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spk02: Good day and thank you for standing by. Welcome to the Precision Drilling Corporation 2023 First Quarter Results Conference Call. I would like to hand the conference over to LaVon Zudonic, Director of Investor Relations. Please go ahead.
spk00: Thank you, Operator. Welcome everyone to Precision Drilling's First Quarter Earnings Conference Call and Webcast. Today, I'm joined by Kevin Neveu, our President and CEO, and Carrie Ford, our CFO. Earlier today, Precision reported strong first quarter results. Kerry will review these results with you, followed by an operational update and outlook commentary from Kevin. Once we have finished our prepared comments, we will open the call to questions. Please note that some of our comments today will refer to non-IFRS financial measures and will 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. As a reminder, we express our financial results in Canadian dollars unless otherwise indicated. With that, I'll turn it over to Kerry.
spk04: Thanks, Yvonne. Precision's Q1 financial results exceeded our expectations for revenue, adjusted EBITDA, earnings, and cash flow. Adjusted EBITDA of $203 million was driven by strong drilling activity, improved pricing, and strict cost control. Our Q1 adjusted EBITDA included a share-based compensation recovery of $12 million, which reflects our stock price decline during the quarter. Without this recovery, adjusted EBITDA would have been $191 million, which compares to $84 million in Q1 2022, an increase of 127%. Revenue for the quarter was $559 million, an increase of 59% from Q1 2022. Margins in both the U.S. and Canada were higher than guidance, resulting from stronger than expected pricing, higher ancillary service revenue, and improved cost performance. I commend our marketing and operations teams for achieving these results. In the U.S., drilling activity for precision averaged 60 rigs in Q1, consistent with our activity in the previous quarter. Daily operating margins in Q1, excluding the impacts of turnkey and IBC, were $14,179 U.S. dollars. an increase of $2,330 from Q4. For Q2, we expect normalized margins to be relatively flat with Q1. In Canada, drilling activity for precision averaged 69 rigs, an increase of 6 rigs, or 9% from Q1 2022. Daily operating margins for the quarter were $13,558, an increase of $1,210 from Q4 2022. For Q2, our daily operating margins are expected to be approximately $10,000, down from Q1 due to normal seasonality and lower fixed cost of absorption. Internationally, drilling activity precision in the current quarter averaged five rigs. International average day rates were $51,753, an increase of 3% from the prior year. In our C&P segment, adjusted EBITDA this quarter was $17.4 million, up 166% compared to the prior year quarter. Adjusted EBITDA was positively impacted by a 53% increase in well service hours and improved pricing, reflecting improved industry activity and higher demand for our services. Well abandonment work represented approximately 30% of well servicing operating hours in the quarter. In addition to strong performance by our well servicing operations, our rentals and camps divisions approximately doubled EBITDA contribution from Q1 last year. Capital expenditures for the quarter were $51 million and included $16 million for upgrade and expansion and $35 million for maintenance. Our full year 2023 capital plan has decreased by $40 million and the new $195 million plan is comprised of $146 million for sustaining infrastructure and $49 million for upgrade and expansion. The decrease in planned capital spending reflects our focus on capital discipline and cost control and includes fewer expected rig upgrades, long lead maintenance deferrals, and lower inflation estimates. As of April 25th, we had an average of 63 contracts in hand for the second quarter and an average of 55 contracts for the full year 2022. 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 quarter, we drew approximately $80 million on our revolver and built our cash balance by $20 million. The cash used during the quarter was less than expected due to strong in-the-quarter collections and completed asset sales. As we have lower seasonal activity in Canada during the second quarter and no semi-annual interest payment, cash is coming in the door and we expect to have paid down the $80 million revolver draw by the end of the second quarter, and we'll concentrate our annual debt reduction in the second half of the year, similar to last year. As of March 31st, our long-term debt position net of cash was approximately $1.1 billion, and our total liquidity position was $540 million, excluding letters of credit. Our net debt to trailing 12-month EBITDA ratio is approximately 2.4 times, down from 6.7 times last year, and our average cost of debt is 7%. We expect our net debt to adjust to EBITDA before share-based compensation expense to be approximately 1.25 times to 1.5 times by year-end. During the quarter, we utilized $5 million to repurchase shares. We remain committed to reducing debt by over $500 million between 2022 and 2025, achieving a normalized leverage of one times or below. Our net debt reduction target for 2023 is $150 million, and we plan to allocate 10% to 20% of free cash flow before principal payments directly to shareholders. Moving on to guidance for 2023, depreciation is the same at $285 million, and SG&A remains the same at $90 million before share-based compensation expense. We expect cash interest expense to be approximately $80 million for the year and cash taxes to remain low with an effective tax rate of approximately 25%. Also for 2023, we expect share-based compensation expense to range between $20 million and $40 million for the share price range between $60 and $100. The annual share-based compensation accrual could increase or decrease another $15 million based on relative share price performance and a multiple between zero and two times. With that, I'll now turn the call over to Kevin.
spk03: Thank you, Kerry. We're very pleased with the strong start to 2023. The momentum we established last year is continuing well into this year, and our long-term outlook remains unchanged. Our market positioning with our fleet of super series rigs, coupled with our alpha automation technology and our evergreen solutions, combined with the remarkably strong long-term energy fundamentals and Precision's broad geographic exposure gives us confidence in our plans for this year and for the long term. And this geographic exposure is key, as weaknesses in one region can be mitigated by strength in others. With that, I'll begin with our international operations in Kuwait and Saudi Arabia. As you know, we recently recontracted seven rigs in the region on five-year contracts. This includes reactivating two previously idle rigs. We guided to some rig downtime as we worked through the recertification process on four of those rigs prior to commencing the new terms. The first of those rigs was back up in operation in early April, about a month earlier than planned as our team was able to fast-track the recertification process. We further expect the remaining three rigs to be on a similar fast track with reactivation spread evenly over the next 12 to 15 weeks. In the third quarter, we'll have eight rigs operating, up from five today and six last year. We see continued good opportunities and have already bid our one remaining idle rig in Kuwait and expect that rig to be active late this year or early next year. That leaves us with one idle rig in Saudi Arabia and three other idle rigs in the region. We will continue to market those rigs throughout the Gulf region as we see several countries beginning to seek increasing drilling activity. Now turning to Canada, this region seems to garner less capital markets attention than the U.S. land industry, but for Canada, for precision, Canada remains firmly in our crosshairs. And said another way, please pay attention, this is going to be very important. We're experiencing sustained strong customer demand underpinned by the imminent completions of the Trans Mountain Oil Pipeline expansion and the Coastal GasLink Pipeline for LNG Canada. Customer demand has been further enhanced by the recent British Columbia settlement with the Blueberry First Nation facilitating oil and gas licensing approvals and driving incremental demand for our already sold-out fleet of Super Triple rigs. In Canada, during the first quarter, we averaged 69 active rigs with a peak of 79 rigs, which was 9% higher than last year. For most of the first quarter, we saw customer interest for an incremental 5 to 7 Super Triples over and above the 29 currently in our fleet. This incremental demand accelerated following the First Nation settlement I mentioned earlier. These strong customer signals remain intact today with our team addressing multiple super triple rig inquiries for post breakup and out into 2024 drilling programs. Looking to 2024 and beyond with LNG Canada prospectively starting up in 2025, we expect super triple demand to continue to grow. And it seems our customers do too. We have several customers who are contemplating multi-year take or pay U.S. style contracts to lock in super triple rigs from multi-year drilling programs. This is a contract structure which in Canada was traditionally only linked to new build rigs previously. We see this as a strong signal that our customers have concerns about rig availability for later this year and for the foreseeable future. Now, we have the capability to mobilize additional ST1200 rigs from the U.S. to Canada. However, we'll require customers to cover the full mobilization cost It would need a day rate consistent with what we'll see in the U.S., which would position those day rates in the upper 30s compared to our fleet average rates today in the low 30s. And for precision, Canada is really a tale of two rig classes. Besides our super triple, the precision super single rig is experiencing the highest demand since 2014. During the winter season, we operated 43 super singles. And even today, through the trough of spring breakup, all of our pad equipped super singles are active drilling for conventional heavy oil. This resurgence of heavy oil drilling is a function of the substantially narrowed WCS discount, a strong US dollar, incentivizing our customers to return to the drill bit. I'll also remind you that the Precision Super Single Rig was the first high-efficiency pad-type rig introduced by Precision in the 1990s. These rigs are low operating costs, highly efficient, highly mobile rigs. but still garner the leading market share in all Canadian heavy oil drilling applications, including SAGD, conventional heavy oil, oil sands, and, of course, the Clearwater Play. As we meet with customers to set the plans for summer and fall drilling programs, we see continued strong demand for super singles for the balance of 2023, and we have some customers now lining up for the winter of 2024 to lock in access to those rigs. With the additional oil takeaway capacity of the soon-to-be-commissioned Trans Mountain Oil Pipeline, we have confidence that this rig demand should be sustained over the long term. As I mentioned earlier, our sales team is in the middle of booking rigs for summer activity, negotiating long-term rig contracts with Montigny, and booking rigs for next winter. These are all critical conversations, and I understand it can relate to our customers' concerns regarding service cost inflation and the price increases we seek. It is very important to note that our rigs today are drilling wells in Canada significantly safer and more than twice as fast as during the last cycle in 2014. And to sustain our high performance and deliver these high levels of safety, the drilling pace and operational excellence, we need to achieve and sustain financial returns above our cost of capital. We are not there yet. But we'll continue to do our part to control our cost, manage all of our costs. But we must also seek to improve in day rates. And this requires close collaboration with our customers, open and effective communications, and most importantly, a shared view of the success of the industry as a whole. Today, we're running 38 rigs. which is about 15% higher than the same time last year, and is consistent with first quarter activity increases from last year. It appears this trend will continue through 2023 for Precision in Canada. Now, while I'm in Canada, I'll also touch on our well-serviced business. As Kerry mentioned, that business performed very well during the first quarter with strong utilization and improved pricing. As with our drilling business, I appreciate that our customers are very sensitive to rate increases and service cost inflation. This is an area where I highlight precision's intense focus on safety and the excellent safety results our well service team continues to deliver. I also highlight the huge challenge of recruiting, training, and retaining crews, particularly with the nature of the well service business. All of this requires highly skilled, experienced, and capable management teams supported by comprehensive recruiting, training, and safety programs. We also have to absorb the significant increase in rig maintenance, repair, and certification costs. None of this comes cheap in 2023, but you can see the scale effect and precision that's been demonstrated by the flawless integration of the high Arctic acquisition over the past few months. Coming out of spring breakup, we expect strong customer demand to continue through the end of this year and into 2024 in our well-serviced business. Now turning to the lower 48, the leading edge rates we mentioned last quarter continue to influence contract renewals and industry peer pricing discipline remains a key market feature even as we see natural gas activity softening with the weaker natural gas prices. With firm oil prices, we do expect oil-directed drilling to pick up some of the slack from gas, but this may take some time. Longer term, later this year and into next year, as LNG exports begin to ramp up, we expect a substantially improved demand across both oil and gas-directed drilling. Our long-term outlook remains positive. Today, we are running 57 rigs in the U.S., down only a small handful from our beacon Q1, And while we've experienced a fair amount of rig churn with re-contracting, well-to-well renewals, and rigs moving to new operators, I'm very pleased with the results our team have delivered to date. Interestingly, our net rig activity in the Hainesville and Marcellus is actually up one rig from earlier this year. And we believe that speaks to our customers seeking the best performing rigs, and particularly their desire for precision super triple rigs with alpha automation. While our sales team has done an excellent job to this point, I don't expect this activity level to hold firm during the second quarter. And while it's hard to guide an exit level for Precision's Q2 activity, I believe we'll have sustained activity levels in at least the low 50s. As I mentioned earlier, oil-directed demand remains firm, and we have several contracted rigs for oil-based projects with startup dates scheduled in the second half, and those projects are proceeding as planned. Bidding activity is remarkably strong, with 58 discrete rig bids in just the past 30 days, and 109 outstanding bids for super triple rigs, all with potential start dates ranging from July through the first quarter of 2024. Now, these bid and customer inquiry volumes are consistent with data points I've mentioned in the past and continue to be a very good indicator of consistent, strong customer interest in high-spec rigs. We will continue to monitor the U.S. market dynamics closely, and while we fully expect near-term pressure on rig activity, will remain highly disciplined with our rig pricing expectations while focusing on maximizing cash flow from operations. Turning to our Evergreen Solutions product line and our Alpha Automation service offerings, I'll begin by highlighting the equity investment we made in Clean Design, our battery energy storage vendor partner. And we see our best systems as battery energy storage systems As a key strategy to reduce rig emissions, we view the equity investment in our partner as critical to support both the growth of clean design as an opportunity for precision to participate in the value creation associated with the broader adoption of clean design solutions both inside and outside the oil and gas industry. A press release also mentioned that we continue to see strong customer support for the alpha automation value creation by improving drilling efficiency and the value that Evergreen provides by reducing rig emissions and lowering fuel costs. These product lines underpin key elements of our high-performance, high-value competitive strategy that provide an avenue for growth while dealing with the risks from emissions. To wrap up, I've got a few comments regarding our business model. Precision drilling was built and refined in the Canadian market. where seasonal volatility and persistent natural gas uncertainty were normal market conditions for most of our history. Our business model was and is structured to tightly control what we can control, such as safety, rig performance, variable and fixed costs, capital spending, managing staffing, all while delivering consistent free cash flow utilizing our highly variable cost operating model. Short-term industry cyclicality does not distract us from our business model or annual priorities. We've repeatedly demonstrated our ability to deliver on our priorities independent of the business cycle. This includes our cash flow and debt reduction targets, which we have consistently met or exceeded, particularly during the pandemic industry collapse of 2020 and 2021. I can assure you that we will confidently deliver on our priorities for 2023, despite weaker natural gas outlook that was expected at the beginning of the year. So on that note, I want to thank the people of Precision for their efforts and the results they continue to achieve controlling those elements of the business each of you impacts. Thank you. I also want to thank our investors for their patience and their support. And with that, I'll now turn the call back to our operator for questions.
spk02: 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.
spk06: Our first question comes from Makar Saeed with ATB. Your line is open.
spk08: Thank you for taking my question. Kevin, could you maybe talk a little bit more about the rate environment and also what are you seeing from a rig release notice perspective? One of your competitors said that the rig release notices kind of were at a very high level in early March, and then they've started to slow down a lot. Are you seeing something similar?
spk03: Well, Kar, good questions. It's really hard to glean out any trend from rig releases. I will tell you that we have seen kind of repeatedly over the last few quarters that our customers will tend to make decisions near a quarter end or before a reporting period so that they can report that they've already completed whatever work they wanted to do. So it's common that at the end of a quarter or early in the next quarter before an earnings call, that if they plan to lay a rig down or two, they do it before their earnings call so they can say the work is already done. So there's usually a little bit of an increase in activity around quarter end, beginning of the next quarter. That's not uncommon. We've seen a bit of that this quarter, but we also saw it in previous quarters. Just speaking to day rates and what we see for rate activity, it depends a little bit on just how competitive the environment is. If we're in an area where We're kind of the only rig around and mobilization costs for other rigs tends to be higher than we're, you know, much closer to those leading edge rates we might have quoted even back on our Q4 conference call. If we're in an area where there tends to be, you know, maybe three or four rigs competing for the same job, then yeah, rates are going to be a little softer. You know, we're expecting to see rates kind of pull back a little bit in those peaks of Q1. And I'd say in that range of $3,000 to $4,000 to $5,000.
spk08: Okay. So leading edge in the gas basis could be in that low 30s to mid 30s kind of level. Is that fair?
spk03: I think that's reasonable. We've been kind of lucky so far in that we've been activating rigs and customers have been seeking out our alpha automation. So far, so good. But going forward, I do expect it to be a little bumpier. And we could see competition in that mid 30s or low 30s range. I think that's possible.
spk08: Okay. And then on the cost of OPEX side, is that kind of falling from or, you know, what trends are you seeing there?
spk04: Hi, Mukar. So we've had a little bit of a labor increase in the fourth quarter that was highlighted in our press release. But other than that, the costs are firm. We're not really seeing any inflationary impacts on a sequential basis. And we could actually see some inflationary relief here in the coming quarters. Okay.
spk08: And maybe inside, like, you know, as you're negotiating your contracts now, do you see rates headed higher for H2, or is it mostly going to be, you know, first quarter next year when you see some new rates?
spk03: Wakari, we kind of have two cycles in pricing in Canada. There's one cycle that starts, begins at Q3, and the second cycle that begins in Q1 of kind of the following year. So I do expect there'll be some opportunity for prices to move up in Q3. Those negotiations are ongoing right now. I did kind of give a lot of detail on my prepared comments around both the cost pressures we have and the need we have to achieve a return on capital above our cost of capital. So I know those conversations are going on. I know our customers are really sensitive to price right now. But the fact is, to sustain this level of performance, we need to have higher rates. So we're going to keep that pressure on the market. And we're going to back that up by having rigs that deliver excellent results for our customers and both safety, performance, and predictability.
spk08: Okay. Thank you very much. That's all from me for now.
spk02: Great. Thanks a lot, Makar.
spk06: One moment for our next question. Our next question comes from Nicole Pereira with Stiefel.
spk02: Your line is open.
spk07: Morning all. For the U.S. rigs that were dropped, was this a function of customers just laying down rigs or was it maybe a little bit of you losing the rigs because you wanted to stay firm on price as well?
spk03: The simple answer to that question is yes, we've had a bit of both. And as I've said in previous calls, Cole, the best signal we can send our customers about discipline is by rejecting prices that are below our thresholds. And I kind of furthered that comment by saying I think it's fair to say that a few customers out there are looking at this period right now as a chance to grab a premium rig and maybe get a discount price. We're not going to let that happen.
spk07: Got it. Thanks. And talked about a rig count in the low 50s in the U.S. Should we be thinking that your rig count stabilizes at that level for the rest of the year or You know, could it maybe climb or fall further in the second half potentially?
spk04: Yeah, so it's all going to ultimately depend on commodity prices. I think we've seen the gas price bottom out here around $2. And, you know, if the oil prices firm up, we think a lot of those rigs that are getting laid down in the gas basins will get picked up in the oil basins. So I think we've got good visibility here for, you know, the next few months. And then beyond that, it's going to be largely a function of where commodity prices are.
spk07: Got it. And I know, obviously, you don't typically give margin guidance beyond one quarter. But I mean, with the US rig count in the low 50s, kind of reasonable to think that the drilling margins should stay at similar levels, although it would probably move around a bit.
spk04: I think with stable activity, we should be able to maintain similar margins.
spk07: Got it. And in Canada, I mean, you talked a little bit about, you know, pricing and so on and so forth. Can you kind of talk about your visibility right now for Q3, Q4 activity relative to Q1 from what you see today?
spk03: Yeah, sure can. The last couple of years, we've been able to actually exceed Q1 activity peaks in third or fourth quarter. I don't think that happens this year. But, you know, a couple of notable features about Q1 that I think do speak to the rest of the year. I think we said our peak was 79 rigs and our average was 69 rigs. To have a 69 rig average and only a 79 rig peak over the entire quarter is quite remarkable. Spring breakup came quite late. Activity stayed quite long because customers kept rigs working as long as they could. And there is a definite focus to level load. So I do expect that our super triples, once they fire back up again, once they're all fired up, they stay active for the rest of the year. whether they fire up on May 15th or April 29th or June 5th, that activity stays flat for the rest of the year. Probably a similar situation with our super singles. I think the variability will be on our tele-doubles. So I think we'll see good loading levels that start early and get to levels in that 60 plus rig range in July and then hold there for the rest of the year. Very stable loading. Our customers are focused on Try to minimize variability in this market. It's a real industrial-based market now, and that plays well into our model.
spk07: Got it. Thanks. And Kerry, on the credit facility side, once you repay the Q1 draw, you don't have much of a balance there to get through. Once you get through that, I mean, is the plan sort of to eventually call your next tranche of bonds and maybe put all or a portion of those on the credit facility?
spk04: So you're correct. We've got about 60, we'll have about $60 million Canadian left on the credit facility based on our guidance for what we're going to do in Q2. So to hit our $150 million target, it will require us to pay down that balance on the credit facility and then about another $90 million for high yield bonds. Those 26 notes are callable at the end of the year. So we'll look to likely use that for some of our debt reduction. And then If we look at where interest rates are right now, there's not a whole lot of difference between the coupon on those 26 notes or the 29 notes and what we're paying on a revolver. So there's not a big benefit to calling those bonds and putting them on the revolver right now.
spk07: Got it. Okay, that's all for me.
spk06: Thanks. I'll turn it back. One moment for our next question. Our next question comes from Luke LeBlanc with Piper Stanley. Your line is open. Hey, good afternoon.
spk05: Kevin, you talked about some possible oil project startups in the second half. Could you maybe kind of give us the order of magnitude that you're expecting there?
spk03: We have contracts to be signed early in the year for reactivations in Q3 and Q4, and those are proceeding. We've worked with our customers on that, and there's been no change in their sentiment. And those would have been at rates that were negotiated back in early Q1.
spk05: Okay. And then on the CapEx, you gave us the dollar amount of how much upgrade CapEx was coming down. But could you talk about maybe how many rates you were planning to upgrade and what those upgrade plans were that you pulled out?
spk03: Sure, we can. You know, it was an amount of money that would be targeting Some additional technology upgrades, which we may slow down on depending on market demand on additional rigs. It was targeting some third pump with generator packages that if the rig count doesn't get above 62 or 63, we probably don't need those upgrades. But if we get back to 62 or 63 rigs, we could bring that capital back into play. So it depends heavily on, like Kerry said earlier, commodity prices and market conditions.
spk04: And there were no major upgrades contemplated in that budget. Okay. Got it. I appreciate it.
spk03: It's fair to say, Luke, when that budget was put together, we were kind of targeting activity increase across the boards of industry-wide 50 rigs. And as we've taken that 50 rigs out of the mix, our piece of that, which might have been four or five or six rigs, would have needed some upgrades, minor upgrades. We've taken that capital out.
spk02: Okay. All right. Thanks a bunch.
spk06: One moment for our next question. Our next question comes from Keith Mackey with RBC. Your line is open.
spk01: Hey, thanks for taking my questions. Maybe just if we could start in Canada. Just wanted to ask about what you're seeing in heavy oil, particularly the clear water, as far as the demand for rig spec. Has that changed at all in the last, call it, one to two quarters, given some changes in how operators in the Clearwater are drilling wells, or have things and have demand remain relatively stable for the type of rig that is most desired in the Clearwater?
spk03: Really, truly a great question. The Clearwater still, early days of development, really, really a couple of years into it right now. And they're still experimenting with the length of the laterals and the number of laterals off each wellbore. So it's a great question. The wellbore configurations are evolving with time and we're keeping pace with that. And nothing right now that's changing is impacting our rig capability. I do expect the torque requirements to go up and we may need to boost the torque on some of our super singles. That's a pretty minor upgrade.
spk06: Okay, got it. Thanks for that.
spk01: Maybe just in the U.S., as far as the low 50s rig count for Q2, what really, I guess, Kevin, is driving that? Is it you have line of sight to some contracts ending that you haven't gotten new rigs or new contracts for yet, or... Or is there, in general, an increased amount of time between contracts as rig churn sort of amplifies?
spk03: Well, I'll be clear. We have visibility on one or two rigs coming down right now, so we know that. But we do expect that the industry account is going to be dropping, and we'll take a piece of that. We'll be bearing a piece of that. So I would say that there's a lot of moving pieces. I gave you the data on the rig bids we have out there right now. I remain pleasantly surprised by the volume of rig inquiries we have. So there might be some timing issues where a rig comes down in maybe late June but gets reactivated in July or August. It's really kind of hard to see how it plays out, but the visibility right now is one or two, not five or 10.
spk01: Yeah, got it. And just on the rig bids, that you have outstanding now. Can you give us a bit of an indication of how those break down by customer type, by region, et cetera?
spk03: No. In the past, I've just kind of quoted the bidding activity more as an indicator of interest. I think I've said in the past that usually about a third to a quarter of those turn into actual rig orders for us or somebody else, and we win a portion of those. We're thinking going forward that something like that, a third or a quarter, turn into real rigs over time, and that hopefully we win our share of that.
spk01: Got it. Thanks for the clarification.
spk03: I will tell you it's biased towards oil, though. No question about that.
spk01: Yeah. Yeah, fair enough.
spk06: Okay. Thank you.
spk03: Great.
spk06: Thank you. One moment for our next question. Our next question comes from Kurt Halit with the Benchmark Company. Your line is open.
spk09: Hey, good afternoon, guys.
spk02: Hi, Kurt.
spk09: Interesting, interesting dynamic at play with the prospects of pulling some rates from the U.S. back up into Canada. It's been a while since we've seen that kind of dynamic play out. So kind of curious about that, Kevin. And I know you mentioned a lot of positive dynamics underway in Canada with the pipelines and the agreement there in D.C. So I don't know how many, you know, is this just kind of a near-term event or is this something where you could potentially see some additional demand pull north of the border, even in 2024.
spk03: So, Kurt, I'll be surprised if we don't move a couple of rigs from the U.S. up to Canada or more. So I think it's going to happen. I don't think it happens inside this calendar year, but it may happen in 2024. So that's just a prognostication. It's not a forecast. But here's what's going on. So we did move two rigs up last year, and both of those are paid moves by the customer, really healthy contracts. And we also saw utilization on that same class of rig increase in the U.S. DJ Basin got a little busier and the competition for those assets increased. So right now today, I think we have two or three that aren't working in the U.S., but we have customers looking at those rigs for the U.S. for DJ Basin drilling. So there'll be a little bit of competition between Canada and the U.S. to see where those rigs best end up. There's no question that we have a market in Canada that was five or six triples short a 1.7 triple short in Q1. We're pretty certain our customers in some cases might have used a lesser performing rig to do the work. We know some work got delayed. We have excess demand for Q3 that we're trying to decide right now how to manage. The clearing price to bring one of those rigs to the US is probably $5,000 or $6,000 above leading edge rates in Canada right now. So it's still a little bit away, which is why I'm leaning towards 2024. No doubt that when LNG Canada gets fired up and they're filling the coastal gas pipeline, I think rigged demand in Canada goes up by five to seven super troubles.
spk06: Interesting.
spk03: Okay. We don't plan to build any. Yeah, I got you.
spk09: All right.
spk03: One other data point there, we did get one contract earlier we mentioned on our Q4 call to do a significant upgrade taking a DCSER rig and converting it to a super spec AC 1500 horsepower rig. We mentioned a $45,000 day rate and a four year contract. So we did do that earlier this year and that rig will get fired up in January 2024. And that's because we simply didn't have the ability to move a 1500 horsepower rig up to Canada. So if we have more opportunities for those kinds of upgrades in Canada, we'd be interested in doing it.
spk09: Okay, great. So it seems like, you know, the outlooks are kind of taking shape now for the rest of the year, and your commentary sounded very similar to one of your U.S. peers from yesterday. So basically, some weakness in natural gas basins on pricing and some I'd say stability or whatever on pricing in oil basins. Now, however, we all know, right, EPs are always going to try to use that against anybody in the oil field service industry. So is there anything in the context beyond typical friction around pricing talk going on in the U.S. that's discernible to you?
spk03: I think the fungibility of rigs kind of confuses the equity markets. It costs money to move a rig. And if a rig's going to move from the Haynesville to the Permian, that's a $700,000 rig move, and it takes a bit of time. So there is financial friction in the fungibility of rigs that the capital markets kind of ignore sometimes. It does mean that if there are – let's just make a number. Let's say there's 10 rigs loose in the Haynesville. That doesn't mean those 10 rigs compete in the Permian at leaving its rates or drive rates down because you've got to factor in that cost to bring the rig over. Whether the drilling contractor is subsidizing the move or whether the E&P is paying for the move, that cost is in the system and creates friction. So I think that's one factor that the equity investors need to think about a little bit as they risk the space. The other thing that is clearly different is the demand by investors for all of us to be disciplined and deliver strong results. I think the willingness to buy market share that might have been around in previous cycles has just gone away. I think most of us would rather show that we're disciplined in our pricing than letting the market drive down our rates. Because once the rate goes down and gets applied, it can be applied across the fleet. That's always the fear. If we remain disciplined and reject work, that supports pricing. And we need that pricing. We need to be able to earn our cost of capital and keep sustaining the productivity we're delivering, whether it's in the Montagnier in Canada or the Hainesville or the Permian Basin.
spk06: Awesome.
spk09: Appreciate the call. Thanks, Kevin.
spk02: Thank you. 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.
spk00: That concludes our conference call for today. Thank you, everyone, for joining, and have a great day.
spk02: Ladies and gentlemen, this concludes today's presentation. You may now disconnect and have a wonderful day.
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