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

Good day, and welcome to the Canacol Energy First Quarter 2022 Financial Results. [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.

Good morning, and welcome to Canacol's First 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; Mr. Mark Teare, Senior Vice President of Exploration; 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 from our first quarter results. Mr. Jason Bednar, our CFO, will then discuss financial highlights. Mr. Mark Teare, Senior Vice President of Exploration, will then discuss some of our exploration plans and new prospective resources estimates that we announced in April. 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. Charle is joining us on the line from Bogotá, and Jason and Mark are 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 and good afternoon, and welcome to Canacol's first quarter 2022 conference call. In the first quarter of 2022, we realized natural gas sales of 182 million standard cubic feet per day, which is above the midpoint of our annual guidance of 160 million to 200 million cubic standard feet per day. What we've seen so far this year in the Colombian gas market is that the Colombian economy and as a result of the Colombian gas market appears set to start growing again as we enter a post-pandemic phase, even though we've also seen relatively high rainfall levels which have provided ample hydroelectric generation capacity. Our stable production and operating conditions allow us to report another quarter with high operating margins of 77% and a relatively high return on capital employed of 19% annualized for the quarter. We continue to progress key growth projects, including the Jobo to Medellin pipeline project, which at the end of the quarter was declared a project of strategic national interest by the government of Colombia. And we continue to return capital to shareholders through dividends and share buybacks, including a significant block purchase of over 5 million shares in late January, as a result of which the total number of shares outstanding declined by just over 3% during the quarter. Subsequent to the first quarter, we announced new prospective resource assessments with total risked mean prospective resource of over 7.6 trillion cubic feet in conventional plays in both the Lower Magdalena Valley as well as a new deep play we are pursuing in the Middle Magdalena Valley. As Carolina already indicated, our Senior Vice President of Exploration, Mark Teare, will discuss these resource estimates and our exploration plans after we finish discussing our first quarter results. I'll now turn the presentation over to Jason Bednar, our CFO, who'll discuss our first quarter financials in more detail.

Thanks, Charle. We continue to execute our plan to develop our natural gas business in the first quarter of 2022. Our operating netback was $3.58 per Mcf in the first 3 months ended March 31, 2022, which is 7% higher in the same period of 2021, virtually unchanged from the prior quarter and very close to our guidance for $3.60, on average, for 2022. Our realized gas price of $4.66 was also very much in line with our guidance for the year of $4.61 to $4.74 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 $4.74 per Mcf. OpEx of $0.36 per Mcf was slightly higher than the prior quarter and up 29% on the same quarter last year. Higher OpEx in both the first quarter of 2022 and the fourth quarter of 2021 was caused by relatively high levels of maintenance work being carried out which we don't expect to persist through the remainder of 2022. That said, as you likely already know, consumer price inflation has been running in the high single digits recently, so higher than it was in recent years. And that means OpEx won't be quite as low going forward as it was in previous years, even when we're not doing any maintenance work. In percentage terms, our gas royalties were 15.5% of gross revenue, which is in line with the average for the preceding 2 years, so hopefully, roughly in line with everyone's expectations. To further highlight the strength and stability of our natural gas business as well as 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 13 quarters, which was 19% for the first quarter of 2022. We reported the following for the first quarter of 2022. $66 million of production revenues, net of royalties and transportation, which represents an 11% increase from Q1 of 2021. The increase was driven by the combination of higher volumes and a higher realized price per Mcf. We also reported $34 million in adjusted funds from operations, which represents an 11% decrease from the same period in 2021. And we reported EBITDAX of $50 million, which represents a 6% increase from the same period in 2021; finally, net income of $24 million when we reported a small net loss in the same period of 2021. To explain the different movements in some of these measures relative to the same quarter a year ago, a big driver of our net income each quarter relates to the Colombian peso strength or weakness during the period as compared to the U.S. dollar, which, of course, is our reporting currency. This impacts the valuation of our tax pools, which are in Colombian pesos. In the first quarter of this year, we recorded a deferred tax recovery of $12 million, while we reported an $11 million noncash deferred tax expense in the same period a year ago. This time last year, I said that the latter was primarily due to the effect of the reduction in the Colombian peso exchange rate on the value of unused tax losses and cost pools. And that in the event the peso strengthens against the U.S. dollar in the future, the corporation would realize a deferred income tax recovery for the period. This is exactly what has now happened, and those 2 numbers alone account for the vast majority of the change in net income relative to the same period a year ago. While EBITDA was up 6% year-over-year, funds from operations saw a decrease of $4.3 million in Q1 as compared to Q1 of 2021 which can be solely attributed to a $7.5 million increase in cash taxes. In the first quarter of last year, we had lower revenues, we had some unrealized foreign exchange losses and one-off exploration well expense related to an unsuccessful well, which is why our cash taxes were relatively low in the first quarter last year, and the opposite occurred in the first quarter of this year, which is why our cash taxes were relatively high this quarter. The 4% increase in the Colombian corporate income tax rate to 35% from the start of 2022 also contributed slightly to the increased cash taxes. Obviously, cash tax is an important part of our financial performance, but we hope everyone recognizes that most of the quarterly fluctuations are driven by things that are either one-offs or likely to reverse from quarter-to-quarter. In terms of guidance on this topic, going forward, we expect our effective tax rate under the current tax regime to be in the range of 25% to 28% of EBITDA. That concludes my comments on our first quarter financial results. I will now turn the presentation over to Mark Teare, Senior Vice President of Exploration.

Thank you, Jason. On April 6, we provided a new resource estimate for our gas exploration blocks in the Lower and Middle Magdalena Valley basins, showing an unrisked mean prospective resource potential of 20.5 trillion cubic feet at Canacol and a risked mean prospective resource of over 7.6 trillion cubic feet estimated by Boury Global Energy Consultants in their audited report effective December 31, 2021. That represents an increase of over 300% in risked mean prospective resource over the last resource report. We continue to see large and relatively unchanged exploration potential in the Lower Magdalena Valley basin, where our core producing operations are located. To quantify that statement, our updated resources evaluation estimated 3.2 Tcf gross unrisked. A 986 Bcf risked gross mean prospective resource for relatively shallow prospects and leads, the vast majority of which are in the Lower Magdalena Valley. We plan to continue testing that resource potential and converting it to reserves with the drilling in the Cienaga de Oro and Porquero play fairways, where our experience and expertise allows us to report an exploration drilling success rate around 80%. Perhaps just as important, drilling in the Lower Magdalena Valley Basin, we will be acquiring new seismic on the large VIM-5 block this year to the north of our core producing field. We anticipate new 3D seismic will allow us to mature material exploration leads to prospects and to continue drilling prospects with a high rate of drilling success once our interpretation of the seismic has allowed us to further refine our resource evaluations for our Lower Magdalena Valley block. The large growth in total prospective resource from previous years is due to increased estimates for our exploration blocks in the middle of Magdalena Valley basin, thanks to the technical work we have been doing to refine our understanding of these blocks as well as being awarded 2 large new blocks from the ANH late last year. These 2 blocks, VMM-53 and VMM 10-1, are on trend with the new deep conventional gas play we have identified and plan to investigate, starting with the drilling of the Pola-1 exploration well this year. In order to provide an indication of this play's potential, we announced unrisked and risked mean prospective resource estimates of 17.3 Tcf and 6.6 Tcf, respectively, for prospects and leads in the deep conventional gas play in the Middle Magdalena Valley basin. In a press release on April 11, we also announced a prospective resource estimate for just the Pola prospect of 1.2 Tcf unrisked and 470 Bcf risked. We don't usually provide resource estimates for individual prospects, and we don't expect that to change going forward. But in this case, we wanted to show that the first prospect we will be drilling this year in this play has significant potential. Of course, we have to highlight that this is exploration. It always carries significant risks and uncertainties. The chance of commercial success at Pola and across the whole play that is implied by the resource estimates we disclosed is around 40%, which is very attractive to us, given the size of the resources we are targeting. We plan to spud the Pola-1 well in August this year, and it will take approximately 3.5 months to drill and a total of 5 months to drill, test and complete. Therefore, we will be expecting results by the end of 2022 or early in 2023. It's also worth highlighting that our plan for Pola anticipates drilling to a depth of more than 17,000 feet, making this the deepest conventional natural gas well we have ever drilled. We anticipate having to manage high temperatures and pressures during drilling as well as during any subsequent operations. That said, there is nothing in our plans for this play that is not a standard operation that the global oil and gas industry has regularly matched for decades. We believe Canacol is uniquely positioned to identify this play's potential, thanks to our history of operations in the Middle Magdalena Valley basin, our experience in the Colombian gas market and our team's broad international experience. We're also confident we have the expertise to test it and potentially develop any commercial discoveries we might be able to make. As you can see, all of our blocks in the Middle Magdalena Valley basin are located relatively close to the existing TGI gas pipeline which has significant spare capacity. We are optimistic about this deep conventional gas play and excited to be drilling our first high-impact exploration well here. But it's important to emphasize Pola is only 1 of 18 targets we have identified on blocks in this play. In total, we have 178 prospects and leads identified across all our plays in the 2 basins. This number could increase as we acquire and evaluate new seismic. Pola is also only 1 of up to 8 exploration wells we plan to drill this year with all other planned wells being in the Lower Magdalena Valley. While we started this year with a discovery in the Porquero fairway at Carambulo, it is unlikely that we will be successful with every well we drill. However, we do expect to continue to see our exploration programs deliver on transferring prospective resources into reserves and ultimately production and cash flow in a cost-efficient manner, utilizing our unique expertise, experience and access to data and technology. Thank you for your attention. I'll now hand it back to Charle.

Thanks for that, Mark. Our quarterly results once again demonstrated high and stable operating margins as well as a very respectable return on capital employed. For the remainder of the year, we anticipate production and cash flow to be near our high guidance rather than the low end of the range, which is simply based on our 2022 take-or-pay contracts which averaged 160 million standard cubic feet per day. We also anticipate that our CapEx spending will come in at around $172 million as we've been contracting services and equipment at long-term very reasonable rates. The practical significance of the national strategic importance that the Medellin pipeline project has been granted by the Colombian government is that the designation should drastically improve the timing of delivery of items critical to the project, including the issuance of the environmental license. We have received binding offers from 4 international pipeline construction consortiums which are currently under valuation, and we are negotiating an additional long-term, take-or-pay gas sales contracts with clients located interior of Colombia to fill the remaining 46 million standard cubic feet per day of initial capacity of the pipeline, which will be 100 million cubic feet. Our exploration drilling program will accelerate in the short term and through the second half of the year as we have now contracted a second drilling rig and we'll be drilling both the Alboka and Cornamusa exploration wells in the Lower Magdalena Valley in parallel, while we have 3 higher-impact exploration wells planned for later in the year, including the Pola-1 well in the Middle Magdalena Valley, which Mark just referenced. In summary, we expect to continue delivering 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.

[Operator Instructions] The first question today comes from Matheus Enfeldt with UBS.

Thanks on the thorough update on the exploratory operations, much appreciated. So my first question is on that very same topic. I mean, looking to the mid- to long-term perspective, as a company, we anticipate to increase production in the context of the new pipeline and the EPM contracts. We do view that there's additional production to come from new exploration. Our question on that sense is we would like to see what the company sees as risks on top of the regular, let's call it like that, the regular exploratory risks for these assets and developments? What are the risks that Canacol is -- if Canacol is unable to achieve production as scheduled for the contracts? And on the other hand, if you are able to achieve production ahead of the start of the EPM contract, is there potential for sufficient spot demand to be met with the new production? That's my first question -- my first theme of questions. And then the second question that we have still on the additional volumes. If you could provide any updates on how are negotiations for the additional volume for the pipeline, other than the EPM contracts?

Okay. I'll take a crack at both questions here. With respect to our production -- future production expectations and as it relates to our exploration programs, the Medellin pipeline, when it comes on stream at the end of 2024, will add an additional 100 million cubic feet per day of production sales to the company. So we expect that in 2025, average production will be sort of in the 320 million to 340 million cubic feet per day range, which can be supported by our existing reserve base and the assumption that we will continue to successfully add reserves through our exploration drilling programs. As Mark highlighted, we do have over 170 exploration prospects identified, the majority of those being in the Lower Magdalena Valley, which is the pipeline -- the new pipeline will be connected to, as well as in the Middle Magdalena Valley. So we feel quite confident with our current base 2P reserves and our risked prospective resource we've identified on the acreage that we operate and being able to continue to replace reserves and grow our reserve base to sustain those levels of production sales in 2025. With respect to risks -- other risks, aside from exploration and development, there are political risks. We are in the midst of an election year here with the results to be decided by the end of June. And there are some risks with respect to the oil and gas business, should there be any change with respect to regulatory or community-type issues associated with the oil and gas operation, but we view those risks as relatively minor and risk that we can easily absorb. With respect to your second question, additional volumes for the pipeline, as I mentioned or as was mentioned, we filled about 55% of the initial volume of the pipeline, initial 100 million cubic feet with the EPM contract. And we're currently negotiating 3 additional contracts which will effectively fill the remaining 45 million cubic feet per day. We expect to achieve that by mid-summer, July, August of this year. And those are all with very large distributors located in the interior of the country.

Congrats on the quarter.

The next question comes from Oriana Covault with Balanz.

This is Oriana with Balanz. I had 3 questions. I don't know if we could go one by one but perhaps link it on with the previous question in terms of production. Can you confirm like which of these 4 wells were drilled during the quarter? And I've been tracking your monthly operational update, and it seems that production keeps on decreasing. So when can we see higher production coming from these new development wells that you drilled during the first quarter? That would be my first one.

Our production is really not necessarily limited by the capacity or productive capacity of the wells. Our production is limited by demand. So it's not like every new well we drill increases our production -- our production sales, I should say. Every new well we drill increases our productive capacity to produce gas, but the real driver on production is actually sales, of course. So we're selling into a market that's relatively stable. It can only absorb so much gas, and we're meeting those commitments with respect to that. So it's not like an oil well where you drill an oil well and you immediately put the oil into a truck and sell it into a pipeline. We're selling the gas directly to the consumers, and there's only so much gas that the market can absorb, so to speak.

Okay. That's clear. And perhaps moving on to a different area. Like if we're not mistaken, the Transmetano pipe connecting Medellin to the TDI backbone would need to be made reversal, just thinking of further future projects that it would flow in both directions for Canacol to sell volumes in Bogotá and Medellin. And for now, gas loads are only flowing in direction from the TDI pipes towards Medellin. So just to understand -- just to make sure that we are getting this correctly, and if we are, who will pay for making this Transmetano bidirectional, Canacol or the owner? That was one of the questions that we had.

Yes. With respect to the directionality of Transmetano, so essentially, when our pipeline is connected, our new pipeline connects to the city gate of Medellin. Essentially, all of Medellin's demand will be met by our pipeline. So there will be basically no need for Transmetano to continue shipping gas from east to west to the city of Medellin. And the way that the reversal of that pipeline occurs is that the clients that we're negotiating with for the remaining 45 million of capacity are all located within Bogotá and Cali. So they, those clients, will sign a transportation agreement with Transmetano, whereby Transmetano will reverse their pipeline, bring the gas that we are selling to those clients, that those clients are buying, from Medellin to Bogotá and Cali. So they will essentially sign with Transmetano a shipping agreement, a transportation agreement, whereby Transmetano will invest in the bidirectionality of the pipeline that reverse the flow, which is a relatively simple operation. You simply have to swing the compression stations around 180 degrees, basically, so that it goes in the opposite direction. But the bottom line is that the reversal of the Transmetano will be executed via the new gas sales agreements, the gas offtake agreements we will sign with clients in Bogotá and Cali.

Perfect. That's very, very clear. And just one last one regarding with Tesorito. Just to confirm, is it already commissioned or at least burning gas in test mode? And if so, how many million cubic feet per day are you expecting it to bring to your top line now that we're closer to the start?

Tesorito commission was delayed from April until July. So we expect that commissioning will start in the month of July, and that will consume up to 40 million cubic feet per day of gas during the commissioning. And then we expect Tesorito will be generating between 25% to 50% capacity, which will be essentially between 10 million and 20 million cubic feet per day of sales.

The next question comes from Josef Schachter with SER.

Thanks, Mark, for the full details and update on the drilling and the size of the prices on the geological side. I look forward to talking to you more about that. My first question is probably for Jason. You bought that 5.31 million shares in January, USD 2.48 a share, CAD 3.23 or so. Are you in a blackout period now? Or is the NCIB still active? What's going on there, especially given how the stock has weakened in the last few weeks?

Yes. I mean, we are in a blackout period. Having said that, there's certain allowances that you could put in your orders ahead of the blackout, just be hands-off, but we chose not to do that this quarter. I see a couple of questions coming in with respect to buybacks and why we haven't been active, so I'll just sort of give a more fulsome answer here to your question. We did buy obviously that USD 13 million to stock this year in January, significantly more than the $8.7 million we did in all of 2021. We have the ability in cash to buy more but we've chosen not to at this point in time, and we'll play that by ear as we move forward.

Okay. So going on the weakness of the stock, are we looking at the reasons more on the political side, given the concern that the leading candidate, Petro, and his running mate, which is considered quite leftist through some of the articles? Is that what you think might be also weighing on the stock?

Correct, yes. After many investigative calls to people like yourself, that appears to be the reason. I mean, our operations are stable quarter-over-quarter. The only rational explanation is the election.

Okay. And last one for me. When -- you've talked about having four companies with final binding bids to build the Jobo-Medellin pipeline. What's the process for reviewing them? What are the kind of critical points you're looking for to make that final decision of who wins the contract, just to get an idea of the scope of those kinds of issues?

Yes. I mean, the contracts we've received are all BOOM contracts, build, own, operate and maintain, whereby Canacol will not make any investment whatsoever ultimately in the pipeline. So our driver is transportation tariff. The contractor will build the pipeline and invest in the pipeline, and they expect a return on their capital of something, 14% or 15% IRR. And our concern is what the resulting transportation tariff they offered us was. And so all we care about is how much it costs to transport a molecule gas from Jobo to Medellin. And obviously, the lower the transportation tariff, the higher we can net off the gas, basically. So that is the sole criteria. All of them are technically qualified. All are international operators, all are very well financed. The driver is transportation tariff.

And Charle, when do you think a decision will be made? What's the window that we should be looking for, for something to potentially come out?

We expect to make the final decision within the next 2 months.

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

Some of my questions have been answered. I just want just repeat what -- just confirm what Jason has said that it seems like the quota for this year's share buyback is mostly gone. Is that a correct assessment? You have to wait for next year for more share buyback?

No. That -- we have ample cash on hand and expect to end the year with ample cash on hand. But at this time, we are not buying shares recently, obviously, but that does not mean that we will not accelerate a share buyback program in the coming months.

Okay. Great. That's reassuring. And also just on your -- do you see the cost -- drilling costs escalate due to inflation in the recent month or in the past year?

Drilling costs are definitely escalating. However, all of our drilling and service contracts are long-term contracts that were all renegotiated last year. So we have a fairly good buffer with respect to escalation associated with drilling and associated services.

Okay. Great. How long are those contracts?

They were renegotiated in July of last year, and the contracts are 2 to 3 years in length.

Okay. That's very good. So in terms of inflation, the natural gas hit $8 last week in the United States. Do you see any more negotiating power for future contracts and then renewing the existing contract?

Well, it's important to keep in mind that Colombia is a closed market. No gas is exported out of Colombia, and very, very little in the way of LNG is imported into Colombia. So Colombia is completely disconnected from the external market, which is great. For the past 10 years, Colombian gas prices have been double WTI, 100% higher than WTI, on average, and now they're lower. So I mean, it's just the fact of life that the gas market in Colombia here is super stable and with no inflation with respect to external natural gas pricing.

Okay. Great. So you should be treating like a utility company.

Yes, indeed.

Very stable, very stable income, and it's just -- somehow, it still vary with the gas price.

We will now take questions submitted through the webcast.

Thank you. So we have a first question from Alejandro Demichelis from Nau Securities. How do you see inflationary pressures impacting the cost to develop the Medellin pipeline?

As I mentioned earlier, the contract will be a BOOM contract, build, own, operate and maintain. They've already submitted binding offers, so any inflationary pressure is borne by the construction consortium and not us.

Thank you, Charle. Then we got several questions from Daniel Guardiola from Banco Pactual. The first one is when are you expecting to select the construction company that will build the Medellin pipeline?

I already answered that one.

And according to your time line of this project, when should construction start for you to honor the starting date of the contract with EPM?

We anticipate the start of construction to occur in July of 2023.

And we have a final question, which is during the quarter, your CapEx execution came in at between 13% to 16% of your fiscal year 2022 working program. How do you expect CapEx to ramp up in the upcoming quarters? And are you still targeting to invest between USD 172 million and USD 209 million in 2022?

I can probably take that, Charle. So I think Charle earlier in his discussion said that we expect to be near the low end of that $172 million. With respect to how that plays out for the remainder of the year. Q1 was slightly lower. We drilled less wells than anticipated. Having said that, moving forward, we expect to drill 3 to 4 wells in each of Q2, Q3, Q4. So we expect the CapEx to be relatively even amongst the remaining 3 quarters.

Thanks, Jason. We have another question from Alejandro Demichelis from Nau Securities. What do you see as the main risk on the Pola prospect?

I think Mark Teare can address that.

Yes, sure, I'll take that. So technically, the main risk as we see it is encountering enhanced permeability development. On 3D seismic, we have used coherence and curvature processing to derive seismic attributes that are predictive of fault and fracture intensity and so aligned with our understanding of the structural framework of the prospect that we're drilling. The well will target these areas with enhanced effective reservoir, which we anticipate to be in close proximity to the large-scale faulting that we see on seismic and that we're targeting with the well.

Thank you, Mark. We have 2 final questions from Roberto Paniagua from [ Colpatria ]. What are the times for the environmental license for Jobo-Medellin and Tesorito operation schedule? And the second question is, are you seeing financial expenses pressure in 2022?

So we expect the environmental permit to come out prior to July of 2023, at which time construction will start. I don't quite understand the -- Could you repeat the Tesorito question?

What's the Tesorito's operation schedule, which I believe you already answered as well.

Well, I think I already answered that, yes. That's right.

Then the second question is, are you seeing financial expenses pressure in 2022?

I can probably answer that. So with a little bit of foresight, as you recall, in November, about 5 months ago, we redid our bond, right? So the old rate was at 7.25%. Our new rate is 5.75%, so we were actually saving money, if you will, on -- in terms of interest, which is a very large financial expense. Charle already answered the CapEx questions on this topic with regard to locking in service contracts and tubulars, et cetera, for the foreseeable future. And I'll just touch briefly on operating costs, although I did deal with it at a high level earlier, right? So our guidance has always been for the last several years that our OpEx would be roughly $0.30 in Mcf. We've had quarters last year that were a few cents lower than that. And of course, this quarter was higher, right, which is in perspective, right? An 8% increase on $0.30 is roughly $0.025. And if you apply that to 180 million cubic feet a day like this quarter, that increase is $400,000 a quarter, right? So even when we look at some of the maintenance work, which was probably responsible for $0.05 increase in OpEx, and we do not expect to see that moving forward, that translates to only $800,000 a quarter. So it's somewhat de minimis on $50 million of EBITDA a quarter.

Thanks, Jason. I believe we have one more question from Oriana from Balanz.

The next question is from Oriana Covault with Balanz.

Just had a quick follow-up with regards to your drilling plans. You were mentioning that you expect to drill about 3 to 4 wells per quarter and with CapEx fairly stable. So how should we think of the Pola-1 1 and the other 2 wells that are from this deep conventional play falling in since they are expected to be higher cost? Just wanted to confirm that.

Good point. I believe we're -- unless Mark corrects me here, we're scheduled to spud Pola in August. You're correct. That is a higher-cost well. So Q3 -- while it's drilling through half of Q3 and all of Q4, those 2 quarters would be higher-weighted CapEx than Q2. You're quite correct.

The next question comes from [ Roberto Ianez ] with [ Casa de Lesa ].

I have one question related with the buyback program. Could you repeat that you're expecting to make more share buybacks in 2022?

Yes. We have the cash ability to do so, whether it's current cash on hand or expected cash come year-end. I would anticipate us making more buybacks during 2022, but the timing as to how much and when is not yet decided. Once again, for perspective, we did $13 million in Q1. We did $8.7 million in total for all of 2021. And I will remind everyone that our current dividend of CAD 0.052 a quarter represents roughly 8% dividend yield at this price, so there is -- there are ample shareholder returns already in the mix.

This concludes our question-and-answer session and concludes the conference call. Thank you for attending today's presentation. You may now disconnect.