Precision Drilling Corp (PDS) 2021 Q4 法說會逐字稿

Good day, ladies and gentlemen. Thank you for standing by, and welcome to the Precision Drilling Corporation 2021 Fourth Quarter and End of Year Results Conference Call and Webcast. (Operator Instructions) Please be advised that today's conference may be recorded. (Operator Instructions)

I would now like to hand the conference over to your speaker host today, Mr. Carey Ford, Senior Vice President and Chief Financial Officer for Precision. Please go ahead, sir.

Thank you, Olivia, and good afternoon, everyone. 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, our President and Chief Executive Officer. During news release earlier today, Precision reported its fourth quarter and year-end 2021 results. Please note that these financial figures are in Canadian dollars unless otherwise indicated. Some of our comments today will refer to non-IFRS financial measures such as 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 businesses.

With that, I'll turn it over to you, Kevin.

Thank you, Carey, and good afternoon. While the global recovery remains uneven and with some lingering uncertainties, the fundamentals for Precision may be the best I've witnessed in 4 decades. Global oil demand has almost fully recovered, but with sharply reduced activity and virtually 0 exploration drilling over the last 2 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 inventories of drilled uncompleted wells or DUCs, as they are called, have dwindled. Super-spec rig supply is tight, tighter than most 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 marching our day rates back into positive earnings territory, and then driving rates further to achieve a reasonable return on our invested capital. Precision and 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 in 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 to the commodity price and the overshoots is simply not possible today. Capital discipline is well in [transfer into] industry -- 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.

And 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 4 years, eclipsing $1 billion in debt reduction since 2018, and reaching a net debt-to-EBITDA leverage level of below 1.5x.

Importantly, we also announced a prioritization of return of 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 business' ability to grow market, 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 of $64 million, increased 16% from the fourth quarter of 2020, supported by higher North American activity. Also included in adjusted EBITDA during the quarter is share-based compensation expense of $6 million, inventory write-downs of $3 million, and nonrecurring 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 4 rigs from Q3. Daily operating margins in the quarter, absent impacts of turnkey and idle but contracted payments were USD 5,648, an increase of USD 410 from Q3.

The increase was impaired by USD 620 per day of charges related to nonrecurring margin impacts. Absent impacts of turnkey and labor, daily operating margins would have been USD 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, asset [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 6 rigs and average day rates were USD 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 2021 activity, and expectations for continued rig activations in 2022.

Our 2022 capital plan is $98 million, is comprised of $56 million for sustaining and infrastructure, and $42 million for upgrade and expansion, which relates to anticipated investments supporting Alpha Technologies and contracted customer upgrades. As of February 9, 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 continue 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 31, 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 5.5x, and 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 2.8x. 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 1.5x 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 is increasing in both 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 semiannual 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 and our effective tax rate to be 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% for the third quarter, and with 52 rigs we're in 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 the trajectory may continue through the year. Leading-edge rates have progressed to the mid-20s for active rigs and are now moving to the same range for cold rigs due to the rising industry-wide rising 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 2 basin to basins for Triple rig moves.

Regarding Precision's market discipline and pricing strategy, the key pricing signal we can send to our customers is refusal to accept lower-than-threshold day rates, and this 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 the peak levels we anticipated, but this is largely due to some customer-driven delays. We expect the activity will remain firm with a seasonal slowdown driven by weather, not by budget exhaustion. Currently, we're running 66 rigs, 4 additional rigs are delayed for customer supply chain and location preparation issues.

This work should be completed later in the quarter. Customer indications for second quarter look very strong. The spring breakup rig demand running 25% to 30% higher than last year. And an 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 traction in Canada during 2021, and we expect that trend to continue in 2022. And our customers don't like to hear this. But it is essential that the Canadian services industry recovers such 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 US 0.79 range. The cash flows for our Canadian customers are all-time highs. And this brings me to discuss a specific play in Canada. And 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 stay handful of rigs in 2019. With horizontal wells and measured depths in the 2,800 meter range, the drilling programs are ideally suited to Precision's high-performance Super Single pad-style rig. Precision currently is operating 11 Super Single rigs in the Clearwater region, holding a 55% market share. And this has grown from just 3 rigs in 2019 before the pandemic. We think the Clearwater like the Montney has a good long term -- has good long-term fundamentals with strong commodity price support, very good geology and pad-style horizontal drilling were high-efficiency drilling rigs derisk the F&D costs.

The Clearwater will continue to be a strong demand driver for Precision' Super Single rigs. Now for some, it might be easy to discount or reject the Canadian market. Yet with Precision's blanketed Canadian footprint, our Super Single and Super Triple rigs, combined with their scale efficiency in our high-performance, high-value strategy. Canada remains a very strong and key geography for Precision's cash flow generating capabilities.

To round out our Canadian business, Carey mentioned our Well Service group is 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. And this demand has been further enhanced by the federally funded well site reclamation program. Labor challenges are constraining the well service industry yet, our team has performed very well, fully staffing to 50 rigs we are running today. And 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 to our customers, and have succeeded in pushing rates in the right direction. And again, 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 margin improvement through 2022.

Turning to our international business. We continue to operate 3 rigs in Kuwait and 3 rigs in Saudi Arabia. We're working with our clients in both markets on upcoming tender specifications, and we are bidding for opportunities with other operators in the region that have nothing new to report today. My expectation remains that as OPECs production limits are fully removed in the coming months, these potential rig activations 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 has run its 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 our Alpha digital products continues to grow. As we've reported in our press release, we are expanding our AlphaAutomation 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 continue to 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 0. Customer acceptance and uptake has been strong with 48% of our operating fleet today equipped with at least 1 EverGreen emission reduction solution. With current bookings, we expect to have 10 EverGreen combustion fuel monitoring systems installed and running, and 6 hybrid battery storage systems operating by midyear. I expect that over the next few years, all of our rigs we 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, and 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 delever as guided.

Our other priorities, including a strong focus on free cash flow and expanding our technology offerings will continue in 2022. So finally, I want to thank the people of Precision, out in the rigs, in our support centers, in their offices, for the safety and the work execution that underpins everything we do as an oil service provider. And with that.

I'll now turn the call back to the operator for comments -- questions.

(Operator Instructions) Our first question coming from line of Aaron MacNeil with TD Securities.

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 rents given the improvement in the sector?

Aaron, this is Carey. So I would say that part of it is a labor increase that we implemented in December, which was about $800 a day. I think that's kind of standard for -- we're talking about the U.S. market, kind of standard for our peers. We do have some reactivation costs that we're still absorbing. We reactivated 6 rigs in Q4, and we plan to reactivate another 6 rigs in Q1. And that's kind of trending at $150,000 to $200,000 a day. So that's pushing costs up a little bit. And we do have a little bit of inflation. I think it's a lot lower than other segments of the oilfield service sector, but we do have a little bit of inflation. So all in all, it might be, call it $1500 a day of increased costs that we're passing through. The rest of it would be margin expansion.

And as we mentioned on our last call, we thought that Q3 would mark the bottom or the top of the cycle for margins. And we showed increasing margins in Q4. We expect to continue to show increase 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 and (inaudible) 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. And I'd say we're kind of modestly shifting or moderately shifting more and more positive as we kind of go through each almost each month it passes with the 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, kind of reflect that optimism. There's no question this cycle is different than previous cycles. We're not seeing our customers overshoot commodity price. We're seeing a very well-managed and kind of controlled-pad back of rigs, various is being with the super majors are making small announcements. But it really feels like with the activity we have in our bidding team and our sales team right now that the gains that we were showing in Q1 and into Q2, we expect to carry on for the balance of the year. And we think there could be upside to that, but it just depends how quickly our customers pivot back to bringing in some small amounts of growth.

Understood. It 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 4 or 5 top North American drillers that there's discipline on returns, and that remains largely intact. But I guess I'm wondering, is that also true of 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 with the customer these days, it's almost always a case where it's just us and 1 or 2 others. We don't often see a lot of the smaller competitors. That's especially true in Canada, we're talking about Super Triples. But in the U.S., it will be us 1 or the other 2 or 3 other large drillers competing. So we're really not getting a good sense of what the smaller drillers are doing. So 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. And I guess, it sort of begs the question, that $42 million that's earmarked for expansion and upgrades is that all committed or mostly committed at this point? Or is it a placeholder? And what I'm ultimately trying to drive that is could we see that number expand throughout the year if activity levels are higher than you expect?

Okay. So on the growth capital, some of it is committed. I think we've made some commitments to [kit out] 70 of our Super Triples with Alpha Technologies. So that part is committed. And then 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. And last question for me I have already asked, so I'll turn it over. But it's just such an unusual winter here in Alberta. So just any comments that you can provide on the shape of spring breakup or potential [room ban] activities would be helpful.

No guidance yet. Certainly, it's quite warm this week, and we've already run in some situations where we have some rigs that can't get on to location yet, so it's causing a few delays. My sense is if there's an early weather breakup that pushes a lot more work in pricing attention into late Q2, Q3, it might be a short-term drag on activity, but probably a net positive for the year. That makes sense?

Yes. It makes sense.

Our next question coming from the line of James West with Evercore ISI.

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

Well, I would tell you that I think that the -- it's a bit of a good news, good news story. I think we're going to run out of super-spec rigs in our fleet during this calendar year. And we have another group of rigs, about 15 rigs that are really strong upgrade candidates. That would probably take day rates that have a 3 on the left-hand side. And we need to see some good long-term contracts, probably 2- to 3-year contracts. But a high-quality problem for Precision to be running out of super-spec rigs in calendar year '22.

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. We're still -- the upgrades we're doing are adding up automation, adding hydro drill pipe or pump capacity, and you're still kind of in the low single digits millions of dollars. So we don't think that we're going to have to spend a whole lot of capital to address the market.

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

In the U.S. That's right.

Okay. Okay. That's very helpful. 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 and the big large producers you work for are aware of that. And that's why, of course, they're tendering now.

Could you -- maybe comment on the magnitude of if you were to be successful in some of these tenders or when you are successful, how many more rigs you might commit to the region and if those would be you would 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. So we've got the 3 add rigs in Kuwait that we expect to get reactivated during the year. We've got 1 idle rig on the ground in Saudi that could be activated this year. 3 more idle rigs in Kurdistan, and Georgia, then Iraq. Actually, 1 of those rigs is looking like it might be end up in not up or in Dubai, right? So 2 in Georgia, 2 in Kurdistan, 1 in Dubai that could be activated.

And we've had some tenders recently where we're looking at possibly utilizing some of our Super Singles and some other tenders that might be in the [1,500-horsepower] class. However, if we're utilized in North America, we would probably back away from those tenders.

I just had another comment there, kind of along that operating leverage thing. The most likely rig activations near term would be the 3 Kuwait rigs, which are all -- they're all super-spec [AC] deep capacity rigs that are 6 years old and will require a whole lot of capital to go into a new contract kind of in the $4 million range per rig.

Our next question coming from the line of Taylor Zurcher with Tudor, Pickering, Holt.

First question on Canada. Over the past few -- really the past 2 weeks down here in the U.S., I mean, there's been so much talk about significant pricing improvements. Again, for the U.S. market, you echoed some of those comments in prepared remarks today. So I'm curious if you could just compare and contrast what's going on from a pricing perspective in the U.S. That's what you're seeing in Canada, obviously, a number of different rig classes up there in Canada. And just curious where we sit from a pricing improvement standpoint for each of those rig classes up in Canada.

Yes. Taylor, so I think the pricing movement in Canada is probably a quarter or 2 ahead of the U.S. And there's a couple of reasons for that. One, the market is a bit tighter on the super-spec side, it's fully utilized. It's also more consolidated with primarily just 2 drillers that have the balance of the fleet for super-spec rigs, Super Triples that is in Canada. And then our Super Singles rig in Canada is kind of the cost of its own. There really isn't a strong competitor for Precision, Super Single rig, and it's a highly efficient rigs.

So we've had opportunities with rising demand and tight utilization to move those prices a bit sooner. And there's a seasonality component that comes into Canada, there's kind of a spring, spring for summer, Q3 type pricing circle. Sometimes a second pricing round that happens in the fall for the coming winter season. So there's kind of some natural windows when we engage with customers.

And there's a third factor in Canada that kind of has driven attention that's crewing. It's been particularly hard to recruit personnel in Canada, and that's created a lot of attention right across the oil services space. So I think all of those things have kind of worked to help move rates back into kind of a sustainable range, which are not quite at yet in Canada, but we're hoping to get there in 2022.

I think some of those factors are now coming into play in the U.S., the super-spec rig market is getting essentially, it's not sold out, but between regional dislocations and various differences in rig spec is almost sold out. And I think you'll see it effectively sold out in the next few weeks or a couple of months. So I do think the U.S. gets 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. And against that backdrop, you just mentioned 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, I mean, how are customer conversations are going with respect to term contract duration. It doesn't feel like many of the larger land drillers, including yourselves, have significant term contract coverage, at least not beyond 2022. And I just wonder if the customer urgency is there to go ahead and lock up some of these rigs even if it's at much higher pricing over the course of 2023.

Well, I think we've seen opportunities to contract rigs anywhere from pad to pad all the way out to 2 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 well, but I don't think any customers really fully understand how tight the market really is.

And, Taylor, nobody has a 2023 budget approved yet, like none of our customers do. So there's not a huge preponderance of people looking at long term. I would say that there's just a handful of customers looking to try to lock in lower rates maybe for a longer term, not necessarily locking in higher rates. So I think that certainly, in our case, we've been reluctant to jump at those opportunities looking more at shorter-term higher rate opportunities and the ability to reprice as the market tightens.

Got it. And then one last quick question for me. you're basically talking about going from 50 Alpha systems to roughly 70 by year-end. And I'm just curious how the demand pull works for those sorts of systems. I imagine some of those are going to be outfitted on rigs that are already in the field today?

And so I mean, 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 it almost immediately. We've got a handful of contracts in a performance-based where if we achieve certain performance levels, we'll earn more. So in that case, you can say that we have to earn the compensation, but those are working quite well. The majority of the applications are the a la carte pricing where we put the system on and we run it and we deliver value, and the customers see the value, and move on.

Just, Taylor, on that deployment, you asked a customer pull. We're working closely with our partners. We've always been kind of standardized on how we do this. Part of what we've done is lock-in low capital costs for that acquisition for an extended period by committing to those installations over the course of the year. So it's both balancing the risk on the inflation side, we keep the cost low, but also getting the systems across our fleet as fast as possible.

And our next question coming from the line of Waqar Syed with ATB Capital.

Carey, the potential reactivation cost 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, and we're trying to put a percentage of likelihood of securing those upgrades. So you can say somewhat included in that basket there.

Okay. All right. Kevin, one of your competitors today mentioned that there is 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-foot and draw works on the rig floors. Are you seeing the same kind of differentiation as well as you talk to your customers?

So Waqar, first of all, I guess the good thing and the bad thing is there is no API definition of super-spec. And I would say that each drilling contractor has an interpretation of what they view as the optimum rig design. And whether that includes skidding or walking could be a debate, whether it includes 3 mud pumps or 2 mud pumps can be a debate.

In our case, we actually have a wide fleet of super-spec rigs that have elevated rig floors with the drawworks up on the rig floor. In fact, split [LER] drive assembly so that we keep 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 same on super-specs.

What it comes down to is if you have a client who has a pad where he wants to maybe walk the rig over existing wellheads. He might want that extra clearance. If you've got a pad, which is a new pad and you're drilling it in a line, you may not need that clearance. So it just depends, I'd say it's more customer-specific than industry specific.

We have some of those rigs walking over wellheads are existing, other ones where we have clear pads we're drilling new wells on.

Okay. Great. And then in the international market, you have 6 rigs currently working with 2 contract expirations coming up. Do you see any downtime before they start up again? Or do you think there -- you would be able to renegotiate the contracts before the current contracts expire.

We expect no downtime.

Okay. And then for the Kuwait rigs, do you see them -- Kuwait, typically tenders get delayed, do you think that this year they may happen relatively quickly?

Well, I've been talking about that tender, I think almost all of 2021 and now into 2022. So we've already delayed 1 year from my early conversations. And the other thing I'd say is it seems like every time they make a projection about 4 weeks later a new variant pops up and slows down decision-making. So I'm really reluctant to try to predict what's going to happen in Kuwait. But Waqar, I would say that if Kuwait has their production curtailments removed, I think those tenets go ahead very quickly, or I should say when they have their production curtailments removed, I think those tenders move quickly.

Our next question coming from the line of Ian MacPherson with Piper Sandler.

I appreciate the description of what's happening in the Marten Hill Clearwater play. And I think it was asked a little bit, but I wanted to ask again if you could talk about your breakout of Super Singles versus Super Triples in Canada and speak maybe a little bit more to the differential in day rates or margins between the 2, 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, just to fill in the gaps where I missed something here. The Precision' Super Single rig was developed back in 1992, specifically for heavy oil drilling, I mean, exactly for this type of play. They're designed to be small, fast-moving light pad-capable rigs that have a small footprint can run kind of throughout spring breakup, if necessary, and have a really low efficient operating costs.

So it's a really cool design that's really kind of stuck with us the last 30 years now, and really kept that competitive edge out there. So the rig fits up market very well. Carey, operating costs of that rig would typically be about $4,000 or $5,000 less than a Super Triple in that range?

Correct. Yes.

And we're getting day rates for that rig down in the mid- to upper teens and pushing those levels even.

And that the rig actually does overlap with what in Canada is called the Tele-Double. So people will try to use a Tele-Double compete with us, which typically has a slightly higher operating cost and again, probably needs a higher day rate to get the same margins. In Canada, we have 27 Super Triples. They're all fully utilized right now. And we've given guidance on those rates. Those rates are in the kind of 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. 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 and where that takes your fleet-wide spec at the end of this year. And the market pricing stopped moving today and you repriced everything at leading edge and absorb all your reactivation costs.

(inaudible) do a model for you?

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, and we're getting better fixed cost absorption, and we don't have any reactivation cost. Daily operating costs probably go down a bit from where we're reporting right now. So I think you could see our -- see the fleet generating on average above $10,000 a day of margin.

Yes, I think so. I just -- the one thing I want to be careful with is not extrapolating your sort of 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 higher saturation of Alpha and other [a la carte] add-ons that it would not be unfair to project that. So I just wanted to (inaudible).

Yes. I think that if you go back to 2018 and you looked at where our super-spec rigs were pricing and getting 1 and 2, in some cases, 3-year contracts without Alpha, we were well above [$10,000] a day of margin on that segment of our fleet.

Yes. 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?

So it's a 4-year plan. For the first couple of years, this is almost exclusively going to be share buybacks. And as we get closer to the target leverage level and there's a little bit more visibility in the business, dividend becomes more likely. But for the first couple of years of this capital framework plan, I assume it's going to be share buybacks.

(Operator Instructions) Our next question coming from the line of Cole Pereira with Stifel.

So some pretty good color so far on Canada versus the U.S. And a couple of quarters, you highlighted that the outlook for Canada was especially bright relative to the U.S. in the near term. Just wondering if you really currently see either Canada or the U.S. as being relatively stronger right now, obviously factoring in some of the seasonality in Canada.

I think, Cole, what kind of drives me to leave that is they were a little farther down the pricing trajectory with our Canadian customers. So that's helping [MidCon] look better. I think part of that is the tighter market consolidation in those 2 rig areas in the Super Triple area and in our heavy oil Super Singles area.

So you've got a much more rational market with generally public players that are more rational in their thinking. So it's just -- it behaves more industrial or more structured and more disciplined than less mature markets. That's the way it feels right now. Does that make sense?

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

On the drilling side, it's been a pretty heavy lift for our team, and I know some of them are listening today, they worked pretty hard, but they've met the objective in drilling. It's been much, much tougher in well servicing. And there's 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 consistent over time. So the total pay is much higher that attracts that tracks people that stick a little more to drilling.

In well servicing, it could be good or it could be bad. It's call-out work, it's sort of day-to-day work and it's been much tougher to recruit a lot like a lot of the other oilfield call-out services. So in drilling, no hard work for our team, but they've accomplished the task in drilling and well servicing really hard work. You guys have done a great job. We've got 50 rigs stepped up right now, expect to have more stepped up for Q3 after breakup. But I would say that in well servicing, it's limited activity.

Okay. Perfect. That's great. And so just to clarify on the international rig awards, I mean, reasonable to think that maybe an announcement might occur by midyear? Or is there still just not enough clarity on time lines?

No clarity on time line, but this has been -- I mean, the entire process has been imminent for several quarters now. I recognize that imminent Middle East being slightly different terms than imminent in North America, but there's a lot of work that's gone into these tenders behind the scenes at our customer. We know they're ready, and we know that they're, I think, waiting for the right oil production signals to start making the next step.

Our next question coming from the line of Keith MacKey with RBC Capital.

I just wanted to start off, Kevin, I think I heard you say Q2 looks like it's going to be breakout or breakup anyway, it's going to be 25% to 30% higher than last year. And then I thought that 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, Kevin?

Well, you heard it right. I guess all that I'll say is the previous projections I've given that after Q3 and Q4, it seems like a few weeks after I gave the projection another COVID variant popped up and slow down decision-making. So barring any kind of macro dislocation, I think those projections are what I said. I think Q2 looks like it's 25% or maybe a little more better than last year. And once again, we could see Q3 matching or exceeding Q1 activity levels, again, barring any kind of macro dislocation.

Yes, for sure. I appreciate that it certainly is difficult to forecast what's happening in the macro these days. But certainly, that would be in an incredibly strong level for Q3. Maybe just talk about what gives you the confidence. So based on what you know today to say that and maybe just talk a little bit about the rig types that will sort of make up the gap? Will the mix be similar to Q1, do you think? Or will it be different based on the seasonal drilling at that time?

Yes. So just let me qualify good, great and better. So it does look pretty good compared to 2020 and 2021. If you kind of go back to 2016 and 2014, we're still well below those levels. So while it looks like a pretty strong year relative to what we've just been through, it wasn't very long ago was much, much better times. So keep that in mind. But the mix would look like the winter mix right now. We have our Super Triples pretty much fully utilized. We have a potential to maybe bring on more Super Triple out of the U.S. We're working with customers to see if that happens.

So we could add 1 more Super Triple in Canada. -- but that's fully -- that will be fully maxed out. And then with the Super Singles, we've got a pretty good mix right now with kind of this resurgence in heavy oil kind of driven by Clearwater. But I think there's a little more room to run there. We certainly have more Super Singles. And to reactivate another 5, 10 or 15 Super Singles as well within our current opportunity cycle set.

And just a follow-up on potential (inaudible). And I think there was another couple that moved around basins in the U.S. Can you maybe just talk about some of those regional tightnesses in rig supply and where you're seeing things be the most tightened, Canada, I imagine it's the Super Triple category. And maybe if you could then just talk about the U.S. as well and kind of where you're seeing that tightness and where you think rigs could move as a result.

That's a really great question. I'm actually glad you raised it. Because probably the biggest surprise I've had in 2022 was a customer asking if they can move one of our rigs from Oklahoma to the Permian Basin. I thought there was still some slot capacity in the Permian Basin. But for this particular customer that we're working for, they're paying to move (inaudible) kilometer to the Permian.

Last year, late in December, we moved a rig from the Permian to Eagle Ford. We're looking at some opportunities right now maybe to redeploy some rigs into the Haynesville. So it seems like that regional tightness is kind of coming on everywhere. The only place we have a couple of excess rigs right now is DJ Basin.

Got it. Okay. Very good. And just on the tech adoption. I know historically, I think you talked about U.S. customers are a little quicker to adopt than Canada. Has that changed? Has Canada caught up? Or -- and maybe as a follow-on to that, how the EverGreen line gain traction faster in Canada or the U.S.? Or has it been fairly similar as well?

So first, the EverGreen line has been actually getting good traction in both markets with almost no differentiation. And say that ESG emissions responsibility focus is universal across particularly our public customers, but actually most of our private customers too. So that's a trend we're seeing right across the customer mix and geographic mix.

On the technology piece, so the simple answer is this, on longer-duration wells, technology has more room to show clear improvements. So in shorter duration wells, whether they're shallower or faster, the games tend to be a little bit narrower for the customer and maybe a little tougher sale. So Canadian wells tend to be a little shallower. And there are some areas that are really short duration wells. Tougher sell-- cell on the short duration wells, much easier to sell long duration wells. And by the way, but when I'm talking about long and short, long would be 8 days and short would be 4 days.

Our next question coming from the line of John Daniel of Daniel Energy Partners.

Kevin, just one quick one for me. There's obviously lots of people in our space talked about us being a potentially at the start of a multiyear cycle. I think as we look at just the commodity backdrop. And I'm curious if customers -- if they're looking at it the same way, are they actually talking to you about multiyear arrangements if that belief is true? Just trying to see if you can provide some color on how they're viewing life beyond this year.

John, short answer is, not really. Other than a few customers looking at trying to lock in low rates for longer, I would say that there isn't -- there's no lot of long-term planning that's transmitted down to the land drillers yet around long-term contracts, take or pay. We have a handful of customers say, say, less than a half dozen, where they are seriously making plans beyond 1 year but I wouldn't call it a trend.

Fair enough. But -- and do you suspect that's just because of just how the recent volatility? Because it seemed to me if -- and then kind of a bit of a follow-on on Aaron's questions. When you look at where the business is today, the pricing trends, and all of that, if all else being equal, it seems your rates are going higher next year if this commodity price environment stays where it is. Why wouldn't you want to be proactive in mitigating that risk if you're the customer, just kind of thought. Any color would be great.

Well, John, part of it might be that the drilling rig on these high-efficiency wells is still just a very small fraction of the cost of the total well. So if they're putting their focused on an area where they have a lot of financial exposure, it would be sand proppant, it would be pressure pumping. It probably wouldn't be the rig.

I am 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. This concludes the conference for today. Thank you for your participation. You may now disconnect.