Good day, and thank you for standing by. Welcome to the Precision Drilling Corporation 2022 Q1 results conference call and webcast. At this time, all participants are in a listen-only mode. After the speaker's presentation, there will be a question-and-answer session. To ask a question during the session, you will need to press star one on your telephone. Please be advised that today's conference is being recorded. If you require any further assistance, please press star zero. I would now like to hand the conference over to your speaker today, Carey Ford, Senior Vice President and Chief Financial Officer. Please go ahead. Thanks, Shannon. Good afternoon. Welcome to Precision Drilling's Q1 2022 earnings conference call and webcast. Participating with me today is Kevin Neveu, President and Chief Executive Officer. Precision reported its Q1 results through a press release earlier this morning. Please note that the financial results are in Canadian dollars unless otherwise indicated. Also, please note some of our comments today will refer to non-IFRS financial measures and will include forward-looking statements regarding Precision's future results and prospects, which are subject to a number of risks and uncertainties. Please see our news release and other regulatory filings for more information on financial measures, forward-looking statements and risk factors. Prior to Kevin providing an operational outlook and update, I will review our Q1 financial results. Our Q1 results reflect a very good start to the year with increase in activity, day rates, and margins, and leading edge indicators pointing to an even stronger financial results in the second half of the year. Although the Q1 business performance improved dramatically from the Q1 of 2021, our adjusted EBITDA of $37 million decreased 32% from the Q1 of 2021. The decrease in adjusted EBITDA primarily results from a $48 million share-based compensation accrual charge, without which, adjusted EBITDA would have been $ 84 million. Revenue was $ 351 million, an increase of 49% from Q1 2021. In the US, drilling activity for Precision averaged 51 rigs in Q1, an increase of six rigs from Q4, and daily operating margins in the quarter absent any turnkey or idle but contracted impact were $5,672, essentially flat from Q4 2021. The normalized margins are slightly lower than the guidance provided due to additional staffing of rigs to build hot crews and start-up costs during the quarter. For Q2, we expect normalized margins to increase approximately $1,500 per day. With repricing of spot market rigs, improved fixed cost absorption, and technology pull-through, we expect normalized margins to continue expanding through the second half of the year. In Canada, drilling activity for Precision averaged 63 rigs, an increase of 21 rigs from Q1 2021. Daily operating margins in the quarter were $8,865, an increase of $759 from Q1 2021, and $881 sequentially. Higher than guided margins were supported by higher day rates, strict cost control, and greater fixed cost absorption. Absent the CEWS's impact from the prior year, margins would have been approximately $2,000 a day higher than Q1. For Q2, we expect margins, absent of CEWS and one-time cost recoveries, to be up approximately $500 per day compared with last year due to improved pricing and fixed cost absorption. For reference, daily operating margins in Q2 2021, absent CEWS and one-time recoveries, were $5,247. Internationally, drilling activity for Precision in the current quarter averaged 6 rigs. International average day rates were $50,235, approximately $2,500 lower than the prior year due to expiration of drilling contracts. In our C&P segment, adjusted EBITDA this quarter was $ 6.5 million, down 16% compared to the prior year quarter. Adjusted EBITDA was positively impacted by 9.6% increase in well service hours and improved pricing, reflecting improved industry activity and higher demand for our services. The results for 2022 included 0 CEWS subsidy payments compared to approximately $2 million dollars of, in Q1 of last year. Of note, well abandonment work represented 16% of our operating hours in the quarter. Capital expenditures for the quarter were $ 36 million, and our full year 2022 guidance has increased from $98 million to $ 125 million, comprised of $72 million for sustaining and infrastructure and $53 million for upgrade and expansion, which relates to anticipated contracted rig upgrades and investments supporting Alpha™ technologies. As of April 28, we had an average of 41 contracts in hand for the Q2 and an average of 39 contracts for the full year 2021. We have signed 27 term contracts year to date. Moving to the balance sheet. While our Q1 results reflect negative cash flow and a revolver draw, the Q2 working capital unwind and revolver paydown is happening in real time, and we expect to pay down the majority of Q1's revolver draw by this summer. As of March 31, our long-term debt position net of cash was approximately $ 1.2 billion, and our total liquidity position was over $ 430 million, excluding letters of credit. Our net debt to trailing twelve-month EBITDA ratio is approximately 6.7 times, and average cost of debt is 6.3%. We expect our net debt to adjusted EBITDA before share-based compensation expense to be closer to 3 times by year-end and to decline further into 2023 toward our goal of below 1.5 times. We remain in compliance with all of our credit facility covenants in the Q1 with an EBITDA to interest coverage ratio of 2.7 times. We are committed to reducing debt by over $ 400 million between 2022 and 2025 and allocating 10%-20% of free cash flow before principal payments directly to shareholders. Our debt reduction target for 2022 is $ 75 million. For 2022, we expect to generate free cash flow through operations, expect to benefit from working capital release in Q2 with lower activity during Canadian spring breakup and to catch up with customer collections. From year-end 2021 to year-end 2022, we expect working capital to build by approximately $50 million or $40 million lower than the build we incurred in Q1. Our guidance for 2022 remains the same for depreciation at approximately $ 270 million and SG&A at $65 million-$75 million to $70 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 our effective tax rate to be approximately 5%. That concludes my opening comments. I'll hand the call over to Kevin. Thank you, Carey, and good afternoon. As Carey mentioned earlier, customer demand for our high-performance, high-value services is strong and continues to grow. We're seeing this strength in all our business segments and all our geographies. Our fleet utilization continues to improve and the rates we charge for our services are likewise responding. This is most evident in the lower 48, where the tightening supply of Super Triple rigs became apparent to our customers and led to a step change in rig rates late in the quarter. Leading edge rates, excluding Alpha for our ST-1500 rigs equipped to drill long-reach horizontal wells, have trended into the low $30,000 per day range. The customers have been willing to sign term contracts at these higher rates to secure access to the rigs over the course of the next six to 12 months, and in some cases longer. There's no question that the customers have a rising sense of urgency as they expect high-spec rig shortages later this year. Since our last conference call, we've added 19 term contracts, with a handful of those signed most recently at leading edge rates I mentioned earlier. Today, we have 55 rigs operating in the United States, up from 48 at the beginning of the year. With our contracted rig activations and further ongoing customer negotiations, we see a path to continue this growth trajectory through the year, and our visibility into 2023 is taking shape. Turning to Canada. For the Q1, we experienced strong customer demand matching 2018 activity levels. Importantly, our customers extended the winter drilling programs well into the traditional spring breakup period, driving Q1 activity up almost 50% from last year. Even today, in the midst of spring breakup, we have 33 rigs operating compared to 21 this time last year, continuing the trend. Our customer discussions and bookings point to a strong second half, which will be starting almost a month early with several rig activations scheduled for as soon as the first week of May and ramping up from there. We expect Q3 activity will surpass the winter season for only the second time in memory, and this will be the busiest second half since 2014. As I mentioned in our Q1 call, customer demand for rigs in the heavy oil play, known as the Clearwater and Marten Hills, is gaining momentum. We see strong demand for Precision's unique Super Single rig, and particularly our pad-walking Super Singles, which we expect will be fully utilized this summer and through the fall. SAGD and other conventional heavy oil demand is also strong and will drive our Super Single utilization to its highest level since 2014. I remind you that our Canadian fleet includes 55 Super Single rigs. Our Canadian pad-equipped Super Triples are also fully booked for the balance of the year as the Montney and Deep Basin natural gas activity remains strong. While we did see some rigs relocate from the BC side to Alberta due to the Blueberry River First Nations ruling, we have indications from our customers that BC could see rig activity rebound later this year and into next, putting further demand on the Super Triples. This is a very tight market with strong customer demand and limited rig supply. In Canada, we began the process of implementing cost and price increases over a year ago, but customer resistance has been challenging. For many of our customers, rate discussions we are having today after several years of weak industry demand is uncharted territory. These customer pricing discussions are continuing as we seek to reprice rigs for the second half of 2022. During the Q1 we rejected several opportunities to reactivate rigs due to lower than desired customer rate expectations. The best pricing signal we can send our customers is rejecting work at rates below our required thresholds. Over the last 12 years in Canada, Precision has invested in 28 Super Triple rigs, 25 Super Single rigs, and our $40 million Nisku Technology Center with a fully functioning advanced technology training rig. We've equipped those Super Triple rigs with Alpha automation. We trained over 50 Alpha expert drillers and 30 Alpha expert rig managers. With these assets, technologies, and people, Precision delivers the safest, fastest, most cost-effective, and best quality wells our Canadian customers have ever drilled. The value proposition we offer today is vastly better than any prior rebound cycle, and I fully expect to generate the returns from these investments that our investors deserve. In Kuwait and Saudi Arabia, we also see a rapidly improving market. As I mentioned in the press release, all three active rigs in Saudi Arabia have been renewed for a five-year period with pricing and margins consistent with the prior contract. In Kuwait, the rig tender we have been anticipating for several months was released late in the Q1. This will be a typically extended process involving several months of tendering and contracting steps. The tender includes requirements for several classes of rigs and multiple quantities. Our three idle Kuwait super-spec rigs perfectly meet the complex requirements for the deep drilling rig classes. We believe we'll have an excellent opportunity to contract our idle rigs for activation later this year. However, the rig deployment timing will be fully dependent on our customer scheduling. Precision's technology offerings, including Alpha Digital Solutions and a recently introduced EverGreen Environmental Solutions, continue to demonstrate strong customer appeal. Over half our Super Triples are now equipped with Alpha Automation, and all Alpha rigs currently deployed are earning commercial revenues. Precision's Alpha library continues to grow with 18 commercial apps and our Alpha optimization advisory service gaining a strong customer following. Precision's EverGreen battery energy storage system and our fuel and emissions monitoring app are both commercially deployed on several rigs, and we expect these products will continue to gain broad customer appeal as our customers look to reduce GHG emissions. Interestingly, several EverGreen product solutions have a negative green cost premium in that the energy cost savings generated utilizing the EverGreen solution exceeds the price premium we charge, a highly favorable outcome for an energy transition solution. This, of course, encourages our customer to continue down the path to net zero. We mentioned in our press release the deployment of an EverGreen electric grid powered rig to the Ithaca campus of Cornell University. This is an exciting geothermal project to explore the opportunity for Earth Source Heat as a zero emissions heating source for the Cornell University. We're thrilled to be part of this DOE-funded project and look forward to helping de-risk this zero emission energy opportunity. Precision's well servicing segment continued the pace that began last year with strong Q1 activity up 8% from last year over the same period. With 28 service rigs operating today, we're continuing this trend. Our team is very effectively managing the material cost inflation and fuel cost increases we've experienced. However, the labor challenge has proven much more difficult and is limiting industry well service activity. During the Q1 alone, we experienced demand anywhere from 10-20 rigs greater than our ability to crew rigs. We have substantially increased our recruiting efforts, and with the recently announced hourly labor rate increases, we expect to narrow the rig supply gap as the year progresses. Overall, this business is performing exceedingly well. Our teams worked well to increase rig rates appropriately, and we expect to continue to generate strong cash flows. I'll conclude by thanking all the employees of Precision Drilling for their hard work, their strong safety performance, and the excellent results they produce for our stakeholders. I'll now turn the call back to the operator for questions. Thank you. As a reminder, to ask a question, you will need to press star one on your telephone. To withdraw your question, press the pound key. Please stand by while we compile the Q&A roster. Our first question comes from Taylor Zurcher with Tudor, Pickering, Holt & Co. Your line is open. Hey, Kevin and Carey. Thanks for taking my question. First one's on pricing within the U.S. market. Kevin, I think I heard you say leading edge rates for some of the higher end rigs in the low $30s, excluding Alpha. You know, add Alpha, and you're getting pretty close to the mid-$30s on a leading edge basis. Man, what a difference a couple of years makes. My question is if, you know, against that pricing backdrop, assuming the market stays tight through 2023, which it likely will, you know, is there any reason why your fleet in the U.S. isn't generating mid-teens type daily margins, excluding turnkey and other lumpy items, at some point in 2023? Hey, Taylor. This is Carey. I'd say that you could see a portion of the fleet generate that type of margin. Remember that our operating costs have moved up about $2,000-$2,500 per day. The $30,000 or $31,000 or $32,000 day rate of today is similar to a $28,000 or $29,000 day rate from 2018, which is where we saw day rates get to kind of the last upcycle. When you tack on AlphaAutomation, you would be getting to margins kind of in the low- to mid-teens. Okay, got it. I had a follow-up there. Yeah, go ahead. I'll just add to that for a moment. I think that, we don't expect day rates to stabilize in this range. We think if the supply stays tight, repricing opportunities as the year progresses could see day rates move further yet. Wow, that's encouraging. Okay, a follow-up there. Carey, you were talking a little bit about the cost structure. In the press release, you were talking about how you've oversized some crews to prepare for the activity ramp here in 2022. I'm just curious. I mean, as I look at it sounds like those crew sizes will probably naturally go back to more normalized levels moving forward as more rigs go back to work, such that you know, what's been a cost headwind for you over the past couple quarters might turn the other way. I'm just curious if I'm reading that correctly. It will turn the other way, but I wanna stress the magnitude of it. You know, we got it to a $500 per day increase in margins from Q4 to Q1 in the US, and we delivered flat margins. The reason why was about half of that would have been the overcrewing of rigs, so-called, you know, trying to create hot crews, and the other half of that would have been just startup costs. You know, we activated three or four rigs in Q1 and we experienced startup costs in the $ 200 thousand-$ 250 thousand per rig. I think not having those extra crew members will reduce operating costs a little bit, but it's just gonna be $ 200 a day. Awesome. Thanks for the answers. Thank you. Our next question comes from Aaron MacNeil with TD Securities. Your line is open. Afternoon. Thanks for taking my questions. I know the 1,500s always seem to attract the headlines, but there's been a good pickup in some of the U.S. plays that have historically been well suited for the 1,200 horsepower triples. I'm wondering if you could maybe just give us a sense of how utilization and pricing has trended for that asset class. Aaron, it's Kevin. The trend of those rigs is kind of similar to the 1,500s, you know, recognizing it's a little less expensive rig to operate, a little smaller rig. It's trending along the same direction, not quite as tight on the supply side as the 1,500s. You know, we're not seeing day rates that are approaching $ 30,000 yet, but we're certainly getting into that mid-20,000s range for those rigs, which we're pretty happy with. You know, most of those rigs also have Alpha on top and the opportunity to add Alpha if they don't have Alpha equipped right now. I think the utilization of those rigs, we've got 88 in our fleet, and I believe we've got about 12 working right now. We're moving up into that 70%-80% utilization level, which will give us more pricing power over time. I'll kind of remind you that we did bring one of those rigs up to Canada last year, when the market was looking pretty strong in Canada. I'm not sure we'd do that again. I think that the output in the US or the opportunities in the US might look better over time. Certainly, when you factor in the exchange rates and the rates in the U.S. right now, I think that we could see those rigs fully utilized later this year. Okay. Understood. I certainly noted the comments on the 19 new contracts, leading edge day rates and durations of, I think you said six-12 months, Kevin. You know, with rates where they are, I mean, doesn't the conversation start to turn to whether you can lock in those high prices into longer term contracts, or, you know, do you have to have a major upgrade to see a multi-year contract? You know, I'd say that there's still a fair amount of caution kind of on all sides of the energy industry right now, not wanting to get over our skis, not wanting to commit to too much. While we do have some customers looking out beyond 12 months, and we've signed a couple contracts beyond 12 months, I'd say that there's still a fair amount of just carrying caution around, again, not making huge capital commitments, not making huge contract commitments that might extend out kind of too far in the future. I just read it as capital discipline is still quite important across the E&P space, and certainly it is for us. That certainly is holding back customers from contracting into years where their budgets aren't approved yet. Okay. Understood. Maybe if you'll indulge me, I'll sneak one more in. You know, I can appreciate that there might be some reluctance to reverse course on your capital allocation firm framework that you announced in January, but the stock's nearly doubled since that time. I guess the question is, would it not make more sense to just continue to focus on debt reduction for the time being? Yeah. Aaron, I think we put a four-year capital allocation plan in place so that we have a little bit of flexibility to manage through the cycles, both with needs for cash like we experienced in the Q1 when we're building working capital and spending some CapEx. Then also to where we can kind of pick and choose our times to buy back shares. We're, as we said on the press release and my opening comments, that plan is in place. We would like to continue to execute on that plan, but it's not gonna be a, you know, it's not gonna be the same capital allocation every quarter over the next four years. Okay. Thanks. I appreciate that. I'll turn it over. Thanks, Aaron. Our next question comes from Waqar Syed with ATB. Your line is open. Thanks for taking my question. Kevin, you announced some developments on the geothermal front, and one of your competitors also announced today some investments in geothermal. You know, it could be a coincidence, or is there some acceleration in geothermal developments that you're seeing, or is it still kind of the same kind of growth rate? Just want to see what, you know, whether there's something going on behind the scenes of acceleration in demand for geothermal. Certainly I think that 2022 will be much busier than 2021 on the geothermal front, and probably 2023 is gonna be busier than 2022. I mean, we're in a world which is putting a lot of capital towards energy transition right now, and I think geothermal is one of those solutions that's gonna be part of the energy transition mix. You know, short answer is certainly rising levels of interest. Nothing remotely close to displacing rig activity on the oil and gas side yet, but I think you know, having involvement in these projects is important. You know, it's important from showing we're doing our part perspective, but it's also important because I think there will be some solutions here. I'm a big believer that using geothermal just for heat, not for power conversion or for steam, but using it as a heating source might be an economic solution. We're quite excited about this Ithaca project I mentioned on campus. Okay. In the U.S., where do you expect your active rig count to be, you know, by the end of the year? You know, Waqar, a little hard to say, but if you kind of project forward the growth we've had so far, we'd be probably getting, you know, close to 60 by the end of the Q2. You know, maybe hitting 60, maybe not quite hitting 60. I could see us, with what I see right now today, probably having that go up by another five rigs a quarter for the second half of the year, assuming the customer interest we see today remains and the macro stays in place. I hate to have to qualify every forecast these days, but it seems like as soon as I make a comment on a forecast, there's some major macro change. Yeah. Yeah. You know, in terms of your operating costs, labor costs and all, do you see upward pressures still going forward? Do you think for this year at least, you've captured the inflation from labor perspective? I would say, and I'll let Carey confirm my opinion. I'd say that between kind of rising absorption as we get more rigs active and I think a kind of leveling probably of our crew salaries and things like that, you know, we might have seen the peak of inflation that might be managed and under control at this point. Carey, do you have any comments there? Just that if there are further wage increases in the year, they'll be passed through within the contract. Okay. Well, I think the one thing that really kind of helps the drilling industry out is that, in the drilling industry, we're not building, and don't plan to build, and don't see any opportunity and any reason to even think about building new rigs. If there was a build cycle going on, that would cause all kinds of supply chain issues. We're just operating a rig fleet, which is still operating at activity levels lower than most of the past 10 years. Supply chains are pretty good. You know, I think inflation is under control. I don't see a lot of things on the rise right now that are gonna impact rig operations in a meaningful way. Now if we're wrong, we'll be again pushing prices upwards. I think we're ready. We've got a contract book that allows us and gives us flexibility to reprice rigs at whatever the market cost is at the time. Yeah, to the same, let me ask you on that, like, you know, you know, in terms of getting engines or mud pumps, things like that, for reactivation or just for replacement on existing fleets, you're not seeing any issues at all in getting that? What kind of, you know, inflation are you seeing on equipment? I haven't actually checked the price of a new engine recently, and I know Caterpillar, one of the largest suppliers is suffering some inflation. Unless we get into some kind of major upgrade program, I just don't see us out there, buying large numbers of engines. Yeah. I think that we've got a fleet of rigs right now that in this environment and what we see going forward, that our normal maintenance procedures and repairs and upgrades on engines will handle within our current inventories. Okay, great. Thank you very much. On the mud pump front, you know, if we were to upgrade 5 more rigs, that's 5 mud pumps. That's a drop in the bucket. Yeah, absolutely. Thank you, sir. Thank you, Waqar Syed. Our next question comes from John Gibson with BMO Capital Markets. Your line is open. Thanks, guys. Just in terms of leading-edge rates, I'm just wondering how do they compare to prior peaks? Maybe if you could walk through how cost compares as well. I guess what I'm trying to get at is net how profitable are leading-edge rates right now relative to prior upturns, and I guess where could they get to moving forward? Carey Ford, why don't you start and I'll just come in behind. Yeah, sure. I think when we had prior peaks in, call it, 2014 or 2018, 2017, 2018, rigs got to $28,000 or $29,000 a day. You had an operating cost of right around $14,000 in those time periods. You had a 50% field margin. Right now operating costs with wage increases and a little bit higher cost of operating the rig, operating costs are gonna be in the $16,000-$16,500. If you're assuming a 50% margin, you're gonna be at $32,000-$33,000 a day. I think that's, they're comparable. The top line looks a lot different, but on the margin from a dollar standpoint, they're pretty comparable, and from a margin percentage standpoint, they're almost exactly comparable. I guess moving forward then, if we do see a bit of a bump in rates, is it fair to assume that, you know, you could get above that 50% field margin or even significantly above it? I think it's possible. I think when you add technology and some of the things that will move outside the contract or have already moved outside the contract, I think margins are gonna have a little bit more runway. What I would say is that I think we've hit these rates quite early and the market's changed from the last peak. It's changed in that really the only rigs that are gonna be drilling on these types of large well, you know, development type pads are going to be super-spec rigs. You're not seeing any drag from non-super-spec rigs on the rates. Got it. Thanks. You know, back in 2014, it wasn't a perfect market when it came to super-spec. Today it is. Fair enough. And last one for me. Last call you talked about having somewhere in the range of, you know, 200 bid requests in the U.S. If we fast forward a few months, obviously the world's changed. What are bidding inquiries like today in the U.S? Have these bid requests largely translated into new rig additions better or worse than you expected a few months ago? This is not a non-GAAP metric. I say that jokingly. The bid book hasn't declined in size. I'd say that the hit rate is starting to increase modestly. Fair enough. Thanks a lot for the color. Turn it back. Great. Thanks a lot, John. Our next question comes from Cole Pereira with Stifel. Your line is open. Hi, everyone. Just wanted to go back to day rates from a spot market versus contract perspective. At a high level, so for example, if leading edge day rates are $30,000 a day in the spot market right now, I mean, is there sort of a rule or anything or how we should be thinking about what it would pay to contract that rig for six months or something like that? I'm just trying to think about the discount between the spot and locking in rigs. Cole, I think that there's, you know, really zero discount from a strategy standpoint with our pricing. There might be a discount tied to a customer if they've got multiple rigs or, you know, they were with us back in 2020 when it was quite slow. From a conversion of spot to term, I wouldn't view that as a reason to discount a price to a customer. Okay, perfect. No, that's helpful. Maybe coming back to some of the questions about 2023 revenue per day and margin. I mean, if leading edge day rates stay in the low $ 30,000 a day, I mean, as you get some of the churn through your contracting, is it reasonable to think we could see that reported day rate hit $ 30,000 a day sometime in 2023, or would it probably be, you know, high 20s? I know you don't give guidance, so I'm just trying to sort of feel out the differences there. I'll make a couple comments and let Carey kind of pipe in whenever he wants to here. But I'd say that I do expect most rigs of this class to be trending into that range as they reprice over time. You know, we won't get a full price on every single repricing opportunity. There's certain reasons why we might do it in one or two steps over a period of time. But I do think that if you're looking a year out from now, I'd expect the leading edge rates probably will have moved up, and the average rate will have moved up quite a bit. It's likely you could see the average rate in the $ 30,000 range, and leading rates could be higher than that yet. The momentum on rates hasn't really backed off yet because we're into real tight days with rigs right now. Okay, great. That's helpful. Thanks. Last comment. You know, I just. Go ahead. Cole, I have a couple comments on that. I think that the term I'm gonna use for Precision, I think you'll hear it from most of the public drillers is that we are extremely disciplined around our capital returns right now, whether it's investing in an upgrade on the rig or whether it's trying to get the returns for the rigs we have right now that are already out there in the field. I think the discipline that we're seeing in the marketplace right now is likely the best I've seen in my career, which is almost 40 years now. You've got large public drillers in both markets, Canada and the U.S., that are highly focused on generating returns for their shareholders as our customers have been. I think that discipline is not gonna weaken as time goes forward. It's gonna firm up. Yeah, I would just add maybe what's causing a little bit of uncertainty of where the rates will stop when they rise is the replacement cost of these rigs is much higher today than what they were originally built for. So the rates that made the economics go around and when the rig was built, you know, it's with kind of the infrastructure to build new rigs not really being in place and commodity price inflation and labor inflation, the replacement cost would just be significantly higher than it would have been in 2014 and 2015. Okay, great. That makes sense. Thanks. Turning to drill pipe, I mean, a lot of commentary from some of your peers on that, talking about one-year lead times. I mean, just out of curiosity, how much, call it, months of inventory do you typically keep on hand? You might recall that last conference call, we talked about a drill pipe order we placed last August. We just had a bit of a sense of this shortage or tightness to the market coming. We certainly didn't expect what's been the tragedy that's been going on in the Ukraine right now and that impacting steel. But we did get ahead of this a bit. We did make a large purchase last year of inventory drill pipe, so there was zero lead time on that. We took delivery of that in the third and Q4 of last year. As we began taking those deliveries, we placed additional orders in the Q4. We placed additional orders for pipe in the first and Q2 of this year. We think we're dancing kind of ahead of that one-year lead time that you've heard about, talked about in some other calls over the last few days. I think that we've got the pipe we need to run our business. Okay, great. That's helpful. Thanks. Just out of curiosity, I mean, any instances, whether in Canada or the U.S., where you've seen the inability of an E&P to get casing impact any of your drilling operations? Cole, we've seen that mainly with small operators that are, you know, kind of drilling well to well and not able to plan or buy in volume. With the larger players who, like us, have placed orders in advance and had a sense of these things coming, we have not seen that creep up. You know, we have a small turnkey business, which is part of our disclosure this period, and we see some of the challenges getting casing. Typically, what we're drilling in turnkey tends to be bigger bore wells, deeper gas wells in the Gulf Coast region, where the shortages are a little less pronounced than the common, more common sizes being used for oil and gas right now. Okay, got it. If I wanted to qualify your comments, fair to say that certain customers are having that issue, but it's not material at a larger scale. Is that fair? Certainly not material at a larger scale for our activity right now. Could be plus or minus one rig. I mean, we don't have the visibility on what our customers are buying for casing. I'd also say that I think it's gonna be short-lived. I think that there's an opportunity here for the pipe companies to get things fired up to make probably some pretty good margins. You know, while there might be a lag of a couple of quarters, I think they'll catch up. Okay. Great. That's all for me. Thanks. I'll turn it back. Thanks. Thanks. Our next question comes from Keith MacKey with RBC Capital Markets. Your line is open. Hi. Thanks for taking my questions. Hi, Keith. Hey, I just wanted to, Kevin, go back to some of your comments about Canada shaping up to be the second busiest second half since 2014, though, you know, customers are still trying to grind you on rates, it sounds like. Can you just maybe walk through how the discussions are going? You know, what realities you're kind of trying to bring into the conversation with customers? And then what that ultimately means, do you think, for your second half cash margins? I know, you know, the rig mix is quite a bit different than it would have been in 2014, but you would have had much higher cash margins back in those days. Maybe a lot to unpack there, but any commentary on that would be helpful. Sure, Keith, and it's actually a pretty insightful question. You know, our customers have worked really hard over the past several years in Canada, going back to 2014, to really fine-tune their cost base structure to become as efficient as they've become. They've taken the whole notion of capital discipline deep to heart, and they've restructured their businesses to deliver capital discipline to their investors. Part of that was, you know, getting very aggressive on the costing side, getting very aggressive on the contracting side, and institutionalizing that. They've done a great job with that, and, you know, their investors should be very proud of the work the E&Ps have done managing their costs. They've done that in an environment where rig demand was weak and often declining. I you know, managing that capital discipline in a market where rig demand is increasing, and in fact, in some areas, rig demand exceeds supply, I think is something they need to get up to speed on. We're trying to help them get up to speed on that. We're certainly working to demonstrate the efficiency of the rigs. I kind of went through a litany of the things we've done since that last cycle around improving our rigs with super-spec rigs, with Alpha on the rigs and training our guys to run it and execute it very well. There's no question we're delivering a much better value proposition than we were back in that previous peak, and I think it's our job to help our customers understand that and recognize they need to pay more for it. You know, you've got these two competing forces. We've invested in the rigs and our people and have a higher value proposition. They've worked really hard to lower their costs and manage down in a very soft market. You know, ultimately, market dynamics play out here, and supply and demand works, and I expect rates will move up. Got it. No, that's helpful. And then just secondly, turning to the U.S., if you talk about, you know, 60-ish rigs by the end of Q2 and then adding five per quarter in the second half, would you expect your maybe basin mix in the US to stay roughly the same, or can you see that changing from current levels if we think about those as, you know, 45% or so Permian, maybe 25% Haynesville? And then I know there's some Northeast in there, which is maybe a little bit more constrained takeaway capacity-wise than some of the other areas. But just curious if you can help us kind of walk through where you expect to see some of those rig additions. I'd say probably focused more towards oil, more towards the Permian. Quite surprisingly, one of the contracts we signed recently includes customer paying for a mobilization of a rig from, Carey, remind me, the rig's coming out of. I think it's Wyoming, maybe. Wyoming or Colorado, and moving back to the Marcellus. That's an expensive move. You couple that move cost with the day rates that we're able to achieve right now, and that's a pretty meaningful move back to the Marcellus. You know, I'm surprised by that, but we do see a lot of strength in the Permian. Yeah, we're also seeing a few more rig contracts signed recently for the Eagle Ford. Yep. Got it. Very good. Just finally, maybe circling back to one of the other questions, how protected are you from a you know standby fee perspective or anything like that, you know, if rigs see delays that are you know caused by customer supply chain issues? Is that you know is there fees written into the contracts that kind of give you some protection, or has the market not been there? On every term contract rig, Canada or U.S., they're take or pay contracts. Either take it and use it or they'll pay a standby fee. If it's a well-to-well rig, once that well completes, it might be looking for work somewhere else. Got it. Okay. Thanks very much. That's it for me. Great. Thanks a lot, Keith. As a reminder, to ask a question at this time, please press star then one. Our next question comes from Josef Schachter with Schachter Energy. Your line is open. Good afternoon, everyone, and thanks for taking my call. Carey, you mentioned replacement cost of the rigs are much higher. Can you, if you're doing a Super Triple with all the Alpha products hooked up, what would be the cost to create a new rig right now, just to get an idea of where that number has to go to? Yeah. We haven't priced this out. You know, but I can tell you what it was in 2014 and 2015. We were building Super Triple 1500 AC rigs for about $ 20 million. Then over the next few years, we started upgrading them with walking systems and higher pumping capacity, higher racking capacity, Alpha automation. You probably get to a $25 million asset in those 2014 and 2015 dollars. You can look at what's happened with wages and copper prices and steel prices over time. You know, over the last seven or eight years. Then also look at the fact that we're building 20 rigs a year during that time period. We really had an assembly line style process to construct these rigs, and those assembly lines and supply chains just aren't there. It's, you know, not gonna be 20% or 30% higher. It's gonna be significantly higher than it would have been back in 2014 and 2015. Are we looking at $40 million or more? It could be in that price range. Yep. You know, if we get back into a production build cycle, it might save a few percentage points, but you know, you're not gonna take kind of a $40 million rate and make it $30 million by running back into production. It's gonna be a lot more expensive. I think you're thinking about it the right way. Yeah. If you take a rig that's parked right now and upgrade it to, you know, to meet the standards that are needed in the Permian or the Montney, are we talking about $5 million, $10 million? What would the kind of number be, and how long would it take to take a rig that's been parked and get it ready to be used in the industry? Josef, we have about 12-15 rigs that we call Super Triples, but they're not AC Super Triples. They're DC SCR Super Triples. They've got a lot of the features we have on our Super Triples, but they have a kind of an analog power system, which is referred to as an SCR rig. To convert those to digital AC rigs and capture all the other bells and whistles, probably in the $10 million range, maybe $10-$12 million for those rigs. We could convert some of our DC SCR Super Triples to AC digital Super Triples, probably on the average of around $10-$12 million per rig. Okay. There's a limited number of them. Yeah, we have 12 of those in our U.S. fleet. Okay. If we're looking at with more optimism that, you know, as you mentioned earlier, the lead rates in the States are getting into the thirties, and if you might need to have more money in for CapEx, wouldn't it be something. Again, I'm an accountant who's, you know, I've gone through these cycles. Wouldn't it be, you know, given the stock's gone up 10 times or 12 times from the low of two years ago, wouldn't it make sense to raise some equity here, 2 to 3 million shares, get yourself a pristine, strong balance sheet, and then have the ability to talk to the customer saying, "Look, you want us to build you a rig, you know, you gotta pay us." And they'll see that they can't beat you up because you have such a strong balance sheet. Yeah, I would say that we see no need to raise equity, you know, mainly because we've got all the assets that we need. We talk about one of our priorities this year is maximizing operating leverage, and that's getting all the assets we have to work and pushing day rates on those. That's where we see the biggest growth in EBITDA for our business. Then we look at the cash flow of the business, the outlook for second half of this year and into 2023. The cash flows are gonna be very strong and can fund any kind of CapEx needs that we think that will come before us, along with paying down debt and repurchasing shares. I think that, you know, for the funding needs, the business will fund itself. In terms of needing to build any new rigs, we don't see a need to do that. The day rates required, you know, if we're talking about a build cost being, you know, significantly higher, the day rates would need to be, you know, maybe 30% higher than where leading-edge rates are today. I don't think the market's right. The market isn't there to fund the day rates are not high enough to economically fund a new build. We don't think that we'll see any in the industry for a period of time. Okay. Last one for me. You've had the nice pickup in the margin in Canada, as you mentioned, $ 8,865 up from, you know, $ 8,106 a year ago and, you know, $ 8,013 in Q4. Do you see Canada getting to $ 10,000 earlier, margin, you know, Canadian dollars and of course, we're gonna see $10,000 US, Canada reaching a $10,000 dollar number before the U.S.? It's certainly possible for both markets, you know, by late this year, early next year. It's hard to say, Canada's closer now. It's the rig mix. You know, if we've got all of our Super Triples fully utilized, we've got rates going up on that segment of the fleet, but then we'll be reactivating a lot more Super Singles, and the margins there are just a little bit lower than the Super Triples. We'll see how that mix plays out. I think they're both on track to reach those margin levels, both the U.S. and Canada. Okay. Thank you very much. Thanks for taking my questions. Thank you. Thank you. I'm currently showing no further questions. At this time I'd like to turn the call back over to Carey Ford for closing remarks. Thank you, everybody, for joining our Q1 2022 conference call. Appreciate your time today, and we look forward to talking to you again in July. This concludes today's conference call. Thank you for participating. You may now disconnect.