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

Hello, and welcome to the Canacol Second Quarter 2022 Financial Results Conference Call. [Operator Instructions] Please note this event is being recorded. I would now like to turn the conference over to Vice President of Investor Relations, Carolina Orozco. Please go ahead.

Good morning, and welcome to Canacol's Second Quarter 2022 Financial Results 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 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 summarize highlights for our second 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 2022. At the end, we will have a Q&A session. I will now turn over the call over to Mr. Charle Gamba, President, and CEO of Canacol Energy.

Thank you, Carolina. Good morning or good afternoon to everyone, and welcome to Canacol's Second Quarter 2022 Conference Call. In the second quarter, we realized natural gas sales of 188 million standard cubic feet per day, which is above the midpoint of our annual guidance of 160 million to 200 million standard cubic feet per day, 10% higher than the same quarter in 2021 and 3% higher than the first quarter of this year, thanks to the growing demand for gas in Colombia. If you've been following our monthly updates, you'll also know we sold 198 million stand cubic feet per day in both June and July. So we're clearly trending towards the upper end of our guidance in terms of sales lines for the year. In line with what we said in our last conference call in May, what we've seen this year here in Columbia gas markets is that the economy has started to grow again as the effects of the COVID pandemic wane. This has translated into higher energy demand and hence, higher demand for our natural gas. Our stable production and operating conditions allowed us to report another quarter with high operating margins of 77% and a relatively high return on capital employed of 16% annualized for the quarter. With respect to our current drilling activity, we continue with the execution of our drilling program plan for this year with a total of 6 developments and exploration wells drilled to date from which 3 successful exploration wells have been realized. Finally, at the end of the quarter, we published our 2021 ESG report in which we reported Scope 1 and 2 GHG emission intensities that are more than 50% lower on average than our gas-focused peers and more than 80% lower on average than our oil-focused peers in North and South America. Our emission intensity is lower than the average for many broad equity indices, including some which constantly selects for having low carbon emissions. I'll now turn the presentation over to Jason Bednar, our CFO, who will discuss our second quarter financial results in more detail.

Thanks, Charle. We continue to execute our plan to develop our natural gas business in the second quarter, reported the following for the second quarter of 2022. $70 million of production revenue net of royalties and transportation, which represents a 31% increase from Q2 of 2021. The increase was driven by higher sales volumes and higher realized prices. $39 million in adjusted funds from operations, which represents a 16% increase from the same period in 2021. We also reported EBITDAX of $55 million, which represents a 24% increase from the same period in 2021. And finally, a net loss of $6 million when we reported a small net profit in the same period in 2021. As I've explained on previous conference calls, a big driver of net income each quarter is unrealized foreign exchange gains and losses that can impact the valuation of our tax pools, which were in Colombian pesos. In the second quarter, we recorded a deferred tax charge of $12 million, the majority of which was due to deterioration in the value of the Colombian peso versus the U.S. dollar and without which, we would have reported a healthy positive net income. In the event that the peso strengthens against the U.S. dollar in the future, the corporation would realize a deferred income tax recovery. I'll also note that in Q1 of 2022, we saw a stronger peso. And during that quarter, we booked a $12 million deferred tax recovery, almost identical in quantum to this quarter's deferred tax expense, that's leaving the 6-month year-to-date balance essentially flat. Our operating netback was $3.66 per MCF in the 3 months ended June 30, 2022, which is 17% higher than in the same period in 2021, also 2% higher than the prior quarter, and slightly above our guidance for 360 on average for 2022. In fact, this was the highest quarterly netback we reported since the third quarter of 2019 prior to the COVID-19 pandemic. Our realized gas price of $4.73 was also the highest we've achieved before COVID and was at the upper end of our guidance for the year of $4.61 to $4.74 per MCF, thanks to stronger interruptible prices. Recall that the majority of our guidance is based on sales under fixed-price take-or-pay contracts with an average fixed price of $4.74 per MCF. OPEX was $0.31 per MCF in Q2, down from $0.36 in Q1. On our last call, I stated that during Q1, we were doing some maintenance work, hence the one-time quarter increase. We expect the remainder of the year OPEX to be approximately $0.30. In percentage terms, our gas royalties were $0.16 of gross revenue, which is in line with the average for the preceding 2 years. To further highlight the strength and stability of our natural gas business as well as the growth that we see in our business and financial results, we want to again highlight the return on capital employed, implied by our financial statements over the last 14 quarters, averaging 16% over the last 12 months. That concludes my comments on our second quarter financial results. I'll now hand it back to Charle. Thank you.

Thank you, Jason. Our results for the second quarter once again demonstrated high and stable operating margins as well as a very respectable return on capital employed. While weather presents an important role in power generation and gas demand in Colombia, we're hopeful that strength in electrical demand and economic recovery after the pandemic in Colombia will support continued demand growth for our gas through the remainder of 2022 and beyond. Our guidance for 2022 remains unchanged, and we anticipate production and cash flow to be near our high end for the guidance of 200 million standard cubic feet per day of average gas sales. We also continue to anticipate our CapEx spending will come in closer to the lower end of our guidance at $170 million. Our exploration drilling program will continue at an increased pace for the second half of the year as we drill ahead with 2 rigs currently at [ ClarksonOne and Canada Fleet ] within our core area, and we are planning to contract additional drilling rigs to drill some of our higher impact exploration well planned for the -- later this year. Tesorito, our 200-megawatt thermoelectric plant located 70 kilometers from our Jobo gas processing facility, entered commissioning this summer and is anticipated to commence generating in September of 2022. I'd like to congratulate Celsia, our operating partner for the successful conclusion of the construction process of Tesorito. Finally, we are continuing to evaluate and clarify the bids received from the pipeline construction consortiums and hope to be able to make a selection announcement soon in order to progress this important Median pipeline project. In summary, we are continuing to deliver financial results within our previously stated guidance, allowing us to proceed with both returning capital to shareholders and also investing for growth, operating from a position of financial strength. We're now ready to take any questions.

Thank you. We will now begin the question-and-answer session. [Operator Instructions] At this time, we will pause momentarily to assemble our roster. Our first question today comes from Oriana Covault of Balanz.

This is Oriana Covault of Balanz. Congratulations for the good performance over the quarter. I had 3 questions. If we may go one by one, that would be great. And my first one related to the Tesorito entering commission just if you could share how many NGF per day are you expecting it to bring to your top line now that it started commissioning?

Yes, we've been -- throughout the summer, we've been selling between 8 million to 12 million cubic feet per day to the plant during commissioning. So the plant is not dispatching. They're simply testing the motors and sequence. When the plant enters dispatch in September, a dispatch of electricity, we anticipate up to 20 million cubic feet per day. We'll be going through that plant, assuming a utilization of approximately 50% of the capacity, the 200-megawatt capacity.

Perfect. That's very clear. And my second question with relation to your comments on contracting another drill to the high-impact exploration. Just if you could share how you're preparing for the drilling in Polo-1. Have you made any changes to the expected drilling date and preliminary works that need to be carried over in Polo-1?

Yes, Polo-1, we've contracted a 3,000-horsepower drilling rig. It's a fairly deep well at 18,000 feet, which requires a very large rig, which has been mobilized for the United States. We've commenced activity with respect to the construction of the civil works, the drilling platform that the rig will be located on. And we anticipate the spudding of the Polo-1 well in November. So this year, we're hoping to get the well initiated in the fourth quarter of this year.

Perfect. And just one last one from a higher level standpoint. We've been reading [ or coming ] across some headlines mentioned a possible revival of gas exports from Venezuela to Colombia. So I understand this is purely speculative at this point, but if you could share any -- what are your thoughts about this? And what have you heard in the country in this regard?

Yes, there has been some discussion of importing gas from Venezuela. There's always been an option for a long time. Colombia, of course, used to export 250 million cubic feet per day of gas from Columbia to Venezuela. And there is -- there are outstanding agreements for PDVDA to return that gas at some point to Ecopetrol. They have never -- however, they have never landed on the price of that gas to be returned. But anyways, I think that the importation of gas from Venezuela represents a very interesting opportunity. We're certainly evaluating that opportunity with respect to Canacol as well. However, there's significant -- there are some impediments to that scheme. The first, of course, are the U.S. OFAC sanctions against PDVSA, which would be problematic, which would not permit export of that gas by PDVA o Colombia. So that's one issue that has to be overcome. And the second is a significant investment in infrastructure in Venezuela to reactivate the oil and gas fields to be in a position to be able to export. So I think in summary, it's a very interesting possibility for Canacol, and there are some significant obstacles to overcome in the near to midterm.

The next question comes from Chen Lin of Lin Asset Management.

Some of my questions already been answered. I would like to congratulate for this wonderful, very excellent quarter. I noticed you start buying back shares. I mean, your company share is treating a very depressed level after the Colombia election. So how much room you have to buy more shares from the open market? And then do you plan for any future dividend increase?

Yes, I can answer that. So the first thing I'd like to point out is that we have a very healthy dividend currently at the share price, it's probably 9%-ish. And of course, that's a return to shareholders of approximately $28 million annually, right? So it's certainly not insignificant. As we are -- have a very aggressive capital program heading into a Medellin pipeline in terms of exploration wells, et cetera. I think our normal course issuer bid will be more opportunistic at this stage as opposed to having a set level that we will buy for the remainder of the year.

Okay. Can you tell us how much room you have for share buyback? How much...

Yes, sure. Yes. So it's a formula based on the free float that the TSX does every year. Our number allotted to the buyback this year was approximately 11 million shares, and we bought back between $5 million and $6 million in the first half of this year thus far.

Okay. Great. Good to know you have more room. And can you just expand a little bit? I know it was asked previously, the high impact well, a lot of shareholders really waiting for that, what approximate when you get the rig come in and approximate what time the shareholders will know that it's a success or not?

Yes. Thanks, Chen. As I mentioned on the previous question, the rig is being mobilized 3,000 horsepower. The civil works are being constructed, and we hope to spud the well in November. That would put results into January of next year.

[Operator Instructions] At this time, I would like to turn to Carolina Orozco to address some questions from the webcast.

Thank you. The first question that we have is from Lucas Arias from Compass Group. Lucas is asking, is there a possibility that there will be no more exploration cores. How many years do you estimate that you could operate without problems?

Okay. Thank you, Lucas. We have -- we hold interest in 11 exploration and production contracts 6 in the Lower Magdalena Valley, which is our core operating area, 5 in the middle Medellin value, which is our new high-impact gas exploration area. On those 11 contracts, we have identified about 190 drilling locations, exploration drilling locations, containing on a gross unrisked basis, 18 TCF of prospective gas resource. So we have sufficient inventory to drill over on those 11 blocks for at least 10 years. So we have a very deep portfolio of opportunities for gas on those 11 contracts, which could see us continuing to drill exploration wells and translate those resources, those 17 trillion cubic feet of gross prospective unrisked resource of gas into new reserves for commercial sales.

The next question comes from Leonardo Marcondes from Valores Analytica. The Minister of Maintain Energy just said that the new government in Colombia would not sign any new exploration contracts for gas. And if the gas reserve goes down, we will import gas from Venezuela. What do you think and how can this impact the chemical business in Colombia?

I think I just answered that question, I believe.

Thank you, Charles. The next one is Carlos Carazas from Seminario SAB. Hello, have you estimated the impact of a hypothetical improvement of the Colombian tax reform, the government expect to change the royalties computation in P&L and experts? What do you expect?

Yes. We're still analyzing the impact of the yet-approved reform.

The next question is from Julio Delgar. What is the average maturity of the actual take-or-pay contracts that you currently have?

It's 7.3... Sorry, Charle. 7.3 years is the answer.

The next question is from Mario Epelbaum from First New York Capital. The boom contract that you are about to sign has taken more time than expected. Can you talk about some of the issues around the delay? And how soon do you think you will sign?

No issues. We're currently drafting the final form of the agreement with the party that is being selected, and we anticipate that's back and forth drafting of the agreements, of course. We expect that we will be signing those agreements within the next month.

Thank you, Charle. And operator, I think we have someone else in the queue to ask a question. Can you please let him in?

There’s one from Rodrigo Torres that you should address, Carolina.

Yes. It's coming through, but can we please take Schroders first, and then we will address that in term?

The next question comes from [ Till Moes ] of Schroders.

Congratulations on the results. My question is about Ecopetrol there over the last weeks made announcement about deepwater signs of gas. And it seems that potentially they could be significant as Ecopetrol even said that they could allow the company to become exporters of gas, which I think indicates a potentially game-changing nature of this. So I was wondering what is your take on these announcements and how would they impact the domestic market according to your very first initial take.

Thanks for the question. We've announced 2 announcements. One is a discovery, the [ 201 ] well in the Tayrona contract, which is located off the Cohera coast in Northeast Colombia. That well was drilled in approximately 840 meters of water. So it's a deepwater non-associated gas discovery -- it follows the Orca-1 discovery in the Tayrona contract made by Petrobras in 2014. So it's the second gas discovery in deepwater in Tayrona. There is -- while it is very positive with respect to detecting the presence of gas, the failure to develop Orca, which was discovered in 2014, probably indicates commercial issues associated with developing on a full-field basis, non-associated gas discoveries in that water depth. So while the Uchuva-1 discovery is positive with respect to the presence of gas, there are still uncertainties with respect to the commercial viability of developing both the Uchuva-1 discovery as well as the Orca-1 discovery, which was made in 2014, 8 years ago. The second announcement that Ecopetrol made was with respect to the Gorgon-2 sidetrack, which was an appraisal well of the Gorgon-1 discovery made in the Gulf of Uraba by Anadarko in 2018. The Gorgon-1 well, which is drilled in 2018, encountered gas, and the Gorgon-2 sidetrack well, which was announced earlier this week, confirmed the presence of gas in another part of that discovery. However, the Gorgon discovery is located in 4,200 meters of water, which would make it the deepest, the ultra-deep non-associated gas discovery in the world with considerable issues concerning commercializing discovery and those water depths. So in conclusion, there has continued to be the successful detection of gas in the Caribbean Coast of Colombia, both in moderately deep waters at Uchuva and Orca and ultra-deep waters in Gorgon. However, there are significant issues related to the commercial development of those fields given the water depths for these non-associated gas fields. If they were to be developed, you will be looking at timelines between 8 to 10 years and multi-billion-dollar development projects.

That's very interesting, very clear. Another question is on the mid-gene pipeline project. I was just wondering what is the state of commissions and licensing there? Is there anything that could cross your plans when it comes to environmental regulation, community consultations or so on where the new administration might take a more critical stand?

Yes, with respect to the environmental licensing, so the project, the project late last year was sanctioned by the Colombian government that is a project of strategic national importance to the country. So it has a special designation, which will aid in the environmental permitting process. We are preparing to submit, we have received the DAA from the environmental ministry which essentially is an approval of the pipeline route amongst the options that we presented. They have approved the preferred route that we wish to take. And now we are preparing to submit the environmental permit, the detailed environmental permit late September, early October this year. So we anticipate that, that license should come out in Q2 of next year, which will allow for the commencement of the construction of the pipeline in order to be ready by December 1st, 2024.

The next question is from Oriana Covault of Balanz.

No, I had just a follow-up, but it was already addressed.

I will pass the conference over to Carolina Orozco for more questions from the webcast.

We have another question from Luis Olguin from William Blair. What is the average price of your contracted volumes?

As we released our guidance in December, the average price for 2022 of our take-or-pay volumes is $4.74 per MCF, net of any related transportation charges well at price.

[Operator Instructions]

We have another question from Mariel Bond from First New Year Capital. The boom contract that you are about to sign an -- that has already been taken, excuse me. Let's give us 2 seconds to see if we get any more questions from the webcast or in the queue.

Yes, I see a question here, Carolina… I see a question here, Carolina from Rodrigo Torres from Valora Analytic. Have you seen that question?

Yes, I'm going to read it, again, I think we read it before, but I'm going to read it again, Charle. We got a question from Rodrigo Torres from Valora Analytic. He's asking the Minister of Mines and Energy just said that the new government of Colombia would not sign any new exploration contracts for GAAP. And the -- and if the cash reserves go down, we will input gas in Venezuela. What do you think and how can this impact Canacol's business in Colombia?

Perfect. I think with respect to Venezuela, which I've already discussed, it's certainly an interesting opportunity for Canacol. It's a very large potential source of gas to commercialize here in Colombia. In addition to the 2 issues I mentioned previously, which with respect to the sanctions gain PDVSA and the amount of investment in infrastructure in Venezuela, which would have to be done to achieve this. There's also some uncertainty with respect to the price that, that gas will be sold out within Colombia. So there's a lot of issues with respect to that pricing of that gas potentially being higher than domestic Colombian gas. And of course, I'd like to reiterate that Canacol, as I mentioned previously, has an exploration inventory here in Colombia of over 17 trillion cubic feet of gross unrisk prospective resource that we can drill through here. Thank you.

The next question comes from Josef Schachter of SER.

The question I had for Jason on the royalty deductibility. You've mentioned that you're still looking into it. And congratulations on just starting to have volumes moving to El Tesorito. That was another one, and I'm glad that's moving forward. The last question I had was related to your production of oil. It's up 170%, were these shut-in wells that were uneconomic in the past? Are you spending any money there? What's the outlook for your Colombian oil side and of course, the revenues are pretty good. What do you see happening there going forward?

Josef, yes, those -- that oil production comes from our rank from most oil field looking in the [ Anios ] Basin. We operate that field and our partners are Ecopetrol. So that field has been producing since 2008 for us. It's a very, very mature field. And as you state, the fact of the matter is you're quite correct. With the increase in oil price, we've been able to reactivate wells that were shut in due to negative economics at lower oil prices. So that simply reflects turning on new wells. We have not spent any capital whatsoever in Rancho Hermoso for the past 8 years, and we have no intention of investing any capital in oil-related projects in Rancho Hermoso or anywhere else at this moment.

So going forward, we should just have depletion take that number down? Or is that number able to stay stable for a little while?

It's a very -- it's a mature field. It's been producing, Josef, since 2002. So it's a very old field, very mature and declines are very low. So very stable production, very low declines. We're at the sort of tail end of production from that field, which is going to be very long and very flat in general. It's been... Extremely sensitive to oil price.

[Operator Instructions]. The next question comes from [ Till Moes ] of Schroders.

It's about take-or-pay contracts. You earlier mentioned that the average maturity is 7.3 years. And I was just wondering, as contracts expire, do you plan on renewing them or in the new scenario where the Minister of Mines is openly positioning against exploration licenses? Wouldn't it make sense to increase your spot market exposure as prices could go up in such a scenario? Thank you.

Jason, can you take over?

Yes, sure. So historically, our sales profile has been approximately 80% in take-or-pay contracts. We've been in the gas business with the last 20% being interruptible. We have -- this last quarter was the strongest interruptible prices that we've seen in approximately 2.5 years. But that's more internally driven with respect to supply and demand inside Colombia as Columbia produces approximately 1 BCF a day and uses approximately 1 BCF a day. Obviously, mature gas fields are in decline and are theoretically, at least our price picks up as the demand continues to go up 3% a year, as estimated by [ Hopme ]. We've been in the gas business for since 2012, so approximately a decade. And most of our clients have had renewing contracts during that term. So if you look at any one of the contracts in our portfolio, which are approximately 20 contracts in that portfolio, they routinely roll over at the end of that expiry, and we expect that to continue moving forward.

[Operator Instructions] Seeing no more questions in the queue. This concludes the question-and-answer session as well as the conference. Thank you for your attendance and participation. You may now disconnect.