Precision Drilling Corporation

Good day and thank you for standing by. Welcome to the Precision Drilling Corporation 2024 First Quarter Conference Call. I would like to hand the conference over to LaVon Zadunic, Vice President in Investor Relations. Please go ahead.

Thank you, Operator, and welcome everyone to our First Quarter Conference Call. Today, I'm joined by Kevin Nebue, Precision's President and CEO, and Kerry Ford, our CFO. Earlier today, we reported our first quarter results. To begin our call today, Kerry will review these results and then Kevin will provide an operational update and outlook commentary. Once we have finished our prepared comments, we will open the call for questions. Please note that some comments today will refer to non-IFRS financial measures and include forward-looking statements which are subject to a number of risks and uncertainties. For more information on financial measures, forward-looking statements and risk factors, please refer to our news release and other regulatory filings available on CDAR and EDGAR. As a reminder, we express our financial results in Canadian dollars unless otherwise stated. With that, I will turn it over to Kerry.

Thanks, Lavonne. Precision's Q1 financial results exceeded our expectations for adjusted EBITDA earnings and cash flow. Adjusted EBITDA of $143 million was driven by strong drilling activity, improved pricing, and strict cost controls. Our Q1 adjusted EBITDA included a share-based compensation charge of $23 million. Without this charge, adjusted EBITDA would have been $166 million, which compares to $191 million in Q1 2023, a decrease of 13%. Net earnings were $37 million, or $2.53 per share, representing the seventh consecutive quarter of positive earnings per precision. Funds provided by operations and cash provided by operations were $118 million and $66 million respectively. Margins in the U.S. and Canada were higher than guidance, resulting from stronger than expected pricing, higher ancillary revenues, and improved cost performance. The importance of cost management in field margin generation cannot be overstated, and on this front, I am pleased with the performance of the business. Reducing costs remains a high priority for me, and I continue to work closely with the finance, operations, and supply chain teams to demonstrate continued progress in 2024. In the U.S., drilling activity for precision averaged 38 rigs in Q1, a decrease of seven rigs from the previous quarter. Daily operating margins in Q1, excluding the impacts of turnkey and IBC, were $11,057, a decrease of $755 from Q4, but significantly higher than guidance. For Q2, we expect normalized margins to be above $10,000 per day. In Canada, drilling activity for precision averaged 73 rigs, an increase of four rigs from Q1 2023. Daily operating margins in the quarter were $15,647, an increase of $2,089 from Q1 2023. For Q2, our daily operating margins are expected to be between $13,000 and $14,000. Internationally, drilling activity for precision in the current quarter averaged eight rigs. International average day rates were $52,808, an increase of 2% from the prior year due to rig mix. With the rig activations completed last year, we expect international EBITDA to increase approximately 50% from 2023 to 2024. In our C&P segment, adjusted EBITDA this quarter was $19 million, up 7% compared to the prior year quarter. Adjusted EBITDA was positively impacted by a 28% increase in well-service hours and improved pricing, reflecting the higher demand for our services and the impact of the CWC acquisition completed in November. We continue to create value with the CWC business on both sides of the border, and to date, we have achieved $16 million of the projected $20 million of annual synergies. Capital expenditures for the quarter were $56 million and included $14 million for upgrading and expansion, and $41 million for maintenance and infrastructure. Our full-year 2024 capital plan remains at $195 million and is comprised of $155 million for sustaining and infrastructure, and $40 million for upgrade and expansion. If increased rig activity materializes and upgrade demands continue, our capital plan could increase slightly in the second half of the year. April 24th, we had an average of 46 contracts in hand for the third quarter and an average of 44 contracts for the full year of 2024. Moving to the balance sheet, our Q1 results reflect the seasonal working capital build within our business and one-time payments highlighted in our press release. During the first quarter, we had a slight decrease in cash. As we have lower seasonal activity in Canada during the second quarter and no semi-annual interest payments, cash is coming in the door, and we expect to begin reducing debt in Q2. As of March 31st, our long-term debt position net of cash was approximately $900 million, and our total liquidity position was over $600 million, excluding letters of credit. Our net debt to trailing 12-month EBITDA ratio is approximately 1.5 times, and our average cost of debt is 7%. We expect our net debt to adjust before share-based compensation expense to continue to decline throughout the year. And we are committed to reducing debt by $600 million between 2022 and 2026 and achieving a normalized leverage level of below one times. Our debt reduction target for 2024 is $150 million to $200 million, and we plan to allocate 25% to 35% of free cash flow before principal payments directly to shareholders. Based on a robust free cash flow outlook, we repurchased $10 million of shares during the quarter, twice the pace of last year, a pace we plan to meet or exceed throughout 2024. Moving on to additional guidance for the year, which remains largely unchanged from the prior call, we expect depreciation of approximately $290 million, cash interest expense of approximately $75 million, cash taxes to remain relatively low and our effective tax rate to be approximately 25 percent, selling general and administrative expenses of $100 million before share-based compensation expense. We expect share-based compensation charges for the year to range between $40 million and $50 million at a share price range of $80 to $100, and the charge may increase or decrease by up to $15 million based on the share price performance relative to Precision's peer group. With that, I'll turn the call over to Kevin.

Thank you, Kerry, and good afternoon. As Kerry described, our business is performing very well. From a market perspective, our customers earn an extended period of increasing technology adoption and rig high grading, which aligns perfectly with our high performance and alpha technology-focused competitive strategy. Our team is achieving strong safety execution, excellent rig efficiency, and delivering highly disciplined cost management. We see firm day rates and stable margins across our business with excellent incremental growth opportunities in Canada and the Middle East. We expect normal maintenance investments and some upgrade investments while yielding strong free cash flow for the foreseeable future. For our investors, the majority of our heavy lifting on debt reduction is almost complete. As Kerry mentioned, we have prioritized increasing the return of capital to shareholders. I believe all of this demonstrates the success of our long-term strategy and the value we offer our shareholders. Moving on to the lower 48, industry rigged demand remains muted by weak natural gas prices and operator consolidation. While the leading indicators we monitor continue to point to a likely rebound in demand, the timing of that rebound is not clear. Those indicators include oil prices trending in the range of the upper 70s to lower 80s, Exhausted inventories of drilled and uncompleted wells, a wave of LNG export facilities set to commence operations late this year and into next, and ongoing operator discussions regarding high-grading rigs once the consolidating transactions are complete. Yet the visibility and timing of Raybon is not clear, and we expect a muted demand will persist during the second quarter. Precision's active rig count has hovered in the 40 range for several quarters. Our team has managed the contract churn very well and remain focused on defending price and margins. Now our better than average field margins reflect or better than expected field margins reflect our efforts to manage our costs, leverage our scale and drive free cash flow and expect these results to continue throughout the year. We have line of sight to several seasonal reactivations in the Northern Rockies this quarter, and our team will continue to actively manage near-term rig churn, particularly in the gas stations where we operate. However, I'll not be surprised by somewhat choppy activity levels during the quarter. Turning to Canada, it's a much different story. If the question is, do we see customer interest increasing in anticipation of the Trans Mountain startup? The answer is resoundingly yes. Today, we have 48 rigs operating compared to 38 this time last year. Nine of the 10 rig increase are super singles targeting heavy oil. We see this momentum continuing throughout the summer and exceeding our prior view on Canadian rig demand. With our pad-equipped super singles fully utilized, several customers are seeking to upgrade additional super singles to pad-style rigs. These $2-3 million upgrades come with market-leading day rates and long-term take-or-pay contracts. During the winter drilling season, we peaked at 43 super singles operating and surprisingly expect to get back to that range during mid-summer as activity recovers from spring breakup. However, like the lower 48, the weak natural gas price has been a drag on some Canadian dry gas activity with some operators reducing or delaying near-term gas projects. The impact on precision has been negligible as super triple demand remains very strong with year-over-year activity for precision flat and our fleet essentially fully utilized. Despite the weak ACO pricing, customer sentiment for NatGas remains surprisingly positive. The Coastal GasLink pipe is complete and LNG Canada is targeting final commissioning later this year with first gas shipments to follow. Based on preliminary customer conversations, LNG shipments will reinforce demand for our super triples like we've experienced in heavy oil with our super singles. It appears that customer demand will exceed super triple rig supply, and we may have the opportunity to mobilize additional capacity from the U.S. back to Canada early next year. Currently, we have 48 rigs running and expect to trend to the mid-60s by the end of June and into the 70s in July, well ahead of last year's pace. Keep in mind that during the Canadian spring and summer, weather and forest fires may have a temporary impact on activity, but should that happen, We expect it would serve to increase demand later in the year as those delayed projects pile up. On our February earnings call, we mentioned that we deployed to the field the NOV Atom Rig Floor and Derrick Robotic Pipe Handling System. This is essentially a bolt-on robotic system which can be installed on any precision super triple drilling rig. The first system is performing much better than I expected, with 97% of all rig floor and derrick pipe handling operations fully automated. We have no people working on the rig floor or up in the racking board. Now, of course, this is a highly sophisticated system. We expect several more months of field hardening to fully commercialize this product. However, in just the first 65 days of operations, we've drilled over 15,000 meters, and that's 50,000 feet for our U.S. listeners. We've tripped over 60,000 meters or almost 200,000 feet of drill pipe. We've completed eight whole sections and run the casing for all those sections with a robotic system. We believe that once we have fully field hardened and commercialized Adam, we will match or exceed the maximum efficiency possible with manual pipe handling. We'll eliminate human work from the red zone on the drill rig floor and in the mast while ensuring our customers safe, consistent, predictable, and highly efficient rig floor performance. Our early operational success with the NOV robotic system mirrors the technical success we've previously achieved with our alpha automation, alpha apps, and evergreen initiatives. Most importantly, it demonstrates our approach to new technology development. I'll remind you that our technology strategy has been to collaborate with industry partners who invest in the product R&D while we focus on field deployment and field hardening. Our technology team is comprised of highly experienced engineers and operations experts who work hand in hand with our field operations management team to ensure new technology is deployed with a well-supported, highly structured process. The process is designed to learn and solve deployment challenges quickly and efficiently with minimal cost overheads. Our robotics system is well on this path and we are the industry's first mover with field robotic technology. We believe that the comprehensive skills and operational IP we are developing as we field-harden this system reinforces our first-mover competitive advantage and does so with virtually no overhead burdening our financial performance. Now turning to our Canadian Wealth Service Group, The TMX tailwind is having a similar impact on well-servicing demand. During the first quarter, precision well-servicing averaged 82 active rigs, with peak utilization exceeding 100 rigs several times. On a snapshot and time basis, today we are running 65 well-serviced rigs, which compares to approximately 40 rigs for precision and CWC combined at the same time last year, and we expect this demand profile to continue. With the CWC acquisition, our team has leveraged our scale with significantly increased access to labor and a larger customer base. We have widely expanded our capabilities across Western Canada's sedimentary basin. Customer demand through the years is expected to remain strong, driven by the improved oil price differentials, supporting activity in oil-focused areas, and increased abandonment spending for the remainder of 2024 and into 2025. Moving to our international business, in Kuwait and the Kingdom of Saudi Arabia, we continue to bid our idle rigs for opportunities in both markets and also for other opportunities in the region. Now, competition in these regions has increased as other international drillers are looking to enter the Middle East. The eight precision rigs currently running are delivering a 40% activity growth for precision. We believe there are good opportunities to activate additional rigs this year or early next year as we look to continue our growth in that region. So I'll wrap up our comments by thanking the people of Precision for their hard work and dedication and the excellent results they're achieving for our customers, for our investors, and for the company. With that, I'll now hand the call back to the operator for your questions.

Thank you, ladies and gentlemen. If you have a question or a comment at this time, please press star 1-1 on your telephone. If your question has been answered or you wish to move yourself from the queue, please press star 1-1 again. We'll pause for a moment while we compile our Q&A roster.

Our first question comes from Aaron McNeil with TD Cowen.

Your line is open.

Afternoon, and thanks for taking my questions. As we think about the sort of outperformance in the U.S. relative to margin guidance and then the guidance for that step down in Q2 to, I think, $10,000 per day, what are the sort of puts and takes for the sequential decrease? Like, is it pricing? Are costs increasing? Are you just sort of embedding some continued conservatism in the guide.

Hey, Aaron. I think it's a little bit of all of the above. A little bit of pricing pressure and just maintaining a little bit more fixed cost with a lower activity level puts a bit of pressure on the margins, but we feel pretty good about being able to exceed the $10,000 a day mark.

Got it. Okay. And then maybe just a clarification question for you, Kerry. I know obviously the shareholder returns piece is becoming a bigger focus. Just wondering, could you define how you calculate free cash flows so we can sort of make our own assumptions around what the order of magnitude might be on the buyback?

Yes. I mean, I think in dollar terms, think of it as kind of a $50 to $100 million is probably the range in dollar terms. But we look at free cash flow as EBITDA, less interest, less capex. And that is what we have available for debt reduction and share buybacks.

Thanks, Aaron.

Our next question comes from Cole Pereira with CIFL. Your line is open.

Afternoon all. Sir, U.S. Outlook is largely similar to your peers, but I'm just wondering, can you give some color on how customer conversations are going, any big differences between public and private, oil versus gas, etc.? ?

Hey, Cole. It's Kevin. So fewer conversations on gas than oil these days. And that might be like three or four to one. I'd say there isn't a lot of difference in the type of conversations, but there is one unique piece. So we're in conversations with many of the companies that are involved in transactions on the buy side. And there's going to be a real push to move to higher technology rigs, consolidate vendor groups. So I'd say that there's a high level of engagement right now with some of the larger EMPs in the U.S. looking to understand how successful we've been with Evergreen and with Alpha and even with our robotics automation. And I think as those transactions close and they begin to rationalize their rig fleets, I feel quite good about our positioning right now.

Okay, got it. Thanks. And talked about a higher year-over-year rig count in Canada. I'm just wondering, do you see that? for both heavy oil focused and gas focused rigs in your fleet? Or is there kind of a shift more towards the heavy oil side? And then are you willing to say, you know, on average, what those two different classes of rigs might be generating right now from a margin per day standpoint?

I'll touch on the activity and let Kerry make comments on the margin. But cool. So the delta in activity so far has been oil based. So it's really kind of built up almost following the announcement the pipeline had a firm start date. And I think that's removed any uncertainty from anybody's mind. Certainly the WCS discount has been in place for a little while now. So I think you've got better cash flows for oil. You've got very low geological risk on heavy oil drilling, very predictable drilling programs, highly efficient rigs. So I think it's been an easy decision for our customers to very quickly get back to the drill bit. and get back on programs that were running back in that 2010, 2011, 2012 timeframe, and do it now with the confidence of better takeaway capacity, good marginal discounts, and a good supportive exchange rate. On the gas side right now, I'll be quite clear, we haven't seen any drag due to natural gas prices. Our supertriple activity remains firm and strong in the Montigny. It does look like from conversations that once we're closer to export startup that we'll start to see a response on increased demand on montane rigs. So that's why we're thinking that the day LNG Canada announced that they're commissioning and they're going to be launching their first shipments, I think we'll see a response on the gas side.

Yeah, and I'll follow on there on the margin question. I think if you go back three or four or five years ago, we had a pretty big difference in margin between super triples and super singles. That has changed as we're close to 100% utilization on the super triples and very high utilization on the super singles now. Super singles have a little bit lower operating cost and they're in demand, so the rates are pretty strong. So that difference is, there's still a bit of a difference there, but it's a lot narrower band than it used to be. But the activity difference between 2023 and 2024 is going to be made up of super singles and a few of the tele-doubles that we acquired in the CWC acquisition.

Okay, got it. Thanks. And then just kind of to circle back on some of your comments, fair to say that even with a bit of weakness in natural gas, you're not really seeing any pricing pressure for those rigs?

I think in the super single range in oil, there's no impact whatsoever. And on the triple side, you know, we're in negotiations with clients right now. We are getting lots of rhetoric back and forth around price tension with our customers like we always do. I think we're working hard to make sure we keep our customers happy right now.

Got it. That's all for me. Thanks. I'll turn it back.

Thanks, Cole. Our next question comes from Luke Lemoine with Piper Stanley. Your line is open.

Yeah.

Hey, good afternoon.

Kevin, just wanted to clarify, you talked about the Canadian rig count being in the 60s in June and 70s in Canada. Is that correct?

That's correct. Probably the mid-60s by the end of June and then into the mid-70s by mid-summer. There's always a comment about weather. If it rains hard, we lose rigs very quickly. So forest fires could cause an impact. But I'll just leave those kind of at the sidelines for a moment. Customers have plans to activate rigs and they're booking our rigs and they're having us get our crews lined up to get in the range of 65 rigs by the end of June and 75 rigs in mid-summer. It's unusual to see the rig count get that close to the winter rig count in the summertime. I mean, I'm quite surprised.

Yeah. And then you, you know, we've talked about it on previous calls before and you alluded to it again, you know, possibly bringing your rigs up from the U.S. to Canada, you know, with, I guess, what kind of the Canadian rig count is. you know, surprising year. Is there the possibility you can move more rigs to Canada from the U.S. than you previously expected? Or what do you think the outlook is for that next year?

You know, it's a little hard to say because, frankly, I've been a bit surprised by the response on the oil side to Trans Mountain. Certainly, we weren't planning to see 46 rigs or 48 rigs running in mid-April. It's been a pleasant surprise. It does show you how quickly our customers here can respond to a better macro. On the gas side... You know, I wouldn't be surprised if we were requested by customers to move two or three more rigs up from the US in 2025. We'd want them to pay the most cost. We'd want them to pay for any recertifications or upgrades to Canadian requirements. And we want day rates that are in the upper 30s. So we've been quite clear on that. We certainly do not want to oversupply the market in Canada. That's proven to be really, really poor for our returns. We need to maintain decent returns for our shareholders. So ensuring that if we bring rigs out, they're coming in at the same rate of return we're getting on our current rigs is really important.

Okay. And then on the U.S. rig count, you know, totally get the choppiness. I think you're at 39 right now, switching on the press release. And you talked about, you know, adding one to two in the DJ here, you know, coming up this quarter. Is the right way to think about the 2Q rate count just kind of oscillating around this number, or, you know, how should we handicap it?

Yeah, I'd like to see it stay above 40, but I think it'll oscillate around 40.

Okay. And then sneak one more in. Kerry, on the U.S. margins, you talked about a mixture of, you know, fixed costs, just kind of a lower rate count, less absorption there, and then some rate pressure as well. I mean, would you characterize the rate pressure as pretty minimal at this point?

Yes. Yeah, I think that kind of Our guidance reflects that. It's a little bit of higher cost and a little bit of rate pressure, but, you know, it's less than $1,000 a day.

Okay. Got it. Thanks a bunch.

Luke, I'll just clarify one thing for you, if you don't mind. You mentioned DJ Basin. We're actually looking kind of northern Rockies into the Wyoming area for those rig additions.

Oh, okay. Thank you.

Good. Thank you.

Our next question comes from Keith Mackey with RBC Capital Markets. Your line is open.

Hi, and thank you. Maybe just if we could start out on the shareholder returns front, so 25% to 35% of free cash flow you plan to return to shareholders this year. How does that change as you get towards your debt target? I think the release mentioned getting closer to that 50% mark. How do you think about that in terms of... in terms of actual timing versus achieving your debt reduction targets? Do you move it up before you actually get to the $600 million of debt reduction in 2026, or do you think about it moving sooner than that? Just anything you can do to help us frame the timing on that would be great.

Sure. Keith, the goal here is to get debt down to a below one times normalized level. So that's going to depend on kind of where our EBITDA is in 25 and 26 or where we think it's going to be. But there's a good chance we're in that range next year. And if you look at today, in the last two years, we've paid down $258 million of debt. If you take the midpoint of where we're guiding this year, it's called $175 million of additional debt reduction. We're kind of low to mid-fours there on debt reduction at the end of this year on a $600 million target. So I I think we're going to be well on our way and we're effectively doubling our allocation to, on a percentage basis, our allocation to share buybacks. And we're already getting more confident in taking some of that free cash flow and using it to give direct payments to shareholders. So I think that that type of thinking will continue into 2025. I can't promise that we'll be at 50% next year, but I think I can promise that we're going to increase the allocation next year.

Got it. Okay, that's helpful. And just to follow up on that then, Kerry, is it likely that you'll continue along with the buyback in that scenario, or do you think about a dividend as well, or is it too early to tell?

So we'll have conversations with our board every quarter about capital allocation and the form of the capital allocation. This year, it looks like it's going to be share buybacks, but I think that as we move closer to our long-term goal of getting below one times, a dividend becomes more likely in one form or another. Okay. Thanks very much. That's it for me.

Great. Thanks. Our next question comes from Makar Syed with ATB Capital Markets. Your line is open.

Thank you for taking my question. Kevin, as in the heavy oil basins, you see more and more pad drilling. Do you think that you could see maybe customer demand for teledoubles with pad drilling capability kind of pick up more because you can store more pipe? Do you expect to see that trend?

I'll look at this a couple of different ways, Makar. First of all, we can store almost infinite pipe on a super single because pipes are all racked horizontally on pipe racks. So we're not limited on racking capacity. The super single is an extremely efficient rig and it's got the pipe in the pipe arm right up against the well center line. just before you need it. So it's a really efficient rig. It doesn't require anybody in the derrick to handle that pipe. So it's efficient. It's safe. We can drill the first hole faster than a tele double because we're not having to build double stands as we go. So we're drilling ahead all the time. If it's a single bit run type well, which a lot of these are, we can drill those faster than tele doubles most of the time. There has been some question in the past about the torque capabilities. We're addressing that. The rigs are being hydraulically upgraded to handle the torque. This has been a rig which has approaching a 40-year history in heavy oil as a highly efficient rig. When you look at those drilling times, those racking times, tripping times, and then combine that with either the walking time to walk well to well or the time to move the rig, we can move that entire rig in four to five hours. That's if we're moving it location to location. It is just an amazingly efficient rig. So I think that I don't ignore competition. We only have 55% market share. We don't have it all, but I'm pretty happy with what we have.

Now, just to clarify, I was talking about having two strands of pipe vertically held up in the direct. So that's kind of what I meant with that.

Right. But when you start the well, you don't have two stands of pipe in the derrick. You've got all the pipe in the pipe rack. You've got to bring that pipe in one joint at a time. On a super single, you're always bringing it in 45 feet at a time. So we're drilling.

But on a pad, like moving between wells, that's what I meant.

But my other comment is that we have that single joint of pipe up in the pipe arm right up against the wall center just before they need the pipe. So it's still very efficient drilling ahead compared to a tele-double. And we can pull data from our analytics group and show how we can drill wells, first well, last well on a pad, every bit as efficient or sometimes more efficiently than tele-doubles.

Sure.

That's really interesting. And, you know, the other thing on the Automation looks to be a very interesting opportunity set for you. Do you see the application all across North America? You see the market better in Canada versus U.S.? And then also, do you see that applications in the Middle East market as well?

I think we'll see technology adoption in North America on this type of technology earlier. There is a huge focus on safety. There's a huge focus on consistent, predictable, repeatable, which really plays into any type of pad drilling. So I think that's where the automation technology will have its early traction. But we also do expect that Saudi Arabia and Kuwait don't never want to be left behind in technology. So it's going to, you know, they're going to view themselves as not a fast follower, but a follower.

Yeah.

But I certainly see super majors, large cap E&Ps that are highly focused on predictable, repeatable, and safety being the early adopters of automation technology like this. We have a little ways to go before we're commercial on this yet, but certainly have line of sight to believing that could happen inside this calendar year. That's good.

Well, thank you very much.

Thank you, Makar. Our next question comes from Kurt Haleed with Benchmark. Your line is open.

Hey, everybody. Good afternoon. Hey, Kurt. Hey, so Kevin, yeah, I just wanted to touch base again on, you know, discussions that we've had in the past and you've had about, you know, the dynamics at play where, you know, the Canadian E&P companies are looking to lock in rigs for longer duration contracts to basically take advantage of the energy export capacity. It sounds like there's maybe a little bit of a lull in that dynamic in the near term here because of natural gas prices, but I was really just looking to kind of calibrate that and get an update for you on how much conviction you still have in that structural change in the Canadian market.

Kurt, that's actually a really good question. So I'll break it up into two halves. So you talked about LNG. Let me start with heavy oil and super singles. We have more contracts on super singles today than we've ever had in our history on super singles when we didn't have a new build cycle. And that's for oil plays and tied to oil export through Trans Mountain. So that activity continues. We've got a number of upgrades right now that will be tied to long contracts with the pad upgrades. That momentum is continuing. I believe we have the right portion of our triples fleet for gas contracted. So we're not looking to add more contracts. We want to maintain some exposure to spot market as that market continues to improve. We have some renewals coming up right now. We're working through those with our customers. But I think the proportion of rigs that are locked in with term contracts in Canada and the proportion that are exposed to spot are the right proportion right now. We're not disclosing what that number is. We don't like to give out too much macro information on a rig fleet of 30 rigs. But I feel really good about our contract book, and I feel that we'll maintain a solid contract book and backlog of contracts with our super triples. Likely, if we're right and the LNG shipments start late this year or the next year and demand increases, if we move more rigs from the U.S. up to Canada, they're probably going to be contracted rigs.

Right. Okay. Okay, great. And then sort of going back to one of your other answers from earlier in the context of – I think pricing dynamics in Canada, I think you heard your reference that you're trying to keep your customers happy. Some might interpret that as being willing to discount price. Could you provide some clarity on that?

Yeah, I tell you that our customers are always looking for discounts. We're always looking for an increase. That debate goes on in every single deal, whether it's a long-term contract or a short-term contract. If you look at our market shares, we're in a strong position in kind of every segment we participate. And we want to make sure we maintain good, productive relationships with our customers. So we have to be mindful of their cost drivers also. Kerry gave guidance on margins. We don't expect any margin erosion. And, in fact, margins are still trending upwards. So I'll leave that lack of clarity on the answer hanging.

That's good. That's good. All right. Last one for me, just on the international front. Got a couple of rigs that are still, you know, in region. You mentioned the possibility of maybe getting something for those rigs later this year, early next year. Can you give us an update on what the range of cost it might be to kind of get those rigs ready to go?

Yeah, in the range of $6 million to $12 million for each rig.

Gotcha. Thank you.

So it sort of depends which opportunity we're successful on. If it's $12 million, it'll be a higher day rate and it'll pay back within the first year, roughly. If it's $6 million, it'll be a lower day rate but still pay back within the first year.

Excellent. Thanks, Kevin.

Great. Thanks a lot.

Our next question comes from Tim Monticello with ATB Capital Markets. Your line is open.

Hey, good afternoon.

I just wanted to compare and contrast, I guess, the Canadian and U.S. outlook, I guess, 12 months out. You've got some good line of sight to LNG exports and additional rigged demand. It sounds like the super triple market in Canada is pretty tight. But you've probably, you know, I would think that you'll see some upside in U.S. activity as well. Are those triples that you're talking about, would those be coming out of an idle fleet or rigs that haven't worked in a long time in the US? Or would that be reducing your optionality for additional rigs to go back to work?

Tim, in the U.S., we have two categories of super triple. We have the ST-1200, which is more common in the DJ Basin and the Marcellus. And then we have the ST-1500, which is a 1,500 to 1,800 horsepower rig that's common in the Permian and a little bit in the Marcellus and a little bit in the Haynesville. We would not be moving any ST-1500s, probably only ST-1200s. Okay, got it. I don't think it really reduces our optionality in the U.S. We think that the first movers in the U.S. will be Permian for oil if there's oil response. If there's a natural gas response, it'll be Haynesville where we're very well positioned with our 1500s.

Okay, got it. And then, interesting comment about how busy Q3 in the summer could be in Canada.

Is that strength across rig classes? Are you seeing... I guess the heavy doubles you picked up in the CWC acquisition, you know, incremental demand for those as well, or is it mostly in the higher tier?

I expect our activity in triples in summer of 2024 will look like it did in summer of 2023. So generally flat on our triples and essentially fully utilized. I think most of the incremental activity will be in our super singles year over year.

Okay. And are those doubles performing well?

Oh, yeah. We're doing well with the doubles. It's a little more price competitive. But I think if you look at our activity in Q1, I think we had 12 doubles working during Q1. It's just more competitive. We're not getting the double-digit EBITDA margins in those rigs.

Right. Okay. Well, I appreciate it.

Our next question comes from John Gibson with BMO Capital Markets. Your line is open.

Afternoon all. I just had one, and it's kind of more high level, I guess, just looking at the U.S. market and recent M&A. You touched a little bit on it in the call here about how M&A could drive additional high grading. How have conversations gone in terms of changing lateral length? I've kind of heard that maybe we could be seeing another step change on this front, and just kind of wondering what you're hearing in that regard.

Well, I'll answer the question a little bit differently. So we don't design the well. Our customers design the wells. We've got rigs that are drilled out to 20,000 feet. Those are not very common. We're hearing talk about more of that, but they don't seem very common. 15,000-foot laterals are fairly more common. Everybody wants to have the optionality to drill that length of well, but few people continue doing it. So it looks like the range is somewhere between 10,000 and 15,000 feet. It depends on land holdings and how consolidated the land is. But a full super spec rig today that's got three mud pumps, four generators, 30,000 foot rocking capacity, high torque top drive, has capacity to drill out to 15,000 or more feet.

Okay, great. I'll turn it back. Great. And I'm not showing any further questions at this time. I'd like to turn the call back over to LeVon for any closing remarks.

Thank you, everyone, for attending today. If you have any follow-up calls or questions, please feel free to call the Investor Relations Group. Thank you.

Ladies and gentlemen, that concludes today's presentation. You may now disconnect and have a wonderful day. you Thank you. Thank you.

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Good day and thank you for standing by.

Welcome to the Precision Drilling Corporation 2024 First Quarter Conference Call. I would like to hand the conference over to LaVon Zadunic, Vice President in Investor Relations. Please go ahead.

Thank you, Operator, and welcome everyone to our First Quarter Conference Call. Today, I'm joined by Kevin Nebue, Precision's President and CEO, and Kerry Ford, our CFO. Earlier today, we reported our first quarter results. To begin our call today, Kerry will review these results and then Kevin will provide an operational update and outlook commentary. Once we have finished our prepared comments, we will open the call for questions. Please note that some comments today will refer to non-IFRS financial measures and include forward-looking statements which are subject to a number of risks and uncertainties. For more information on financial measures, forward-looking statements and risk factors, please refer to our news release and other regulatory filings available on CDAR and EDGAR. As a reminder, we express our financial results in Canadian dollars unless otherwise stated. With that, I will turn it over to Kerry.

Thanks, Yvonne. Precision's Q1 financial results exceeded our expectations for adjusted EBITDA earnings and cash flow. Adjusted EBITDA of $143 million was driven by strong drilling activity, improved pricing, and strict cost controls. Our Q1 adjusted EBITDA included a share-based compensation charge of $23 million. Without this charge, adjusted EBITDA would have been $166 million, which compares to $191 million in Q1 2023, a decrease of 13%. Net earnings were $37 million, or $2.53 per share, representing the seventh consecutive quarter of positive earnings per precision. Funds provided by operations, and cash provided by operations were $118 million and $66 million, respectively. Margins in the US and Canada were higher than guidance, resulting from stronger than expected pricing, higher ancillary revenues, and improved cost performance. The importance of cost management in field margin generation cannot be overstated. And on this front, I am pleased with the performance of the business. Reducing costs remains a high priority for me, and I continue to work closely with the finance, operations, and supply chain teams to demonstrate continued progress in 2024. In the U.S., drilling activity for precision averaged 38 rigs in Q1, a decrease of seven rigs from the previous quarter. Daily operating margins in Q1, excluding the impacts of turnkey and IBC, were $11,057, a decrease of $755 from Q4, but significantly higher than guidance. For Q2, we expect normalized margins to be above $10,000 per day. In Canada, drilling activity for precision averaged 73 rigs, an increase of four rigs from Q1 2023. Daily operating margins in the quarter were $15,647, an increase of $2,089 from Q1 2023. For Q2, our daily operating margins are expected to be between $13,000 and $14,000. Internationally, drilling activity for precision in the current quarter averaged eight rigs. International average day rates were $52,808, an increase of 2% from the prior year due to rig mix. With the rig activations completed last year, we expect international EBITDA to increase approximately 50% from 2023 to 2024. In our C&P segment, adjusted EBITDA this quarter was $19 million, up 7% compared to the prior year quarter. Adjusted EBITDA was positively impacted by a 28% increase in well service hours and improved pricing, reflecting the higher demand for our services and the impact of the CWC acquisition completed in November. We continue to create value with the CWC business on both sides of the border, and to date, we have achieved $16 million of the projected $20 million of annual synergies. Capital expenditures for the quarter were $56 million and included $14 million for upgrading and expansion, and $41 million for maintenance and infrastructure. Our full-year 2024 capital plan remains at $195 million and is comprised of $155 million for sustaining and infrastructure, and $40 million for upgrade and expansion. If increased rig activity materializes and upgrade demands continue, our capital plan could increase slightly in the second half of the year. April 24th, we had an average of 46 contracts in hand for the third quarter and an average of 44 contracts for the full year of 2024. Moving to the balance sheet, our Q1 results reflect the seasonal working capital build within our business and one-time payments highlighted in our press release. During the first quarter, we had a slight decrease in cash. As we have lower seasonal activity in Canada during the second quarter and no semi-annual interest payments, cash is coming in the door and we expect to begin reducing debt in Q2. As of March 31st, our long-term debt position net of cash was approximately $900 million and our total liquidity position was over $600 million, excluding letters of credit. Our net debt to trailing 12-month EBITDA ratio is approximately 1.5 times and our average cost of debt is 7%. We expect our net debt to adjust before share-based compensation expense to continue to decline throughout the year. And we are committed to reducing debt by $600 million between 2022 and 2026 and achieving a normalized leverage level of below one times. Our debt reduction target for 2024 is $150 million to $200 million, and we plan to allocate 25% to 35% of free cash flow before principal payments directly to shareholders. Based on a robust free cash flow outlook, we repurchased $10 million of shares during the quarter, twice the pace of last year, a pace we plan to meet or exceed throughout 2024. Moving on to additional guidance for the year, which remains largely unchanged from the prior call, we expect depreciation of approximately $290 million, cash interest expense of approximately $75 million, cash taxes to remain relatively low and our effective tax rate to be approximately 25%, selling general and administrative expenses of $100 million before share-based compensation expense. We expect share-based compensation charges for the year to range between $40 million and $50 million at a share price range of $80 to $100, and the charge may increase or decrease by up to $15 million based on the share price performance relative to Precision's peer group. With that, I'll turn the call over to Kevin.

Thank you, Kerry, and good afternoon. As Kerry described, our business is performing very well. From a market perspective, our customers earn an extended period of increasing technology adoption and rig high grading, which aligns perfectly with our high performance and alpha technology-focused competitive strategy. Our team is achieving strong safety execution, excellent rig efficiency, and delivering highly disciplined cost management. We see firm day rates and stable margins across our business with excellent incremental growth opportunities in Canada and the Middle East. We expect normal maintenance investments and some upgrade investments while yielding strong free cash flow for the foreseeable future. For our investors, the majority of our heavy lifting on debt reduction is almost complete. As Kerry mentioned, we have prioritized increasing return of capital to shareholders. I believe all of this demonstrates the success of our long-term strategy and the value we offer our shareholders. Moving on to the lower 48, industry rigged demand remains muted by weak natural gas prices and operator consolidation. While the leading indicators we monitor continue to point to a likely rebound in demand, the timing of that rebound is not clear. Those indicators include oil prices trending in the range of the upper 70s to lower 80s, Exhausted inventories of drilled and uncompleted wells, a wave of LNG export facilities set to commence operations late this year and into next, and ongoing operator discussions regarding high-grading rigs once the consolidating transactions are complete. Yet the visibility and timing of Ribbon is not clear, and we expect a muted demand will persist during the second quarter. Precision's active rig count has hovered in the 40 range for several quarters. Our team has managed the contract churn very well and remain focused on defending price and margins. Now our better than average field margins reflect or better than expected field margins reflect our efforts to manage our costs, leverage our scale and drive free cash flow and expect these results to continue throughout the year. We have line of sight to several seasonal reactivations in the Northern Rockies this quarter, and our team will continue to actively manage near-term rig churn, particularly in the gas stations where we operate. However, I'll not be surprised by somewhat choppy activity levels during the quarter. Turning to Canada, it's a much different story. If the question is, do we see customer interest increasing in anticipation of the Trans Mountain startup? The answer is resoundingly yes. Today, we have 48 rigs operating compared to 38 this time last year. Nine of the 10 rig increase are super singles targeting heavy oil. We see this momentum continuing throughout the summer and exceeding our prior view on Canadian rig demand. With our pad equipped super singles fully utilized, several customers are seeking to upgrade additional super singles to pad style rigs. These two to $3 million upgrades come with market leading day rates and long-term take or pay contracts. During the winter drilling season, we peaked at 43 super singles operating and surprisingly expect to get back to that range during midsummer as activity recovers from spring breakup. However, like the lower 48, the weak natural gas price has been a drag on some Canadian dry gas activity with some operators reducing or delaying near-term gas projects. The impact on precision has been negligible as super triple demand remains very strong with year-over-year activity for precision flat and our fleet essentially fully utilized. Despite the weak ACO pricing, customer sentiment for NatGas remains surprisingly positive. The coastal gas link pipe is complete and LNG Canada is targeting final commissioning later this year with first gas shipments to follow. Based on preliminary customer conversations, LNG shipments will reinforce demand for our super triples like we've experienced in heavy oil with our super singles. It appears that customer demand will exceed super triple rig supply, and we may have the opportunity to mobilize additional capacity from the US back to Canada early next year. Currently, we have 48 rigs running and expect to trend to the mid 60s by the end of June and into the 70s in July, well ahead of last year's pace. Keep in mind that during the Canadian spring and summer, weather and forest fires may have a temporary impact on activity. But should that happen, we expect it would serve to increase demand later in the year as those delayed projects pile up. On our February earnings call, we mentioned that we deployed to the field the NOV Atom Rig Floor and Derrick robotic pipe handling system. This is essentially a bolt-on robotic system which can be installed on any precision super triple drilling rig. The first system is performing much better than I expected, with 97% of all rig floor and derrick pipe handling operations fully automated. We have no people working on the rig floor or up in the racking board. Now, of course, this is a highly sophisticated system. We expect several more months of field hardening to fully commercialize this product. However, in just the first 65 days of operations, we've drilled over 15,000 meters, and that's 50,000 feet for our U.S. listeners. We've tripped over 60,000 meters or almost 200,000 feet of drill pipe. We've completed eight whole sections and run the casing for all those sections with a robotic system. We believe that once we have fully field hardened and commercialized Adam, we will match or exceed the maximum efficiency possible with manual pipe handling. We'll eliminate human work from the red zone on the drill rig floor and in the mast while ensuring our customers safe, consistent, predictable, and highly efficient rig floor performance. Our early operational success with the NOV robotic system mirrors the technical success we've previously achieved with our alpha automation, alpha apps, and evergreen initiatives. Most importantly, it demonstrates our approach to new technology development. I'll remind you that our technology strategy has been to collaborate with industry partners who invest in the product R&D while we focus on field deployment and field hardening. Our technology team is comprised of highly experienced engineers and operations experts who work hand in hand with our field operations management team to ensure new technology is deployed with a well-supported, highly structured process. The process is designed to learn and solve deployment challenges quickly and efficiently with minimal cost overheads. Our robotics system is well on this path We are the industry's first mover with field robotic technology. We believe that the comprehensive skills and operational IP we are developing as we field harden the system reinforces our first mover competitive advantage and does so with virtually no overhead burdening our financial performance. Now turning to our Canadian Well Service Group, The TMX tailwind is having a similar impact on well-servicing demand. During the first quarter, precision well-servicing averaged 82 active rigs, with peak utilization exceeding 100 rigs several times. On a snapshot and time basis, today we are running 65 well-service rigs, which compares to approximately 40 rigs for precision and CWC combined at the same time last year, and we expect this demand profile to continue. With the CWC acquisition, our team has leveraged our scale with significantly increased access to labor and a larger customer base. We have widely expanded our capabilities across Western Canada's sedimentary basin. Customer demand through the year is expected to remain strong, driven by the improved oil price differentials, supporting activity in oil-focused areas, and increased abandonment spending for the remainder of 2024 and into 2025. Moving to our international business, in Kuwait and the Kingdom of Saudi Arabia, we continue to bid our idle rigs for opportunities in both markets and also for other opportunities in the region. Now, competition in these regions has increased as other international drillers are looking to enter the Middle East. The eight precision rigs currently running are delivering a 40% activity growth for precision. We believe there are good opportunities to activate additional rigs this year or early next year as we look to continue our growth in that region. So I'll wrap up our comments by thanking the people of Precision for their hard work and dedication and the excellent results they're achieving for our customers, for our investors, and for the company. With that, I'll now hand the call back to the operator for your questions.

Thank you, ladies and gentlemen. If you have a question or a comment at this time, please press star 1-1 on your telephone. If your question has been answered or you wish to move yourself from the queue, please press star 1-1 again. We'll pause for a moment while we compile our Q&A roster.

Our first question comes from Aaron McNeil with TD Cowan.

Your line is open.

Afternoon, and thanks for taking my questions. As we think about the sort of outperformance in the U.S. relative to margin guidance and then the guidance for that step down in Q2 to, I think, $10,000 per day, what are the sort of puts and takes for the sequential decrease? Like, is it pricing? Are costs increasing? Are you just sort of embedding some continued conservatism in the guide.

Hey, Aaron. I think it's a little bit of all of the above. A little bit of pricing pressure and just maintaining a little bit more fixed cost with a lower activity level puts a bit of pressure on the margins, but we feel pretty good about being able to exceed the $10,000 a day mark. Got it. Okay.

And then maybe just a clarification question for you, Kerry. I know obviously the shareholder returns piece is becoming a bigger focus. Just wondering, could you define how you calculate free cash flows so we can sort of make our own assumptions around what the order of magnitude might be on the buyback?

Yes. I mean, I think in dollar terms, think of it as kind of a $50 to $100 million is probably the range in dollar terms. But we look at free cash flow as EBITDA, less interest, less capex. And that is what we have available for debt reduction and share buybacks.

Thanks, Aaron.

Our next question comes from Cole Pereira with CFO. Your line is open.

Afternoon, all. Sir, U.S. Outlook is largely similar to your peers, but I'm just wondering, can you give some color on how customer conversations are going, any big differences between public and private, oil versus gas, etc.? ?

Hey, Cole. It's Kevin. So fewer conversations on gas than oil these days. And that might be like three or four to one. I'd say there isn't a lot of difference in the type of conversations, but there is one unique piece. So we're in conversations with many of the companies that are involved in transactions on the buy side. And there's going to be a real push to move to higher technology rigs, consolidate vendor groups. So I'd say that there's a high level of engagement right now with some of the larger EMPs in the U.S. looking to understand how successful we've been with Evergreen and with Alpha and even with our robotics automation. And I think as those transactions close and they begin to rationalize their rig fleets, I feel quite good about our positioning right now.

Okay, got it. Thanks. And talked about a higher year-over-year rig count in Canada. I'm just wondering, do you see that? for both heavy oil focused and gas focused rigs in your fleet? Or is there kind of a shift more towards the heavy oil side? And then are you willing to say, you know, on average, what those two different classes of rigs might be generating right now from a margin per day standpoint?

I'll touch on the activity and let Kerry make comments on the margin. But cool. So the delta in activity so far has been oil based. So it's really kind of built up almost following the announcement the pipeline had a firm start date. And I think that's removed any uncertainty from anybody's mind. Certainly the WCS discount has been in place for a little while now. So I think you've got better cash flows for oil. You've got very low geological risk on heavy oil drilling, very predictable drilling programs, highly efficient rigs. So I think it's been an easy decision for our customers to very quickly get back to the drill bit and get back on programs that were running back in that 2010, 2011, 2012 timeframe, and do it now with the confidence of better takeaway capacity, good marginal discounts, and a good supportive exchange rate. On the gas side right now, I'll be quite clear, we haven't seen any drag due to natural gas prices. Our supertribal activity remains firm. and strong in the Montigny. It does look like from conversations that once we're closer to export startup that we'll start to see response on increased demand on Montigny rigs. So that's why we're thinking that the day LNG Canada announced that they're commissioning and they're going to be launching their first shipments, I think we'll see a response on the gas side.

Yeah, and I'll follow on there on the margin question. I think if you go back three or four or five years ago, we had a pretty big difference in margin between super triples and super singles. That has changed as we're close to 100% utilization on the super triples and very high utilization on the super singles now. Super singles have a little bit lower operating cost and they're in demand, so the rates are pretty strong. So that difference is, there's still a bit of a difference there, but it's a lot narrower band than it used to be. But the activity difference between 2023 and 2024 is going to be made up of super singles and a few of the tele-doubles that we acquired in the CWC acquisition.

Okay, got it. Thanks. And then just kind of to circle back on some of your comments, fair to say that even with a bit of weakness in natural gas, you're not really seeing any pricing pressure for those rigs?

I think in the super single range in oil, there's no impact whatsoever. And on the triple side, you know, we're in negotiations with clients right now. We are getting lots of rhetoric back and forth around price tension with our customers like we always do. I think we're working hard to make sure we keep our customers happy right now.

Got it. That's all for me. Thanks. I'll turn it back.

Great. Thanks, Cole. Our next question comes from Luke Lemoine with Piper Stanley. Your line is open.

Yeah.

Hey, good afternoon.

Kevin, just wanted to clarify, you talked about the Canadian rig count being in the 60s in June and 70s in Canada. Is that correct?

That's correct. Probably in the mid-60s by the end of June and then into the mid-70s by mid-summer. There's always a comment about weather. If it rains hard, we lose rigs very quickly. So forest fires could cause an impact. But I'll just leave those kind of at the sidelines for a moment. Customers have plans to activate rigs and they're booking our rigs and they're having us get our crews lined up to get in the range of 65 rigs by the end of June and 75 rigs in mid-summer. It's unusual to see the rig count get that close to the winter rig count in the summertime. I mean, I'm quite surprised.

Yeah. And then you, you know, we've talked about it on previous calls before and you alluded to it again, you know, possibly bringing your rigs up from the U.S. to Canada, you know, with, I guess, what kind of the Canadian rig count is. you know, surprising year. Is there the possibility you can move more rigs to Canada from the U.S. than you previously expected? Or what do you think the outlook is for that next year?

You know, it's a little hard to say because, frankly, I've been a bit surprised by the response on the oil side to Trans Mountain. Certainly, we weren't planning to see 46 rigs or 48 rigs running in mid-April. It's been a pleasant surprise. It does show you how quickly our customers here can respond to a better macro. On the gas side... I wouldn't be surprised if we were requested by customers to move two or three more rigs up from the US in 2025. We'd want them to pay the most cost. We'd want them to pay for any recertifications or upgrades to Canadian requirements. And we want day rates that are in the upper 30s. So we've been quite clear on that. We certainly do not want to oversupply the market in Canada. That's proven to be

really really poor for our returns we need to maintain decent returns for our shareholders so ensuring that if we bring rigs out they're coming in at the same rate of return we're getting on our current rigs is really important okay and then um on the us recount you know totally get the chalkiness i think you're 39 right now switching on the press release and you talked about you know adding one to two in the dj here you know coming up this quarter Is the right way to think about the 2Q recount just kind of oscillating around this number, or, you know, how should we handicap it?

Yeah, I'd like to see it stay above 40, but I think it'll oscillate around 40.

Okay. And then sneak one more in. Kerry, on the U.S. margins, you talked about a mixture of, you know, fixed costs, just kind of a lower recount, less absorption there, and then some rate pressure as well. I mean, would you characterize the rate pressure as pretty minimal at this point?

Yes. Yeah, I think that kind of Our guidance reflects that. It's a little bit of higher cost and a little bit of rate pressure, but it's less than $1,000 a day.

Okay. Got it. Thanks a bunch.

Luke, I'll just clarify one thing for you, if you don't mind. You mentioned DJ Basin. We're actually looking kind of northern Rockies into the Wyoming area for those rig additions.

Okay. Thank you.

Good. Thank you.

Our next question comes from Keith Mackey with RBC Capital Markets. Your line is open.

Hi, and thank you. Maybe just if we could start out on the shareholder returns front, so 25% to 35% of free cash flow you plan to return to shareholders this year. How does that change as you get towards your debt target? I think the release mentioned getting closer to that 50% mark. How do you think about that in terms of... in terms of actual timing versus achieving your debt reduction targets? Do you move it up before you actually get to the $600 million of debt reduction in 2026, or do you think about it moving sooner than that? Just anything you can do to help us frame the timing on that would be great.

Sure. Keith, the goal here is to get debt down to a below one times normalized level. So that's going to depend on kind of where our EBITDA is in 25 and 26 or where we think it's going to be. But there's a good chance we're in that range next year. And if you look at today, in the last two years, we've paid down $258 million of debt. If you take the midpoint of where we're guiding this year, it's called $175 million of additional debt reduction. We're kind of low to mid-fours there on debt reduction at the end of this year on a $600 million target. I think we're going to be well on our way, and we're effectively doubling our allocation to, on a percentage basis, our allocation to share buybacks, and we're already getting more confident in taking some of that free cash flow and using it to give direct payments to shareholders. So I think that that type of thinking will continue into 2025. I can't promise that we'll be at 50% next year, but I think I can promise that we're going to increase the allocation next year.

Got it. Okay, that's helpful. And just to follow up on that then, Kerry, is it likely that you'll continue along with the buyback in that scenario, or do you think about a dividend as well, or is it too early to tell?

So we'll have conversations with our board every quarter about capital allocation and the form of the capital allocation. This year, it looks like it's going to be share buybacks, but I think that as we move closer to our long-term goal of getting below one times, a dividend becomes more likely in one form or another.

Okay.

Thanks very much.

That's it for me. Great.

Thanks.

Our next question comes from Makar Syed with ATB Capital Markets. Your line is open.

Thank you for taking my question. Kevin, in the heavy oil basins, you see more and more pad drilling. Do you think that you could see maybe customer demand for teledoubles with pad drilling capability kind of pick up more because you can store more pipe? Do you expect to see that trend?

I'll look at this a couple of different ways. First of all, we can store almost infinite pipe on a super single because pipes are all racked horizontally on pipe racks. So we're not limited on racking capacity. The super single is an extremely efficient rig and it's got the pipe in the pipe arm. right up against the well center line just before you need it so it's a really efficient rig it doesn't require anybody in the derrick to handle that pipe so it's it's efficient it's safe we can we can drill the first hole faster than a tele double because we're not having to build double stands as we go so we're drilling ahead all the time if it's a single bit run type well which a lot of these are we can drill those faster than tele doubles most of the time There has been some question in the past about the torque capabilities. We're addressing that. The rigs are being hydraulically upgraded to handle the torque. This has been a rig which has approaching a 40-year history in heavy oil as a highly efficient rig. When you look at those drilling times, those racking times, tripping times, and then combine that with either the walking time to walk well to well with the time to move the rig, we can move that entire rig in four to five hours. That's if we're moving it location to location. It is just an amazingly efficient rig. So I think that, you know, I don't ignore competition. We only have 55% market share. We don't have it all, but I'm pretty happy with what we have.

Now, just to clarify, I was talking about having two strands of pipe vertically, you know, held up in the direct. So that's kind of what I meant with that.

When you start the well, you don't have two stands of pipe in the derrick. You've got all the pipe in the pipe rack. You've got to bring that pipe in one joint at a time. On a super single, you're always bringing it in 45 feet at a time.

On a pad, moving between wells, that's what I meant.

But my other comment is that we have that single joint of pipe up in the pipe arm right up against the well center just before they need the pipe. So it's still very efficient drilling ahead compared to a tele-double. And we can pull data from our analytics group and show how we can drill wells, first well, last well on a pad, every bit as efficient or sometimes more efficiently than tele-doubles.

Sure.

That's really interesting. And, you know, the other thing on the Automation looks to be a very interesting opportunity set for you. Do you see the application all across North America? You see the market better in Canada versus U.S.? And then also, do you see, you know, that applications in the Middle East market as well?

Automation.

Yeah, sorry.

I'm sorry.

Yeah, for automation. So, yeah. Yeah. Yeah, I think we'll see technology adoption in North America on this type of technology earlier. There is a huge focus on safety. There's a huge focus on consistent, predictable, repeatable, which really plays into any type of pad drilling. So I think that's where the automation technology will have its early traction. But we also do expect that Saudi Arabia and Kuwait never want to be left behind in technology. So they're going to view themselves as not a fast follower, but a follower. But I certainly see super majors, large cap E&Ps that are highly focused on predictable, repeatable, and safety being the early adopters of automation technology like this. We have a little ways to go before we're commercial on this yet, but certainly have line of sight to believing that could happen inside this calendar year. That's good.

Well, thank you very much. Thank you.

Thank you, Makar. Our next question comes from Kurt Haleed with Benchmark. Your line is open.

Hey, everybody. Good afternoon. Hey, Kurt. Hey, so, Kevin, yeah, I just wanted to touch base again on, you know, discussions that we've had in the past and you've had about, you know, the dynamics at play where, you know, the Canadian E&P companies are looking to lock in rates for longer-duration contracts to basically take advantage of the ROGs you know, export capacity. It sounds like there's maybe a little bit of a lull in that dynamic in the near term here because of the natural gas prices, but I was really just looking to kind of calibrate that and get an update for you on how much conviction you still have in that structural change in the Canadian markets.

Kurt, that's actually a really good question. So I'll break it up into two halves. So you talked about LNG. Let me start with heavy oil and super singles. We have more contracts on super singles today than we've ever had in our history on super singles when we didn't have a new build cycle. And that's for oil plays and tied to oil export through Trans Mountain. So that activity continues. We've got a number of upgrades right now that will be tied to long contracts with the pad upgrades. That momentum is continuing. I believe we have the right portion of our triples fleet for gas contracted. So we're not looking to add more contracts. We want to maintain some exposure to spot market as that market continues to improve. We have some renewals coming up right now. We're working through those with our customers. But I think the proportion of rigs that are locked in with term contracts in Canada and the proportion that are exposed to spot are the right proportion right now. We're not disclosing what that number is. We don't like to give out too much macro information on a rig fleet of 30 rigs. But I feel really good about our contract book, and I feel that we'll maintain a solid contract book and backlog of contracts with our super triples. Likely, if we're right and the LNG shipments start late this year or the next year and demand increases, if we move more rigs from the U.S. up to Canada, they're probably going to be contracted rigs.

Right. Okay. Okay, great. And then sort of going back to one of your other answers from earlier in the context of – I think pricing dynamics in Canada, I think you heard you reference that you're trying to keep your customers happy. Some might interpret that as, you know, being willing to discount price. Could you provide some clarity on that?

Sure. Yeah, I tell you that our customers are always looking for discounts. We're always looking for an increase. That debate goes on in every single deal, whether it's a long-term contract or a short-term contract. If you look at our market shares, we're in a strong position in every segment we participate. And we want to make sure we maintain good, productive relationships with our customers. So we have to be mindful of their cost drivers also. So Kerry gave guidance on margins. We don't expect any margin erosion. And in fact, margins are still trending upwards. So I'll leave that lack of clarity on the answer. That's good.

That's good. All right. Last one for me, just on the international front. Got a couple of rigs that are still in region. You mentioned the possibility of maybe getting something for those rigs later this year, early next year. Can you give us an update on what the range of cost it might be to kind of get those rigs ready to go?

Yeah, in the range of $6 million to $12 million for each rig.

Gotcha. Thank you.

So it sort of depends which opportunity we're successful on. If it's $12 million, it'll be a higher day rate and it'll pay back within the first year, roughly. If it's $6 million, it'll be a lower day rate but still pay back within the first year.

Excellent. Thanks, Kevin.

Great.

Thanks a lot. Our next question comes from Tim Monticello with ATB Capital Markets. Your line is open.

Hey, good afternoon.

I just wanted to compare and contrast, I guess, the Canadian and U.S. outlook, I guess, 12 months out. You've got some good line of sight to LNG exports and additional rigged demand. It sounds like the super triple market in Canada is pretty tight. But you've probably, you know, I would think that you'll see some upside in U.S. activity as well. Are those triples that you're talking about, would those be coming out of an idle fleet or rigs that haven't worked in a long time in the U.S.? Or would that be reducing your optionality for additional rigs to go back to work?

Tim, those would be – in the U.S., we have two categories of super triple. We have the ST-1200, which is more common in the DJ basin in the Marcellus. And then we have the ST-1500, which is a 1,500 to 1,800 horsepower rig that's common in the Permian region. and a little bit in the Marcellus, and a little bit in the Haynesville. We would not be moving any ST1500s, probably only ST1200s.

Okay, got it.

I don't think it really reduces our optionality in the U.S. We think that the first movers in the U.S. will be Permian for oil, if there's oil response, and if there's a natural gas response, it'll be Haynesville, where we're very well positioned with our 1500s.

Okay, got it. And then...

Interesting comment about how busy Q3 in the summer could be in Canada. Is that strength across rig classes? Are you seeing, I guess, the heavy doubles picked up in the CWC acquisition, incremental demand for those as well, or is it mostly in the higher tier?

So I expect our activity in triples in summer of 2024 will look like it did in summer 2023. So generally flat on our triples and essentially fully utilized. I think most of the incremental activity will be in our super singles year over year.

Okay. And are those doubles performing well?

Yeah, we're doing well with the doubles. It's a little more price competitive. But I think if you look at our activity in Q1, I think we had 12 doubles working during Q1. It's just it's more competitive and we're not getting the double-digit EBITDA margins in those rigs.

Right, okay. Well, I appreciate it.

Our next question comes from John Gibson with BMO Capital Markets. Your line is open.

Afternoon all. I just had one, and it's kind of more high level, I guess, just looking at the U.S. market and recent M&A. You touched a little bit on it in the call here about how M&A could drive additional high grading. How have conversations gone in terms of changing lateral length? I've kind of heard that maybe we could be seeing another step change on this front, and just kind of wondering what you're hearing in that regard.

Well, I'll answer the question a little bit differently. So we don't design the well. Our customers design the wells. We've got rigs that are drilled out to 20,000 feet. Those are not very common. We're hearing talk about more of that, but they don't seem very common. 15,000-foot laterals are fairly more common. Everybody wants to have the optionality to drill that length of well, but few people continue doing it. So it looks like the range is somewhere between 10,000 and 15,000 feet. It depends on land holdings and how consolidated the land is. But a full super spec rig today that's got three mud pumps, four generators, 30,000 foot rocking capacity, high torque top drive, has capacity to drill out to 15,000 or more feet.

Okay, great. I'll turn it back. Great. And I'm not showing any further questions at this time. I'd like to turn the call back over to LeVon for any closing remarks.

Thank you, everyone, for attending today. If you have any follow-up calls or questions, please feel free to call the Investor Relations Group. Thank you.

Ladies and gentlemen, this concludes today's presentation. You may now disconnect and have a wonderful day.