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Good morning, and welcome to the STEP Energy Services Q1 2020 Results Conference Call and Webcast. [Operator Instructions] I would like to remind everyone that this conference call is being recorded today, May 12, 2022 at 9:00 Mountain Time.
On the call today are Regan Davis, Chief Executive Officer; Klaas Deemter, Chief Financial Officer; and Steve Glanville, President and Chief Operating Officer. Now I'll turn the conference over to Regan Davis. Please go ahead.
Good morning, everyone. Thank you for joining us for this call. The format this morning will be Klaas will give an update on finances, Steve will give an update on operations. And I'll provide some closing comments summarizing what you probably already will hear from them. So I'll turn it over to Klaas at this time.
Morning. Good morning, everybody. Thanks, Regan. So before we begin, I'd like to remind everyone that this conference call may contain forward-looking statements and other information based on current expectations or results of the company. Certain material factors or assumptions that were applied in drawing conclusions or making projections are reflected in the forward-looking information section of our Q1 2022 M&A. Several business risks and uncertainties could cause actual results to differ materially from these forward-looking statements and our financial outlook. Please refer to the risk factors and risks management section of our MD&A for the quarter ended March 31 for a more complete description of business risks and uncertainties facing STEP. This document is available on our website as well as on SEDAR.
During this call, we're going to refer to several common industry terms and certain non-IFRS measures that are, again, more fully described in our MD&A, which is again on our website or SEDAR. So I'm going to give a brief overview of our financial results, and then I'll turn the mic over to Steve, who is going to provide some operational detail.
So the first quarter of 2022 delivered the confident start to the year that the company signaled in its Q4 2021 release. First quarter revenue was highest in Q1 and in our history and highest quarter since Q3 2018. Revenue for the quarter was $219.5 million, which is about 60% higher than the $136 million we generated in Q1 of 2021 and up from $159 million in Q4 of last year. Biggest driver, of course, is a familiar story of higher commodity prices, strong oil and gas prices enjoyed by our clients drove activity higher with rig count moving up significantly in Canada and the U.S.
Revenue in Canada was a touch under $147 million compared to $109 million in Q1 of last year and $91 million in Q4 of 2021. Utilization was higher across the board and the strong demand from our oil-focused customers allowed us to feel the low pressure crew that's specifically targeted this oil-focused work. Steve will get into the details of the crew, but it was a nice tuck-in addition that we can activate with minimal capital spend. In addition to this small crew, we operated 4 larger fracturing crews and 8 coiled tubing units in Canada.
Revenue in the U.S. was $72.7 million compared to $27.5 million in Q1 2021. Just note, we really operated 2 fracture spreads in Q1 of last year, whereas we're operating 3 fracture spreads this year. Our $72.7 million compares to the $67 million that we earned in Q4 of last year. In addition to those 3 spreads, we also operated 8 coiled tubing units in U.S. We're able to move up pricing in both Canada and the U.S. during the quarter, but we didn't get real movement until after we saw our January results, which were hammered by inflation and a somewhat slow start to the month.
Once we saw these results in early February, we gave our sales teams a mandate to increase prices and said that we are preparing to lose work if our clients didn't accept increases. We were able to move prices up 10% to 15% in Canada, 20% to 25% in the U.S. However, we won't get full benefit of these increases until the coming quarters, given the timing of how they rolled up in Q1. Keeping price steady through Q2 in Canada and haven't had to gauge the price discounting. It typically happens during the spring breakup period. Our U.S. team is continuing to push pricing higher through the quarter following the lead of our much larger competitors in the basins that we operate in.
We generated $36.9 million in adjusted EBITDA in Q1 2022, up from $16 million in Q1 of last year, which I'd like to point out also included $3.5 million of CEWS. And we were also up from the $17 million that we earned in Q4 2021. As noted in our MD&A, inflation limited the returns that we were able to achieve in this quarter but I want to point out that this is the highest first quarter EBITDA since Q1 2018, and we're extremely proud of the hard-working professionals in our company that made this possible. The strong EBITDA performance translated into the first quarter of positive net income since Q3 of 2018. The $9.2 million net income earned this quarter translated into an earnings per share of $0.135.
Shifting to our balance sheet. We saw a significant increase in our working capital compared to the fourth quarter. The increase in our net debt was a result of the increased drawn on our credit facilities to fund the higher working capital demands of the business. We maintained adequate liquidity through the quarter and expect that our lines will touch 0 this week as we harvest that working capital following a small lull in activity here in Canada due to the spring breakup.
We remain in compliance with all our covenants. And subsequent to the quarter end, we delivered notice of early termination of the covenant relief provisions of our grants in Q3 2021. These provisions were due to expire at the end of Q2 2022, but the early termination reduced our ordering costs by about 200 basis points for the balance of the quarter. Just to put that into context, it's about $10,000 a day that we are able to return to the bottom line through that.
In response to the expected increase in activity, the Board of Directors has improved a modest increase to our 2022 capital budget of about $8 million, bringing our total budget to $56 million for the year. This capital will fund our ESG oriented investments into dual fuel and auto-reduction kits as well as an increase in our maintenance capital to respond to the higher activities and expectations for the year.
With that, I'll turn the call over to Steve, who will provide some more comments on our operating conditions and our outlook for Q2 and the balance of the year.
Thanks, Klaas, and good morning. I'll take a few minutes to talk about some of the operational highlights that we realized in the first quarter as well, provide brief commentary on how the second quarter is progressing for the business. Utilization was very strong through most of Q1, despite the typical cold weather impacts early in the quarter and the omicron COVID-19 variant, which caused some operational disruptions. I'd like to take this opportunity and really thank our field professionals for battling through these tough conditions without minimal operational challenges.
The high utilization for the quarter is a direct effect of the increase in drilling activity due to the surge in commodity prices. Remember, WTI rose from the start of the quarter at $77 a barrel and averaged $95 a barrel through the quarter. Also, the exciting part about the current commodity cycle for our business, and in particular, our Canadian business is the increase in natural gas prices since most of our operations are focused on liquid-rich natural gas completions. At the start of the year, NYMEX gas prices were around $4, and today, they hover around that $7 for MMBtu. The U.S. rig count averaged 636 rigs, up 17% from the past quarter and a 68% increase year-over-year.
In Canada, the rig count averaged around 193. And on a combined basis, we pumped over 600,000 tons of proppant of which STEP supplied 64% of that and the remaining being client supplied. This was a 10% increase from the previous quarter on 615 operating days for our active frac crews. I'll dive a bit deeper and discuss operational results from each of our geographic regions. Starting with our U.S. frac business. We continue to operate 3 large frac crews with each crew having between 50,000 and 60,000 horsepower available. Majority of the work was where we were active in the Permian Basin. Proppant and last-mile delivery bottlenecks resulted in some minor delays, which impacted optimum frac efficiencies. A quick wrap up in the basin activity put us straight on supply chain and third-party infrastructure. However, we believe this will correct itself in the coming quarters as additional resources will be added.
One other highlight for the quarter is one of our Tier 2 frac crews has a bolt-on dual-fuel system, which is quite a bit different than the current systems that are out there, whereas it is a direct injection, which is very comparable to what's the Tier 4 that is out there today. And we averaged around 75% substitution, so we're quite happy with the results of that fleet.
In the U.S., our coiled tubing business had a slower start at the beginning of the quarter, as activity typically follows the frac completions and since both operators took time off during the holiday season. This created about a 2-week lag to reach full utilization in January due to wells not being handed over for milling operations. At the end of the quarter, we staffed an additional unit in the Rockies region as high demand warranted the expansion. This additional overhead was captured in that quarter. However, revenue was not, and we'll be following in the subsequent quarters. So this will put us at 9 deep active coiled tubing that's currently in the U.S. We are very pleased with the results that our U.S. business put up in Q1, and we look forward to improving our bottom line margins. As we continue to work with our dedicated clients, they increase pricing.
Over to our Canadian business. On the frac side, we operated 5 frac spreads with 215,000 horsepower during the quarter. And as Klaas had mentioned, we did reactivate a fifth frac spread, and it was mainly focused on lower intensity work in the Viking and Cardium areas, and we really were able to capitalize with our bundled services with our coiled tubing assets. Total operating days for the quarter surged 42% on a quarter-over-quarter basis as demand for our frac services increased. One other interesting note for a quarter for the frac side is, as Klaas had mentioned, our idle reduction control kits were -- we have 10% of our fleet installed without on our horsepower, and with the delays and constraints from the third-party trucking perspective, we were able to remove some of our tractors off of our horsepower units and use that as our internal hauling business. So pretty excited about that technology.
On the cultivating side of our Canadian business, we were also extremely active in the first quarter, and we operated 8 deep capacity coiled tubing units, which was an increase from the previous quarter. As we look into the outlook, rig counts, of course, in 2022, are expected to track approximately 25% higher in Canada relative to 2021 and over 25% or more in the U.S. The increase in rig count will drive demand for our services, which will push the limits to the overall fleet capacities. Our operations, both in Canada and the U.S., have experienced very strong levels of activity thus far in the quarter, besides the typical slowdown season that happens in Canada during the breakup period, which, of course, is due to road restrictions. We are expecting record-breaking quarters for both our U.S. and our Canadian business units as we've been able to increase pricing across every business unit versus, in the past, provided a discount in Canada for the slow Q2.
Looking forward into the third quarter, we are seeing increased activity prior to Q3 of 2021 for both geographic regions. Currently, our Canadian frac schedule is filling up, and we expect it to be fully utilized or sold out in the coming weeks. And in the U.S., we will -- with the increase in drilling activity, we expect similar utilization metrics as we are seeing in Q2. Our pricing discussions from our clients, they've responded positively with almost everything across the board, and we expect that to translate into higher margins for our business. I'll now turn it over to Regan for some closing comments.
Thanks, Steve. Again, I think most of my comments will sort of touch on stuff that Steve and Klaas already spoken to so well. I'll start with -- like, I couldn't be happier that Q1 and how it turned out. It really was great momentum this quarter for the company. Utilization was strong. The cooperation with our clients to ultimately result in net margin improvements for our business, the incredible execution from our field professionals, and then in April, just so excited that the first quarter, we were able to complete our first IOR drop. Now IOR is a technology that ultimately results in -- it's applied through existing wells to help improve recovery from those wells. And given our suite of global IP from gas frac, we are in a really unique position to be able to develop that market with very low competition.
As I look at the outlook, I think it's worth noting that we've had quarter-over-quarter improvements since Q4 of 2020. And we've got, obviously, a very constructive outlook as we look through the balance of this year and into 2023. And I think we've all had the benefit of reading some of the commentary from global energy producers, from large industry leaders, OFS leaders in our space to support that outlook. We have -- obviously, we have great success moving pricing up through Q1, and as Steve mentioned, that pricing is going to carried through into Q2, resulting in improved margins with virtually no discounts in recognition of how tight supply of our business assets are.
U.S. pricing is literally improving by the month. And I would like to note that if you look at our Q1 results for the U.S. division, I think they stand up very well, if not better, than many of our larger U.S. competitors. The Canadian rig count is the highest at this time of the year since 2014. The U.S. rig count is 57% higher year-over-year. We have a very strong visibility to strong utilization for our manned assets for the back half of the year. And I would suggest, as we think about it moving into Q1 '23, assuming this environment maintains the momentum it's having, we would love at additional capacity into the market in Q1 of 2023. All this, I think it's appropriate given the profitability in the sector that our business and our sector, OFS sector, it gets comfortable with pursuing top of the cycle margins, but it's only appropriate.
I would, once again, thank you -- thank all of our professionals for the fantastic execution during Q1. And note that during a very busy time, we continued to have success advancing our digital and operational optimization strategies. I would highlight that our team is a very, very proud participant in the energy supply network, which has, most recently, been gaining respect globally.
Final comment would be, we're very pleased to share that we've released our first ESG report. This report clarifies the company's progress and ongoing commitment to supporting our clients with emissions reductions. It speaks to our track record of strong governance. And it establishes our commitment to our team through safety and our culture. That brings my comments to a close. Back to you, the operator.
[Operator Instructions]
Our first question today is from Cole Pereira with Stifel.
Congrats on the quarter. I just wanted to refer back to the commentary on Canada. So talking about it being largely sold out. Pricing, obviously, improving on a net basis. I mean, I'm just wondering, it's obviously fair to think that, that Q3 EBITDA could be equal to, if not, materially higher than Q1 here?
Cole, it's Steve here. Great question. Just what I had mentioned, we're definitely -- we have minimal white space on our calendar for Q3. And yes, we probably expect that quarter to be equal or higher than our Q1 EBITDA numbers.
Okay. Perfect.
Yes. I mean that's the Canadian business how it has been. Of course, our U.S. business definitely seeing higher traction from a pricing standpoint and utilization has been there already. So the additional revenue, of course, will help from the bottom line perspective.
Okay. Great. And just coming back to your comments on it being a record quarter for the U.S. business. I mean I assume that's for a record Q2. I mean if I look back to 2019, 2018, this business was generating, call it, $15 million, $25 million of EBITDA a quarter. I mean are you kind of looking at a different metric other than EBITDA with that comment? Or is there some potential to get within that range?
Sorry, is it for the U.S. business, Cole?
Yes. Sorry, just for the U.S. business.
Yes. I think if we take a look at our recent -- the recent context, we're certainly going to be much stronger than we've been there before. There's potential for us to get back to those 2018 numbers, but I don't think that's right now unless Steve you got some additional thoughts on that.
Yes. I don't think we'll quite hit that, Cole, but I do see as Regan had mentioned, like pricing is changing almost on a daily basis there. I mean there is no frac capacity available in the U.S., call it, for a frac crew today, I bet you'd be the one to get a crew in place.
Okay. Perfect. Go ahead.
Sorry, it's probably we're loading -- as we look at our results month-over-month and annualize the EBITDA per fleet, we're comfortably inside the mid-teens now on EBITDA per fleet. And all indications are that's going to continue if not improved.
Okay. Got it. No. That makes sense. And I'm just wondering, are you able to provide any goalpost around how we should be thinking about working capital changes in Q2 and then in the second half of the year, acknowledging there's obviously still some uncertainty?
Yes. So we're going to see -- I mentioned there in my commentary, we had a bit of a lull and we talked about that in the MD&A as well, in kind of April and early May in our Canadian business. So we're seeing some harvest come back into our accounts. So we actually -- we'll touch 0 in our accounts, but we're going to build that right back up again here as we ramp up here.
So I would say on a net basis for Q2, we'll see a harvest there, and then we'll see a bit of a build out again in Q3. And then kind of depending on how Q4 goes with that end of the December kind of time frame, we're looking really deeply into the crystal ball here, but I expect we'll see a bit of a recovery there. So on a net-net basis, I guess, over the year, I would say, that Q1 is probably a high point and will probably on a net basis through the year will come down a bit against that.
The next question is from Keith MacKey with RBC.
Maybe just talk about given the current and future price increases -- certainly have talked about where you kind of expect margins to see. But really where -- going into Q2, 3 and 4, how should we be thinking about margins on a consolidated basis relative to Q1?
I mean our expectation is, it's going to improve. I mean do you want more detail on that. I mean I think the U.S., as we mentioned, is showing improving results month-over-month. And our clients are very cooperative in Canada as we seek good and improved end margins as we move through the year.
I can't remember which one of our drIllers said it, but they were talking about pricing increases to the point of -- I don't think it was pamper or maybe it was not comfortable, I can't remember the exact wording. But the drillers who typically lead with these things, they're pushing that pricing narrative extremely strongly down in the U.S. And if you recall from the U.S. bumpers, the message is, we're full and the prices are going up and up and up. So we're happy to that. I mean we're not a big presence in that market the way we are in Canada, but we're happy that hits your wagon to that train. And on the U.S. side or Canada side, strong pricing commentary coming out of our Canadian peers as well. So we expect continued sequential improvement.
Perfect. No, that's helpful. Maybe just secondly, on the balance sheet a little bit. So certainly, operationally, the outlook for margins and EBITDA is quite strong with capital not expected to go up too, too much. So it sounds like there should be some free cash flow through '22 and likely '23. But how are you thinking now about the term loan maturity into 2023? And with refinancing that and maybe just a little bit more about your approach there? And if when we should expect to see something happen on refinancing of that?
Yes. So our facility goes -- it expires, I guess, at the end of July of 2023. We've had preliminary conversations with our lenders quite constructive around kind of our proposed structure. Our goal internally -- and it is certainly something we're communicating to the market as well as that we've got a strong debt reduction focus. The best way for us right now to add value to our shareholders is to pay down that debt to give us that flexibility when that inevitable downturn comes again.
So I anticipate that we'll have some news coming out towards the end of this quarter, maybe it's the beginning of Q3, around that. The free cash flow that we're starting to generate is meaningful, and we should be able to knock that debt down to a much more manageable number. We're around 2.5x on a trailing 12 basis, I think, if I recall correctly, in Q1. And if you kind of line that out to where we expect to be towards the end of this year, we'll be significantly better than that with 2023. The forecast if those come to fruition, then we'll be in a much healthier position from a debt perspective.
Our next question is from Waqar Syed with ATB Capital Markets.
Okay. Congrats on a great quarter. My question -- first question relates to input inflation. Are you seeing any stability in inflation that you're experiencing? And you talked about some of the price increases that you're getting. Could you also talk about the net price increases that you're getting versus just the gross price increases?
So Waqar, I'll start just by touching on that, the gross versus net. So when we raised prices in Q1, it was a bit reactive to kind of what we saw in January. And I say reactive, we were pushing the price narrative continually through Q4 and into January and we thought we were staying out of it until we saw how hard inflation kind of hit in that month. So if we take a look at Canada, it was, I think, this quarter around 10% to 15% in the MD&A. Our debt number on a quarterly basis, there was probably around $5 million, and in the U.S., it was -- we're now 20% to 25% range. But again, inflation -- limits of that -- inflation and I'm going to say timing as well limit that to around that 5%.
We'll see benefit coming on that. But Steve is going to talk to you in a second about where we're seeing all those pricing pressures. It's not going away, and it's something that we're continually talking to our clients around end tickets. Our sales guys are getting tired of the revolving door, going back to their clients, but it's -- like, we're seeing the same thing coming through our front door, and we have to pass those price increases on.
Sorry, Waqar. I'll just add on to what Klaas was commenting on. Obviously, our main focus is making sure that we have a happy employee base, and that was our first -- obviously, we had to increase wages there, which was well needed. It's been a long time since our field professionals were receiving an increase. So of course, we implemented that into our business starting at the beginning of the year. And from that, of course, we saw increases from a supply chain standpoint. So higher profit costs, higher fuel, of course, everybody is filling up their vehicles today. We know the price of that, that's obviously impacting our business. And then, of course, the biggest thing was our proppant. And so our clients have all been accepting of these changes and these price increases.
And obviously now Klaas had mentioned just from a net standpoint, we need to get margin back from the business so that we can continue to invest in the capital intensity of our equipment. So our clients are understanding that and have been really, really willing to work with us on those price increases.
I'll give you a couple of examples that we talked about yesterday. So Goodyear tires just gave us a 20% price increase forward where we buy a lot of our light-duty trucks. They said we probably will only get 85% of our order. [indiscernible] is hardly even willing to commit to any kind of pricing even if we give them a PO. Kenworth, it will take 18 to 24 months to get a tractor loaded today, and the list goes on.
So there's been a feeling that we may have caught up to inflation, but there -- it feels like there may be another leg coming. And if you think about the pressures that we're facing in labor and everything else, every other business is doing the same thing, talking about raising wages. And this is where we get into that whole economic discussion around inflation -- and these are transitory, and our feeling is, it's not transitory, and we're going to continue to see that pressure here for the coming year.
Okay. Then could you also talk about the coiled tubing market? What are you seeing there in terms of pricing?
Waqar, it's Steve here. All of this started in the U.S. market, in particular, the Permian. There's probably an oversupply still today in the Permian market when it comes to coiled tubing completions. So we've been a little bit harder to move price. We've been very successful. We've locked up 2 out of our 3 coiled tubing units on long-term contracts with a large client in that area. And we've been able to see 25% to 30% price increases there for the remainder of the year. So that's been helpful for our business.
As we move north into the Rockies and into the Bakken, we've had a few competitors disappear in that area, and we've been able to increase prices perhaps even a little bit higher than that. But later on in the quarter, so we didn't really realize that until really kind of March time frame. So we expect to see that obviously coming into Q2. In the Canada, there's such a limited amounts of, I guess, competitors in this space, and we had high utilization, of course, in the Canadian market, and I typically see that going, obviously forward into Q2 and Q3. And it has been leading the price march on our coiled tubing business since we're beginning to enjoy the market share for that.
And your U.S. equipment, you're already running at a very high utilization level. How much room do you have to increase equipment in Q3 and Q4?
Yes. I mean we would look at increasing it to just one additional fleet. If we see the demand there, we'd be wanting to secure a long-term contract before we even look at that, Waqar. One thing that we don't really -- we don't talk about, and Regan mentioned it in his closing comments about our IOR technology, we are starting to see some traction there, and we expect to see some additional traction as we get better well results or more data from that well that we completed. And that would definitely help both from a top line and bottom line perspective in the U.S., going forward.
Could you maybe expand on that a little bit? I know you were doing some field tests on that technology. Could you maybe provide some more color?
Yes. I mean the job itself was extremely successful. We were able to see some diversion happen, which was exactly what we wanted, while results initially so far have been holding in there, and in fact, it has increased the field around it. So pretty early on right now, Waqar, but we're extremely ecstatic about the level of safety that was performed on the job and the high level of execution. We had a number of clients or potential clients that were waiting for this first job to be done. And now they're talking with us about some work that they want to put in the calendar.
So I think a couple of the other more technical aspects. Part of this process is the chemical cocktail that is intended to change the wet-ability for the surface tension of the reservoir and liberate water, only water, and of course, change the viscosity, if you will. We've seen success with that part of the technology as well, which is very encouraging. It validates the modeling.
And the other piece that we expected, but we're very pleasantly surprised was how effective it was at cleaning up wax in the wellbore. The well -- the tubing -- the wellbore itself was highly plugged with wax, therefore, doing more damaged due to deferred plugging due to the wax. Fluid that we injected was very, very effective to that, essentially dissolving and liberating that wax problem. So another really encouraging side benefit from the technology.
Do you think the customer would wait for another -- would wait for 90 days or so to get production data or more like 180 days? Or how long do you think the customer would feel comfortable with the dataset to go ahead with additional programs?
I always think of these 90 days as the time frame we're thinking, but Steve referred to other clients that we're in advanced discussions with working through just sort of administrative-type hurdles at the moment. So we have several wells in the queue that we expect to -- and start getting results in the coming weeks and months.
And just my last question, Klaas, in terms of working -- cash flow from working capital changes. What's your expectations for Q2 and for the second half of this year?
Yes, we'll get a harvest coming out of Q2, Waqar? And then as we go back into Q3, we'll probably build up that a little bit. And then in Q4, we'll see probably a bit of a harvest to come through there against -- I mean, operationally, if we're -- if we see the ramps that we're optimistically seeing, we may actually see a bit more of a build in Q4 as winter activity really begins to pick up. But for now, we're kind of on the conservative side saying we'll model a bit of a recovery there at the end of Q4.
[Operator Instructions]
Our next question is from John Daniel with Daniel Energy Partners.
Just a question on the -- Steve, I think you mentioned the bolt-on kits on the dual fuel. Can you remind us what percent of the fleet has that capability? And what the plans are to expand that capability?
Good question, John. So we have basically 22 pumpers in our U.S. fleet out of 80 that have this bolt-on kit. We -- Klaas had mentioned some of our capital expansion plans that we've got approved from our Board yesterday and now we would be adding some additional kits for our U.S. business. So if you kind of look at it, we're around 60,000, horsepower we'll get up to close to 80,000 horsepower by the end of Q3.
Got it. And then just curious if you can play -- the kit, the bolt-on, is that from the engine OEM or is that from a third party?
It is from a third party. It was a proven system, actually, used in a mining operation, same engines that we use on our frac pumps that we're using on haul trucks from a mining perspective. So the technology is proven in that aspect, and we were the first one to bring it into the North American market. And as I mentioned before, we saw substitution percentages average around 70% and upwards of 75% to 80% because it is a direct injection versus a fumigated system that a typical Tier 2 OEM would have.
Okay And then the final one for me. I think you mentioned the Kenworth lead times of 18 to 24 months to secure new tractors. Is that what -- did I hear those numbers correctly?
Yes. John -- that's feedback from our ops guys there in that meeting just recently.
If you wanted -- sorry, John, I'll just add on to what Klaas comments were. I mean, obviously, a lot of our tractors would be special order, particularly holding coiled tubing in as heavy loads, so large transfer cases, heavy haul units, and those custom tractors are -- you're at least 18 months out for that.
Okay. I know -- you don't have to speak for the industry. I'm asking this question anyways, but are we looking at a situation where the trucking situation gets worse? I mean could you guys put lots of miles on tractors today, right? You can't be -- spare parts are harder to get. What's going to happen? What's your review from 9 to 12 months from now on just how you move equipment, whether it be sand or whatever? I'm just curious to get your thoughts on that.
Good question. I mean, as you know, I mean, most of our -- I mean, all of our tractors on the frac side typically will sit on location for 3 weeks, 4 weeks at a time, not putting on any miles. So we have a fleet of tractors that are maybe age-wise old but obviously able to -- we don't have lots of life at them. So -- and I talked about our idle reduction control system that we are -- we have 10% of our fleet in Canada. We're adding some more capacity there. So these kits are excellent from an ESG standpoint where the units aren't running. They're shutting off, and it allows that flexibility to pull that track on road and begin hauling ourselves. We saw that in Q1 in Canada, and we'll continue to invest in that technology going forward in North America.
We have no further questions at this time. I'll turn it back to the presenters for any closing remarks.
Thank you, everyone, for joining. We appreciate your interest. Have a good day.
Ladies and gentlemen, this concludes today's conference call and webcast. Thank you for participating. You may now disconnect.