Ladies and gentlemen, thank you for standing by, and welcome to the Precision Drilling Corporation 2021 first quarter results conference call and webcast. At this time, all participants lines are in 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, Dustin Honing, Director of Investor Relations and Corporate Development. Thank you. Please go ahead, sir. Thank you, Denise, and good afternoon, everyone. Welcome to Precision Drilling's first quarter 2021 earnings conference call and webcast. Participating today on the call with me are Kevin Neveu, President and Chief Executive Officer, and Carey Ford, Senior Vice President and Chief Financial Officer. Through our news release earlier today, Precision reported its first quarter 2021 results. Please note that these financial figures are in Canadian dollars unless otherwise indicated. Some of our comments today will refer to non-IFRS financial measures such as EBITDA and operating earnings. Our comments will also include forward-looking statements regarding Precision's future results and prospects, which are subject to certain risks and uncertainties. Please see our news release and other regulatory filings for more information on financial measures, forward-looking statements, and these risk factors. Carey will begin today's call by discussing first quarter financial results. Kevin will then follow by providing an operational update and outlook. With that, I'll turn it to you, Carey. Thank you, Dustin. Our first quarter Adjusted EBITDA of CAD 55 million decreased 47% from the first quarter of 2020. The decrease in Adjusted EBITDA primarily results from a decrease in drilling activity in all regions. Also included in Adjusted EBITDA during the quarter is CAD 11 million in share-based compensation expense and CAD 9 million in CEWS assistance payments. As a reminder, the CEWS program supports employment in Canada. Precision has utilized this program to preserve jobs within our organization. We applaud the Canadian federal government for this program and its impact on supporting employment during the pandemic. The recent Canadian federal government budget that was presented included a proposal to extend the CEWS program beyond its current June expiration. We will provide additional guidance on how the program will affect Precision when details firm up. For now, we expect the Precision impact to be greater than what we communicated in February. In the U.S., drilling activity for Precision averaged 33 rigs in Q1, an increase of seven rigs from Q4. Daily operating margins in the quarter were $7,027, a decrease of $4,131 from Q4. The decrease in margins is primarily due to lower idle but contracted revenue earned during Q1 this year, higher operating costs driven by startup costs relating to 12 rigs activated year to date, and turnkey activity. Absent impacts from idle contracted rigs and turnkey, daily operating margins would have been $1,217 lower than Q4, with the balance of the difference driven mostly by lower day rates and start-up costs. For Q2, we expect start-up costs and turnkey activity to continue, along with no IBC revenue, such that normalized margins, absent turnkey and IBC, will decrease between CAD 500 and CAD 750 per day. I'll make a few comments on start-up costs in the U.S. In 2018, our peak activity reached 82 rigs in November and activity troughed at 19 rigs in September last year. During that 22-month period, over 60 rigs were stacked and preserved in good condition to be reactivated at a later date. Precision had 57 rigs working in March of last year, and substantially all of the rigs we have reactivated since the trough last year were working in the first part of 2020. Activating those rigs require us to incur some operating costs to cold start rig crews, inspect and certify critical components such as top drives and engines, restock consumables, and sometimes mobilize the rig or rig components. We have found the average cost to activate each rig has been approximately CAD 150,000-CAD 200,000. Some of these costs are incurred before the rig goes to work, and some of it is incurred in the first few months of operations. We expect this level of start-up costs to continue as we add the next 25-30 rigs in our US fleet. In Canada, drilling activity for Precision averaged 42 rigs in the quarter, a decrease of 21 rigs from the first quarter of 2020. Daily operating margins in the quarter were CAD 8,106, an increase of CAD 901 from Q1 2020. Margins were supported by a strict focus on operating costs and CEWS assistance, offsetting lower fixed cost absorption. Absent the CEWS impact, margins would have been CAD 6,760 or CAD 445 lower than Q1 last year. For Q2, we expect margins absent of CEWS and one-time recoveries to be up CAD 500-CAD 1,000 per day compared with last year due to cost reduction initiatives, higher fixed cost absorption from increased activity. For reference, daily operating margins in Q2 2020, absent CEWS and one-time recoveries, were approximately CAD 4,000. Internationally, drilling activity for Precision in the current quarter averaged six rigs. International average day rates were $52,744, down approximately $1,500 per day from the prior year. This was due to rig mix and lower rig move revenue. In our C&P segment, Adjusted EBITDA this quarter was CAD 7.8 million, a 140% increase from the prior year quarter. Adjusted EBITDA was positively impacted by a 2% increase in well service hours, reflecting improved industry activity, lower cost structure, CEWS program support, and CAD 2.3 million in restructuring charges in the prior year quarter. Well abandonment work in the first quarter of this year represented approximately 15% of our operating hours. Capital expenditures for the quarter were CAD 8 million, and our full year 2021 guidance remains CAD 54 million, comprised of CAD 38 million for sustaining infrastructure and CAD 16 million for upgrade and expansion, which relates to anticipated investments supporting Alpha technologies and contracted customer upgrades. As of April 21st, we had an average of 36 contracts in hand for the second quarter and an average of 31 contracts for the full year 2021. Moving to the balance sheet, we continued to reduce both absolute and net debt levels primarily through free cash flow generation. As of March 31st, our long-term debt position net of cash was approximately CAD 1.1 billion, and our total liquidity position was approximately CAD 700 million, excluding letters of credit. Our net debt to trailing 12-month EBITDA ratio is approximately 5.2 times, and average cost of debt is 6.6%. We remain in compliance with all of our credit facility covenants in the first quarter, with an EBITDA interest coverage ratio of 2.1 times. During the quarter, we reduced total debt by CAD 29 million and made an additional CAD 22 million debt reduction subsequent to the quarter end, totaling CAD 51 million debt reduction year-to-date, over halfway to meeting our debt-reduction target range of CAD 100 million-CAD 125 million for this year. Our capital allocation program remains substantially weighted to debt reduction, and we remain on track to meet or exceed our 2021 debt reduction target and our long term debt reduction target of CAD 800 million between 2018 and 2022, where we have already reduced debt by CAD 601 million since the beginning of 2018. For 2021, we expect to continue generating free cash flow through operations. We expect some benefit from working capital release in Q2 with lower activity during the Canadian spring breakup after a CAD 18 million working capital build in Q1. For reference, the working capital build since our trough in Q3 2020 has been approximately CAD 44 million, which has been driven by higher activity. For 2021, our guidance for depreciation, SG&A, and interest expense remains unchanged at CAD 290 million, CAD 55 million before share-based compensation expense, and CAD 85 million respectively for the year. We expect cash taxes to remain low and our effective tax rate to be in the 5%-10% range. One of note, as a result of the previously reported change in our accounting treatment for a portion of our share-based compensation plans from equity settled to cash settled, we incurred an additional charge of CAD 2 million in the quarter as a result of our increased stock price. This treatment of share-based compensation change will lower future equity dilution and will introduce a bit more volatility in reported share-based compensation expense in the future. With that, I will now turn the call over to Kevin. Thank you, Carey, good afternoon. We're in the midst of a strong drilling services recovery cycle coming off the collapse of 2020. Without any doubt, the outlook has substantially improved even from just a few weeks ago. Global excess inventories of crude are rapidly declining. Demand for crude continues to recover, trending towards pre-pandemic levels as the global economy gradually opens. While the pricing for our services generally lags increasing demand during these recovery cycles, we see many indicators that the fundamentals for land drilling are well into a rebound. We believe the firm and stronger commodity prices for both gas and oil will lead to increased drilling demand as the year progresses. However, financial discipline by our customers, the oil and gas producers, is here to stay. Prioritizing investor returns while carefully managing growth is the way of today and the future for the oil and gas industry. Precision's digital technology offerings fit this need by enabling our customers to lock in performance improvements, eliminate human error and variance, but most importantly, this drives industrial scale-based cost and risk reductions across their complete drilling programs. Let me begin by updating you on customer adoption and the success we're having with our Alpha digital suite of technologies. First, we view the very strong sequential customer adoption as leading indicator that the efficiency, the performance, and repeatability that Alpha provides will drive market share growth for Precision. We noted eight new customers utilizing these technologies since the beginning of the year. We also mentioned 27% sequential growth in billable days for the AlphaA utomation platform. We've also increased our suite of AlphaApps from six to 16 as we commercialized 10 additional apps during the quarter. This resulted in apps revenue doubling the pace of last year with over 1,200 billable apps days during the first quarter. Importantly, our Alpha digital technologies are allowing our customers to drill better quality wells. Reduce our drilling costs, reduce fuel consumption, and importantly, reduce GHG emissions while delivering consistently predictable industrial scale repeatability in their operations. AlphaAnalytics utilizes Precision's on-staff experienced drilling engineers who comprehensively analyze offset well data to improve the customer drilling plan by providing process, placement, and performance recommendations. During the first quarter, we built AlphaAnalytics for almost 1,000 drilling days. Our customers view this as a high-value service. We expect customer adoption to accelerate. If you want more details on the specific efficiency and cost reduction benefits of our Alpha suite of technologies, you can find over a dozen field case studies on our website. Turning to our business update, I'll start with our Canadian Well Service business, which is experiencing a sharp improvement in customer demand and offers insight to the operating leverage Precision can deliver as this recovery takes shape. Most of the listeners on this call will know that we undertook a comprehensive organizational restructuring and cost reduction effort in this segment over the past couple of years. I'll note that sequentially, our well service activity was up 28% to 35,000 man-hours during the first quarter, returning to pre-pandemic levels. Also point out that only 15% of our work was due to the Federal Well Abandonment Programs, suggesting a strong increase in underlying customer demand. We expect demand will stay strong throughout the year. Notably, by the close of business on the first day of April, our 2021 monthly hours exceeded the full month hours we achieved in April of 2020. As another reminder, today we have 26 service rigs running compared to zero on the same day last year. We're obviously seeing that business rebound nicely into these stronger commodity prices. We expect this business is on track to deliver strong free cash flow and will continue to demonstrate excellent operational leverage as the activity remains strong. Moving to the U.S. Drilling activity in the U.S. recovered a little faster than we expected, with Precision now operating 40 rigs by mid-April. Well ahead of our prior guidance, which suggested we would reach this level by the end of June. As mentioned earlier, we continue to see strong uptake on our Alpha technology products, with 60% of our U.S. rigs running AlphaAutomation and AlphaApps. We continue to closely monitor our customers' completions activities as they work through the excess inventory of drilled but uncompleted wells. Current drilling activity levels are not matching the completion rates or even at levels to sustain current oil production volumes. We believe this points to increasing rig demand when the DUC inventories are exhausted later this year. We have further visibility for potential reactivations through the end of the third quarter and expect our activity to move into the upper 40s later this year. From a pricing perspective, we believe leading edge rates bottomed in the first quarter, and we see opportunities to charge CAD 2,000-CAD 3,000 premiums with these recently reactivated rigs reprice as our customers have a strong preference for what they term hot rigs. Carey mentioned the activation cost we experienced restarting rigs during the first quarter. I expect these transitory costs to linger as we activate additional rigs, yet I'm confident that as each of these rigs return to full operation, the costs will quickly normalize in line with our long-term averages. The potential inflationary effects of the pandemic economic recovery stimulus plans is a growing concern. Labor cost inflation is less of a concern as most of our customer contracts provide for increased day rates if labor costs increase. Labor accounts for roughly half of the daily operating cost of our rigs. The other half of the operating cost is procured materials, including rig expendables, spares, and miscellaneous repairs parts. Steel and other commodity inflation will likely impact these product costs as the year progresses. We believe our operational scale of our volume procurement and leveraging our supply chain will help mitigate some of these potential inflationary factors. I think this reinforces the importance of scale as a key competitive advantage in the land driller segment. Now, we believe the impacts of inflation will be well understood across the drilling value chain, and rate increases to offset these costs will ultimately be expected by our customers. We will keep a very close watch on inflation, and we still expect to improve our margins as the year progresses. Turning to our international business, as mentioned in our press release, the financial performance of this segment remains stable. Encouragingly, pre-tender work has commenced in Kuwait, and we are expecting to see opportunities develop in the second half to reactivate possibly all three idle rigs in Kuwait. In Saudi Arabia, forward visibility is less clear, but our expectation is that once all of the industry IBC rigs in country are reactivated, that the tender opportunities will begin to emerge. It seems that rig activations will track the reduction of OPEC-related export curtailments. Moving to Canada, we're in the middle of the seasonal spring break-up slowdown period. We mentioned in our press release that we have 20 rigs operating today, and this compares to less than 10 at this time last year. We have indications and commitments for a normal summer recovery period and expect to exit Q2 with close to 40 rigs operating, and again, more than twice last year's activity, and we expect that will trend out through Q3 into the fourth quarter. While pricing has been challenged over the past 12 months in the Canadian market, we see opportunities for price recovery later in the year and would expect to fully recover any inflationary factors. We also expect full utilization of our Super Triple rigs, the Montney and Duvernay drilling programs, and expect strong customer uptake on our Alpha digital products for these rigs. The company's positioning in Canada in the Canadian market remains very strong and provides an excellent source of free cash flow as we seek to continue reducing our total debt levels. As Carey mentioned, with CAD 51 million of debt reduction already achieved, we remain highly confident in our ability to meet or exceed our 2021 debt reduction targets. Moving on to our third priority. We have several customer collaboration-based GHG emission reduction projects underway in both Canada and the U.S. In Canada, we will be deploying a hybrid natural gas generating and battery energy storage system on a drilling rig during the third quarter. In the U.S., we have several customers transitioning to 100% natural gas or blended gas diesel power systems as they reactivate our rigs. During the quarter, we deployed a real-time rig-based GHG emission monitoring system in the field to validate and monitor precisely direct rig emission estimates. We are also developing several partnerships with green power solution providers to seek solutions to further drive down field emissions. We believe this strategy, which is similar to the partnerships we utilized to develop our Alpha Digital products, spreads out both the risk and investment requirements to several industry participants as we develop green solutions for our rigs. We believe that Precision Drilling will be a critical contributor to reducing and eventually eliminating the GHG emissions from the upstream oil and gas drilling industry. I'll conclude by thanking the employees of Precision for their perseverance, dedication, and hard work as we have all dealt with the many challenges of the past 12 months. I'm especially proud of the high-quality work our team has delivered and the strong and effective pandemic risk management program our team has implemented and successfully executed. Precision and our people have completely avoided any field service interruptions due to the virus and the related challenges. Thank you to the full Precision team. I'll now turn the call back to the operator for questions. Your first question comes from Taylor Richardson with Tudor, Pickering, Holt. Your line is open. Good afternoon. Thank you. Kevin, I wanted to start by asking a question on pricing. You made the comment that in the U.S. market, you think you'll be able to get a, or command a $2,000 to $3,000 a day premium versus some other rigs out there, at least for the rigs that are hot. I just wonder, the rest of the market, the rest of your peers are all doing the same thing, and they're all reactivating hot rigs as well. I was hoping you could just explain that a bit more and what you mean by $2,000 to $3,000 a day. What premium are you measuring that against? Any color there would be helpful. Yeah, for sure, Taylor. I think as this market's kind of evolved off the bottom of 2020, and we in the industry activated rigs. Those rigs were being activated from stacked into operations. We were bringing crews back out to the rigs. We were getting the rigs back up and going again. Competition was fairly intense. We've heard lots of talk about leading-edge day rates on those rigs. Comments that those are kind of like mid-teens, sometimes a little higher, sometimes a little lower for the activation of those rigs. Once those rigs have been running and drilled through their first contract, those contracts are generally short-term. We've been trying to keep that book near-term, so 30-day contracts, some 60-day contracts, some well-to-well contracts. When those rigs reprice on the next contract, that's when we expect that that rig will get a premium over a cold stacked rig. That premium could be, we're saying in the range of CAD 2,000-CAD 3,000, maybe more, depending on location and availability, timing. Okay. Yeah, that makes sense. Just to be clear, when you identified that CAD 2,000-CAD 3,000 a day, you talked about some labor and input cost inflation. That CAD 2,000-CAD 3,000 a day you're talking about would be pure margin fall through, or would that be some cost recovery as well? Really, I view that as pure margin follow through. Okay. Certainly, the day rates coming off bottom were unsustainable for the industry, and we need to see strong leadership on getting rates back into a sustainable range. Okay. A follow-up to international, you talked about some early tendering exercises going on in Kuwait and elsewhere in the Middle East. I was hoping you could help us think through what the typical timeline is as it relates to some of these early tendering activities eventually turning into a contract and then eventually the rig going back to work. You talked about the potential for all three of the rigs in Kuwait to go back to work in the second half, but any color around the typical timeline there would be helpful. We did give some guidance. We'd hoped or thought that we might have a likelihood of getting some or maybe all of those rigs activated before the end of the year. I'd just say stay tuned and listen to our updates. Likely we'll have a lot more information come our July Q2 conference call. The work right now in Kuwait's all pre-tendering work. It's kind of vendor surveys and analytics to make sure the rigs meet the specifications. Certainly, our new build rigs all meet specifications, so we're quite confident that we'll be quite competitive on these rigs. Awesome. That's helpful. I'll turn it back. Thank you. Thank you. Your next question comes from Waqar Syed with ATB Capital Markets. Your line is open. Thanks for taking my question. Kevin, you mentioned that your rig activity in the U.S. could be up into the high 40s by late this year. Are all those rigs kind of spoken for already? Do you have firm contracts, or this is just like in discussion mode right now? Waqar, I think it's a combination of open bids we have out there, customer discussions we have ongoing, and maybe a little bit of reading the tea leaves that we see out there. Okay. Is this incremental demand still from the privates, or are you seeing some public E&Ps getting involved as well? It's still weighted towards the privates, but what we've seen so far this year has been about two-thirds privates, about one-third publics, and I think that weighting looking forward would be similar. I think there's likely room for the publics to start moving into a few more rig activations in the second half of the year once they demonstrate a couple of quarters of good free cash flow, which we think they will. Halliburton in their call yesterday mentioned that they now expect U.S. E&P budgets to be up about 10% or so year-over-year. Previously, they were commenting that it's going to be actually down by maybe 2%-3% or so year-over-year. In your discussions with privates and publics, do you get that sense? Well, Waqar Syed, usually we're the last to hear because, of course, they're trying to run game theory on us and our day rates. We're less likely to hear forward guidance on capital spending than some other services might. Listen, it makes sense. You have to realize these budgets were probably created when the WTI prices were in the 40s, not the 50s or 60s late last year. Certainly we expect that our customers, both in the U.S. and Canada, will demonstrate very strong free cash flow during Q1 and obviously again during Q2. We think some of that money comes back into drilling. Okay, good. Yeah. The expectation is that public E&Ps may pick up activity late in the year, November, December, when that CapEx number may be reported in next year's number and not in this year's number. That's kind of their thinking from discussions. Hopefully that's the case. That's all I have. Yeah. I was gonna say, one thing we're certain of is that current drilling rates are inadequate to support current E&P production levels. Right. Yeah. Yeah. We do see our customers using their inventory of uncompleted wells to support production right now. That can't go on forever. That's gonna work its way down. Good. Yeah. Thank you. That's all I have. Thank you very much. Great. Thank you. Your next question comes from Cole Pereira with Stifel. Your line is open. Morning, everyone. Just wanted to start on margins. In the U.S. it sounds like they're going to take a bit of a step down next quarter, which I mean is understandable with all the startup costs. I mean, as we think about the rest of the year, obviously the startup costs will continue, but at the same time, I expect there to be some sort of economies of scale. I mean, do you kind of expect a bit of a recovery in that metric even as you activate more rigs, or how should we think about that? I think you're thinking about it the right way, Cole. Kevin mentioned we think that the spot pricing bottomed in the first quarter. We've got more rigs that have been fired up, so we have hot rigs to market, which should push pricing up a bit more. You're also correct about the startup costs. They'll be spread over more activity days as we keep adding to the rig count. We would expect after the second quarter, if the fundamentals for the industry hold together, that the margins will start expanding in the third quarter. Okay, perfect. That's helpful. Thanks. As we think about the international rig tenders, are you able to quantify how much you think you might need to spend to activate these rigs? I assume if you did have to spend that it would be obviously contracted. Cole, that's a great question. There will be CapEx involved. Those rigs have been idle now for a year, and before that their age is a little over six years old, so there'll be some time-based recertifications, particularly on things like BOP stacks. We're thinking that's gonna be in the range of CAD 3 million-CAD 5 million per rig, and we would expect that that would be recovered very quickly in the contract, likely well within the first year. We'd expect a contract that is measured in years duration, not quarters. Okay, perfect. That's helpful. Thanks. Just curious on the GHG monitor pilot. Should we be thinking about it as a relatively immaterial in the near term from a cost perspective? And how are you thinking about that from a revenue model standpoint? Would you like it to just be sort of a day rate add-on, or how do you think about that? Yeah, I really see all of the things we're gonna be doing around reducing our environmental footprint as part of the value we provide. If it involves capital, we'll look for capital recovery in some normal upgrade window, whether that's one year, two years, or four years, will kind of depend on the scope and the length of the contract. I would tell you that partnering with our customers in finding ways to reduce the footprint, but doing it on a capital recovery basis is very important for us. Okay, gotcha. Does that answer your question? Yeah. That works. From a balance sheet perspective, given where the bonds are trading right now, do you see yourself more paying down the credit facility in the near term and then maybe think about terming out some of that debt even more in the later half of the year? We're in a position where we have optionality. Obviously, we're generating free cash flow that we can use for debt reduction. We have a healthy cash balance. We have a little bit of balance left on our revolver, and we have our '23 notes that are callable at par in December of this year. We'll look to potentially make open market purchases throughout the year or pay down the revolver, and at the end of the year, we will have the ability to call those '23 notes to meet our debt reduction targets. In terms of longer term, at some point in the next Call it 18 months, it's likely that we would execute a high yield transaction to term out some of the longer, or actually I should say, nearer term maturities. We think it's probably a little bit too soon right now. We actually have been chipping away at the 2023 and 2024 notes. As we move along in time, those balances will be smaller than they are today. Okay, great. That's a good color. That's all for me. I'll turn it back. Thanks for the answers. Thanks, Cole. Your next question comes from John Daniel with Daniel Energy Partners. Your line is open. Hey, guys. Thank you for including me. Hey, John. Kevin, just on your activity comments, it's a nice progression to the high 40s. Can you just elaborate on the duration of those opportunities, given where the strip is? Are they trying to lock it in for 2022? Just any color on that would be appreciated. We have some customers trying to lock in, kind of leading edge rates for a longer period of time. Few of those go beyond about a 12-month cycle. We're obviously trying to always keep a blend of, kind of medium and short-term contracts. We're not too exposed to either direction. In this type of rising market, we are anxious to see contracts roll over. Okay. Yeah, understandable. Last one. I didn't mean to give you a long answer on that answer, but I'll tell you, most of the contracts are less than a year. I understand that you want it be less than one year today, but I didn't know if because of where the strip is, if people are now asking for more term. Notwithstanding where you want the pricing to be, but just conceptually, if they want to lock these things in for longer. Very few companies have a 2022 budget identified yet, so not a lot is looking beyond the first few months into 2022. Okay, got it. I think some of the companies are still trying to recover from 2020 and really understand where they're gonna be sitting financially over the course of this year before they get too committed to 2022. Although, I will tell you, the long-range planning on 2022 is looking quite robust. Right. It seems to me that there could be a rush, as Waqar alluded to in the fourth quarter, people trying to lock stuff up. That plays to you guys in terms of rising inquiries equals rising rates. I don't know if people just want to get ahead of it. Seems like a smart thing to do from the customer. For sure right now, every penny they save matters. If they're back into getting rigs, and a rig is CAD 3,000 or CAD 4,000 a day more, and they're gonna be drilling 20-day wells, that's only CAD 60,000 against what's probably a CAD 2 million or CAD 3 million well. The rig cost is just a lot less meaningful than it might've been in any previous recovery cycle. I agree. They always look at that number. First thing they look at, right? On an AFE, day rate, typically. No, they do. Hey, Kevin, In a rising tide, I would tell you that getting a good rig is probably more important than shaving the last penny off the price. Absolutely. No, I don't disagree with that. Last one, Kevin, just sort of big picture thoughts on your well service business as it relates to opportunities in the United States for expansion. We have a very small footprint presently into North Dakota, which really leverages. I know. our Southern Saskatchewan capabilities. We don't really see any expansion beyond that natural extension of our activities. Nothing beyond that. Okay. That's all I got. Thank you, guys. Thank you, John. Your next question comes from Keith Mackey with RBC Capital Markets. Your line is open. Hi, good afternoon, everyone. Hi, Keith. Hey, I just have one question for you. Appreciate it might be a bit sensitive, so would appreciate any comments you could make on it. Given the CAD 9 million Wage Subsidy is pretty substantial in the context of Q1's CAD 55 million EBITDA, what is the sense or the strategy as that program potentially ramps down through Q2? Is it, we're holding on to capability for an upswing in the second half of the year, or is there potentially some restructuring to be done? Any comments you could make to that effect would be helpful. Well, Keith, through most of last year, we did most of the restructuring that we think is necessary. I'd add a couple of things here. I think that we did preserve jobs that would've otherwise maybe not have been in the company without that program. I would tell you that today, a large portion of the value is actually across the field operations in drilling and well servicing. You could say that, in fact, the drilling rigs are running a little cheaper right now, and the service rigs are running a little cheaper, and that value is kind of being earned by the operating companies giving the services a little cheaper. I'd expect that likely, as those relief programs start to wind down, we will look to push rates higher to reflect the increased cost. Got it. Maybe just as a follow-up on that, I was sort of also wondering if any potential ramp-up in the site reclamation program spending that some expect in the second half of the year kind of plays into your footprint the way you've got it set up now. I'll have to tell you that we're pretty enthusiastic right now about our performance in well servicing. Any increase in reclamation awards, and we've been very well kind of blanketing that business right now, is all really good flow-through right to the bottom line for us. I think we'll be pushing hard to win more of those awards and continue to support the increase in demand we see in the field for conventional well service and remediation work. Got it. Okay. That's it for me. Thanks very much. Great. Thanks, Keith Mackey. Again, as a reminder, to ask a question, please press star, then the number one on your telephone keypad. Your next question comes from Ryan Koontz with Morgan Stanley. Your line is open. There's been a lot of talk about whether operators in the U.S. are going to stick to managing budgets to production maintenance mode or if they're going to maybe pick up activity. I wanted to ask a similar line of questioning, but in Canada, just in your conversations with customers, do you get the sense that Canadian operators are in maintenance mode as well? Or how would you characterize the strategy in that market? Dan, I would say that transition probably happened two or three years earlier in Canada, where our E&Ps were forced into a maintenance or fiscal discipline mode really as early as 2014 or 2015, after the first OPEC collapse. I think it's been running longer in Canada. I think the E&Ps in Canada are trying to find ways now to do both generate good shareholder capital returns and find ways to develop modest growth. You've seen a couple of transactions up in Canada that are designed to eke out a couple of E&P transactions, to eke out some of the synergies, grow production, but not necessarily increase capital spending. Certainly, we're going to see activity come up off of the 2020 extremely low levels that we experienced last year. Got it. That was my follow-up is, you said in the U.S. you think that we're running below maintenance activity levels. Obviously, the answer's a lot more complex in Canada given seasonality and the different resource plays. Just wondering if there's any kind of a bogey you could point to for what might represent maintenance activity levels like a maintenance rig count in Canada. A little hard to that because the mix of hydrocarbons is a bit different in Canada. The emphasis the last couple of years for our triples has been around what I referred to on my prepared comments as Montney and Duvernay. It's a natural gas basin, but it's actually very wet and the wells are essentially being paid for by the natural gas liquids that are being produced. Those are still going into pipelines that get shipped over to the heavy oil producers, and it's used as a diluent for heavy oil being piped to the U.S. You've got natural gas liquids, you've got natural gas, and you've got oil. All three are quite constructive right now and with the Canadian oil and gas complex operating in a disciplined mode, I think there's room to see activity move up and still be disciplined. Understood. Thanks a lot for the color. I'll turn it back. Thank you. Your next question comes from Jeff Fetterly with Peters & Co. Limited. Your line is open. Good afternoon, everyone. Just a quick follow-up question on the technology side. Kevin, you've obviously laid out the adoption and successes you're seeing across Alpha and some of the emissions stuff. How should we think about the impact on your day rates and margins from both first Alpha, but also the emissions piece? On the emissions piece, I'll start there. If we make a capital addition to the rig, be it a natural gas engine or a battery power pack, we'll look at that like it's an upgrade, and we'll look for typical upgrade economics, which means payback within the contract period. That could be one year, it could be two years. Unlikely it stretches out to three years. If there's a capital enhancement to the rig, we'd want to see our capital recovered. We view our customers being partners with us in those GHG emission reduction efforts. I think I even talked about a couple of those on the last call where we had some upgrades we did that were specific to both natural gas conversions and footprint of the rig where our customers paid for those upgrades. Coming back to the Alpha, great question. I'm glad you asked it so I can dive into this a little bit. The price we posted for AlphaAutomation in Canada is CAD 1,500 per day. In the U.S., $1,500 per day U.S. That price has stuck in the market. It's a price we introduced originally three and a half, four years ago. That's essentially a price that allows us to recover any capital investments we need to make within a couple of 100 days. After that, it is essentially EBITDA for us. On the AlphaApps, we're charging in the range of anywhere from CAD 200, CAD 250 up to about CAD 1,000 per day, depending on the value the app creates. In some cases, if we own the app, all of the revenue comes to us. If it's owned by a partner, there may be some revenue sharing agreement, generally there's no operating cost for an app, it's all EBITDA. On our revenue model for our optimization AlphaAnalytics, we're charging a per day rate for the days that we do the optimization for our customers. These are all per day adders to the base rig cost. What we see happening, Jeff, is that the rig may need to compete on a per rig basis, all of the adders a la carte to the price of the rig go on top, there is simply no competition on these technology offerings. We're not being bid down on our technology offerings. Conceptually, we should think about the CAD 1,500 per day base rate being applied across the 30 plus rigs consistently that you have running today? I think we gave a U.S. penetration rate of about 60%. In Canada, on our Super Triples, I didn't give a rate on that, but it's less than 50% right now. We expect over time that both Canadian and U.S. fleets will trend towards full utilization. Okay. Thank you. On the CapEx side, the CAD 54 million budget, is there some room built in for maintenance capital tied to the U.S. fleet ramping up faster than you had previously talked about? Is there some potential that your capital program needs to expand? Ignoring the comment earlier about the reactivations internationally. Hey, Jeff Fetterly, it's Carey. I would say that capital plan of CAD 54 million incorporates a steady increase in activity in our U.S. recap throughout the year. That's how we budgeted it. If there's a sharp ramp, if we get to an activity level that's higher than what Kevin Neveu guided to, high 40s towards the end of the year, there'd be a little bit of an increase. We're talking probably low single digits, millions of CAD. In the CAD 3 million-CAD 5 million per rig for the international, that would be incremental to that 54 number that's currently guided? That would be. Again, that would be associated with signing a long-term contract. Yep. Okay. Thanks for the color. Your next question comes from Dan Healing with Canadian Press. Your line is open. Oh, hi, guys. Thanks for taking my question. Hey, Dan. Hi. I was looking for some comment on Joe Biden and Justin Trudeau announcing bigger emission targets for Canada and the U.S. by 2030. I heard on the call that Precision Drilling is doing things to help customers reduce emissions while they're drilling. I wonder from a higher level in terms of what the industry can expect to happen, and Precision Drilling specifically over the next, what, eight and a half years. What's the impact going to be? Dan Healing, these are obviously extremely aggressive targets being laid out by leaders in Canada and the U.S. I think there's an absence of process or plan behind the targets, but you need to start with the target, and I understand that. I think the objectives that they're trying to achieve, we agree with and we support. In our case, there are solutions for drilling rigs that take them to essentially zero emissions almost immediately. We've done that in the past with grid-powered drilling rigs. That's not science fiction. It's easy to accomplish. The only issue is having adequate grid power in the field to the rig. As these fields mature and become more industrialized, I expect to see more industrial-grade electric power applied to the fields, and that likely gets better. I think that from a drilling perspective, getting to zero or near zero, or certainly getting to the targets they've talked about, which are 40% and 50% reductions, are achievable. In our case, to convert one of our Super Triple rigs from a diesel-powered rig to a high-line powered rig is a very small amount of capital. Okay, just as a follow-up, are there things that the government should be doing for the oil and gas companies and the drilling companies to get them to these targets? I think that any of the technology incubators or technology support that the government's giving for all of the alternative energy sources, the oil and gas industry should be looking at very hard. That would include everything from solar and wind power to hydrogen fuel cells and highline power. I think those avenues are open to us now, and I think that I know my team is looking hard at the opportunities we have to seek out federal R&D assistance for alternative power that we're looking at. Okay, thanks very much. Great. Thanks, Dan. There are no further questions at this time. I'll turn the call back to Dustin Honing for closing remarks. Thank you everyone for joining today's call. We look forward to speaking with you when we report second quarter results in July. Denise, you may disconnect. Thank you. This concludes today's conference call. You may now disconnect.