Precision Drilling Q1 2024 Earnings Call Transcript

Quartr
Provided by Quartr
April 25, 2024

There are 12 speakers on the call.

Operator

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 Levon Zdunik, Vice President, Investor Relations. Please go ahead.

Speaker 1

Thank you, operator, and welcome, everyone, to our Q1 conference call. Today, I'm joined by Kevin Neveu, Precision's President and CEO and Cary Ford, our CFO. Earlier today, we reported our Q1 results. To begin our call today, Terry 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.

Speaker 1

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 Cary.

Speaker 2

Thanks, Lamon. Precision's Q1 financial results exceeded our expectations for adjusted EBITDA, earnings and cash flow. Adjusted EBITDA of $143,000,000 was driven by strong drilling activity, improved pricing and strict cost control. Our Q1 adjusted EBITDA included a share based compensation charge of $23,000,000 Without this charge, adjusted EBITDA would have been $166,000,000 which compares to $191,000,000 in Q1 2023, a decrease of 13%. Net earnings were $37,000,000 or $2.53 per share, representing the 7th consecutive quarter of positive earnings for Precision.

Speaker 2

Funds provided by operations and cash provided by operations were $118,000,000 66 $1,000,000 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.

Speaker 2

And on this front, I'm 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 7 rigs from the previous quarter. Daily operating margins in Q1 excluding the impacts of Turnkey and IBC were US11,057 dollars a decrease of US755 dollars from Q4, but significantly higher than guidance.

Speaker 2

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 $14,000 Internationally, drilling activity for Precision in the current quarter averaged 8 rigs. International average day rates were US52,808 dollars an increase of 2% from the prior year due to rig mix.

Speaker 2

With the rig activations completed last year, we expect international EBITDA to increase approximately 50% from 2023 to 2024. In our C and P segment, adjusted EBITDA this quarter was $19,000,000 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 $16,000,000 of the projected $20,000,000 of annual synergies. Capital expenditures for the quarter were $56,000,000 and included $14,000,000 for upgrade and expansion and $41,000,000 for maintenance and infrastructure.

Speaker 2

Our full year 2024 capital plan remains at $195,000,000 and is comprised of $155,000,000 for sustaining and infrastructure $40,000,000 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. As of April 24, we had an average of 46 contracts in hand for the Q3 and an average of 44 contracts for the full year 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.

Speaker 2

During the Q2, we expect to have a during the Q1, we had a slight decrease in cash. As we have lower seasonal activity in Canada during the Q2 and no semi annual interest payments, cash is coming in the door and we expect to begin reducing debt in Q2. As of March 31, our long term debt position net of cash was approximately $900,000,000 and our total liquidity position was over $600,000,000 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 adjusted EBITDA before share based compensation expense to continue to decline throughout the year.

Speaker 2

And we are committed to reducing debt by $600,000,000 between 2022 2026 and achieving a normalized leverage level of below 1 times. Our debt reduction target for 2024 is $150,000,000 to $200,000,000 and we plan to allocate 25% to 35% of free cash flow before principal payments directly to shareholders. Based on the robust free cash flow outlook, we repurchased $10,000,000 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 $290,000,000 cash interest expense of approximately $75,000,000 cash taxes to remain relatively low and our effective tax rate to be approximately 25%, selling, general and administrative expenses of $100,000,000 before share based compensation expense.

Speaker 2

We expect share based compensation charges for the year to range between $40,000,000 $50,000,000 at a share price range of $80 to $100 and the charge may increase or decrease by up to $15,000,000 based on the share price performance relative to Precision's peer group. With that, I'll turn the call over to Kevin.

Speaker 3

Thank you, Kerry, and good afternoon. As Kerry 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.

Speaker 3

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 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 forty eight, industry rig demand remains muted by weak natural gas prices and operator consolidation.

Speaker 3

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 Raybond is not clear and we expect the muted demand will persist during the Q2. Precision's active rig count has hovered in the 40 range for several quarters. Our team has managed their contract churn very well and remain focused on defending price and margins.

Speaker 3

Our better than average field margins reflect our 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 much different story. If the question is, do we see customer interest increasing in anticipation of the Trans Mountain start up?

Speaker 3

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 style rigs.

Speaker 3

These $2,000,000 to $3,000,000 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 forty eight, 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 natgas remains surprisingly positive.

Speaker 3

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 Triple 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.

Speaker 3

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 projects delayed projects pile up. On our February earnings call, we mentioned that we deployed to the field the NOV, ADAM, Rig Floor and Derek Robotic Pipe Handling System. This is essentially a bolt on robotic system, which can be installed on any precision Super Triple drilling rig.

Speaker 3

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 and we expect several more months of field hardening to fully commercialize this product. However, in just the 1st 65 days of operations, we've drilled over 15,000 meters and that's 50,000 feet for our U. S.

Speaker 3

Listeners. We've tripped over 60,000 meters or almost 200,000 feet of drill pipe. We've completed 8 whole sections and run the casing for all those sections with the 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.

Speaker 3

Our early operational success with the NOV robotic system mirrors the technical success we 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 and 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.

Speaker 3

Our robotics system is well on this path to where the industry's 1st mover with field robotic technology. We believe that the comprehensive skills and operational IP we're developing as we field hard in this system reinforces our 1st 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 Q1 Precision Well Servicing averaged 82 active rigs with peak utilization exceeding 100 rigs several times. On a snapshot in 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.

Speaker 3

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 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 through 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.

Speaker 3

The 8 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 in 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.

Operator

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

Speaker 4

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?

Speaker 4

Like is it pricing? Are costs increasing? Or are you just sort of embedding some continued conservatism in the guide?

Speaker 2

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.

Speaker 4

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?

Speaker 2

Yes. I mean, I think in dollar terms, think of it as kind of a $50,000,000 to $100,000,000 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.

Speaker 4

Excellent. I'll turn it back. Thanks.

Speaker 3

Thanks, Aaron.

Operator

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

Speaker 5

Afternoon all. So U. S. Outlook is largely similar to your peers, but I'm just wondering can you give some color on how Hey, Cole. It's Kevin.

Speaker 5

So, fewer

Speaker 3

Hey, 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.

Speaker 3

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 and Ps 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 the rig fleets, I feel quite good about our positioning right now.

Speaker 5

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?

Speaker 5

And then are you willing to say on average what those 2 different class of rigs might be generating right now from a margin per day standpoint?

Speaker 3

I'll touch on the activity and I'll let Carey make comments on the margin. But cool, so the delta in activity so far has been oil based. So and 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.

Speaker 3

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 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 super turbo activity remains firm and strong in the Montney.

Speaker 3

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 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.

Speaker 2

Yes. And I'll follow on there on the margin question. I think if you go back 3 or 4 or 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.

Speaker 2

So that difference is there's still a bit of a difference there, but it's a lot narrower than it used to be. But the activity difference between 2023 2024 is going to be made up of super singles and a few of the teledoubles that we acquired in the CWC acquisition.

Speaker 5

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?

Speaker 3

I think in the super single range in the oil, there's no impact whatsoever. And on the triple side, 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.

Speaker 5

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

Operator

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

Speaker 6

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

Speaker 3

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 and 75 rigs in midsummer.

Speaker 3

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.

Speaker 6

Yes. And then you we've talked about on previous calls before and you alluded to it again, possibly bringing rigs up from the U. S. To Canada. I guess, what kind of the Canadian rig count surprising here?

Speaker 6

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?

Speaker 3

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 2 or 3 more rigs up from the U.

Speaker 3

S. In 2025. We'd want them to pay the move 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.

Speaker 3

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.

Speaker 6

Okay. And then on the U. S. Rig count, totally get the choppiness. I think you're 39 right now, so what you have in press release.

Speaker 6

And you talked about adding 1 to 2 in the DJ here coming up this quarter. Is the right way to think about the 2Q rig count just kind of oscillating around this number? Or how should we handicap it?

Speaker 3

Yes. I'd like to see it stable 40%, but I think it'll oscillate around 40%.

Speaker 6

Okay. And then sneak one more in. Terry, On the U. S. Margins, you talked about a mixture of fixed costs, just kind of lower rig count, less absorption there and then some rate pressure as well.

Speaker 6

I mean, would you characterize the rate pressure as pretty minimal at this point?

Speaker 2

Yes. And 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.

Speaker 6

Okay, got it. Thanks so much.

Speaker 3

Luca, 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

Speaker 7

for those rig additions.

Speaker 8

Okay. Thank you.

Speaker 3

Good. Thank you.

Operator

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

Speaker 9

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.

Speaker 9

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 $600,000,000 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.

Speaker 2

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 2025 and 26 and 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 to date, in the last 2 years, we paid down $258,000,000 of debt.

Speaker 2

If you take the midpoint of where we're guiding this year, let's call it $175,000,000 of additional debt reduction. We're kind of low to mid 4s there on debt reduction at the end of this year on a $600,000,000 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 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. 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.

Speaker 9

Got it. Okay, that's helpful. And just a 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?

Speaker 2

So we'll have conversations with our Board every quarter about capital allocation in 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.

Speaker 9

Okay, thanks very much. That's it for me.

Speaker 3

Great, thanks.

Operator

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

Speaker 10

Thank you for taking

Speaker 11

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 teledouble with pad drilling capability kind of pick up more because you can store more pipe? Do you expect to see that trend?

Speaker 3

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 racked horizontally on pipe racks. 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.

Speaker 3

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 teledouble 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 teledouble most of the time.

Speaker 3

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 a approaching a 40 year history in heavy oil as a highly efficient rig. And 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 time to move the rig.

Speaker 3

We can move that entire rig in 4 to 5 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 50 percent market share.

Speaker 3

We don't have it all. But I'm pretty happy with what we have.

Speaker 11

Okay. Now just to clarify, I was talking about having 2 stands of pipe vertically held up in the direct. So that's kind of what I meant with it.

Speaker 3

Right. But when you start the well, you don't have 2 stands of pipe in the DERIC, you've got all the pipe in the pipe rack. You've got to bring that pipe in 1 joint at a time. On a super single, you're always bringing it in 45 feet at a time. So we're drilling

Speaker 7

But now but on a

Speaker 11

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

Speaker 3

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 teledouble. And we can pull data from our analytics group and show how we can drill wells first well, last well on the pad every bit as efficient or sometimes more efficiently than teledouble.

Speaker 11

Sure. That's really interesting. And 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.

Speaker 11

S? And then also do you see that applications in the Middle East market as well?

Speaker 3

Automation? Yes, sorry. I'm just asking for that. Yes, for automation.

Speaker 11

So I think we'll

Speaker 3

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.

Speaker 3

So it's going to they're going to view themselves as not a fast follower, but a follower. But I certainly see super majors, large cap E and 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.

Speaker 11

That's good. Well, thank you very much.

Speaker 8

Thank you, Bhakar.

Operator

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

Speaker 7

Hey, everybody. Good afternoon. Hey, Kurt. Hey, Kurt. Hey, so Kevin, yes, I just wanted to touch base again on discussions that we've had in the past and you've had about the dynamics at play where the Canadian E and P companies are looking to lock in the rigs for longer duration contracts to basically take advantage of the LNG export capacity.

Speaker 7

It sounds like there's maybe a little bit of a lull in that dynamic in the near term here because of natural gas pricing. 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?

Speaker 3

Kurt, that's actually a really good question. So I'll break it up in 2 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 where we didn't have a new build cycle.

Speaker 3

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.

Speaker 3

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.

Speaker 3

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, early next year and demand increases, if we move more rigs from the U. S.

Speaker 3

Up to Canada, they're probably going to be contracted rigs.

Speaker 7

Right. Okay. All right, great. And then going back to one of your other answers earlier in the context of, I think pricing dynamics in Canada. I think you heard you referenced that you're trying to keep your customers happy.

Speaker 7

Some might interpret that as being willing to discount price. Could you provide some clarity on that?

Speaker 3

Yes. I'd 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 short term contract. If you look at our market shares, we're in a strong position in kind of every segment we participate.

Speaker 3

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.

Speaker 3

So I'll leave that lack of clarity in the answer.

Speaker 7

That's good. That's good. All right. Last one for me, just on the international side, you've 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.

Speaker 7

Can you give us an update on what the range of cost that might be to kind of get those rigs ready to go?

Speaker 3

Yes, in the range of $6,000,000 to $12,000,000 for each rig.

Speaker 8

Got you.

Speaker 7

Thank you.

Speaker 3

So it sort of depends which opportunity we're successful on. If it's $12,000,000 it will be a higher day rate and it will pay back within the 1st year roughly. If it's $6,000,000 it will be a lower day rate, but still pay back within the 1st year.

Speaker 7

Excellent. Thanks, Kevin.

Speaker 3

Great. Thanks a lot.

Operator

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

Speaker 10

Hey, good afternoon. 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 maybe a lot of insight to LNG exports and additional rig demand.

Speaker 10

It sounds like the super triple market in Canada is pretty tight. But you probably 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.

Speaker 10

S? Or would that be reducing your optionality for additional rigs to go back to work?

Speaker 3

Tim, those would be in the U. S. We have 2 categories of Super Triple. We have the ST1200, which is more common in the DJ Basin in the Marcellus. And then we have the ST 1500, which is a 1500 to 1800 horsepower rig that's common in the Permian and a little bit in the Marcellus and a little bit in the Haynesville.

Speaker 3

We would not be moving any ST-1500s, probably only ST-1200s.

Speaker 8

Okay, got it.

Speaker 3

And then So 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 will be Haynesville, where we're very well positioned with our 1500s.

Speaker 10

Okay, got it. And then interesting comment about how busy Q3 in the summer could be in Canada. Is that strength across rig classes? Like are you seeing, I guess, the heavy doubles have picked up in the CWC acquisition, incremental demand for those as well? Or is it mostly in the higher tier

Speaker 3

rate expectations? So I expect our activity in triples in 20 20 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.

Speaker 10

Okay. And are those doubles performing well?

Speaker 3

Yes, we're doing multi 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. Okay. It's just more competitive and we're not getting the double digit EBITDA margins in those rigs.

Speaker 4

Right. Okay.

Speaker 10

Well, I appreciate it a lot there. A little bit

Speaker 3

color, yes.

Operator

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

Speaker 8

open. Good afternoon all. I just had one and it's kind of more high level, I guess, looking at the U. S. Market and the recent M and A, you touched a little bit on it in the call here.

Speaker 8

I thought how M and A could drive additional high grading. How have conversations gone in terms of changing lateral lengths? Like 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 on in that regard?

Speaker 3

Well, I'll say that 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 people talk about more of that, but they don't seem very common.

Speaker 3

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 $15,000 It depends on land holdings and how consolidated the land is. But a full super spec rig today that's got 3 mud pumps, 4 generators, 30,000 foot rocking capacity, high torque top drive has capacity to drill out to 15,000 or more feet.

Speaker 8

Okay, great. I'll turn it back.

Speaker 2

Great. And

Operator

I'm not showing any further questions at this time. I'd like to turn the call back over to LaVonne for any closing remarks.

Speaker 1

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.

Operator

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

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Earnings Conference Call
Precision Drilling Q1 2024
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