Good morning, ladies and gentlemen, and welcome to the Ensign Energy Services Inc. First Quarter 2022 Results Conference Call. At this time, all lines are in a listen-only mode. Following the presentation, we will conduct a question-and-answer session. If at any time during this call you require immediate assistance, please press star zero for the operator. Also note that the call is being recorded on Monday, May ninth, 2022. Now 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 defensive 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 providers spanning four continents and eight countries, employing over 4,000 people with CAD 3 billion of assets consisting of 245 drilling rigs, 100 well service rigs, a directional drilling business, and an MPD 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 that 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 Australian operation, which hampered our first quarter results slightly. While the drilling industry is able 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 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 true 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 costs 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 in an obvious uptick in elastic demand market. We also announced the sale of two 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. Having 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 zero recordable incidents in four of our five 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 continued 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 CAD 332.7 million in the first quarter of 2022, a 52% increase compared to revenue of CAD 218.5 million generated in the first quarter of the prior year. Adjusted EBITDA for the first quarter of 2022 was CAD 70 million, a 40% increase from adjusted EBITDA of CAD 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 Canada Emergency Wage Subsidy in 2021 by the government of Canada, of which CAD 4.7 million was received in the first quarter of 2021. Depreciation expense in the first quarter of 2022 was CAD 70 million, 1% lower than CAD 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 Canada Emergency Wage Subsidy, the full reinstatement of salary rollbacks, and annual wage increases. Net capital proceeds for the quarter were CAD 10.8 million, consisting of proceeds from dispositions of CAD 42.7 million.
Offsetting the proceeds were CAD 8.1 million in upgrade capital and CAD 23.9 million in maintenance capital, for a total of CAD 32 million. Included in dispositions was a sale of two 3,000-horsepower AC drilling rigs that were cold stacked in Mexico for proceeds of $34 million. We are now targeting CAD 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 CAD 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. 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 nine 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. 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 of CapEx, we have identified an additional CAD 5 million in incremental growth, quick pay projects on both sides of the border, which will guide, as Mike pointed out, our 2022 CapEx up only about CAD 5 million from our last call to about CAD 115 million. California continues to be affected with a lack of well licenses, which is keeping four to five 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 work, 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%-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 CAD 30,000 and low 20,000s for the high-spec doubles. These rates are still below the cost inflation-adjusted highs of mid-30,000s and mid-20,000s 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 and at higher 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're also starting to expand our rental fleet within Chandelle Rentals with specialty high-torque drill strings that clients are requesting for longer-reach laterals.
Anytime a client requests a special drill string 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 Burgan with our client. Our two Bahrain rigs are in the final stages of recontracting for another three 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 this time.
All our rigs are cold stacked in secure yards there. Australia has been stuck at seven 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 two rigs that has been delayed, and we are in the final stages of securing contracts for one to two 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 Autopilot platform on 42 of our rigs today and have an install backlog of three months. We also introduced our EDGE ECO Monitoring, along with our EDGE ECO Proactive Fuel Management System, which reduces GHG emissions and fuel costs for our client.
All of these Edge products are a la carte revenue stream opportunities that price out anywhere from CAD 600-CAD 2,400 a day. We also leverage our Edge technology suite for our performance-based incentive contracts, where we can make an incremental CAD 3,000 a day at P90 metrics and up to CAD 5,000 a day at P50 metrics. The sell for PB contracts is quite simple. We want to earn CAD 0.30 of every dollar we save the client. This aligns with the notion that the drilling rig services is roughly 30% of the daily spread costs for the client. With that, I'll turn it back to the operator for questions.
Thank you, sir. Ladies and gentlemen, if you would like to ask a question, please slowly press star followed by one on your touchtone phone. You will then hear a three-tone prompt acknowledging your request. If you would like to remove yourself from the question queue, please press star followed by two. If you are using a speakerphone, we do ask that you please lift the handset before pressing any keys. Please go ahead and press star one now if you do have a question. Your first question will be from Waqar Syed at ATB Capital Markets. Please go ahead.
Thank you for taking my question. 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 it was one reactivation in the U.S. in the quarter. We'll see some reactivations in the next couple of quarters. Non-material, but definitely not what we saw in Q4.
Just in that case, in Q2, how many rig reactivations are expected? What will be the likely cost there?
We've goot nine rig reactivation and upgrades that are occurring, those will hit mostly in the second quarter.
Yes.
Waqar, they're ranging anywhere from 750 to maybe 1.5, somewhere in that range.
The majority of that is CapEx related as it relates to an upgrade.
Okay. 750 would be like, let's say, the OpEx impact, and the rest is a CapEx impact? Is that fair?
Yeah.
Okay. That makes sense. Now in terms of thinking about G&A costs going forward, is CAD 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%, so that essentially CAD 40 million-CAD 45 million for G&A is probably a good number to have. We don't foresee really anything that's gonna 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 a large increase in G&A.
Yeah, our operating costs per day on the overhead side are probably dropping, Waqar, when we look at budget to actual on days, probably almost CAD 1,000 a day.
Yeah. Okay. Bob, in terms of margins, where do you think the margins could go up to? Let's think about like gross profit margins. Roughly, could we get to 30% type gross profit margins in the, you know, coming quarters or years? Or how should we think about like the, what the peak margins are like?
Well, you know, we certainly have got a lot of traction right now. I mean, coming out of the gate, you know, we moved rates, as I mentioned, 20%-25%.
Okay.
We signaled to our clients that, you know, to expect 10% quarter-over-quarter margins. As I mentioned in my preamble there, about 90% of that is sticky on the EBITDA side. You know, I think we're, you know, we're probably quarters away from getting close to 30%, I would sense, not years. Yeah.
That's a gross profit margin number, right? Which is 24.3% or so in Q1.
Right. Right.
Yeah. Okay. In terms of, Bob, you mentioned that there were some upgrades 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?
Yeah. Generally, it depends on the rig specific.
Okay.
There's rigs that the racking board is easily modified to 25,000-foot racking capacity. The top drives would've been scheduled in for a recertification. While we're doing that, we upgrade those for about another CAD 200 thousand to a high-torque. 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 CAD 4,500 a day for those drill strings. The drill strings just aren't lasting as long as they used to because of rotary steerables. We're getting a lot of excess wear.
Mm-hmm.
On the tube. That's happening. The other component is, you know, we've got a good inventory of pumps, so adding a pump onto the rig is relatively easy. It's just the fitting it into the rig. Most of these high-spec rigs already have 7,500 PSI fluid handling systems, so there's not much required there.
Okay. How many rigs would be falling in that 1,500 horsepower AC, 7,500 PSI circulating systems with like, you know, that 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 US?
Correct. In the U.S.
Right. Okay.
Yeah. 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.
Right.
Bifurcation quite yet. Yeah.
Okay. Fair enough. In terms of the share-based comp, that was a you know number was high, CAD 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. For run rate, it's really gonna be dependent on how things kind of roll with the share price. As of today, that stock-based comp would actually be a recovery with today's price. Like, you can't really get too much guidance on what that would look like. The option grants and everything are done end of March, start of April. We have stuff roll off, stuff comes back on. From the number of outstanding securities that would be mark-to-market, it's fairly neutral, so it's really just share price driven.
Okay. Great. That's all I have. Thank you very much.
Thanks, Waqar Syed.
Your next question will be from Aaron MacNeil at TD Securities. Please go ahead.
Hey, morning all. Thanks for taking my questions. Bob, you mentioned the 20%-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's evolved for that double asset class over the past year? What do you see going forward, just given the high utilization of AC triples in Canada?
Well, I mean, the Cardium Central Alberta oil market was quite decimated in the last few years. The high-spec doubles, which, you know, we've got the highest market share of fleet capacity in Canada. I mean, it was down, you know, CAD 13,000-CAD 14,000 at one point. It started moving up last year. Into the CAD 15,000-CAD 16,000, we saw momentum getting into the high teens here in the first quarter. Our current bids on our high-spec doubles are in the low twenties now, CAD 20,000+.
Perfect. Mike, I know you've mentioned land sales in the past, but is there anything that's sort of, you know, 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? 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 quarters.
Yeah. For land, we have two properties up in Nisku available for sale. Those are currently on the market, so I think 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. Those are north of CAD 30 million in total. We can see some definitely some deleveraging from those assets transactions. From a working capital perspective, I mean, Q2 is definitely a harvesting of the Canadian drilling winter season accounts receivable. 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.
Q2 definitely is one of our better quarters for collections.
Okay. That's all for me. We'll turn it over. Thanks, guys.
Aaron.
Thank you. Next question will be from Keith Mackey at RBC. Please go ahead.
Hi. Good morning, everyone. This first question would be on the rig activations in the U.S. You're at 50 now with, you know, 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. 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, you know, the market in terms of rig additions throughout the year?
I mean, if we're sticking to the margin versus market share. We're not trying to put more rigs that are required 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. 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. At the end of the quarter, you're good and 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 gonna be moving parts to that, but you know, 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?
You know, we're definitely comfortable with what we have. If you look, I mean, Q2 of the prior year, EBITDA was CAD 45.6 million. If you kind of look at where consensus is, it's 63.7 for Q2 of 2022. You're seeing a significant increase in activity in EBITDA. The bank covenant is on a trailing 12. As we drop the lower quarters from 2021, you'll see that covenants start to improve as we go out throughout the year. We definitely have enough room for it and don't foresee any issues.
Got it. Just finally from me, if we think about your contract book and the 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, you know, longer -term contracts now? Or you think rates are still below where they need to be to sign a multi-year contract in, you know, in these regions, or is it starting to look pretty good?
Multi-year contracts are really a no-go right now. We're anywhere where we've got a client who's looking for an annual contract, you know, we're having ladders built in basically every quarter. You know, we'll do a present value and give a blended rate if they're really insisting on an annual number, and it'll be quite a bit higher than the current quarterly rate that we're suggesting. You know, when I look at on an inflation-adjusted basis, most of this labor and other costs, you know, our high-spec triples were getting in the low 30s before. When you look at capital replacement, these rigs are all built in U.S. dollars.
You look at the degradation of the Canadian dollar, if we focus on that market specifically. These are almost CAD 30 million rigs now. You know, we've always mentioned that, you know, to get a reasonable rate of return, you need to have CAD 1,000 of margin for every CAD 1 million invested. That holds true, you know, more particularly in Canada, where, you know, rigs don't get 365 days a year. You know, they typically get 250, 275 days a year. It's different than the U.S. You've always got a little bit of a differentiation there.
On a net-net basis, I think, you know, before anyone would ever start to contemplate new builds, they're gonna have to see day rates in the high 30s for the high-spec triples and the high 20s for the high-spec doubles. We got a ways to go.
Got it. That's it for me. Thanks very much.
Thank you.
Next question will be from John Gibson at BMO Capital Markets. Please go ahead.
Morning, all. First for me, just kinda, you know, 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 rig rates? Then maybe if we look into Q3, what percentage of rigs will be under contract at the higher pricing levels?
Right. In Canada, essentially zero. All of our contracts peel off right around breakup, which is pretty typical. Through the Nabors acquisition, they peeled off all their contracts in June. We're in the middle of recontracting those at rates what I mentioned. In the U.S., we try and get a cadence of a quarter of the fleet every quarter. 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 three years. In Argentina, we have, they're basically annual contracts.
We're just in 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. Australia is generally on annual contract basis outside of special project campaigns. 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 one for me. Can you talk about where field margins are at on your various rate classes, you know. Then, you know, 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 the disclosure on the rig types, I guess. I mean, we're seeing, I think, broad-based. I mean, all the rigs are definitely contracting up 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 rope, soap, and dope that would impede on some of that. You could say a good chunk of the increases that we're seeing across the board will definitely go down to our margins.
Got it. Last one for me. Sorry if I missed this, but you've talked about the cadence of rig additions 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.. We're gonna be mirroring each other.
Great. Thanks a lot. I'll turn it back.
Thanks, John.
Thank you. Once again, ladies and gentlemen, as a reminder, if you would like to ask a question, please slowly press star followed by one on your touchtone phone. Your next question will be from Andrew Bradford at Raymond James. Please go ahead.
Good morning, guys. Thanks for taking my questions. I just wanna revisit the sort of the leading-edge rates a little bit, first in the U.S. 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. You have 36 super-spec triples as you indicated. Like, how many of those rigs do you see are tracking that kind of rate?
As I mentioned.
Sorry, just to interrupt you, Bob. Just, it's another way of asking. Are all 36 of those rigs, you know, are they attracting all the same rates? Are they all similarly specced?
Yeah, they would all be working into those rates. I would suggest that certainly in the next four months, that all of those rigs will be at those rates, as our contracts are turning over and being recontracted. The leading edge today on those rigs for a contract coming off and recontracting is in the low thirties. That's with pipe and the technology suite that they're used to on that rig continuing.
Fair to say that all 36 of those rigs, does that include the nine that are subject to upgrade right now?
Correct.
Okay. They are definitely all working in that, you know, 60 rig third quarter number, 65 rig fourth quarter number.
Right. The other thing we're finding is, and we've got 46 of the what we call the high-spec rigs that can be upgradeable. Let me back up. Of the nine, probably four of those would be the high-spec triple that are being pulled up into a super-spec category. We'll end up with about 40 super-spec triples. We're finding that essentially our U.S. business has sold out of the super-spec triples, and so the operator is saying, "Well, what's your next class of rig?" Of course, the high-spec 1,500 is the next class of rig, and in some cases the operator is saying that'll work just fine, too.
You know, the super-spec triples are the most desirable. If, when they can't get it, the high-spec triple is what we're finding able to do similar work. It may not be able to do four-mile laterals, but it can certainly do three-mile laterals very cost effectively.
Yeah, 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. Yeah, in Canada, I think you or maybe one of the previous analysts alluded to the idea that you know, as the demand increases for the high-spec rigs in Canada, you're finding some pull on the high-spec doubles.
Mm-hmm.
You know, when we talk about the rates going from, I think you said, you know, so CAD 13,000 a day or so at the bottom to maybe just north of CAD 20,000 in the low 20s today, is how many rigs does that apply to in your active rig mix now?
In Canada we've got 30 of the high-spec doubles in Canada that fall into that category. We have 44 conventional doubles. 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. That basically puts us at a fleet of 76... I'm sorry, 74 doubles, half of them being high-spec doubles. The high-spec doubles get further bifurcated.
Some of them have self-moving systems on them, and those ones are going for around, you know, the low 20s. We typically add CAD 2,000 a day for our self-moving capability on whatever rig it may be.
Of those 74 rigs, can you ballpark for me, like, how many would be in your rig mix? Maybe not today, how many would you anticipate being in your active rig mix early in the summer?
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 - 20-25. 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. Thanks for that. Sorry, I don't wanna stretch this too long here, but you'd also indicated earlier on that a lot of the Nabors' 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-
The, um-
Some of that increment will already be accommodated?
Yeah. I'm sorry, Andrew. Yeah. They were at prices set over a year and a quarter ago. The cost escalations are afforded by the CADC contract, and they're all on CADC contracts. Labor escalations are passed through and any other general industry increase they may see as a pass-through as well.
Does that 20%-25% price increase that you had mentioned, is that? Then you said 10%, I think you said net of cost. Is that 20%-25%? Like, should we be thinking about that as, you know, notionally around CAD 5,000 a day bump to your margin on those rigs? Or is that-
Correct.
The top line bump? Yes.
No, that's the margin bump. Yeah. Yeah. Well, my point was that, labor is the single biggest cost, but it's covered by contract escalation. If we assume CAD 4,000 a day as an operating cost on a triple, and you get 5% inflation on this, you're talking CAD 200. CAD 200 on, let's say, a CAD 20,000 day rate is 1%. If you use that simple math, the point being that, you know, 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.
I think it'd be unreasonable to think that there won't be some cost inflation. I was just trying to put it into perspective. To your point there, John or Andrew, about in that example, CAD 5,000 on the high-spec triples, is the increase in the margin. Yes.
Okay. 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. If you pick a number of CAD 4,000 a day and 5% quarter-on-quarter, you're getting about CAD 200 a day margin reduction from that. That's it.
Okay. Last question for me, I promise. It just relates to customer retention, particularly in, 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? Do you have a preference for one or the other when it comes to rate bumps?
Yeah. 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 a third of the time that we did five, six years ago. 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 than Canada, a lot of private companies, emerging companies, names we haven't heard before. But we're certainly not losing any clients with our rate increases.
You're indifferent then?
Mm-hmm. Exactly.
Okay. That's perfect. Thank you very much for answering the questions.
Thanks, Andrew.
Thank you. 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, the climb 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 delivering 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 three 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. At this time, we do ask that you please disconnect your line.