the third quarter, we also completed the drilling of 3 wells, 2 of which were successful Breva wells of the Aguas Vivas discovery that we had reported during the second quarter. And the third is a discovery with the San Marcos exploration model immediately to the east of the Aguas Vivas discovery. In October, we completed the drilling of the Corneta-1 exploration well, which has been cased and suspended as a future water exposal while having encountered noncommercial volumes of gas. The rig is currently mobilizing to drill the Siku-1 exploration well, which is targeting gas bearing sandstones of the CDO reservoir in close proximity to the corporation's Clarinete gas field. Siku-01 exploration while is anticipated to take approximately 5 weeks to drill, complete and test prior to the end of the year. I'll now turn the presentation over to Jason Bednar, our Chief Financial Officer, who will discuss the financial results in more detail. When he's done, I will discuss the outlook for the remainder of 2021 and beyond.

Thanks, Charle. We continue to execute our plan to develop our growing natural gas business in the third quarter. We reported the following key results for the third quarter of 2021. $66 million of production revenues, net of royalties and transportation being a 15% increase relative to the same period in the prior year. $38 million in adjusted funds from operations, which represents a 14% increase from the same period in 2020. EBITDAX of $54 million, which represents a 27% increase from the same period in 2020, and net income of $8.8 million, which represents an increase of over 200% from the same period in 2020. Our gas operating netback was $3.49 per Mcf in the 3 months ended September 30, 2021, which is effectively unchanged from the same period in the prior year, but does represent 11% increase relative to Q2 as we saw a recovery from the short-term issues that impacted realized prices during the second quarter. Our operating margin at 79% for the quarter was also effectively unchanged from the same period for the prior year, but a slight recovery from levels reported for the previous quarter. As you can see, our realized prices and netbacks remain very stable, and our average realized price is on trend to be in line with our guidance for the 2021 year average of $4.10 to $4.50 per Mcf. Recall that the majority of our guidance is based on sales under fixed price take-or-pay contracts with an average fixed price of $4.50 per Mcf. It's worth mentioning that the $0.34 increase in the Q3 realized price as compared to Q2 is notable in that this delta is almost solely attributable to the interruptible contracts, which comprise approximately 20% of our gas sales portfolio. To further highlight the strength and stability of our natural gas business, we want to again highlight the return on capital employed implied by our financial statements over the last 11 quarters. Our return on capital employed remains high by E&P industry standards at 21% in the third quarter of 2021 and 16% on a 12-month trailing basis. With a cash position of $43 million, the working capital surplus of $38 million and an undrawn credit facility availability amounting to almost $100 million, Canacol has a lot of financial flexibility to adjust our investment plans when we find good reasons to do so. In Q3, we took advantage of a dip in our share price and repurchased $4.6 million of common shares. Adding that to the $7.5 million we paid with our quarterly dividend, means we returned over $12 million to shareholders in the third quarter alone. In closing, our Q3 results were strong and relatively stable with a notable recovery from issues that caused a slight deterioration in our results in the prior quarter that were related to short-term events and the COVID pandemic. We remain well positioned to continue growing our business and returning cash to shareholders going forward. At this point, I'll hand it back to Charle. Thank you, everyone.

Thanks, Jason. For the remainder of 2021, we expect to continue delivering results within our previously stated guidance, allowing us to continue operating from a position of financial strength, returning capital to shareholders while also investing for growth. For the remainder of '21 and looking into early 2022, the corporation is focused on the following 5 objectives: Firstly, maintaining a continuous exploration focused drilling program, which we plan to continue into 2022, targeting a 2P reserves replacement ratio of more than 200% as per historical trends. Secondly, having successfully acquired 655 square kilometers of new 3D seismic on the corporation's VIM 5 and SSJN-7 blocks this year. We will now be focused on refining our exploration prospect inventory within those areas, in the meantime planning our drilling as well as additional seismic for 2022. Thirdly, continuing to progress our projects to construct new gas pipeline from the whole natural gas processing facility to Medellin. We anticipate completing the following activities by the end of Q1 2022. Firstly, finalize work on the environmental permit to submit to the ANLA for approval. Secondly, finalize the selection of the construction company that will 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 new gas sales contracts with consumers in the interior to fill the initial 100 million cubic feet per day capacity of the pipeline. The fourth objective for the remainder of the year is to continue strengthening of our environmental, social and governance strategy and reporting as we evaluate how we can improve our already industry-leading metrics in this regard. And finally, the continuation of our return of capital program to shareholders through both dividends and share buybacks. Similar to prior years, we expect to announce up 2022 guidance in early December. I'd like to thank the entire Canacol team as well as our contractors, partners and clients for their continued support and hard work. We are now ready to answer any questions that you might have.

[Operator Instructions] Our first question comes from [ Passo Suza ] with UBS.

I would like to ask 2 questions actually. The first one, you already comment a little bit on the outlook for 2021 and beginning of 2022. But we would appreciate if you could give more color on next steps to the pipeline construction. How is the selection of the construction company going? Are you having any trouble in receiving offers from these companies? And also, how are additional negotiations for the remaining of the volumes going? I know there is plenty of time until they start in 2024, but can we expect an announcement in the short-term? And my second question, we heard this week from an oil company, they are already experiencing some inflation costs, mainly on CapEx. Is this something that you are also experiencing? And could it have any impact on future investments such as this construction pipeline? Those are my questions.

With respect to the outlook for 2021 and 2022, and in particular, the near-term steps with respect to the Jobo to Medellin pipeline, as I mentioned during the call, we're currently compiling the environmental permit for the project, which we anticipate submitting to the ANLA, which is the regulatory body for the environmental side. We'll submit that in -- by the end of Q1 of 2022. And we expect that license will take between 12 to 16 months to emerge from the ANLA, at which point we can start the construction. So that's a very important step that we're well -- we're advancing very well. Secondly, we're currently in the process of selecting the contractor who will build and operate the pipeline. We have received -- we have sent out -- circulated elicitation for the project in late September. And we have received a number of offers this week, which we are currently reviewing before choosing which offer to go ahead with. And we expect essentially to negotiate the final contract between now and the end of February so that we can sign that contract with the pipeline constructor by the end of Q1 2022. And finally, with respect to the first part of your question, with respect to additional gas sales, as you know, the initial capacity of the pipeline is 100 million cubic feet per day, of which 55 million will be allocated to EPM, located in Medellin. So that means we have an additional 45 million cubic feet per day of capacity to sell. So we are currently -- we have been in negotiations for the past 2 months with large distribution clients in the cities of Bogota and Cali, still the remainder of that 45 million of spare capacity. So I expect that within the next 6 to 9 months, we will have essentially signed an additional 45 million cubic feet per day of capacity so that when the pipeline comes into operation in December of 2024, we'll have a full 100 million cubic feet per day of sales signed by that period of time. With respect to your second question, inflation cost and CapEx, as usual, with the recuperation of oil prices places, we see service costs starting to escalate within the sector. Fortunately, the majority of our contracts we renegotiated over the past 12 months, and they're all very long-term contracts between 2 to 4-year service contracts with strict control on escalation. So we're somewhat insulated from that escalation. As you have to recall, we were one of the only companies that were actively drilling for the past 2 years. Many of the companies stopped drilling and have had to negotiate new contracts, whereas our contracts have been in place for several years, and were never dropped. So we're in a relatively good position with respect to stability with respect to those contracts and price escalation in particular.

Our next question comes from Josef Schachter with Schachter Energy Research.

A couple of questions for me. Number one, we saw in the quarter, a 24% increase in your crude oil volumes in Colombia. Have you taken a different approach to the asset? Are you looking now to stay -- having a bit of an oil leg in the business? And are you looking to grow that beyond just the one project?

Hello, Josef, I trust you're doing well. With respect to the oil production, we only operate one oil asset now, which is the Rancho Hermoso field, which was, of course, our very first operated asset in Colombia in 2008. We've been very actively trying to divest that contract for the past 3 years, unsuccessfully. Hopefully, with this better price environment, the asset might be a little more attractive for divestment. But our plan is to continue to completely exit oil exploration and production to remain and focus on 100% natural gas. So the short answer to your question is volumes are up slightly, but our interest is to divest those assets and no longer participate in oil production or commercialization.

Okay. So in terms of the Arrow Exploration, supports you've done there and the position you have, Marshall is going around, doing a lot of marketing, raising money and wants to grow the volumes to 3,000 BOEs. Would they be a likely potential buyer of the Rancho Hermoso? Or do you see that needing a different buyer? And what is M&A activity in the oil and gas sector looking like in Colombia? Is that something that's picking up so that you have a likelihood of selling it in 2022, the remaining oil asset directly?

I think that this is a very small asset. We're netting a couple of hundred barrels a day. This is a very mature producing field. It's been producing for over 20 years now. There is obviously interest -- increasing interest given the recovery of oil price at the current level. So I think that 2022 would be an opportune time to divest of our interest in that asset. I don't know exactly who it will be to, Arrow or another party. But I think that oil prices recovering to current levels will certainly help us with respect to achieving our objective of divesting all of our remaining oil production.

And Arrow is also something that at some point you divest as well?

Well, we own a position, we're shareholders in Arrow as a result of the past -- of the initial capital raised back in 2018, and we converted some of our debt to shares in the recent capital raise. So we're a fairly large shareholder in Arrow, and we hope that Marshall and his team achieve their objectives. I think that they're well within the range of possibilities. The assets are very good that they have in terms of exploiting and then increasing production. So as any shareholder, we simply wish to see the best return on our investment in Arrow, and I think with the management team that's in place and the assets that they have, that's a good likelihood, particularly if oil prices remain fairly robust.

Last one for me. El Tesorito starts up in 2022. When is the window for that now, it was originally going to be December, then last it was March of next year? What does that look like? And how do you see the ramp-up of demand for electricity from that? Is about half the demand needed right away, so you'll get the gas volumes for that? And will it take 6 months, a year, 2 years for them to get to total capacity? How do you envision the volumes for you as that plant ramps up?

El Tesorito is currently scheduled to enter commissioning in February of next year and be online by the end of March of next year. So the end of the first quarter, we will see the facility come online with commissioning in February. The outlook with respect to electrical demand in Colombia is very robust. The electrical demand has been increasing historically 3% to 4% per year. Hydro capacity is fixed essentially. There are no new hydro projects entering until at least 2024 at the very earliest, which would be the Ituango project. So we've seen a lot of reliance on thermoelectric power generation to backstop that increase in demand. So we expect that, that facility, Tesorito will be generating at least half capacity, at least 100 megawatts April 1 onwards to essentially cover the shortfall in electrical demand as well as the delay in the various and hydroelectric project as well as the renewable projects, solar projects and wind projects have all been delayed as well due to environmental permitting and community issues. So we're starting to see demand kind of outstrip new capacity, which bodes very well for thermoelectric power generation and Tesorito in particular.

Okay. That does it for me. Congratulations on a nice quarter.

Thank you, Josef.

I would now like to turn the conference back over to Carolina Orozco to read questions submitted via the webcast.

Thank you. The first question comes from [ Colin Grant ]. What were the sales for the month of October?

That came out in the press release yesterday of 192 million cubic feet a day.

Thanks, Jason. The second question comes from Sofia Rojas from BD Capital. When do you expect to draw the remaining line from the bridge loan?

So to refresh everyone's memory, the bridge loan relates to a facility we put in place to move along the Medellin pipeline project back a little over a year ago. We were required when we put the facility to place to draw the first $25 million, which will be for environmental and things like that. The bulk of that is still unspent as of now. The remaining $50 million, which she is referring to is for long lead time items, such as pipe, et cetera, when we have more clarity that the -- ideally, the environmental permit is soon to be released. As Charle stated several times in previous calls, that permitting process could take anywhere between 12 and 18 months loosely. And we have until July 31, 2023, to use that facility. So whatever that may be, 21 months from now. So sometime prior to July 31, 2023, is the answer.

Thank you, Jason. And we have one last question from [indiscernible] from Credicorp Capital. Hi, can you give me more color related to the increase in royalties?

Our royalties are -- they're a blend, and I'm going to assume he's talking about percentages, right? In absolute dollars, the royalties are higher because our production and sales price is higher this quarter. So in terms of percentages, most of our production comes from 2 blocks, VIM 5, which has a 22% royalty rate and Esperanza, which has an 8% royalty rate. So as we drill more on VIM 5 and to have more production on VIM 5, the royalty rates slowly creep up. And vice versa, if we were to focus more drilling on Esperanza, they would slowly creep down. So that's the bottom line. 2 different blocks, 2 different royalty structures.

We have received a couple more questions. The first one is from Daniel Guardiola from BTG Pactual. I wanted to know your thoughts on the recent gas crisis that is unfolding in Europe and Asia and potential positive effect for Canacol. What portion of your contracts are expiring this year? And how do you expect the mix of production between contracted and volume sold in interruptible market to evolve in 2022?

Yes. Thanks, Daniel. I'll answer those questions, Jason. With respect to international gas prices, the only -- Colombia is a very isolated gas market. Almost all of the demand is met by domestic production, there's very little importation. However, the recent high prices in Europe have certainly increased LNG pricing well above domestic pricing. So if we sort of take a look at what the average domestic price for gas is, you're looking at around $4.50 to $5 per MMBtu at the wellhead as opposed to LNG prices now in Europe, which are running in the $13 to $15 range and Japan which was over $30 earlier this year as well. So the high price of international gas is simply putting a strain on importing any gas to Colombia. So we're seeing very moderate type of price increases related to that. But certainly the importation of gas into Colombia is not an option for any users given the high price. So sort of just strengthens the local market dynamics. With respect to the percentage of contracts, take-or-pay contracts expiring at the end of November. We're looking at about 25 million cubic feet per day coming off in terms of take-or-pays. We've already negotiated the replacement of those volumes. And as always, we are going to target a ratio of take-or-pay to interruptibles of 70% to 80%. So the anticipation is that in 2022, as in previous years, 70% to 80% of our gas sales will be via fixed take-or-pay contracts, with the remaining 20% to 30% sold into the interruptible markets. But we certainly expect to see demand being very robust and actually have a very good -- that has had a very good impact on pricing for the replacement of the take-or-pays that are expiring at the end of this year, we're experiencing very good pricing at the moment.

Thank you, Charle. We have another question from Laura Lopez from Casa de Bolsa. One, based on your outlook for the end of the year, in relation to the drilling program, what are your expectations in terms of production and sales and its proportions over sales by 2022?

For the last several years, we have released our guidance in mid-December, and that's what we'll do this year. So no answer to that question at this point.

Thank you, Jason. Please give us 2 seconds. We're going to check if there's any more questions in the queue. We have one from Carlos Carazas from Seminario SAB. Congratulations for the results. I was wondering if you can repeat which will be the volume contracted by EPM in the new pipeline?

Sure. So the contract with EPM is for 11 years. So it starts December 1, 2024, and it expires on November 30, 2035. So the first volume for the first year from December 1, 2024, to November 30, 2025, the minimum volume contracted by EPM is 21 million cubic feet per day. On December 1, 2025, through to the end of 2035, the volume will be approximately 51 million to 52 million cubic feet per day for each of those 10 years.

Thank you, Charle. The next question is from Ezequiel Fernandez from Balanz. The environmental permit that you should be filing shortly for the pipes, is it for the Jobo-Medellin connection alone or for the link up to the TGI network as well?

So the whole Jobo-Medellin pipeline will essentially run from our gas processing facility at Jobo and it will connect into the City Gate of Medellin, so in very close proximity to Medellin. So it will actually connect into the Transmetano pipeline. So there will be no direct connection of this pipeline to the TGI pipeline. However, upon connecting to City Gate in Medellin, the Transmetano pipeline will be available to ship gas from City Gate Medellin through to Sebastopol, which is about 200 kilometers to the east where it connects into the TGI pipeline. So our gas, 45 million cubic feet per day will flow through the Medellin City Gate into the Transmetano and then be directed eastwards into the TGI pipeline for distribution to Bogota and Cali.

Next question is from Daniel Guardiola from BTG Pactual. Considering the year-to-date execution of the CapEx, I wanted to know if you are considering to revise downwards your CapEx for 2021? And if so, if you are considering to further increase shareholder's remuneration and/or pay down debt?

Yes. I think our latest expectation on CapEx will certainly not be the high case of $140 million that we put out in December 2020 relating to 2021. Our own latest internal estimates are approximately $117 million. So obviously, slightly less. With respect to the delta and what we're going to do for it, I mean, that will also be wrapped up into a 2022 budget. As we're all aware, we're only 50 days away from this year ending.

Next question is from Luis Carlos Gaitan from Itau Asset Management. Can you guys give us some color on any pending litigation settlements? And just to confirm, if the Davivienda credit line was outstanding for USD 12.9 million was converted to Colombia pesos?

Okay. I can take that. There are no litigation that we're involved in. There's no pending litigation settlements. That $12.9 million, which is actually USD 12.6 million at today's rate is indeed denominated in Colombian pesos, and it's a bullet payment that matures in June of 2024. It is indeed correct, it was due to a prior potential litigation that we settled many years ago.

Thank you, Jason. This was the last question that we had. So with this, we conclude the conference call today. Thank you all for participating in our third quarter conference call, and hope you join us next quarter again. Have a great day.

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