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Good morning, ladies and gentlemen, and welcome to the Ensign Energy Services Inc. First Quarter 2022 Results Conference Call. [Operator Instructions] Also note that the call is being recorded on Monday, May 9, 2022. And I would like to turn the conference over to Nicole Romanow. Please go ahead.
Thank you, Sylvie. Good morning, and welcome to Ensign Energy Services' first quarter 2022 conference call and webcast. On our call today, Bob Geddes, President and COO; and Mike Gray, Chief Financial Officer, will review Ensign's first quarter highlights and financial results, followed by our operational update and outlook. We'll then open the call for questions.
Our discussion today may include forward-looking statements based upon current expectations that involve several business risks and uncertainties. The factors that could cause results to differ materially include, but are not limited to, political, economic and market conditions, crude oil and natural gas prices, foreign currency fluctuations, weather conditions, the company's defense of lawsuits, the ability of oil and gas companies to pay accounts receivable balances or other unforeseen conditions, which could impact the demand for services supplied by the company.
Additionally, our discussion today may refer to non-GAAP financial measures such as adjusted EBITDA. Please see our first quarter earnings release and SEDAR filings for more information on forward-looking statements and the company's use of non-GAAP financial measures. With that, I'll pass it on to Bob.
Thanks, Nicole, and thank you all for joining our call today. As you know, Ensign Energy Services is one of the largest global energy service provider spanning 4 continents and 8 countries, employing over 4,000 people with $3 billion of assets consisting of 245 drilling rigs, 100 well service rigs and directional drilling business and an NPV business line, also a rentals division. With the world catapulted from a COVID-induced demand pinch now to a global supply challenge, the result of sanctions from the Russian and Ukraine conflict, the world needs to bring back production and drill holes in the ground to access said energy for a recovering world economy. Ensign's first quarter results is delivering right on schedule as planned and is up sequentially year-over-year and quarter-over-quarter. This industry is coming from all-time low rates and is climbing the hill rather quickly to recapture pricing, while continuing to deliver the value proposition our clients have grown to expect from Ensign over the years.
We continue to see activity manifest itself into quarter-over-quarter pricing leverage, which is teeing up accelerated pricing momentum as we move forward. While we had little direct COVID effects on the business in North America in Q1, we still had COVID affect our activity in our Australia operation, which hampered our first quarter results slightly.
While the drilling industry is able to move -- to finally move pricing up to narrow the gap between rates and value delivered for our services, the question is how cost inflation is affecting our margins? The question then becomes, how sticky is the margin increase? With operational costs, net of labor costs that are exposed to inflationary effects representing about 20% of the sticker day rate, witnessing a quarter-over-quarter projected cost inflation of roughly 5%, the effective margin drag for the business is really only 1% quarter-over-quarter. In other words, 90% of a Q-over-Q rate increase is sticky and makes its way right to the gross margin bottom line. Keep in mind that most of our contracts and certainly all contracts in North America contain a crew wage escalation clause that covers any labor increase as a pass-through with an increase to the base day rate. Offsetting any cost inflation is, of course, overhead per day efficiency. With overhead fixed cost spread over more operating days, our margin gets more torque and easily offsets any operational cost inflation creep.
We continue to focus on margin versus market share as the most productive and profitable approach and an obvious uptick in elastic demand market. We also announced the sale of 2 idle Mexican rigs that were cold stacked 3,000 horsepower rigs, purpose built for the deep gas Mexican market, which came to us via acquisition a few years back. We have no desire to expand operations into Mexico and being laser-focused on debt reduction, the opportunity to sell these assets was acted on.
Also very happy to report that we had a record 0 recordable incidents in 4 of our 5 business units. The application and stringent application of standard rig operating procedures, coupled with our highly effective standardized training program, the GSS, allows us to continue to train new recruits into a safe and efficient work environment. I'll turn it over to Mike for financials.
Thanks, Bob. Over the first quarter of 2022, the operating environment for the oil and natural gas industry continue to be positively supported by strong commodity prices and demand for both crude oil and natural gas. Ensign's results for the first quarter of 2022 reflects positive improvements to oilfield services activity, day rates and financial results year-over-year. Operating days were up in the first quarter of 2022 with Canadian operations experiencing an increase of 1,882 drilling days; United States, a 43% increase; and international operations showing a 2% increase compared to the first quarter of 2021.
The company generated revenue of $332.7 million in the first quarter of 2022, a 52% increase compared to revenue of $218.5 million generated in the first quarter of the prior year. Adjusted EBITDA for the first quarter of 2022 was $70 million, a 40% increase from adjusted EBITDA of $49.9 million in the first quarter of 2021. The 2022 increase in adjusted EBITDA can be primarily attributed to improved industry conditions, increasing both drilling and well servicing activity.
In addition, operational activity increased as a result from the company's acquisition of 35 land-based drilling rigs during the third quarter of 2021. Offsetting the increase was the elimination of the Canadian emergency wage subsidy program in 2021 by the Government of Canada, of which $4.7 million was received in the first quarter of 2021.
Depreciation expense in the first quarter of 2022 was $70 million, 1% lower than $71 million for the first quarter of 2021. G&A expense in the first quarter of 2022 was 18% higher than in the first quarter of 2021. G&A expenses increased in support of increased operational activity, the end of the Canadian emergency wage subsidy program, the full reinstatement of salary rollbacks and annual wage increases.
Net capital proceeds for the quarter were $10.8 million, consisting of proceeds from dispositions of $42.7 million. Offsetting the proceeds were $8.1 million in upgrade capital and $23.9 million in maintenance capital for a total of $32 million. Included in dispositions was the sale of 2 3,000-horsepower AC drilling rigs that were cold stacked in Mexico for proceeds of USD 34 million. We are now targeting $115 million in capital expenditures for 2022, and we'll continue to look at projects with the appropriate payouts.
Long-term debt net of cash was reduced by $61.9 million since year-end and debt reduction continues to be our focus. On that note, I will return the call back to Bob.
Thanks, Mike. So we'll provide an operations update, starting with the U.S. In our U.S. business unit, we own and operate a fleet of 88 high-spec drill rigs across the U.S. platform and also 50 well service rigs focused on the Rockies and California markets. We also run a tight directional drilling business in the Rockies. The U.S. generates over 54% of our revenue and our consolidated EBITDA. The U.S. is currently running 50 rigs out of 88 high-spec rigs with visibility to 60 in the third quarter and 65 by year-end.
We just recently completed the upgrade of 9 high-spec triples into super-spec triples in the U.S. Permian market, which will produce incremental results starting third quarter. Our super-spec triples are today being priced into the low 30s range. We have the ability to address additional shovel-ready upgrade projects, which would require notional incremental growth capital paying out in less than 12 months. But let me be perfectly clear, as industry recaptures its pricing platform and claws its way back up, the focus remains margin versus market share. While on the subject to CapEx, we have identified an additional $5 million of incremental growth, quick-pay projects on both sides of the border which will guide, as Mike pointed out, our '22 CapEx, up only about $5 million from our last call to about $115 million. California continues to be affected with the lack of well licenses, which is keeping 4 to 5 of our rigs from going to work anytime soon. Nonetheless, we're making up the delta by activating and contracting other rigs across our diverse U.S. operational base. Our directional drilling business in the U.S. is Rockies-centric and basically works our turnkey projects with our drill rigs. Our U.S. well service business operates in the Rockies and California markets and is the premier service provider in both these areas. This business continues to enjoy high utilization, 80%-plus and is able to attract rate increases quarter-over-quarter. Moving up to Canada. With the acquisition of the Nabors Canadian assets last August, Ensign has the largest fleet of drill rigs with 123 high-spec and conventional rigs in Canada. In the first quarter, we had expectations that the rig count might hit a peak of 300 rigs, and hence, we became an early market price maker, raising prices out of the gate in January. What happened is that the rig count hit a peak of only 220 and our first quarter results were slightly buffered as a result.
We have 25 high-spec triple and double rigs operating today over breakup on pad works, with another 25 starting up next month, with a good chunk of our rigs coming off contract in June, we have raised rates about 20% to 25% across the board, exiting breakup depending on the rig type. We are seeing leading-edge bid rates for the high-spec triples close to 30,000 and low 20s for the high-spec doubles. These rates are still below the cost inflation adjusted highs of mid-30s and mid-20s pre-COVID for the high-spec triples and high-spec doubles, respectively. As I pointed out earlier, our Canadian drilling business unit operated without any recordable safety incidents. To execute in a winter season with a quick ramp-up in activity that we see in the Canadian region every year is a testament to our Canadian team. We also operate a fleet of 53 well service rigs, which operate with about 60% excess capacity that can expand into this building market. Our directional drilling business had a tough first quarter, but is exiting breakup with about 15 jobs lined up at entire rates. Unless you own rotary steerables, which is only a handful of the directional drilling companies in Canada, the basic directional drilling business is still a crowded space. We also started to expand our rental fleet within Chandel Rentals with specialty high-torque drill strings that clients are requesting for longer reach laterals. Anytime a client requests a special drill stream with the rig, we put that outside of the rig day rates and charge a rental price.
Moving to international. Our international business unit outside of the COVID-related well scheduling situation in Australia came in as planned for the quarter. Kuwait continues to operate operationally in the upper decile with our client. Our 2 Bahrain rigs are in the final stages of recontracting for another 3-plus year contract. Argentina has put a second deep high-spec rig to work in the Neuquén field this second quarter. We are slowly seeing bid activity improving in Argentina, but it's certainly not at the same pace as North America. Venezuela is getting teased with possible OFAC loosening, but there is nothing to report at this time. All our rigs are cold stacked in secure yards there. Australia has been stuck at 7 rigs, mostly through all of the COVID time frame and is just seeing some light at the end of the COVID tunnel. We have worked for an additional 2 rigs that has been delayed, and we are in the final stages of securing contracts for 1 to 2 incremental rigs that would start up fourth quarter, most likely in Australia.
Drilling solutions technology, we continue to see high uptake for our EDGE drilling solutions technology suite, our drilling rigs control technology. We now have our EDGE AP, AutoPilot, platform on 42 of our rigs today and have an installed backlog of 3 months. We also introduced our EDGE eco monitoring reporting along with our EDGE eco proactive fuel management system, which reduces GHG emissions and fuel costs for our clients. All of these EDGE products are a la carte revenue stream opportunities that price out anywhere from $600 to $2,400 a day.
We also leverage our EDGE technology suite for our performance-based incentive contracts where we can make an incremental $3,000 a day at P90 metrics and up to $5,000 a day at P50 metrics. The sale for PB contracts is quite simple. We want to earn $0.30 of every $1 we save the client. This aligns with the notion that the drilling rig services is roughly 30% of the daily spread cost for the client.
With that, I'll turn it back to the operator for questions.
[Operator Instructions] And your first question will be from Waqar Syed at ATB Capital Markets.
Bob and Mike, what was the rig reactivation costs in the quarter?
Definitely not as much as we saw in Q4. We only, I believe, was one reactivation in the U.S. in the quarter. We'll see some reactivations in the next couple of quarters. So not material, but definitely not what we saw in Q4.
Okay. So just in that case, in Q2, how many rig reactivations are expected? And what will be the likely cost there?
So we've got 9 rig reactivation and upgrades that are occurring and those will hit mostly in the second quarter, Waqar. And they're, gosh, they're ranging anywhere from $750 million to maybe $1.5 million, somewhere in that range.
The majority of that is CapEx related as it relates to an upgrade.
Okay. So $750 million would be like, let's say, the OpEx impact? And the rest is a CapEx impact? Is that fair?
Yes.
Okay. That makes sense. Now in terms of thinking about SG&A costs going forward, is $10.9 million kind of run rate the right way to think about it? Or should we look at it from a percentage of revenue basis?
No. I think that $10.9 million, so that essentially $40 million to $45 million for G&A is probably a good number to have. We don't foresee really anything that's going to change on the increases. We've done a lot of work in the past to make sure that any increases in activity aren't seen with the large increase in G&A.
Yes. Our operating cost per day on the overhead side are probably dropping, Waqar, when we look at the budget to actual on days, probably almost $1,000 a day.
Yes. Okay. And then, Bob, in terms of margins, where do you think the margins could go up to? Let's think about like gross profit margins, so roughly could we get to 30% type gross profit margins in the coming quarters or years? Or how should we think about getting back what the peak margins are like?
Well, we certainly have got a lot of traction right now. I mean, coming out of the gate, we moved rates, as I mentioned, 20% to 25%. We signaled to our clients that to expect 10% quarter-over-quarter margins. As I mentioned in my preamble there, about 90% of that is sticky on the EBITDA side. So I think we're probably quarters away from getting close to 30%, I would sense, not years. Yes.
And that's a gross profit margin number, right, which is 24.3%-or-so in Q1?
Right, right.
Okay. Okay. And then in terms of -- Bob, you mentioned that there were some upgrades from super trip -- from triples to super triple AC rigs. Could you maybe provide some details on what kind of upgrade was that? What equipment was added? And what was the kind of cost to do an upgrade?
Yes. Generally, and it depends on the rig specific, there's rigs that the racking board is easily modified to 25,000-foot racking capacity. The top drives would have been scheduled in for a recertification. While we're doing that, we upgrade those for about another $200,000 to a high torque. Then we're -- any of the high-spec pipe that the clients are asking, the 5.5 pipe is always on the outside, and that goes for around $4,500 a day for those drill strings. The drill strings just aren't lasting as long as they used to because of all the re-steerables. We're getting a lot of excess wear on the tube, so that's happening.
The other component is we've got a good inventory of pumps, so adding a pump on to the rig is relatively easy. It's just the fitting it into the rig. And most of these high-spec rigs already have 7,500 psi fluid handling systems. So there's not much required there.
Okay. So how many rigs would be falling in that 1,500-horsepower AC 7,500 psi circulating systems with like that other 25,000-foot racking capacity? How many rigs in the U.S. would fall in that particular category?
It would probably be about 36 would be the -- what we would call our super-spec triple category.
In the U.S.?
Correct. Correct. In the U.S.
Right. Okay.
Yes. In Canada, there's not much bifurcation between the high-spec triple and what we'd call the super-spec triple in the Permian. There's just no bifurcation quite yet. Yes.
Okay. And in terms of the share-based comp that was -- your number was high, $10.4 million. Mike, going forward, what kind of a run rate should we be thinking about? And what were maybe some of the factors that drove that number high?
Essentially, it was a 100% increase in the share price. So for a run rate, it's really going to be dependent on how things kind of roll with the share price. So as of today, that stock-based comp would actually be a recovery with today's price. So you can't really get too much guidance on what that will look like.
The option grounds and everything are done end of March, start of April. So we have stuff roll off, stuff comes back on. So from the number of outstanding securities that would be mark to market, it's fairly neutral. So it's really just share-price driven.
Your next question will be from Aaron MacNeil at TD Securities.
Bob, you mentioned the 20% to 25% increase on day rates. And then I think you said doubles in the low 20s. I guess my question is, can you speak how pricing has evolved for that double asset class over the past year? And what do you see going forward just given the high utilization of AC triples in Canada?
Yes. Well, last -- I mean the Cardium Central Alberta oil market was quite decimated in the last few years, and the high-spec doubles, which we've got the highest market share of fleet capacity in Canada, I mean, it was down 13,000, 14,000 at one point, it started moving up last year in the '15, '16, we saw momentum getting into the high teens here in the first quarter and our current bids on our high-spec doubles are in the low 20s now, 20 plus.
Perfect. Mike, I know you've mentioned land sales in the past, but is there anything that's sort of high probability in the pipeline in terms of asset sales in order to kind of accelerate some of the debt reduction plans you have internally? And maybe you could also add, while you're at it, what you think working capital balances might -- how they might trend over the next couple of quarters?
Yes. For land, we have 2 properties up in this Q available for sale. Those are currently on the market. So I think there's -- we're starting to see some increased interest in that, so I don't think there'll be anything in the near term, but I believe in the future, we'll definitely see those properties start to move, which will definitely go towards the balance sheet and those are north of $30 million in total. So we can see some -- definitely some deleveraging from those assets transactions.
From a working capital perspective, I mean, Q2 is the definitely harvesting of the Canadian drilling winter season accounts receivable. So we'll see Q2 continue to build up our liquidity. And then we'll see kind of going into Q3, how things are shaping up, but Q2 definitely is one of our better quarters for collections.
Next question will be from Keith MacKey at RBC.
The first question would be on the rig activations in the U.S. You're now with the line of sight to 60 in Q3 and 65 by year-end is, I believe, what I heard. I think that's a little bit more constructive maybe than some of the U.S. peers that are forecasting for their own rig additions.
So can you maybe just talk a little bit about where you see those rigs going back to work? And essentially how you're able to outperform the market in terms of rig additions throughout the year?
So I mean if we're staying to the margin versus market share MO, we're not trying to put more rigs that are required into the market -- out into the market at a faster pace than anybody else, but certainly at an equal pace looking to claw back on the margins first.
I think, specifically, the areas -- the Permian is the area that's gathering the most amount of attention for us. That's where we've got our biggest upside. And maybe a couple of rigs into the Rockies region. As I mentioned, California is still hampered by some well license issues, typical California challenges, right?
Got it. Makes sense. And at the end of the quarter, you were in good standing with credit facility covenants, but fairly tight, I would say, on the senior debt-to-EBITDA covenant. Mike, can you just maybe talk about how you expect this to trend through the remainder of the year?
I know both the debt and the EBITDA are going to be moving parts to that. But how wide do you -- how wide of a margin do you expect to have on your covenants as the year progresses and you bring more rigs back into the field but also face some reactivation costs?
We're definitely comfortable with what we have. If you look, I mean, Q2 of the prior year, EBITDA was $45.6 million. If you kind of look at where consensus is, it's -- what is it 63.7% for Q2 of 2022. So you're seeing a significant increase in activity in EBITDA.
So the bank covenant is on a trailing 12. So as we drop the lower quarters from 2021, you'll see that covenants start to improve as we go out throughout the year. So we definitely have enough room for it and don't foresee any issues.
Got it. And just finally for me, if we think about your contract book and that proportion of long-term contracts that you've currently got. I know rates are moving up in Canada and the U.S., how are you thinking about longer-term contracts now? Do you think rates are still below where they need to be to sign a multiyear contract in these regions? Or is it starting to look pretty good?
So multiyear contracts are really a no go right now. We're anywhere where we've got a client who is looking for an annual contract, we're having ladders built in basically every quarter, and we'll do a present value and give a blended rate if they're really insisting on an annual number, and it will be quite a bit higher than the current quarterly rate that we're suggesting.
So when I look at, on an inflation-adjusted basis, most of this labor and other costs, our high-spec triples, we're getting in the low 30s before. And when you look at capital replacement, these rigs are all built in U.S. dollars, and you look at the degradation of the Canadian dollar, if we focus on that market specifically, these are almost $30 million rigs now.
And we've always mentioned that to get a reasonable rate of return, you need to have $1,000 of margin for every $1 million invested. And that holds true more particularly in Canada, where rigs don't get 365 days a year. They typically get 250, 275 days a year. So it's different than the U.S. So you've always got a little bit of a differentiation there. So on a net-net basis, I think before anyone would ever start to contemplate new builds, they're going to have to see day rates in the high 30s for the high-spec triples and the high 20s for the high-spec doubles. So we've got a ways to go.
Next question will be from John Gibson at BMO Capital Markets.
First for me is kind of touching on Keith's last question. If you look at the upcoming contract season, what percentage of your rigs under contract today would be at sort of legacy rates? And then maybe if we look into Q3, what percentage of rigs will be under contract at the higher pricing levels?
Right. In Canada, essentially 0. All of our contracts peel off right around breakup, which is pretty typical. Through the Nabors acquisition, they peeled off -- all their contracts peeled off in June, so we're in the middle of recontracting those at rates, what I mentioned. In the U.S., we try and get a cadence of 1/4 of the fleet every quarter, and we're probably close to that.
When I look at the U.S., International is a different flavor again. The Middle East, our Kuwait rigs are contracted to '25. Our Bahrain rigs are in the middle of being recontracted here for another 3 years. In Argentina, we have -- they were basically annual contracts. We're just the middle of recontracting one of them with a major -- with a rate increase.
The other one was -- already had rate increases into its short-term contract. And Australia is generally on annual contract basis outside of special project campaigns, but I would suggest that its cadence is pretty well blended through the year. It is not coming off in one particular month.
Is it fair to assume then that you'll see a pretty big step change in that revenue per operating day at least in Canada in Q3?
Oh, for sure. I think right across the board, except for the Middle East and Argentina, where we've got more stable or less beta contracts.
Got it. Second for me, can you talk about where field margins are at on your various rate classes? And then given some pricing increase in the back half of the year, could we go quite a bit north of 50%, you think?
We don't really do disclosure on those -- on the rig types, I guess. But I mean we're seeing, I think, broad-based. I mean all the rigs are definitely contracting up on -- from the day rate perspective. A lot of the, I'd say, inflationary costs like fuel and labor are really on the outside of the contract. So it's more of your [ ropes opened up ], that would impede on some of that. So you could say, a good chunk of the increases that we're seeing across the border will definitely go down to our margins.
Got it. And last one for me, sorry if I missed this, but you talked about the cadence of regulations in the U.S. Where do you see your rig count peaking in Canada in the back half of the year?
I think we'll get to 65, John, by the end of the year in Canada and in the U.S. So we're going to be mirroring each other.
[Operator Instructions] Your next question will be from Andrew Bradford at Raymond James.
I just want to revisit sort of the leading-edge rates a little bit, first in the U.S. And you sort of talked about north of 30,000 a day, which is not much different than what a lot of your competitors in the U.S. are talking about as well. And you have 36 super-spec triples as you indicated, so like how many of those rigs that you see are tracking that kind of rate?
Yes. As...
Sorry, just to interrupt you, Bob, just -- it's another way of asking, are all 36 of those rigs, are they attracting all the same rates that they all similarly expect?
Yes. They would all be working into those rates. I would suggest that certainly in the next 4 months that all of those rigs will be at those rates as our contracts are turning over and being recontracted. But the leading edge today, on those rigs, for a contract coming off and recontracting is in the low 30s. That's with pipe and the technology suite that they're used to on that rig continuing.
And fair to say that all 36 of those rigs, does that include the 9 that are subject upgrade right now?
Correct.
Okay. And so they are definitely all working in that 60-rig third quarter number or 65 fourth quarter number?
Right. The other thing we're finding is we've got 44 of the 1,500 -- I'm sorry, 46 of the, what we call the high-spec rigs that can be upgradable. And let me back up, of the 9, probably 4 of those would be the high-spec triple that are being pulled up into a super-spec category. So we'll end up with about 40 super-spec triples. But we're finding that the -- essentially, the U.S. business is sold out of the super-spec triples.
And so the operator is saying, "Well, what's your next class of rig?" And of course, the high-spec 1,500 is the next class of rig. And in some cases, the operator is saying, that will work just fine too. So the super-spec triples -- the most desirable is when they can't get it, the high spec triple is we're finding able to do similar work. It may not be able to do 4-mile laterals, but it can certainly do 3-mile laterals very cost effectively.
All these bells and whistles are nice to have when they're priced lower, not necessarily need to have in a lot of cases...
Exactly.
Which is kind of similar -- yes, in Canada, I think you alluded to the idea that you -- or maybe one of the previous analysts alluded to the idea that as demand increases for the higher-spec rigs in Canada, you're finding some pull on the higher-spec doubles. And so when we talk about the rates going from, I think you said 13,000 a day-or-so at the bottom to maybe just north of 20,000 and the low 20s today, is -- how many rigs does that apply to in your active rig mix now?
So in Canada, we've got -- let me see here, we've got 30 of the high-spec doubles in Canada that fall into that category, and we have 44 conventional doubles. And some of the conventional doubles are very close to high-spec doubles. Some of them are just missing a 7,500 psi system, which is easily upgradable. We've got one rig, in fact, that a client has agreed to pay a surcharge over the next 10 months, and we're adding the 7,500 psi system onto it.
So that basically puts us at a fleet of 76 -- I'm sorry, 74 doubles, half of them being high-spec doubles. And the high-spec doubles gets further bifurcated, some of them have self-moving systems on them. And those ones are going for around the low 20s. We typically add $2,000 a day for our self-moving capability on whatever rig it might be.
But of those 74 rigs, how -- can you ballpark for me like how many would be in your rig mix? Maybe not today, but I mean, would you anticipate being in your active rig mix early in the summer?
The -- certainly, the biggest uptick has been on the high-spec doubles where we've had capacity to increase. I would suggest that we're probably going from 15 to 20 to 25. We'll probably be sold out of our high-spec doubles here going into the fourth quarter based on some of the initial conversations we've been having with certain clients.
That's encouraging. And I don't want to stretch us too long here, but you had also indicated earlier on that a lot of the neighbor's rigs contracts were rolling at the end of June. Would those contracts have already had price escalators built into them to accommodate cost inflation that you've seen to this point such that the increment -- some of that increment will already be accommodated?
Yes. Sorry, Andrew. Yes, they were at prices set over 1.25 years ago. The cost escalations are afforded by the [ CADC ] contract, and they're all on [ CADC ] contracts. So labor escalations have passed through and any other general industry increase that you may see as a pass-through as well.
So does that -- so that 20% to 25% price increase that you had mentioned, is that at this -- and then you said 10%, I think you said net of cost. Is that 20% to 25%? Like should we be thinking about that as notionally around $5,000 a day bump to your margin on those rigs? Or is that the top line bump, yes?
No, that's the margin bump. Yes. Yes. My point was that labor is the single biggest cost, but it's covered by contract escalation. If we assume $4,000 a day as an operating cost on a triple and you get 5% inflation as you're talking $200, at $200 on, let's say, a 20,000 day rate is 1%.
So if you use that simple math, the point being that we are expecting some cost inflation. We found in the first quarter of 2022, our Canadian business unit was able to hold costs through the quarter. But I think it would be unreasonable to think that there won't be some cost inflation. So I was just trying to put it into perspective. To your point there, John -- or Andrew, about in that example, about $5,000 on the high-spec triples is the increase in the margin, yes.
Okay. And I'm sorry to labor the point, but subsequent cost increases, even if it's just labor, will those be incremental to that new rate? Or is that you're sort of bumping the price to accommodate future cost escalation?
The labor is a complete pass-through, operational cost increase. And if you pick a number of $4,000 a day and 5% quarter-on-quarter, you're getting about $200 a day margin reduction from that. That's it.
Okay. Last question for me, I promise. It just relates to customer retention, particularly within your U.S. fleet. Are you finding that as contracts roll the rig is changing customers? Or is it tending to stay with the customer? And do you have a preference for one or the other when it comes to rate bumps?
Yes. Well, we've got lots of long-term customers. We haven't lost a good client because of rate bumps. They all quite understand what's been happening. I mean, we're drilling wells in 1/3 of the time that we did 5, 6 years ago. So we've been creating real value to the client. They understand the market, they understand the wage increases for the crews. They also understand the great safety record we're continuing to deliver.
We also are finding, in the U.S. more so in Canada, a lot of private companies, emerging companies and names we haven't heard before. But we're certainly not losing any clients with our rate increases.
So you're indifferent then?
Exactly.
Thank you. And at this time, we have no further questions. Please proceed with closing remarks.
All right. Well, thanks, everyone. The entire industry has come through arguably the most challenging times it's ever seen. And while rates suffered as a result, it climbed back to reasonable returns on the assets invested continues. While we claw back our rates to pre-COVID numbers and notwithstanding while we are clearly in an inelastic demand market, we will continue to focus on delevering -- on delivering and delevering value to our client base and continue to focus on safety for our professional crews out in the field.
Look forward to our next call in 3 months' time. Thank you.
Thank you, sir. Ladies and gentlemen, this does indeed conclude your conference call for today. Once again, thank you for attending. And at this time, we do ask that you please disconnect your lines.