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

Thank you, operator, and welcome, everyone, to our first quarter conference call. Today, I am joined by Kevin Neveu, Precision’s President and CEO; and Carey Ford, our CFO. Earlier today, we reported our first quarter results. To begin our call today, Carey 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 SEDAR and EDGAR. As a reminder, we express our financial results in Canadian dollars, unless otherwise stated. With that, I will turn it over to Carey.

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 control. 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 for 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 and field margin generation cannot be overstated. And on this front, I’m pleased with the performance of the business. Reducing cost 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 7 rigs from the previous quarter. Daily operating margins in Q1, excluding the impacts of turnkey and IBC were $1,057, 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 4 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 8 rigs. International average day rates were $52,808, an increase of…

Thank you, Carey, and good afternoon. As Carey described, our business is performing very well. From a market perspective, our customers are in 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. And as Carey mentioned, we have prioritized increasing the turn 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 rig 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 operated discussions regarding high-grading rigs once the consolidating transactions are complete. Yet the visibility and timing of rebound is not clear, and we expect a muted demand will persist during the second 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 start-up? The answer is resoundingly yes. Today, we have 48 rigs operating compared to 38 this time last year. 9 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 our rigs. These $2 million to $3 million upgrades come with market-leading day rates and long-term take-or-pay contracts. During the winter drilling season, we peaked up 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 AECO pricing, customer sentiment for nat gas 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 trend to the mid-60s by the end of June and…

Thank you. [Operator Instructions] Our first question comes from Aaron MacNeil with TD Cowen. Your line is open.

Afternoon. 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?

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 the 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, Carey. I know obviously, the shareholder returns piece is becoming a bigger focus, just wondering, could you define how you calculate free cash flow so we can sort of make our own assumptions around how – like 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 million 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.

Excellent. I will turn it back. Thanks.

Pleasure.

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

Afternoon, all. So 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, etcetera?

Hi, Cole, it’s Kevin. So fewer conversations on gas than oil these days, and that might be like 3 or 4 to 1. 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 E&Ps in the U.S. looking to understand how successful we’ve been with Evergreen and with the Alpha and even with our robotics automation. And I think as those transactions close and they begin to rationalize the 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, on average, what those two different class of rigs might be generating right now from a margin per day standpoint?

I’ll touch on the activity, and I’ll let Carey make comments on the margin. But – Cole, so the delta in activity so far has been oil-based – so – and it’s really kind of built up almost following the announcement of the pipeline had a firm start date. And I think that’s removed any uncertainty from anybody’s minds. Certainly, the WCS discounts 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 we’re running back in that 2010, 2011, 2012 time frame and do it now with the confidence of better takeaway capacity, good marginal discounts, that run 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 Super Triple activity remains firm and strong in the Montney. It does look like from conversations that once we’re closer to export start-up that we’ll start to see a response on increased demand on Montney 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.

Yes. And I’ll follow on there on the margin question. I think if you go back 3 or 4, 5 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, we’re in negotiations with the clients right now. We’re 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 will turn it back.

Thanks, Cole.

Our next question comes from Luke Lemoine with Piper Sandler. Your line is open.

Yes. 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 whether 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, 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.

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

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 were not – we were 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 U.S. in 2025. We want them to pay the move cost. We want them to pay for any recertifications or upgrades to Canadian requirements. And we want day rates that are up in 30. 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 we bring rigs out there 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, totally get the choppiness, I think you’re 39% right now, switching on the press release, and you talked about adding one to two in the DJ here coming up this quarter. Is the right way to think about the 2Q rig count just kind of offsetting around this number? Or how should we handicap that?

Yes, I’d like to see it stable 40%, but I think it will lostlate around 40%.

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

Yes. I think that’s 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 so much.

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

Okay, thank you.

Great. Thank you.

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

Hi, 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 your release mentioned getting closer to that 50% mark. How do you think about that in terms of actual timing in 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 below 1x normalized level. So it’s going to depend on kind of where our EBITDA is in ‘25 and ‘26, 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 than in the last few years, we paid down $258 million of debt, if you take the midpoint of where we’re guiding this year, let’s call it $175 million of additional debt reduction. Your we’re kind of low to mid-4s there on debt reduction at the end of this year on a $600 million target. So 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 buyback – 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 type of thinking will continue into 2025. And 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 a follow-up on that then, Carey, 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 1x a dividend becomes more likely in one form or another.

Okay, thanks very much. That’s all for me.

Good, thanks.

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

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

I will look at this a couple of different ways, Waqar. First of all, we can store almost infinite pipe on our Super Single because pipes are that close only on pipe rocks. So, we are not limited on rocking 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 direct to handle that pipe. So, it’s efficient, it’s safe. We can drill the first hole faster than a Tele-Double because we are not having to build double stands as we go. So, we are 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 are addressing that. The rigs are being hydraulically upgraded to handle the torque. This has been a rig which has a – approaching a 40-year history in heavy oil as a highly efficient rig. And when you look at those drilling times, those rocking times, tripping times and then combine that with either the rocking time to walk well to well, we plan to move the rig. We can move that entire rig in four hours to five hours. That’s if we are 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 at all, but I am pretty happy with what we have.

And then just to clarify, I was talking about having two stands of pipe vertically held up in the direct. So, that’s kind of what I meant with that.

Right. When you start the well, you don’t have two stands pipe in the deck, you got all the pipe in the pipe rack. You are going to bring that pipe in one joint at a time. On the Super Single, you are always bringing it in 45 feet at a time. So, we are drilling that…

But no, 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 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. Now, that’s really interesting. And 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?

Automation?

Yes, sorry. Yes, for automation. Yes. I think we will see technology adoption in North America on this type of technology earlier. There is a huge focus on safety. There is 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 – they are 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 are commercial on this yet, but certainly have line of sight to believing that could happen inside this calendar year.

Sounds good. Thank you very much.

Thank you, Waqar.

Our next question comes from Kurt Hallead with Benchmark. Your line is open.

Hi everybody. Good afternoon.

Hi Kurt.

Kevin, yes, I just wanted to touch base again on discussions we have had in the past and you have had about the dynamics at play where the Canadian E&P companies are looking to lock in rigs for longer duration contracts to basically take advantage of the LNG export capacity. It sounds like there is 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 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 will break it up in 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 have ever had in our history on Super Singles when we didn’t have a newbuild cycle. And that’s for oil plays and tied to oil export through Trans Mountain. So, that activity continues. We have 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 are 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 are 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 are 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 will maintain a solid contract book and backlog of contracts with our Super Triples. Likely, if we are right and the LNG shipments start late this year, early next year and demand increases, if we move more rigs from the U.S. up to Canada, they are probably going to be contracted rigs.

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

Yes. I would tell you that our customers are always looking for discounts. We are always looking for to increase that debate. That debate goes on at every single deal, whether it’s a long-term contract or a short-term contract. If you look at our market shares, we are 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. Carey gave guidance on margins. We don’t expect any margin erosion. And in fact, margins are still trending upwards. So, I will leave that lack of clarity in the answer.

That’s good. Alright. Last one for me, just on the international front. You 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?

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

Okay. Got it.

So, it sort of depends on which opportunity we are successful on. If it’s $12 million, it will be a higher day rate, and it will pay back within the first year roughly. If it’s $6 million, it will 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 Monachello with ATB Capital Markets. Your line is open.

Hi. Good afternoon. I just wanted to compare and contrast, I guess the Canadian and U.S. outlook, I guess 12 months out, you have got some little insight to LNG exports and additional rig demand. It sounds like the Super Triple market in Canada is pretty tight. But you probably I would think that you will see some upside in U.S. activity as well. Are those triples that you are talking about, would those be coming out of an idle state 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 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 1200.

Okay. Got it.

And 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 is oil response. If there is a natural gas response, it will be Haynesville where we are very well positioned with our 500s.

Okay. Got it. And then interesting comment about how busy Q3 and the summer could be in Canada, is that strength across rig classes? Like 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 rig…?

I expect our activity in triples in 2020 – summer of 2024, 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?

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

Great. Okay. Well, appreciate…

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

Good afternoon. I just had one, and it’s kind of more high level. I guess, just looking at the U.S. market and the recent M&A, you touched a little bit on it in the call here. What our M&A could drive additional high grading, how have conversations gone in terms of changing lateral length? Like I have kind of heard the way maybe we could be seeing another step change on this front? And just kind of want to what you are hearing in that regard.

Well, I will say that – I will answer the question a bit differently. So, we don’t design the well. Our customers design the wells. We have got rigs that have drilled out to 20,000 feet. Those are not very common. We are hearing talk about more of that, but 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 a few people continue doing it. So, it looks like the range is somewhere between 10,000 and 15,000. It depends on land holdings and how consolidated the land is. But a full Super-Spec rig today that’s got three mud pumps for generators, 30,000-foot rocking capacity, high torque top drive has capacity to drill out to 15,000 or more feet.

Okay. Great. I will get back.

And I am not showing any further questions at this time. I would like to turn the call back over to Lavonne 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 does conclude today’s presentation. You may now disconnect and have a wonderful day.