PRECISION DRILLING Corp Q4 FY2021 Earnings Call

Good day, ladies and gentlemen, and thank you for standing by. Welcome to the Precision Drilling Corporation 2021 Fourth Quarter and End of Year Results Conference Call and Webcast. At this time, all participants are in listen-only mode. After the speakers' presentation, there will be a question and answer session. I would now like to hand the conference over to your speaker host today, Carey Ford, Senior Vice President and Chief Financial Officer for Precision. Please go ahead, sir.

Thank you, Olivia, and good afternoon. Welcome to Precision Drilling's fourth quarter and year-end 2021 earnings conference call and webcast. Participating today on the call with me is Kevin Neveu, President and Chief Executive Officer. The earnings release earlier today, Precision reported its fourth quarter and year-end 2021 results. Please note, these financial figures are in Canadian dollars unless otherwise indicated. Some of our comments today will refer to non-IFRS financial measures such as adjusted EBITDA and field-level results. Our comments will also include forward-looking statements regarding Precision's future results and prospects, which are subject to certain risks and uncertainties. Please see our news release and other regulatory filings for more information on financial measures, forward-looking statements and these risk factors. Kevin will begin today's call by providing an overview of current market dynamics. I will follow with a discussion of results and our financial position. Kevin will then provide an overview and outlook for our various business segments. With that, I'll turn it over to you, Kevin.

Thank you, Carey, and good afternoon. While the global recovery remains uneven and there are some lingering uncertainties, the fundamentals for Precision may be the best I've witnessed in four decades. Global oil demand has almost fully recovered, but we faced sharply reduced activity and virtually zero exploration drilling over the last two years. The resulting oil and gas prices are strong, and the markets are firmly acknowledging the rapidly tightening oil and gas supply-demand equation. The inventory of drilled uncompleted wells, or DUCs as they are called, has dwindled. Super-spec rigs are tighter than people understand, and customer demand will shortly absorb the remaining spare capacity. Labor inflation is here and real, but service price inflation is also here, and it is real. As I've said in prior calls, we are moving our day rates back into positive earnings territory and then driving rates further to achieve a reasonable return on our invested capital. Precision's Super Triple rigs are the most efficient, safe, and environmentally responsible rigs that the industry has ever operated. The technologies we are deploying under our EverGreen banner have the capability to measure, track, and eliminate GHG emissions at the drilling rig, and we can do this with cost-effective proven solutions. The uneven nature of the economic recovery and the risk of further economic interruptions continue to cause some uncertainty. But this uncertainty is mitigated by the laser-like focus on financial discipline by the capital markets. Precision's customers who are generating record levels of cash flow have responded to those investor expectations with highly disciplined capital allocation strategies. Balance sheets are largely repaired, and the producers are returning capital to shareholders through dividends, special dividends, and share buybacks, further cementing the capital discipline mantra. The boom-like rapid recovery scenario we've seen in prior cycles, where rig demand correlates with commodity prices and that overshoots, is simply not possible today. Capital discipline is well entrenched throughout the industry, and this is driving a longer, slower, and extended recovery cycle with shareholder returns remaining prioritized. Combining the measured recovery with the industry's determined focus on emissions and corporate responsibility defines a healthy strong future for Precision and for our customers. With that, I'll now turn the call back to Carey Ford for our financial results.

Thank you, Kevin. In early January, we released our capital allocation framework through 2025, where we expect to pay down $400 million in debt over the next four years, eclipsing $1 billion in debt reduction since 2018, and reaching a net debt to EBITDA leverage level of below 1.5 times. Importantly, we also announced a prioritization of returning capital directly to shareholders, allocating 10% to 20% of free cash flow before debt reduction toward this goal. We recognize the substantial operating leverage inherent in Precision Drilling and the ability to grow in a growing market to generate adequate cash flow to fund growth, reduce debt, and return capital to shareholders. Moving on to our fourth quarter results, our fourth quarter adjusted EBITDA was $64 million, increasing 16% from the fourth quarter of 2020, supported by higher North American activity. Also included in adjusted EBITDA during the quarter were share-based compensation expenses of $6 million, inventory write-downs of $3 million, and non-recurring labor impacts of $3 million. Absent these items, adjusted EBITDA would have been $76 million for the quarter. In the U.S., drilling activity for Precision averaged 45 rigs in Q4, an increase of four rigs from Q3. Daily operating margins in the quarter, absent impacts of turnkey and idle but contracted payments were US$5,648, an increase of US$410 from Q3. The increase was impaired by US$620 per day of charges related to non-recurring margin impacts. Absent the impacts of turnkey and labor, daily operating margins would have been US$1,030 higher than Q3. For Q1, we expect margins absent of IBC and turnkey to increase approximately $500 per day from Q4 levels. In Canada, drilling activity for Precision averaged 52 rigs, an increase of 24 rigs or 87% from Q4 2020. Daily operating margins in the quarter, absent CEWS and shortfall payments, were $7,990, an increase of $1,095 from Q4 2020. Q4 margins net of CEWS and shortfall payments increased $2,701 sequentially from Q3 2021. For Q1, we expect margins absent of CEWS and shortfall payments to increase between $1,500 and $2,000 per day compared to Q1 2021 and up approximately $500 per day sequentially. Internationally, drilling activity for Precision in the quarter averaged six rigs, and average day rates were $52,069, down approximately 6% from the prior year due to active rig mix. In our C&P segment, adjusted EBITDA this quarter was $6.3 million, up over 18% compared to the prior year quarter. Adjusted EBITDA was positively impacted by a 21% increase in well servicing hours, reflecting higher industry activity in the quarter. We expect results will further strengthen in Q1 due to increased industry activity and additional work supported by the Canadian government's $1.7 billion well site abandonment and rehabilitation program. Of note is the team's success in capturing pricing increases to cover both increased wages and the removal of the CEWS program support in an effort to drive higher margins. Capital expenditures for the quarter were $28 million and $76 million for the year. Our capital expenditures were in line with expectations and higher than 2020 as a result of increased activity in 2021 and expectations for continued rig activations in 2022. Our 2022 capital plan is $98 million, comprised of $56 million for sustaining infrastructure and $42 million for upgrading expansion, which relates to anticipated investments supporting Alpha technologies and contracted customer upgrades. As of February 9th, we had an average of 39 contracts in hand for the first quarter and an average of 31 contracts for the full year 2022. Moving to the balance sheet, we continued to reduce both absolute and net debt levels primarily through free cash flow generation and succeeded in reducing debt by $115 million in 2021. As of December 31st, our long-term debt position net of cash was approximately $1.1 billion, and our total liquidity position was approximately $530 million excluding letters of credit. Our net debt to trailing 12-month EBITDA ratio is approximately 5.5 times and our average cost of debt is 6.4%. We remain in compliance with all our credit facility covenants in the fourth quarter with EBITDA to interest coverage ratio of 2.8 times. With continued debt reduction and activity expectations, we believe we will end 2022 with a substantially lower net debt to EBITDA ratio moving Precision much closer to our goal of below 1.5 times leverage. For 2022, we expect to continue generating free cash flow through operations and do not expect incremental benefit from working capital release as activity increases in both the U.S. and Canada. For 2022, we expect to generate strong free cash flow for the year with Q1 cash flow impacted by front-end loaded CapEx, working capital build, our semi-annual interest payment, and year-end payments. Our year-end target for debt reduction in 2022 is at least $75 million. For 2022, we expect depreciation to be approximately $270 million. We expect SG&A to be $65 million to $70 million before share-based compensation expense. We expect cash interest expense to be below $80 million for the year, and we expect cash taxes to remain low with our effective tax rate in the 5% range. With that, I will turn the call over to Kevin.

All right. Thank you, Carey. So beginning in U.S. land, we continue to experience strong demand for our Super Triple rigs. As Carey mentioned, our activity and rates have been tracking well with Q4 activity up 10% from Q3. With 52 rigs running today, Q1 activity is already trending up 12 sequentially and may rise further as our first quarter rig activity approaches the mid 50s. With current customer interest and bidding activity, it seems this trajectory may continue throughout the year. Leading edge rates have moved into the mid 20s for active rigs and are now progressing into the same range for cold rigs due to the rising industry-wide activation costs. While Super-Spec rigs are not fully sold out, industry supply is much tighter than most people believe. Regional shortages have developed, and customers are paying full trucking costs for basin-to-basin moves. Between mid-December and mid-February, Precision's customers have upfronted the cost for basin-to-basin Super Triple rig moves. Regarding Precision's market discipline and pricing strategy, the key pricing signal we can send our customers is a refusal to accept lower than threshold day rates, which means we walk away. I'll tell you that we are not pursuing market share. Our focus is on the economic return for each rig opportunity we pursue. Turning to our Canadian business, the winter drilling season is off to a strong start. Activity is slightly lower than peak levels we anticipated, but this is largely due to some customer-driven delays. We expect activity will remain firm, with seasonal slowdown driven by weather, not by budget exhaustion. Currently, we are running 66 rigs, with four additional rigs delayed due to customer supply chain and location preparation issues. This work should be completed later in the quarter. Customer indications for the second quarter look very strong, with spring break-up rig demand running 25% to 30% higher than last year. Early indications are that Q3 activity may again exceed winter activity levels. All of this bodes very well for our Canadian business. As Carey mentioned, we've demonstrated excellent rate correction in Canada during 2021, and we expect that trend to continue in 2022. I know our customers don't like to hear this, but it is essential that the Canadian services industry recovers to sustainable financial returns. Canadian producer economics are very strong indeed, with Western Canada select currently trading at its highest level since April 2014 and the Canadian dollar exchange rate in the $0.79 U.S. range. The cash flows for our Canadian customers are at all-time highs. This brings me to discuss a specific play in Canada. While we have often talked about the Montney, today I want to talk about the Marten Hills Clearwater Play. This is a relatively new heavy oil play, which has grown to 21 industry rigs active today from just a handful of rigs in 2019. With horizontal wells and measured depths in the 2800 meter range, the drilling programs are ideally suited to Precision's high-performance Super Single pad style rig. Precision is currently operating 11 Super Single rigs in the Clearwater region, holding a 55% market share, which has grown from just three rigs in 2019 before the pandemic. We think the Clearwater, like the Montney, has good long-term fundamentals with strong commodity price support, very good geology, and pad style horizontal drilling where high-efficiency drilling rigs de-risk the F&D costs. The Clearwater will continue to be a strong demand driver for Precision's Super Single rigs. Now, for some, it might be easy to discount or reject the Canadian market. Yet with Precision's extensive Canadian footprint, our Super Single and Super Triple rigs, combined with our scale efficiency and our high-performance high-value strategy, Canada remains a very strong and key geography for Precision's cash flow-generating capabilities. Turning to our well service group, as Carey mentioned, we are experiencing very strong customer demand and delivering substantially improved revenue and operating margins. Customer demand looks to remain strong following several years of low activity and pent-up operator demand for both conventional well servicing and well abandonments. This demand has been further enhanced by the federally funded well site reclamation program. Labor challenges are constraining the well-serviced industry, yet our team has performed very well, fully staffing the 50 rigs we have running today. We expect to have further crew capacity activated for what is looking like a strong second half of 2022. The team has worked very hard to justify the value Precision provides our customers and has succeeded in pushing rates in the right direction. The service industry hourly rates have improved from the lows of 2020. The industry still needs substantially higher prices to be financially sustainable. I know our team is well-focused on this challenge and we expect to see continued marginal improvement through 2022. Turning to our international business, we continue to operate three rigs in Kuwait and three rigs in Saudi Arabia. We're working with our clients in both markets on upcoming tender specifications, and we're bidding for opportunities with other operators in the region that have nothing new to report today. My expectation remains that as OPEC production limits are fully removed in the coming months, these potential reactivations will materialize. Turning to our digital strategy, for pad-based development style drilling, the game has changed, and the bar has been reset. The days of pushing our crews and equipment faster and harder have run their course. Today, our most cost-efficient customers have adopted our Alpha digital automation and digital analytics to optimize and ensure maximum rig efficiency, process, and cost control. Customer acceptance and demand for Alpha Digital products continue to grow; as we reported in our press release, we are expanding our Alpha Automation footprint across our fleet and expect to have fleet coverage up to 70 by the end of this year. We also continue to add to our library of Alpha Apps and demonstrate the value to our customers. I expect this growth trajectory to continue and further drive our competitive advantage. Turning to ESG, I'm very excited about the progress we've made in a very short time with our EverGreen suite of environmental solutions. As I mentioned earlier today, our customers are increasingly focused on rig emissions and sustainability. Precision's EverGreen technologies encompass several lower CO2 emission, combustion power alternatives, hybrid battery power systems, grid power systems, and combustion fuel real-time monitoring systems offering our customers a range of solutions to monitor and reduce emissions right down to zero. Customer acceptance and uptake has been strong, with 48% of our operating fleet today equipped with at least one EverGreen emission reduction solution. With current bookings, we expect to have 10 EverGreen combustion fuel monitoring systems installed and running and six hybrid battery storage systems operating by mid-year. I expect that over the next few years, all of our rigs will utilize some combination of EverGreen products to reduce GHG emissions, meeting our customers' targets. Now turning to our annual strategic priorities, I'm very pleased that we completed and delivered on the priorities we outlined at the beginning of 2021. I thank the employees of Precision for contributing to those priorities. For 2022, I want to be clear that we've adjusted our capital allocation plans by now also prioritizing targeted capital returns to our shareholders. This is a clear indication that we believe we have a strong and stable capital structure with a sustainable runway of deployable free cash flow. We'll continue to reduce debt and deliver as guided. Our other priorities, including a strong focus on free cash flow and expanding our technology offerings, will continue in 2022. Finally, I want to thank the people of Precision out there on our rigs, in our support centers, and our offices for the safety and the work execution that underpins everything we do as an oil service provider. With that, I'll now turn the call back to the operator for comments and questions.

Thank you, ladies and gentlemen. Now the first question comes from the line of Aaron MacNeil with TD Securities. Your line is now open.

Thanks for taking my questions. You've mentioned the leading-edge day rates in the mid 20s matching a lot of your peers that have reported over the last few weeks. I guess I'm just wondering how much of that is keeping up with cost inflation and how much of it would be capturing more economic rent given the improvement in the sector?

Aaron, it's Carey. Part of it is a labor increase that we implemented in December, which was about $800 a day. I think that was kind of standard for the U.S. market and kind of standard for our peers. We do have some reactivation costs that we're still absorbing. We reactivated six rigs in Q4 and we plan to reactivate another six rigs in Q1. That’s trending at $150,000 to $200,000 a day, so it's pushing costs up a little bit. We do have some inflation, I think it's a lot lower than other segments of the oil field service sector, but we do have a little bit of inflation. So all in all, it might be call it $1,500 a day of increased cost that we're passing through. The rest of it would be margin expansion, and as we mentioned in our last call, we thought that Q3 would mark the bottom or the trough of the cycle for margins. We showed increasing margins in Q4, and we expect to continue to show increases in margins in Q1 and Q2. So we would be capturing more of the margin through higher day rates than we saw through most of 2021.

Understood. And acknowledging your January press release with the guidance for Q1. But since that time we've seen companies like Exxon and Chevron announce they're going to start growing again in the Permian. And I guess my question for you is on the margin—have your expectations for the activity outlook in both Canada and the U.S. changed since you put that press release out? And if so, could you provide any order of magnitude?

Aaron, I'd say, yes, they have changed. We're moderately shifting more positively as we can go through almost each month that passes with these stronger commodity prices. But I would say that our guidance on activity into the back half of the year, particularly in my comments both for the U.S. and Canada reflects that optimism. There's no question, this cycle is different from previous cycles. We're not saying our customers overshoot the commodity price. We're seeing a very well managed and controlled backup of rigs. Beginning with the super majors making small announcements. It really feels like with the activity we have from our bidding and sales team that the gains we were showing in Q1 and into Q2 might continue to carry on for the balance of the year. We think there could be upside to that, but it just depends on how quickly our customers pivot back to bringing in some small amounts of growth.

Understood. Seems like we're in the early stages of an equipment upgrade cycle. I don't know if you agree or disagree. But it also seems like among the four or five top North American drillers, there's discipline on returns that remains largely intact. But I'm wondering is that also true with some of your smaller competitors that we may not be tracking as closely?

It's kind of hard to say. Generally, when we're competing up with the customers these days, it's almost always just us and one or two others. We don't often see a lot of the smaller competitors, especially true in Canada when we're talking about Super Triples. But in the U.S. it's usually us and a couple of other large drillers competing. So we really don't get a good sense of what the smaller drillers are doing. We just don't see a lot of competition from those smaller drillers.

Okay. That's helpful. Carey, on the capital program, you mentioned in your prepared remarks that it would be front-end loaded. I guess it begs the question that the $42 million earmarked for expansion and upgrades— is that all committed or mostly committed at this point, or is it a placeholder? Ultimately, I am trying to understand if we could see that number expand throughout the year if activity levels are higher than you expect.

Some of it’s committed. I think we made some commitments to get 70 of our Super Triples with Alpha technologies. That part is committed. We have some long-lead items that we've committed for some near-term upgrades. But you're right, if activity does grow faster than we expect and there are more economic upgrade opportunities, that number could go up throughout the year.

Okay understood. Last question for me, I've already asked. So, I'll turn it over. It's just been such an unusual winter here in Alberta. Any comments that you can provide on the shape of spring break-up or potential activities would be helpful?

No guidance yet. Certainly, it's quite warm this week, and we've already run into some situations where we have some rigs that can't get onto location yet, causing a few delays. My sense is if there's early weather break-up, that might push a lot more work and pricing tension into late Q2 and Q3. It might be a short-term drag on activity but probably a net positive for the year.

Okay.

Does that make sense?

Yes, makes sense. I'll turn it over. Thanks.

Thanks, Aaron.

Our next question comes from the line of James West with Evercore ISI. Your line is open.

Hey, Kevin, Carey, how you doing?

Good, James. How are you?

I'm doing well. First question on North America. What do you see is the biggest constraint to your growth at this point? Is it that you need to upgrade rigs for specifications? Is it labor, or is it supply chain? It seems to me like we're going to see a nice pickup in the rig counts and I'm curious about what you see as the impediment to that?

Well, I would tell you that I think that it's a bit of a good news story. We're going to run out of super-spec rigs in our fleet during this calendar year. We have another group of about 15 rigs, which are really strong upgrade candidates that would probably require day rates that would have a three on the left-hand side.

Okay.

We need to see some good long-term contracts, probably two to three year contracts. But it would be a high-quality problem for Precision to be running out of super-spec rigs in calendar year 2022. Yes. And I'll just add to that. When we talk about operating leverage within Precision, what we're talking about is the spare capacity that we have to address the super-spec market in the calendar year where limited upgrades are required. The upgrades we're doing, such as adding Alpha automation, accelerating high torque drill pipe or pumping capacity, are still in the low single-digit millions of dollars. We don't expect to have to spend a lot of capital to address the market.

Carey, we have 55 rigs running or 52 rigs running today, and we have 67 super-spec rigs available in the U.S.

That's right.

Okay. That's very helpful. Thanks, guys. And then maybe just one more for me on the Middle East. We're clearly going to have a call on additional production at some point. The big large producers you work for are aware of that, and that's why they are tendering now. Can you comment on the magnitude of if you were to be successful in some of the tenders? Or when you are successful in getting the rigs, how many more rigs you might commit to the region? And would those be—would you move rigs, or would those be upgrades, and how would that impact your capital program?

There's a fair amount of bidding activity right now going on. We have three idle rigs in Kuwait that we expect to reactivate during the year. We've got one idle rig on the ground in Saudi that could be activated this year, three more idle rigs in Kurdistan and Georgia that are wrecked. Actually, one of those rigs is looking like it might end up in Abu Dhabi or Dubai. So two in Georgia, two in Kurdistan, one in Dubai could be activated. We've had some tenders recently; we're looking at possibly utilizing some of our Super Singles and some other tenders that might be in the 1500 horsepower class. However, if we're utilized in North America, we would probably back away from those tenders.

Okay. Got it. Thanks, guys.

I just want to add another comment there along that operating leverage theme. The most likely rig activations in the near term would be the three Kuwait rigs, which are all super-spec AC, deep capacity rigs that are six years old and won't require a whole lot of capital to get into a new contract, kind of in the $4 million range per rig.

Okay. Got it. Thanks.

Thanks.

Our next question comes from the line of Taylor Zurcher with Tutor, Pickering and Holt. Your line is open.

Hey, Kevin and Carey, good afternoon. First question on Canada. Over the past few—really past two weeks down here in the U.S., there's been so much talk about significant pricing improvements. Again, for the U.S. market, you echoed some of those comments in your prepared remarks today. I'm curious if you could just compare and contrast what's going on from a pricing perspective in the U.S. with what you're seeing in Canada. Obviously, a number of different rig classes up there in Canada, and I'm just curious where we sit from a pricing improvement standpoint for each of those rig classes up in Canada?

Yes, Taylor. I think the pricing movement in Canada is probably a quarter or two ahead of the U.S. There are a couple of reasons for that. One, the market's a bit tighter on the super-spec side, it's fully utilized. It's also more consolidated with primarily just two drillers that have the balance of the fleet for super-spec rigs, namely Super Triples in Canada. And for Super Singles, there really isn't a strong competitor for Precision's Super Single rig, and it's a highly efficient rig. We've had opportunities with rising demand and tight utilization to raise those prices a bit sooner. There's also a seasonality component that comes into Canada, with a spring-summer pricing circle and sometimes a second pricing round that happens in the fall for the coming winter season. So there are natural windows when we engage with customers. A third factor that has driven tension in Canada is crewing; it's been particularly hard to recruit personnel, creating attention across the oil services space. All of those things have helped move rates back into a sustainable range, which we hope to achieve in 2022. I think some of those factors now apply to the U.S. The super-spec rig market is getting—while not sold out, between regional dislocations and various differences in rig specs, it's almost sold out. I think you'll see it effectively sold out within the next few weeks or a couple of months. So I believe the U.S. will get on the same track that we see in Canada between Q1 and Q2, and you're hearing the front-end piece of that today from us.

Yes, good to hear. Against that backdrop that you just mentioned, the super-spec market is going to be pretty fully utilized here pretty soon, not just for your fleet, but for the broader market. I'm curious, how are customer conversations going with respect to term contract durations? It doesn't feel like many of the larger land drillers, including yourselves, have significant term contract throughout coverage at least not beyond 2022. I just wonder if the customer urgency is there to lock up some of these rigs even if it's at much higher pricing over the course of 2023?

I think we've seen opportunities to contract rigs anywhere from pad-to-pad all the way up to two years. I'd say that this tightening has been kind of sneaking up on everybody a little bit in that I think the drillers know it well. But I don't think any customers really understand how tight the market really is. Nobody has a 2023 budget approved yet, so there's not a huge preponderance of people looking at long-term contracts right now. I would say that there are just a handful of customers trying to lock in lower rates for a longer term, not necessarily locking in higher rates. In our case, we've been reluctant to jump at those opportunities, focusing more on shorter-term, higher-rate opportunities with the ability to reprice as the market tightens.

Got it. One last quick question from me. You've been talking about going from 50 Alpha systems to roughly 70 by year end. I'm curious how that demand pool works for those sorts of systems? I imagine some of those will be outfitted on rigs that are already in the field today. Do we go through a trial phase where you put the system on a rig, the operator tries it out, and then starts paying for it? Or do you expect to get compensated for that almost immediately?

We expect to be compensated for that almost immediately. We've got a handful of performance-based contracts where if we achieve certain performance levels, we'll earn more. In that case, you could say that we have to earn the compensation. Those applications are pretty standard now, can be managed in an a la carte pricing framework where we install the system, run it, and deliver value, and the customers see that value. We move on.

Understood, thanks for the answers, Kevin.

And just, Taylor, on that deployment you mentioned about customer pool. We've been working closely with our partners. As we've always standardized on how we do this, we also managed to lock in lower capital costs for that acquisition for an extended period by committing to those installations over the course of the year. This balances the risk on the inflation side so we keep costs low while also getting the systems across our fleet as fast as possible.

Great. Thank you.

Our next question comes from the line of Waqar Syed with ATB Capital Markets. Your line is now open.

Thanks for taking my question. Carey, the potential reactivation costs for the Kuwait rigs. Are they included in the CapEx number or not yet?

Yes. We haven't specified. I think we've got a basket of upgrades that we see on the board. We're trying to put a percentage of the likelihood of securing those upgrades, so you can say that somewhat included in that basket.

Okay. All right. Kevin, one of your competitors today mentioned that there's a further segmentation of the super-spec rig market in the U.S. and that customers are demanding rigs that have rig floors with very high clearance, 21 to 23 feet, and draw works on the rig floors. Are you seeing the same kind of differentiation as you talk to your customers?

So, Waqar, the good thing and bad thing is there is no API definition of super-spec. Each drilling contractor has their interpretation of the optimum rig design. Whether that includes skidding or walking can be debated; whether it includes three mud pumps or two mud pumps could also be debated. In our case, we actually have a wide fleet of super-spec rigs that have elevated rig floors with the draw works up on the rig floor. In fact, a split LER drive assembly keeps all the rig controls up on the rig floor. So that particular need we can meet with our Super Triple rigs.

Okay. But is there a differentiation in day rates for those rigs versus those that do not have that capability and still in super-spec?

It comes down to whether you have a client who has a pad where he wants to walk the rig over existing wellheads; he might want that extra clearance. If you have a pad which is a new pad, and you're drilling it in a line, you may not need that clearance. It depends. It's more customer-specific than industry-specific.

Okay, great. Then in the international market, you have your six rigs currently working with two contract expirations coming up. Do you see any downtime before they start up again, or do you think you would be able to renegotiate the contracts before the current contracts expire?

We don't expect any downtime.

Okay. For the Kuwait rigs, do you see them—in Kuwait, tenders typically get delayed? Do you think that this year they may happen relatively quickly?

I've been talking about that tender for almost all of 2021 and now into 2022. So, it's already delayed one year from my early conversations. Every time I make a projection, about four weeks later a new variant pops up and slows down decision-making. I'm really reluctant to predict what's going to happen in Kuwait. I would say that if Kuwait has their production curtailments removed, those tenders will likely proceed very quickly.

Yes.

Or, I should say when they have their production curtailments removed, those tenders will move quickly.

Right. Makes sense. Thank you very much. Those were all my questions.

Thank you, Waqar.

Our next question comes from the line of Ian MacPherson with Piper Sandler. Your line is open.

Thanks. Good afternoon, Kevin and Carey.

Hi, Ian.

I appreciate the description of what's happening in the Martin Hill Clearwater play. I think it was asked a little bit, but I wanted to get a clearer picture. If you could talk about your breakout of Super Singles versus Super Triples in Canada? Speak maybe a little bit more to the differential in day rates or margins between the two, if that's a material consideration for us as we think about that play folding into your mix?

Sure. I'll give a bit of coverage, and Carey can fill in the gaps where I missed something. The Precision Super Single rig was specifically developed back in 1992 for heavy oil drilling. It was designed to be small, fast-moving, light pad capable rigs with a small footprint, capable of running throughout spring break-up if necessary, and has a very low, efficient operating cost. It's a really cool design that's stuck with us for the last 30 years, keeping that competitive edge out there. The rig fits upmarket very well. Carey, the operating costs of that rig would typically be about $4,000 or $5,000 less than a Super Triple?

Correct.

In that range. We're getting day rates for that rig now in the mid to upper teens and pushing those levels even.

Okay, great.

In Canada, we have 27 Super Triples. They're all fully utilized right now, and here we've given guidance on those rates. Those rates are in the low to mid-20s range right now for the base rig. Technology charges are above that, and a lot of the things you put on the rig are also above that.

Okay. That's great. Thank you. Sort of a simple, high-level question for the U.S. market. If you were able to pro forma your fleet for all of the upgrades that you're planning for this year, where that takes your fleet-wide spec at the end of this year? If the market pricing stops moving today, and you repriced everything at leading edge and absorb all your reactivation costs, is it asking if you do a model for your fleet?

Are they asking if you do a model for your fleet?

Yes. Wouldn't your pro forma cash margin easily be above $10,000 on that hypothetical basis?

I think if you're looking at leading-edge being in the mid-20s, we’re getting better fixed cost absorption and do not have reactivation costs. Daily operating costs probably go down a bit from where we’re reporting right now. So, I think you could see the fleet generating, on average, above $10,000 a day margin.

Yes, I think so. The one thing I want to be careful with is not extrapolating your tip-of-the-spear data point on pricing and inappropriately extrapolating it across the entire fleet. But it seems to me that your whole fleet or the vast majority will be at that leading-edge capability, and probably with the higher saturation of Alpha and other a la carte add-ons that it would not be unfair to project that. So I just wanted that?

Yes. I think that if you go back to 2018 and you look at where our super-spec rigs were pricing, and you're getting one and two in some cases three-year contracts without Alpha, we were well above $10,000 a day in margin on that segment of our fleet.

Yep. Thanks. And then the other one for me, I don't know if we've talked about this already on the call. Have you discussed the framework through which you're examining dividends versus buybacks with the capital return plan?

It's a four-year plan. For the first couple of years, this is almost exclusively going to be share buybacks. As we get closer to the target leverage level and there's a little bit more visibility in the business, a dividend becomes more likely. But for the first couple of years in this capital framework plan, assume it's going to be share buybacks.

Got it. Thanks, Carey. Thanks, Kevin.

Thank you.

Afternoon everyone. So some pretty good color has been provided so far on Canada versus the U.S. A couple of quarters ago, you highlighted that the outlook for Canada was especially bright relative to the U.S. in the near term. I wonder if you currently see either Canada or the U.S. as relatively stronger right now, factoring in some of the seasonality in Canada?

I think, Cole, what drives me to say Canada is a little farther down the pricing trajectory with our Canadian customers, helping make Canada look better. Part of that is the tighter market consolidation in the Super Triple area and in our heavy oil Super Singles area. You've got much more rational markets with generally public players that are more rational in their thinking. So it behaves more industrially, more structured, and more disciplined than the less mature markets. That's the way it feels right now. Does that make sense?

Yes. That's good color. Thanks. And so you briefly touched on Q1 in Canada, talking about some customer logistics issues possibly putting a bit of a lid on activity. I'm just curious, have you seen labor really be much of a restriction into getting rigs activated in the quarter?

On the drilling side, our team had a pretty heavy lift, and I know some of them are listening today. They've worked pretty hard, but they've met the objective in drilling. It's been much, much tougher in well servicing. There are a couple of good reasons for that. The drilling jobs have a slightly higher hourly rate, but the work is more consistent and repeatable, and they typically get a lot more overtime and more consistency over time. So the total pay is higher, attracting people that stick a little more to drilling. Wells servicing can be good or bad; it's call-out work and tends to be day-to-day work. It's been much tougher to recruit staff like many other oil field call-out services. In drilling, no hard work for our team, but they've accomplished the task. But well servicing remains tough, and we've got 50 rigs stepped up right now for that.

Okay, perfect. That's great. Thanks. On the international rig awards, is it reasonable to think that maybe an announcement might occur by mid-year? Is there still just not enough clarity on timelines?

No clarity on timeline, but this has been imminent for several quarters now. I recognize that 'imminent' in the Middle East means slightly different terms compared to North America. A lot of work has gone into these tenders behind the scenes with our customers. We know they're ready, and I think they're waiting for the right oil production signals to start making the next step.

Okay, perfect. That's all for me. Thanks. I'll turn it back.

Thanks, Cole.

Our next question comes from the line of Keith Mackey with RBC Capital. Your line is open.

Hi. Good afternoon and thanks for taking my questions. I just wanted to start off. Kevin, I think I heard you say Q2 looks like it's going to be trying to break out or break up, but it's going to be 25% to 30% higher than last year. I thought, and you said Q3 is going to be strong as well, potentially stronger than the winter level. Did I hear that right? Or what was the comment there?

You heard it right. I guess all that I'll say is the previous projections I've given that Q3 and Q4 seemed to see that after I provided guidance, another COVID variant popped up and slowed down decision-making. Barring any macro dislocation, I think those projections are as I said: Q2 looks like it’s up 25% or maybe a little bit more compared to last year. Again, we could see Q3 matching or exceeding Q1 activity levels, but that depends on any macro dislocation.

Yes, for sure. Appreciate that it certainly is difficult to forecast what's happening in the macro these days. That would be incredibly strong level for Q3. Can you maybe just talk about what gives you the confidence to say that and maybe just talk a little bit about the rig types that will make up the gap? Will the mix be similar to Q1, or do you think it will be different based on the seasonal drilling at that time?

Yes, to clarify that: While it looks pretty strong compared to what we've just been through, we aren't at peak levels like we were in 2014 or 2016. The mix would look similar to the winter mix right now. Our Super Triples are pretty much fully utilized. We have a potential to bring one more Super Triple up from the U.S. and are working with customers to see if that happens, so it could be fully maxed out. With our Super Singles, we've got a pretty good mix right now with this resurgence in heavy oil driven by Clearwater, and we certainly have room to run there. We have the potential to reactivate another five, ten, or even fifteen Super Singles as well within our current opportunity cycle set.

Got it. And just a follow-up on potentially bringing up the rigs. I think there was another couple that moved around basins in the U.S. Can you talk about some of those regional tightness in rig supply? Where are you seeing things become the most tight in Canada? I imagine it's in the Super Triple category. Also, could you talk about the U.S. in terms of where you're seeing that tightness and where you think rigs could move as a result?

That's a great question. The biggest surprise I've had in 2022 was a customer asking if they could move one of our rigs from Oklahoma to the Permian basin. I thought there was still some slack capacity in the Permian basin. But this particular customer was willing to pay upfront for one of our rigs to move to the Permian. Late December last year, we moved a rig from the Permian to Eagleford. We're currently looking at some opportunities to redeploy rigs into Haynesville. It seems the regional tightness is developing everywhere. We only have a couple of excess rigs right now, and that's in the DJ basin.

Got it. Okay. Very good. And just on the tech adoption. Historically, I believe you've mentioned that U.S. customers were a little quicker to adopt than Canada. Has that changed? Has Canada caught up? As a follow-on, has the EverGreen line gained traction faster in Canada or the U.S., or has it been fairly similar as well?

First, the EverGreen lines have been getting good traction in both markets with almost no differentiation. I'd say ESG emissions responsibility focus is universal across our public and private customers alike, so that's a trend we're seeing across the customer mix and geographic spread. On the technology side, the simple answer is this: On longer duration wells, technology has more room to demonstrate clear improvements. In shorter duration wells, whether they're shallower or faster, the gains tend to be narrower for the customer, and it's a tougher sell. So, Canadian wells tend to be a bit shallower, and there are areas that are really short-duration wells. These shorter wells are a mixed bag and harder to push technology.

Got it. Thanks so much.

You're welcome.

Our next question comes from the line of John Daniel of Daniel Energy Partners. Your line is open.

Good afternoon, guys.

Hey, John.

Kevin, just one quick reference from me. Lots of people in our space talked about the possibility of us being at the start of a multi-year cycle. I'm curious if customers are viewing it the same way—are they talking to you about multi-year arrangements if that belief is true? Any color on how they see life beyond this year, would be great?

Short answer is not really. We have a few customers looking to lock in low rates for longer terms; however, I wouldn't call that a trend. It's more like a handful of customers—less than half a dozen—who are making plans beyond one year. The reason might be that in terms of cost, a drilling rig often isn't as significant an expense compared to the total well costs. They might focus on areas where they have larger financial exposures, like sand profit or pressure pumping.

Fair enough. Do you suspect that's a function of the recent volatility? It seems to me, if the commodity backdrop remains stable, your rates are going higher next year if this environment holds. Why wouldn't customers want to be proactive and lock in these rigs now to mitigate that risk?

Well, John, it might also be that the drilling rig on these high efficiency wells is a very small fraction of the cost of the overall well. They have less tendency to focus on rig costs.

Okay. Fair enough. I appreciate your time as always. Thanks.

Thank you.

I'm showing no further questions at this time. I would now like to turn the call back over to Mr. Carey Ford for any closing remarks.

Okay. Thank you for joining us this afternoon. We look forward to connecting with you on our Q1 conference call in April. Have a good day.

Ladies and gentlemen, that does conclude our conference for today. Thank you for your participation. You may now disconnect.