Precision Drilling Corp (PDS) 2021 Q1 法說會逐字稿

Ladies and gentlemen, thank you for standing by, and welcome to the Precision Drilling Corporation 2021 First Quarter Results Conference Call and Webcast. (Operator Instructions). Please be advised that today's conference is being recorded. (Operator Instructions).

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 $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 $11 million in share-based compensation expense and $9 million in CEWS assistance payments. As a reminder, the CEWS program supports employment in Canada and 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. But now -- but 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 7 rigs from Q4. Daily operating margins in the quarter were USD 7,027, a decrease of USD 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 start-up costs relating to 12 rigs activated year-to-date and turnkey activity.

Absent impacts from idle-but-contracted rigs and turnkey, daily operating margins would have been USD 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 cost and turnkey activity to continue, along with no IBC revenue, such that normalized margins, absent turnkey and IBC, will decrease between $500 and $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 cost to cold start rig crews, inspect and certified 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 $150,000 to $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 to 30 rigs in our U.S. 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 $8,106, an increase of $901 from Q1,, 2020. Margins were supported by a strict focus on operating cost and cues assistance, offsetting lower fixed cost absorption. Absent the cues impact, margins would have been $6,760 or $445 lower than Q1 last year. For Q2, we expect margins, absent of CEWS and onetime recoveries to be up $500 to $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 onetime recoveries were approximately $4,000. Internationally, drilling activity for Precision in the current quarter averaged 6 rigs. International average day rates were USD 52,744, down approximately USD 1,500 per day from the prior year. This was due to rig mix and lower rig new revenue. In our C&P segment, adjusted EBITDA this quarter was $7.8 million, 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, fused program support and $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 $8 million, and our full year 2021 guidance remains $54 million. Comprised of $38 million for sustaining infrastructure and $16 million for upgrade and expansion, which relates to anticipated investments supporting Alpha technologies and contracted customer upgrades.

As of April 21, we had an average of 36 contracts in hand for the second quarter at an average of 31 contracts for the full year 2021. Moving to the balance sheet. We continue to reduce both absolute and net debt levels primarily through free cash flow generation. As of March 31, our long-term debt position net of cash was approximately $1.1 billion, and our total liquidity position was approximately $700 million, excluding letters of credit.

Our net debt to trailing 12-month EBITDA ratio is approximately 5.2x 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 2.1x. During the quarter, we reduced total debt by $29 million and made an additional $22 million debt reduction subsequent to the quarter end, totaling $51 million debt reduction year-to-date. Over halfway to meeting our debt reduction target range of $100 million to $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 $800 million between 2018 and 2022, where we have already reduced debt by $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 an $18 million working capital build in Q1. For reference, the working capital build since our trough in Q3 2020 has been approximately $44 million, which has been driven by higher activity. For 2021, our guidance for depreciation, SG&A and interest expense remains unchanged at $290 million, $55 million before share-based compensation expense and $85 million, respectively, for the year.

We expect cash taxes to remain low and our effective tax rate to be in the 5% to 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 $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 we'll 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, and 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.

And 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 firmly -- 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 wave 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. So let me begin by updating you on customer adoption and the success we're having with our Alpha digital Suite technologies.

First, we view the very strong sequential customer adoption as a leading indicator that the efficiency, the performance and repeatability that Alpha provides will drive market share growth for Precision. We noted 8 new customers utilizing these technologies since the beginning of the year, we also mentioned 27% sequential growth in billable days for the AlphaAutomation platform. We've also increased our suite of AlphaApps from 6 to 16 as we commercialized 10 additional apps during the quarter.

And this resulted in apps revenue doubling the pace of last year with over 1,200 billable apps stays during the first quarter. Importantly, our Alpha digital technologies are allowing our customers to drill better quality wells, reduced our drilling costs, reduce fuel consumption and importantly reduce GHG emissions while delivering consistently predictable industrial scale repeatability in their operations.

Now AlphaAnalytics utilizes Precisions 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, and 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. I 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. And notably, by the close of business on the 1st day of April, our 2021 monthly hours exceeded the full month hours we achieved in April of 2020. And as another reminder, today, we have 20 service -- 26 service rigs running compared to 0 on the same-day last year. So 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 $2,000 to $3,000 premiums with these recently reactivated rigs reprice as our customers have a strong preference for with the term hot rigs.

Now 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 each of these rigs return to full operation, the costs will quickly normalize in line with our long-term averages. Now 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 of labor cost increase, and 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 repair 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.

And 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 3 idled 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 breakup 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 of 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 up 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, I 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 $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 story 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 that say reactivate our rigs. During the quarter, we deployed a real-time rig-based GHG emission monitoring system in the field to validate, 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 our partnership, the partnerships we utilized to develop our Alpha digital products, spreads up 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 over 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. So thank you to the full Precision team. I will now turn the call back to the operator for questions.

(Operator Instructions)

Your first question comes from Taylor Zurcher with Tudor, Pickering, Holt.

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 I guess, some other rigs out there, at least for the rigs that are hot. And I just wonder, I mean, 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. So 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? So any color there would be helpful.

Yes. For sure, Taylor. I think as this market has kind of evolved off the bottom of 2020, and we and 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 kind of back up and going again. Competition was fairly intense. We've heard lots of talk about leading edge day rates on those rigs.

Comment 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 kind of 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 where we expect that rig will get a premium over a cold-stacked rig. And that premium could be we're saying the range of $2,000 to $3,000, maybe more, depending on location and availability, timing.

Okay. Yes, that makes sense. And just to be clear, when you identified that $2,000 to $3,000 a day, you talked about some labor and input cost inflation, that $2,000 to $3,000 a day you're talking about would be pure margin fall through? Or would that be some cost recovery as well?

Really, it is our view that as pure margin follow through. 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. My follow-ups of international, you talked about some early tendering exercises going on in Kuwait and elsewhere in the Middle East. And I was hoping you could help us think through what the typical time line is as it relates to some of these early tendering activities eventually turning into a contract and eventually the rig going back to work? You talked about the potential for all 3 of the rigs in Kuwait to go back to work in the second half, but any color around the typical time line there would be helpful.

We did give some guidance. We'd hope, thought that we might have a likelihood of any summer, 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 is all pre-tendering work, it's kind of sender surveys and analytics to make sure the rigs meet the specifications, certainly, our new build rigs all made specification. So we're quite confident that we'll be quite competitive on these rigs.

Next question comes from Waqar Syed with ATB Capital Markets.

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? Or is that -- do you have firm contracts? Or this is just like in discussion more right now?

Waqar, I think it's a combination of open bids we have out there, customer discussions we have ongoing. And then maybe a little bit of reading the tea leaves that we see out there.

Okay. And 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 2/3 private, it's about 1/3 public, and I think that waiting looking forward would be similar. But I think there's likely to test to start moving into a few more rig activations in the second half of the year, but they demonstrate a couple of quarters of good free cash flow, which we think they will.

No 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% to 3% or so year-over-year. In your discussions with privates and publics, do you get that sense?

Waqar, usually, we're the last to hear because, of course, they're trying to run game theory on us in our day rates. So we're less likely to hear forward guidance on capital spending than some other services might but listen, it makes sense. You have to realize these budgets, we're probably accretive when the WTI prices were in the 40s, not the 50s or 60s late last year. And 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. So we think some of that money comes back into drilling.

Okay. Good. Yes. 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 numbers. So that's kind of their thinking from discussions. So hopefully, that's the case. That's all I had.

I was going to say, one thing we're certain of is that current drilling rates are inadequate to support current E&P production levels. We do see our customers using their inventory of uncompleted wells to support production right now, that can't go on forever. That's going to work its way down.

Your next question comes from Cole Pereira with Stifel.

Just wanted to start on margins. So 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 start-up costs. But I mean, as we think about the rest of the year, obviously, the start-up costs will continue, but at the same time, I expect there'll be some sort of economies of scale. So 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 the right way, Cole. Kevin mentioned, we think that the spot pricing bottomed in the first quarter. We've got more rigs that have fired up. So we have hot rigs to market, which should push pricing up a bit more. And you're also correct about the start-up costs. They'll be spread over more activity days as we keep adding to the rig count. So 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. So as we think about the international rig tenders, I mean, are you able to quantify how much CapEx you might -- how much do you think you might need to spend to activate these rigs? And 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. We have -- those rigs have been idle now for a year. And before that, their age is a little over 6 years old, there'll be some time-based recertifications. Particularly on things like BOP stacks. We're thinking that's going to be in the range of $3 million to $5 million per rig. And we would expect that, that would be recovered very quickly in the contract, likely well in the first year. And we'd expect a contract that is measured in years duration, not quarters.

Okay. Perfect. That's helpful. Just curious on the GHG monitor pilot. I mean, 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?

Yes. I really see all of the things we're going to be doing around reducing our environmental footprint. As part of the value we provide, and if this involves capital, will look for capital recovery in some normal upgrade window, whether that's 1 year, 2 years or 4 years, it will kind of depend on the scope at the length of the contract. But we think that -- 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. Got you.

Does that answer your question?

Yes, yes, that works. So from a balance sheet perspective, I mean, given where the bonds are trading right now, do you 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?

Yes. So 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.

So 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'll have the ability to call those 23 notes to meet our debt reduction targets. And 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, near-term maturities. We think it's probably a little bit too soon right now. And we actually have been chipping away at the 23 and 24 notes. So as we move along in time, those balances will be smaller than they are today.

Your next question comes from John Daniel with Daniel Energy Partners.

Kevin, just on your activity comments, it's a nice progression in 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. But few of those go beyond about a 12-month cycle. We're obviously trying to find -- always keep a blend of kind of medium and short-term contracts. We're not too exposed to either direction. But we -- in this type of rising market, we are anxious to see contracts roll over. I didn't really give clarity on that answer. But I would tell you, most of the contracts are less than a year.

Well, I understand that why it'd be less than a year today. But I don't know if because of where the strip is if people are now asking for more term. And notwithstanding where you want the pricing to be, but just conceptually if they want to lock these things in for longer. Am I making...

Very few companies in 2022 budget identified yet. So not a lot is looking beyond the first few months into 2022.

And then just want to will try to recover from 2020 and really understand where they're going to be sitting financially over the course of this year before they get too committed to 2022. Although I will tell you, the long rates funding on '22 is looking quite robust.

Right. I just -- it seems to me that there could be a rush, as Waqar alluded to in the fourth quarter, people trying to lock stuff up and then that placed your to you guys in terms of rising equals rising rates. And I don't know if people just want to get ahead of it, feels like a smart thing (inaudible) the customer.

So for sure, right now, every penny they save matters. But if they're back into heating rigs and at a rig is $3,000 or $4,000 a day more, and they're going to be drilling 20-day wells. That's only $16,000 against what's probably a $2 million or $3 million well. So the rig cost is just a lot less meaningful than it might have been in any previous recovery cycle.

I agree, but they always look at that number. First thing they look at, right, on an AFE day rate typically.

They do. But it's -- in a rising tide, I would tell you that getting a good rig is probably more important than saving your last penny off the price.

Absolutely. No, I don't disagree 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, pressing into North Dakota, which really leverages our other Saskatchewan capabilities, but we don't really see any expansion beyond that natural extension of our activities, nothing beyond that.

Your next question comes from Keith MacKey with RBC Capital Markets.

I just have one question for you. And appreciate it might be a bit sensitive, so I would appreciate any comments you could make on it. But given the $9 million wage subsidy, it's pretty pretty substantial in the context of Q1's $55 million EBITDA, like what is the sense or the strategy as that program potentially ramps down through Q2? Like is it a 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.

Keith, through most of last year, we did most of the restructuring that we think is necessary. But I'd add a couple of things here. I think that we did preserve jobs that would have otherwise maybe not a bit of the company without that program. But I would tell you that today, a large portion of the value is actually across the field operations and drilling and well servicing.

And you could say that, in fact, the drilling rigs are running a little cheaper right now and the service rigs are a little cheaper. And that value is kind of being earned by the operating companies going the service is a little cheaper.

So I'd expect that as those likely as those relief programs start to wind down, we will look to push rates higher to reflect the increased cost.

Got it. And maybe just on -- as a follow-up on that. I was sort of also wondering if that 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 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 increasing demand we see in the field for conventional well service and remediation work.

(Operator Instructions)

Your next question comes from Dan (inaudible) from Morgan Stanley.

There's been a lot of talk about whether operators in the U.S. are going to kind of stick to managing budgets to production maintenance mode or if they're going to maybe pick up activity. I kind of 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 kind of in maintenance mode as well? Or how would you kind of characterize the strategy in that market?

Dan, I would say that, that transition probably happened 2 or 3 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 sort of OPEC collapse.

So 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. Does eke out, some of the synergies, grow production, but not necessarily increased capital spending.

And certainly, we're going to see activity kind of come up off of the 2020 extremely low levels we experienced last year.

Got it. And yes, that was kind of my follow-up is on, you said in the U.S., you think that we're running below maintenance activity levels. Obviously, the answer is a lot more complex in Canada given seasonality in the different resource plays. But just wondering if there's any kind of a bogey you could point to for what might represent maintenance activity levels like maintenance rig count in Canada.

A little hard to that because the mix of hydrocarbons is a bit different in Canada. The emphasis in the last couple of years for our Triples has been around what I referred to in my prepared comments as Montney and Duvernay. And that's 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. And those are still going to pipelines get shipped over to the heavy oil producers and it's used as a diluent for heavy oil being piped to the U.S.

So you've got natural gas liquids, you've got natural gas, and you've got oil. All 3 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.

Our next question comes from Jeff Fetterly with Peters & Company.

Just a quick follow-up question on the technology side. So given you've obviously laid out the adoption and successes you're seeing across Alpha and some of the emission stuff. How should we think about the impact on your day rates and margins from both first Alpha but also the emissions piece?

So on the emission space, 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, and that could be 1 year, it could be 2 years, unlikely it stretches out to 3 years. So if there's a capital enhancement to the rig, we want to see that capital recovered. So we view our customers being partners with us in those GHG emission reduction efforts.

Now -- and I think 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 and footprint of the rig where our customers paid for those upgrades. Now 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 U.S., USD 1,500 per day U.S.

That price has stuck in the market. It's a price we introduced originally 3.5, 4 years ago. That's essentially price that allows us to recover any capital investments we need to make within a couple of hundred days. And after that, it is essentially EBITDA for us. On the apps, we're charging in the range of anywhere from $200, $250 up to about $1,000 per day depending on the value of 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. But generally, there's no operating cost for an app, so 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. So these are all per day adders to the base rig cost. So what we see happening, Jeff, is that the rig may need to compete on a per rig basis, but all of the adders, a la carte to the price of the rig go on top, and there is simply no competition on these technology offerings. We're not being bid down on our technology offerings.

So conceptually, we should think about the $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 60% and in Canada, on our super Triples, I didn't give a rate on that, but it's less than 50% right now. But we expect over time that both Canadian and U.S. fleets will trend towards full utilization.

And on the CapEx side, the $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? Or is there some potential that your capital program needs to expand? Obviously, ignoring the comment earlier about the reactivations internationally.

Jeff, it's Carey. I would say that, that capital plan of $54 million incorporates a steady increase in activity in our U.S. rig count throughout the year. So that's how we budgeted it. Now if there's a sharp ramp. If we get to an activity level that's higher than what Kevin guided to kind of high 40s towards the end of the year. There'll be a little bit of increase, but we're talking probably low single digits, millions of dollars.

In the $3 million to $5 million per rig for the international, that would be incremental to that $54 million number that's currently guided?

That would be. But again, that would be associated with signing a long-term contract.

Our next question comes from Dan (inaudible) with Canadian Press.

I was looking for I was looking for some comment on Dolby and Justin Trudeau announcing bigger emission targets for Canada and the U.S. by 2030. And I heard on the call that precision drilling is doing things to help customers reduce emissions while they're drilling. But I wonder from a higher level in terms of what the industry can expect to happen and Precision Drilling specifically over the next, what, 8.5 years, what's the impact going to be?

Dan, these are obviously extremely aggressive targets being laid out by leaders in Canada and the U.S. And I think there's an absence of process or plan behind the targets, but you need to start with the target. I understand that. And I think the objectives that they're trying to achieve, we agree with and we support. And in our case, there are solutions for drilling rigs that take them to essentially 0 emissions almost immediately. We've done that in the past with grid-powered drilling rigs.

And that's it's not science fiction. It's easy to accomplish. The only issue is having adequate grid power in the field to the rig. But as these fields mature and become more industrialized, I expect to see more industrial-grade electric power applied to the fields, and that like gets better. So I think that from a drilling perspective, getting to 0 or near 0 are certainly getting to the targets they've talked about, which are 40% and 50% reductions are achievable. And 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 is giving for all of the alternative energy sources the oil and gas industry should be looking at very hard. And that would include everything from solar and wind power to hydrogen fuel cells and high line power. But 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.

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.