Canacol Energy Ltd (OTCQX:CNNEF) Q3 2022 Earnings Conference Call November 11, 2022 10:00 AM ET
Company Participants
Carolina Orozco – Vice President-Investor Relations & Communications
Charle Gamba – President & Chief Executive Officer
Jason Bednar – Chief Financial Officer
Conference Call Participants
Oriana Covault – Balanz
Josef Schachter – SER
Chen Lin – Lin Asset Management
Steven Bodzin – REDD Intelligence
Operator
Good day, and welcome to the Canacol Energy Third Quarter 2022 Financial Results Conference Call. All participants will be in a listen-only mode. [Operator Instructions] After today’s presentation, there will be an opportunity to ask questions. [Operator Instructions] 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.
Carolina Orozco
Good morning, and welcome to Canacol’s third quarter 2022 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’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 US dollars. We will begin the presentation with our President and CEO, Mr. Charle Gamba, who will summarize highlights from our third 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 and looking out to 2023. At the end, we will have a Q&A session.
I will now turn the call over to Mr. Charle Gamba, President and CEO of Canacol Energy. Charle, we cannot hear you.
Charle Gamba
Hello?
Carolina Orozco
Yes. Yes. We can hear you now.
Charle Gamba
Can you hear me now, Carolina?
Carolina Orozco
Yes.
Charle Gamba
Hello.
Carolina Orozco
Yes, Charle. We can hear you now. It appears we’ve lost connection with our speaker Charle. Please wait as we reconnect. [Technical Difficulty]
Operator
Ladies and gentlemen, we’ve reconnected with our speakers. Charle, please go ahead.
Charle Gamba
Good morning, everybody. I apologize for the delay had connecting. Anyway, good morning and good afternoon, and welcome to Canacol’s third quarter 2022 conference call. In the third quarter of 2022, we realized natural gas sales of 184 million standard cubic feet per day, which is above the midpoint of our annual guidance of 160 to 200 million standard cubic feet per day.
Tesorito, the 200-megawatt thermal electric plant, in which we hold a 10% equity interest and for which we are the sole supplier of gas, began generating electricity in mid-September. I’d like to, again, congratulate Celsia, our operating partner, for the successful conclusion of the construction process and look forward to this investment contributing to continued growth in our business, both through our equity investment and of course, through increased demand of our gas.
Our relatively stable production and operating conditions allowed us to report another quarter with high netbacks and operating margin of 78% and a relatively high return on capital employed of 17% annualized for the quarter. We continue with the execution of our drilling program planned this year with a total of nine development and exploration wells drilled to-date, which includes four successful exploration tests.
Finally, subsequent to quarter-end, we signed a strategic renewal SETCO to build on operate and maintain Jobo to Medellin pipeline project, which I will discuss in more detail, when I talk about the outlook for the remainder of this year and beyond.
I’ll now turn the presentation over to Jason Bednar, our CFO, who will discuss our third quarter financials in more detail.
Jason Bednar
Thanks, Charle. We continue to execute our plan and develop our natural gas business in the third quarter. We reported the following for the third quarter of 2022. $70 million of production revenue net of royalties and transportation, which represents a 6% increase from Q3 of 2021. The increase was driven by higher realized prices more than offsetting slightly lower sales volumes.
We reported $39 million in adjusted funds from operations, which represents a 1% increase from the same period in 2021 and also reported EBITDAX of $56 million, which represents a 4% increase from the same period in 2021. Finally, we reported a net loss of $5 million compared to a net profit of $9 million in the same period in 2021.
As I’ve explained on many previous conference calls, a big driver of our net income each quarter is unrealized foreign exchange gains and losses that can impact the valuation of our tax pools, which are in Colombian pesos.
In the third quarter, we recorded a deferred tax charge of $11 million, the majority of which was due to a deterioration in the value of the Colombian peso versus the US dollar, and without which, we would have reported substantial positive net income. In the event that the peso strengthens against the US dollar in the future, the corporation would realize a deferred income tax recovery.
Our gas operating netback was $3.73 per Mcf in the three months ended September 30, 2022, which is 7% higher than in the same period in 2021, 2% higher than the prior quarter and 4% above our guidance for $3.60 on average for 2022.
Our realized gas price of $4.76 was the highest we’ve achieved since prior to COVID and was above our guidance for the year of $4.61 to $4.74 per Mcf, thanks to stronger interruptible prices. We’re encouraged by the persistence of robust pricing for interruptible gas sales, despite lower absolute demand. 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 $0.28 per Mcf in Q3, down from $0.36 in Q1 and $0.31 in Q2, as we were undertaking less maintenance and benefiting from a lower Colombian peso when measuring our local costs in US dollars. We continue to anticipate very little maintenance in the second half of the year and expect 2022 average OpEx to be approximately $0.30 per Mcf.
In percentage terms, our gas royalties were again 16% of gross revenue, which is in line with the average for the preceding two years. I will highlight again, the return on capital employed implied by our financial statements over the last 15 quarters, averaging 16% over the last 12 months.
That concludes my comments on our third quarter financial results. I’ll now hand it back to Charle.
Charle Gamba
Thanks, Jason. Our results for the third quarter once again demonstrated high and stable operating margins, as well as a very respectable return on capital employed. Our guidance for 2022 remains unchanged. We anticipate production and cash flow to near a high end for our guidance, which was based on 200 million standard cubic feet per day of average gas sales, with CapEx coming in closer to the lower end of our guidance at $170 million.
Our exploration-driven program will continue at an increased pace through the remainder of this year and into early 2023, with four relatively high impact exploration wells, either spudded or due to spud within weeks at Saxafon, Chimela, Dividivi and Natilla. This will allow us to meet our guidance for drilling 12 wells in 2022 with a 13th well Natilla reaching TD in early 2023.
In May-October, we issued an update on our Jobo to Medellin pipeline project. Specifically, we announced the successful execution of agreement with the Shanghai Engineering and Technology Corp. consortium, or SETCO, to build and operate the pipeline project. SETCO is a Chinese-based construction and pipe fabrication consortium with experience in building major gas pipelines in Asia and the Middle East.
Recall that this is the third time in Canacol’s history that we have initially championed and funded a gas pipeline project with a different corporate entity has subsequently taken on and been built, owned, upgrade and maintain.
The prior two projects with Promigas allowed us to grow pipeline takeaway capacity from our Jobo facilities from less than 50 million standard cubic feet per day in 2016 to 200 million standard cubic feet per day today. And this Jobo to Medellin pipeline project will increase total pipeline takeaway capacity to over 300 million standard cubic feet per day when it is completed in late 2024.
Consistent with what we did for those prior projects, we won’t be committing or we won’t be commenting on the cost of this project beyond stating that Canacol has agreed to pay a fixed fee for a certain volume of gas to be transported through the pipeline to Medellin over a certain period of time.
In combination with long-term sales contracts we have signed, we expect to achieve attractive impacts at a slight premium to what we’re currently achieving selling exclusively to consumers in the Caribbean coast.
Our recent update on the Medellin, project highlighted that we now have two 12-year take-or-pay gas sales contracts for a total volume of 75 million cubic feet per day going to Medellin through the pipeline when he commenced operation in 2024, late 2024. This project has significant strategic value for Canacol and for Columbia.
As Canacol pursues its mission of improving the lives of millions of Columbians by supporting the Colombian government’s vision of transitioning to a future with cleaner but no less abundant energy using natural gas as a key transition fuel. More specifically, this project will allow consumers in the interior of Columbia to maintain or grow gas use through the middle of this decade despite expected declines in production from the largest producing gas fields operated by Ecopetrol in the interior of Colombia. The project will also allow Canacol to increase our gas sales and netbacks by accessing what is a new market for us and doing so in a cost-effective manner.
I’d like to thank everyone at Canacol and SETCO that worked so hard to bring us to this point, and I look forward to updating you over the coming quarters and years as SETCO works to complete the project. As in prior years, we’ll be announcing our 2023 guidance in the first half of December. In summary, we are continuing to deliver financial results within our previously stated guidance, and we continue to both return capital to shareholders at the same time investing for growth.
We’re now ready to take your questions.
Question-and-Answer Session
Operator
We will now begin the question-and-answer session. [Operator Instructions] The first question today comes from Oriana Covault with Balanz. Please go ahead.
Oriana Covault
Hi, good afternoon. Thanks for taking my questions . This is Oriana Covault with Balanz. And I have two questions if I can go one by one, that would be great. First with regards to the Jobo managing pipeline. Just wanted to understand if these contracts with EPM include any fines and/or penalties associated with delays of the entry in operations of the contract? And if so, if these events are cost because of construction delays on the EPC side, are they covered by Canacol or passed through the contractor. That was my first question.
A – Charle Gamba
Thank you for that question. As with any of our gas sales contracts, we cannot comment on any of the particular details associated with the contract, including those…
Oriana Covault
Okay. Understood. Just perhaps following up on the exploration plans. If you could share any updates around the deep gas wells, particularly Pola – 1 that I understood was part of the — under the schedule for the last quarter? And how are these coming along?
A – Charle Gamba
Thank you. Pola-1 is the first deep La Luna target cash flow we’re drilling in our new acreage position in the middle Magdalena Valley, of Colombia. We are using a 3,000 horsepower rate well is quite deep, up to 19,000 feet in terms of total vertical depth. And we had some delays with respect to the contracting of that rig. We initially intended to spud that well the last quarter here of 2022, but we anticipate splitting that well now the first quarter of 2023. So the civil works for that well has been constructed and the site is prepared and ready to accept the 3,000 horsepower rig that will arrive here in the first quarter to drill that well. That well will take approximately five months to drill and complete the test. So we expect the timing of that well in the first quarter of 2023.
Oriana Covault
Okay. Perfect. That’s very clear. Thank you.
Operator
The next question comes from Josef Schachter with SER. Please go ahead.
Josef Schachter
Good morning Charle and Jason, good to talk to you. First question, in your Note 18 of the results, it shows that when you’re talking about the SETCO deal, it talks about the reimbursement of the US$12 million of cost. Is that something that’s going to be paid to Canacol before year-end, or is that something that will happen in 2023?
Charle Gamba
Hi, Josef. Yeah, that payment will be made upon the receipt of the environmental permit for the project, at which point SETCO will reimburse all costs up to that date to Canacol as anticipated in August of 2023.
Josef Schachter
Okay. So August 2023. Okay, good. Next question for me. The four wells that you’re drilling; Saxafon, Chimela, Natilla, and Dividivi; two of them should be finished before year-end. Are we looking at 10 to 20 Bcf targets? Are they bigger than that? And do you expect that they will be included in your reserve report at year-end if they’re finished and you get to test them before year-end?
Charle Gamba
Yeah, three of them; Chimela, Saxafon and Dividivi will be completed and tested prior to year-end; only Natilla, which is a much deeper well above 15,000 to 16,000 feet on SSJN-7. That will be finished drilling towards the end of January, early February. So we expect that should any of those three wells, which would be Saxafon, Chimela and Dividivi proof up gas, we will be booking those as reserves on our 2022 reserve balance, correct.
Josef Schachter
Okay. And Chimela, when I look at the map, is VMM 45, just in the area of Pola-1, are you drilling this one to derisk Pola-1, or is this a totally different structure?
Charle Gamba
Yes. This is — Chimela is targeting sandstones, conventional sandstones of the Tertiary Lisama formation. This formation is very productive in the area. Grant here it produces from the same sand stones and new to the west of Chimela from their Acordionero field. This is a little deep, however, deeper than there, but the 2,000 to 3,000 feet deeper than their targets there. And we’re expecting that the base of Lisama here will contain primarily natural gas as opposed to primarily oil.
So it’s a separate target. It’s a tertiary sandstone target. We expect it to be gas charged along the same false systems that connected to the deeper La Luna Pola target. That’s where all the gas is expected to be coming from. But it’s a solar test.
Josef Schachter
Okay. And as you go down to these zones, are these also zones that you expect to find in Pola, so that if Pola doesn’t have the success of the lower zone than the uphole zones could be successful. Is that what you’re looking at here, or is it totally different structurally?
Jason Bednar
Yes. We view it as certainly derisking the tertiary section associated with Pola, which also has tertiary targets and the presence of gas as well will be very important. So it’s somewhat derisks the deeper Pola location, even though Pola is a La Luna target.
Josef Schachter
Okay. And last one for me. Your CapEx budget is so large. And of course, you’re also having the capital requirements on the dividend. Have you thought of having a DRIP so that people who see the stock is quite cheap could get in with using the DRIP format that’s available for the company? Is that something you guys are considering as a way of rewarding shareholders without doing cash and then having more cash for other company needs?
Charle Gamba
I can answer that. It is indeed something the Board has considered and is considering. So, thank you for bringing it up and expressing your interest in that.
Josef Schachter
Okay. I think I’ll leave it there. Thanks, and hope you guys do move — consider the DRIP I think that for retail shareholders, that might be something that would be of a great consideration. With that, thanks so much for answering my questions.
Charle Gamba
Thanks, Josef.
Operator
The next question comes from Chen Lin with Lin Asset Management. Please go ahead.
Chen Lin
Hi, thank you for taking my question. Actually, I just continue for the DRIP. For the United States based in United States, there is a tax withholding. Do you intend to offer that DRIP through Canadian only or open to potentially to invest like me in the United States?
Charle Gamba
Yes. Thanks, Chen. One of the reasons we started examining this was for exactly the reason you bring up. And my expectation, if it’s offered is that we could offer it to all shareholders.
Chen Lin
Good. So — but for us, we will have to have a tax withholding first, or is this not tax? I don’t know. I mean, I’m not expert in that — tax laws — international tax laws?
Charle Gamba
Yes. If you want to give me a call after this conference call or any time next week. I am not the resident tax expert either, but I know we have worked through this situation.
Chen Lin
Okay. Great. Thank you. The other question I have is with this new government, they are not open for new concession my understanding. And on your existing concession, there is — you basically can continue to do all the exploration. Is that correct? Just want to confirm with you?
Jason Bednar
Yes. So — with respect to the existing exploration and production blocks held by operators in Colombia, activity will continue as normal under those contracts. There will be the ability to drill exploration appraisal and development wells on all existing contracts.
With respect to new exploration bid rounds and the availability of new exploration areas, initially the position of the government and the Ministry of Mines and Energy, the Ministry of Mines and Energy was not to award any new contracts as they viewed there are being sufficient contracts already to explore during the next four years. However, in recent weeks, the President of the Republic has indicated that they are currently assessing the possibility of offering up new exploration and production areas sometime during the next four years. So it seems like they’re backing a little off that position, but nothing definitive in either direction for reaching.
Chen Lin
Thank you. Hopefully, the EU energy crisis is a wake up for the government. And also, do you foresee any royalty changes or going forward in the country?
Charle Gamba
Again, there’s going to be no changes to existing E&P contracts, which means that the royalties that are associated with those contracts would not be changed. So no, there’s no perspective on any changes in royalty. So those will remain as they are in existing contracts.
Chen Lin
Okay. Great. Thank you. Hopefully, this will discourage your competitor from exploring where you grow your production. Just to confirm, your Pola 1 is queue for drilling next year, right? And we should hear shareholder, we should hear something by midyear. Is that correct?
Charle Gamba
Yes, yes. We’ll be publishing our guidance for 2023, including our drilling program by mid-December and the plan rate now, Chen, is to initiate the drilling of Pola 1 in Q1 of 2023, and that well will take approximately five months to drill, complete and test.
Chen Lin
Thank you. Can you just remind us what the target risk and risk target of this Pola 1?
Charle Gamba
The target is La Luna for cretaceous La Luna it’s gas. We have unrisked gross recoverable resource, mean resources of around 500 Bcf with risk prospective resource of around 200 Bcf. So it’s a very large target for us, a very important well. And of course, this is the first deep well we’ll be drilling into our La Luna position in the middle may. We have just under 1 million net hectares under license there for the La Luna with some 15 Tcf of gross mean unrisked prospective resource identified in the La Luna by third-party auditors.
Chen Lin
Great. Thank you. Good luck.
Charle Gamba
Thank you. Thank you, Chen.
Operator
The next question comes from Christine Ronac [ph] with HSBC. Please go ahead.
Unidentified Analyst
Hi. Thank you. Question, on the new tax royalty, I know it’s not finalized. Finalized is going to happen next week. Remind me, I think your corporate tax rate of 35% does not go up, like it does for the oil companies. I wasn’t sure if you just don’t have any step-up like the oil producers? And then if you don’t have a tax royalty, tax deduction anymore, I just take whatever you have been deducting time your royalty time 35%. So I’m getting roughly like $20 million that would going to be paid until 2024, if I’m just at all roughly close, that would be great. Thank you.
Jason Bednar
Okay. Thanks, Christine. I can handle this. And I see on our e-mail questions that we’ve got multiple on the exact same topics. So I’ll try and make this fulsome. So, first of all, to my knowledge, the reform is not yet passed. As it currently stands in front of Congress, gas — natural gas is not subject to the income served tax. So you’re correct on that. And royalty — but royalties will not be deductible. So when we go down this last path, so once again, our income tax rate of 35%, we do not expect that to change as it sits now, but we will not be able to deduct royalties, which is the same as oil — which will be the same effect that all companies will also have, right?
So that effect would be our 35% tax rate on the base royalty of 6.4%. So not to make this too complicated, but some of our blocks have royalties of 20%, some have a 6.4%. What’s the delta that delta’s generally an x factor that people bid on when they first bid on the block from the ANH. The non-deductibility as we currently understand it is on the base royalty of 6.4%. So it would be the effect would be 35%, 6.4% of revenue.
Operator
I will now pass the conference over to Carolina Orozco, for any further — more questions on the webcast.
Carolina Orozco
Thank you. The first question that we have is from Andres Duarte from Corficolombiana. Andreas is asking, can you please brief us on the difference between gas input prices and local contract prices currently and in the near future?
Charle Gamba
Importation prices compared to domestic, correct?
Carolina Orozco
Correct.
Charle Gamba
Yeah, domestic wellhead pricing this year in 2022 has averaged between 450 and 550 from gas producers. Imported LNG loads delivered in Cartagena has been very few this year. There were some loads imported earlier on in 2022, at landed prices of $14 to $16 not regasified. So LNG prices of the — the LNG loads that have landed here in Cartagena this year have been approximately 3x the price prior to being the gasified commercialized as domestic wellhead prices.
Carolina Orozco
Thank you, Charle. The next question is from Roberto Paniagua from Casa Voca. Roberto is asking what is the impact on shareholder value creation with Canadian proposal to impose 2% tax on a stock buyback as of January 2024.
Jason Bednar
Yeah, I can answer that. So I mean, our share buybacks this year totaled $13 — approximately US$13 million. So 2%, of course, would be, I think that’s $260,000. So I mean it’s — I don’t think any corporate company is in favor of this. Having said that, it’s a $260,000 for us. I don’t think it’s going to impair any value creation.
Carolina Orozco
Thanks, Jason. We have another question from Pierre Groner. Pierre is asking. I would like to know more on the company’s rationale on the proposed consolidation mentioned in October 24 press release?
Charle Gamba
Yes. Okay. So the — our share price has slid a bit some of our peers have higher share prices. That’s not the motivation. The thought process here, many corporate accounts have discussed trading fees with us. We believe that a long — sorry, trading fees, meaning the price they pay on a per share basis and they can lower their trading costs, perhaps attract more interest.
I think it’s important to note that we decided to do this consolidation alongside the SETCO pipeline announcement which we think will be transformational to the company in a year or two’s time and took the opportunity to address some of the concerns raised by some of our shareholders alongside this monumental announcement for us.
Operator
We have another question from…
Carolina Orozco
Yes, please, go ahead, operator.
Operator
The next question from the audience side comes from Steven Bodzin with REDD Intelligence. Please go ahead.
Steven Bodzin
Hi, thank you very much. There’s been some news reporting about the possibility of reopening that Venezuela pipeline and reversing at bringing some gas imports, not a lot of details so far. I don’t even know if it’s realistic. I’m guess if you have any thoughts about it or whether that could pose any challenges over the next five to 10 years?
Charle Gamba
Yes. Thanks for that question. There has been some speculation earlier on in the summertime about the possibility of the gas from Venezuela. Of course, Venezuela contains the big gas reserves. And there’s plenty of gas in Venezuelan most of the current gas production there is being used for internal consumption, of course.
So, there’s sort of three issues associated with the possibility of importing gas from Venezuela. This is infrastructure. There is a pipeline between Venezuela and Colombia that was built back in 2008. That pipeline used to be used to transport gas from Colombia to Venezuela and as well as uses quite a bit of gas in the Maracaibo area for reinjection into oil-producing reservoirs to maintain reservoir pressure.
That pipeline went into disuse in 2014. The pipeline has a capacity of about 300 million cubic feet per day. So, the pipeline has essentially been shut in for almost eight years. So, there is quite a bit of uncertainty with respect to what investments are required to make into that pipeline, which is about 350 kilometers long to repair it as well as install the correct new compression equipment and reverse the flow.
So there is an investment of uncertain magnitude required to-date that pipeline. And the pipeline I should add is owned and operated by PDVSA, The Venezuelan National Company.
The second question is the availability of gas, as I mentioned, the majority of produced gas in Venezuela, particularly in Western Venezuela, which has access to that pipeline is currently used in the domestic market. There is not much of a surplus of gas in the Venezuelan market currently to export in Colombia.
And the third question, of course, is price. The price of that gas sent from Venezuela to Colombia. Naturally, PDVSA and the Venezuelan government is thinking about exporting gas, in particular to the European market in liquefied form where pricing, of course, is much better.
As I mentioned on the call here to a question a little earlier, well-head prices in Colombia are $4.50 to $5.50 per MMBtu. And of course, gas prices in Europe, is as high as $40. So with respect to exporting gas, it’s very likely that the Government of Venezuela and PDVSA, would focus on liquefying and exporting gas to Europe instead of much higher pricing as opposed to Colombia.
But having said that, those are sort of the three main elements associated with, that possibility of importing gas from Venezuela to Colombia.
Steven Bodzin
Sounds like you’re not especially concerned about the competitive threat.
Jason Bednar
Not in the near-term, no, certainly not within the next two to five years. And again, I think that realistically and very sensibly, I would imagine the Venezuelan Government will be more focused on exporting that gas to much higher value markets.
Steven Bodzin
I guess, the reason I asked about the five-year plus timeline is just looking at the time line for the bond maturity and thinking long-term. Do you, it’s — but it sounds like you’re just keeping an eye on it, not an immediate issue.
Jason Bednar
No, it’s not any issue. And again, the price is — I don’t think, I don’t think anyone is expecting Venezuela to give away its gas. I think that there will be a price associated with that, and it will be closer to international prices than to Colombian Domestic prices.
Steven Bodzin
Okay. Thank you.
Operator
This concludes our question-and-answer session and concludes the conference call. Thank you for attending today’s presentation. You may now disconnect.
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