Precision Drilling Corp (PDS) 2021 Q2 法說會逐字稿

Good day, and thank you for standing by. Welcome to the Precision Drilling Corporation 2021 Second Quarter Results Conference Call and Webcast. (Operator Instructions)

Please be advised that today's conference is being recorded. (Operator Instructions)

I would now like to hand the conference over to your speaker today, Dustin Honing, Director of Investor Relations and Corporate Development. Please go ahead.

Thank you, Mattie, and good afternoon, everyone. Welcome to Precision Drilling's Second Quarter 2021 Earnings Conference Call and Webcast. Participating today on the call with me are Kevin Neveu, President and Chief Executive Officer; and Carey Ford, Senior Vice President and Chief Financial Officer.

Through our news release earlier today, Precision reported its Second Quarter 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 EBITDA and operating earnings. Our comments will also include forward-looking statements regarding Precision's future results and prospects, which are subject to a number of 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. Carey will begin today's call by discussing second quarter financial results. Kevin will then follow by providing an operational update and outlook.

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

Thank you, Dustin. Before we discuss our second quarter results, I'd like to notify the audience on this call that Dustin will be taking on a new role within Precision overseeing the finance operations and other administrative functions within our Well Service division. As you all know, Dustin has managed PD's Investor Relations efforts very well over the past 2.5 years, and he is ready for a new challenge within our organization. For the time being, you can contact me with Investor Relations matters.

Moving on to our second quarter results. Precision's second quarter results were characterized by increasing North American activity, field margin performance exceeding our prior guidance and continued strict focus on cost control and cash flow generation.

Our second quarter adjusted EBITDA of $29 million included a share-based compensation expense accrual of $26 million. Absent this accrual, adjusted EBITDA would have been $55 million, far exceeding our expectations. The unusually large share-based compensation accrual resulted from our share price of approximately doubling between the end of Q1 and the end of Q2 and our cash-settled accounting treatment. As noted on our last conference call, the cash treatment and share price volatility may present higher volatility in financial results. Please keep in mind, we have the ability to pay a portion of these awards as either cash or equity upon vesting.

During the quarter, we received $9 million of CEWS assistance payments. As a reminder, the CEWS program supports employment in Canada, and Precision has utilized this program to preserve jobs within our organization. The CEWS program has continued into the third quarter, and we expect the impact to Precision to be approximately $25 million for 2021.

In the U.S., drilling activity for Precision averaged 39 rigs in Q2, an increase of 6 rigs from Q1. Daily operating margins in the quarter were USD 6,752, a decrease of USD 275 from Q1, primarily due to legacy contracts rolling off into the spot market, offset by higher spot market pricing on new rigs and increasing adoption of Alpha technologies. Absent impacts from IBC and turnkey, daily operating margins would have been USD 227 lower than Q1.

During the quarter we activated 6 rigs, and the reactivation expense remained in the $150,000 to $200,000 range, and we expect the same cost per reactivation for the coming quarters. For Q3, we expect normalized margins to be in line with Q2, an indication of average field margins bottoming this summer.

In Canada, drilling activity for Precision averaged 27 rigs, an increase of 18 rigs from Q2 2020 and representing a tripling of the rig count. Daily operating margins in the quarter were $7,124, a decrease of $1,918 from Q2 2020. Absent the CEWS impact, margins would have been $5,247 or $1,378 higher than Q2 last year.

For Q3, we expect margins absent of CEWS and onetime recoveries to be consistent with Q2 and slightly down compared to Q3 last year due to rig mix, offset by price increases, improved fixed cost absorption and higher Alpha technology adoption. For reference, daily operating margin in Q3 2020, absent CEWS and onetime recoveries were $6,270.

Internationally, drilling activity for Precision in the quarter averaged 6 rigs, and international average day rates were USD 54,269, consistent with the prior year. In our C&P segment, adjusted EBITDA this quarter was $4.3 million, up approximately $5.5 million compared to the prior year quarter. Adjusted EBITDA was positively impacted by a 466% increase in well servicing hours. In addition, a lower cost structure, CEWS program support and well abandonment work supported the quarter's financial results. Well abandonment work represented less than 20% of our operating hours in the quarter.

Capital expenditures for the quarter were $20 million, and our full year 2021 guidance has increased to $63 million comprised of $41 million for sustaining and infrastructure and $22 million for upgrade and expansion, which relates to anticipated investments supporting Alpha technologies and contracted customer upgrades.

As of July 22, we had an average of 33 contracts, in hand, for the third quarter and an average of 34 contracts for the full year 2021. In June of this year, we completed a USD 400 million offering of senior notes due in 2029 with a coupon of 6 7/8%, and an extension of our revolving credit facility to 2025. These transactions enabled us to push out our first maturity to 2026, reduce our interest cost and left approximately $200 million in prepayable debt on our balance sheet, all while maintaining a strong liquidity position.

As of June 30, our long-term debt position, net of cash, was approximately $1.1 billion, and our total liquidity position was approximately $500 million, excluding letters of credit. Our net debt to trailing 12-month EBITDA ratio is approximately 5.8x and our average cost of debt is 6.3%. We remain in compliance with all our credit facility covenants in the second quarter with an EBITDA to interest coverage ratio of approximately 2x.

During the quarter, we reduced total debt by $23 million and year-to-date debt reduction is $52 million, over halfway to meeting our debt reduction target range of $100 million to $125 million for the year. Our capital allocation program remains substantially weighted to debt reduction, and we remain on track to meet or exceed our long-term reduction target of $800 million between 2018 and 2022, where we have already reduced debt by $602 million since the beginning of 2018. For the remainder of 2021, we expect to continue generating free cash flow through operations with higher activity, improved pricing and only $22 million of cash interest due, we expect cash flows to be robust in the second half, supporting further deleveraging.

For 2021, our guidance for depreciation and G&A before share-based compensation are $280 million and $55 million, respectively. As a result of our recent debt refinancing, our run rate cash interest expense is less than $80 million, and we expect it to move lower as debt pay down should continue in 2021. Finally, we expect our cash taxes to remain low and our effective tax rate to be below 10%.

With that, I will now turn the call over to Kevin.

Thank you, Carey, and good afternoon. I'll now take a few minutes to discuss the strong recovery developing in our North American businesses and update you on our progress towards our 2021 strategic priorities.

But before I start, I want to reflect that the last year has been -- last 1.5 years has been extremely challenging for our industry and especially the people who work here at Precision. The pandemic health challenges, the lockdowns, the industry layoffs and the early retirements and the increased individual workloads have taken a huge personal toll on our people. Our field operations remain fully staffed and unavoidably working in close contact, but have managed the pandemic challenges on the job and at home exceptionally well. Over the last 2 months, we have fully reached after our corporate offices in Houston and Calgary, and I thank our people for the excellent work they performed in their roles remotely over the past year, and I appreciate the challenges they continue to face every day.

We are at the beginning stages of what's emerging as a strong industry recovery, and we rely on the hard-working and loyal Precision team to execute our business, support our customers and help drive the results our investors and stakeholders expect.

While Carey fully covered off our recent debt financing activities, I'll just add that I'm extremely pleased to have substantially resolved our maturity profile, lowered our interest carrying expense and maintained our strong liquidity, all while continuing to make excellent progress towards both our short-term and long-term debt reduction targets. We believe that reducing our debt levels and bringing our leverage level below 2x EBITDA will create substantial value for our investors. It should be clearer now than ever before that our scale-based business model, utilizing high-value, long-life assets, coupled with highly skilled crews and leading digital technologies creates a strong, full cycle free cash flow profile, and the asset base will require minimal capital that we invested for the foreseeable future.

So turning to our regional markets. I believe the rebounding customer demand we see in Canada -- in the Canadian segment has brought implications as leading indicator for what we expect to develop in the U.S. From a high level, Canadian customer demand has returned to above pre-pandemic levels. Even during the second quarter, our Canadian drilling activity, while tripling last year's level, was in line with 2019. In our Well Service business, second quarter activity was over 7x what we experienced last year, also in line with 2019 activity levels. Now several weeks into the third quarter, we see demand levels trending substantially higher than 2019, and I'll come back to that in a few moments.

Looking closer at our Canadian customer mix, while private equity producers play an important role, over 2/3 of the demand we see comes from publicly listed producers. This group has seen -- has experienced several years of operating within capital-constrained and fiscally disciplined framework. They've been focused on debt reduction and return of capital to shareholders since the middle of the last decade, and they've driven cost efficiencies through all aspects of their business models. Additionally, we've seen several key consolidating transactions in our customer space that further builds up producer scale and efficiency. And now with the improving commodity fundamentals, the firm AECO Gas and Western Canada Select oil prices and resilient NGL pricing, they have responded quickly, but modestly increasing drilling activity while remaining highly capital disciplined. This modest increase in the spending has a meaningful impact when multiplied across the full producer space. I'm confident we'll see a similar trend emerge in the U.S., as public producers -- as the public producers -- older producer hedges roll off and are replaced with the current strip and those customers find a path to balance modest growth with sustained shareholder returns.

Currently, our Canadian drilling rig count to 52 operating rigs compares to 13 this time last year and exceeds both 2019 and 2018 levels. We mentioned in our press release that we had several more rig activations planned through the third quarter and should see activity trend into the upper 50s later this quarter with the potential for additional rig activations in the fourth quarter as our customers prepare for a busier 2023 -- 2022.

Unusually, we expect Precision's Q3 total drilling days will exceed the Q1 winter drilling season. The only other time I've seen this happen was during the 2010 recovery following the global economic recession. That slowdown pales in comparison to what we've experienced over the past 18 months. Early in July, we agreed with the customer to a long-term contract, which includes the cost to mobilize the Precision's Super Triple rig from Colorado to Northeastern BC, further strengthening our market position in the Montney play. I think we'll have additional opportunities for ST-1200 rig redeployments to Canada as our customers look to their 2022 drilling budgets.

Labor shortages have emerged across the Canadian oil service industry as a serious challenge. We are finding that many people have left the industry and are reluctant to return. The East Coast commuting workers are not able to easily travel, and the pandemic-related unemployment insurance programs seemly discouraged workers from reentering the workforce at least for now. We believe that recruiting and training employees is a core Precision competitive advantage and will ensure that we sustain a strong market position as this recovery continues.

For you, the takeaway is that the labor tightness is significantly impacting the service industry and providing a meaningful backdrop for rate increases. We began those price increase discussions with our customers during the second quarter, and increased rates on all rig classes, several hundred dollars above any cost inflation impacts. Marching our rates back to positive net income territory is the key objective of our sales team, and we believe this will be possible with the rate increases, which will began this spring and will continue as pricing discussions commence in the fall for the 2022 winter drilling season.

Now turning to our Canadian Well Service division. The recovery there is remarkable with current activity trending well above 2019 levels. Today, we have 38 Well Service rigs operating compared to 29 in 2019. We expect this demand to remain strong through the next year. This healthy rebound has several fundamental base drivers. We are seeing increased workover spending by our customers as they look to rework existing wells to improve or restore production. Customer demand has increased for completions activity tied to the increased drilling programs and, of course, the additional well abandonment work related to the government subsidized well abandonment programs that are all driving demand.

Labor constraints are hitting this industry's segment part, primarily due to the call out and less predictable day-to-day nature of the employment. Again, Precision's recruiting capabilities are largely mitigating this risk for us. Yet the labor challenge provides a strong catalyst for price increases. As with our drilling group, our Well Service sales team is charged with marching out pricing and margins back to positive net earnings territory.

So in summary, our Canadian businesses will not require significant capital spending other than customer-funded technology enhancements and activity-based maintenance capital. This segment remains well structured to generate strong and increasing free cash flow for the foreseeable future. Now I'll remind the listeners that the Canadian recovery is not characterized by massive shifts in E&P spending. What we are seeing are modest incremental increases in spending by a highly disciplined group of public producers.

Now turning to the U.S. We think the U.S. market is poised for a similar rebound in activity requiring only modest increases in spending by U.S. producers. Our U.S. customers have learned to operate efficiently. They continue to pay down debt, and they return capital to shareholders. Producer consolidation is underway, and we believe there will be an urgency to replace the rapidly reclining inventories of drilled, but uncompleted wells. Like Canada, we expect even a modest increase in U.S. producer spending will drive significant and meaningful demand for our super-spec rigs like our Super Triples and particularly for our Alpha digital technologies. Currently, we are running 42 rigs in line with our prior guidance and expect to be running 45 rigs by mid-Q3. Visibility for additional rig additions continues to emerge with drilling activity up significantly.

Pricing for idle rig reactivations is improving and/or categorize this range as mid- to upper teens for prospective rig activations. Now regional labor challenges and local rig availability are emerging as pricing opportunities as we see customers weighing rig redeployment costs versus minor spec upgrades and higher rates. Now on active rig renewals, where the customer is either looking to retain a running and crude up rig or acquire someone else's running crude up rig, pricing is trending in the $20,000-plus range now. And we see this as a constructive and improving price environment across all rig categories. To date, the majority of our activity increases have been with private equity and gas-focused operators. Looking forward, we're expecting a shift towards more oil-related activity and publicly traded producers. It's our view that virtually all rigs activated this year will be super-spec and particularly if they are targeting development drilling programs.

So I think this is a good point to shift to our Alpha technology update. As reported in our press release, it appears we crossed the technology tipping point with our customers at the beginning of this year. The efficiency gains and predictability improvements we deliver with AlphaAutomation are becoming well understood and accepted by all customers, and we are seeing wide-scale customer adoption. Our AlphaAutomation days were up 30%, sequentially, despite the reduced seasonal activity in Canada. And now with 16 commercial AlphaApps, we saw AlphaApp revenue almost doubled in the second quarter versus the first quarter.

AlphaAnalytics is also gaining strong customer acceptance with sequential utilization also stepping up over 70%. Notably, during the second quarter, we contracted 3 super-spec rigs on a long-term basis with a new customer, a major operator. These rigs will be activated during the third and fourth quarter with full AlphaAutomation, AlphaApps and AlphaAnalytics product suite. We view this as a technology-driven market share gain.

Clearly, digital enablement is a theme we are hearing from virtually every customer today. And there's no question that our Alpha technology suite delivers strong digital value and our a la carte pricing model is ensuring that we get our share of that value creation.

The second common theme we hear from virtually all customers today is regarding reducing GHG emissions. Our decision to target ESG as a strategic priority this year could not have come at a better time. You may have noticed our announcement last week of the Precision e-team across functional group of experts within Precision tasked with leveraging our environmental and emission strategies.

Also included was the announcement of our EverGreen environmental brand and the specific ongoing initiatives to provide reduced and 0 emission power sources for our rigs. The e-team has made excellent progress this year, and we are very well positioned with our customers as a key service provider helping solve their GHG challenges. We also published our second annual corporate responsibility report, which is aligned with SASB and TCFD disclosure standards.

I recommend you go to our website and review our comprehensive corporate responsibility disclosure.

Lastly, in our International business segment, as Carey mentioned, activity was stable during the second quarter with 3 rigs operating in Kuwait and 3 rigs operating in the Kingdom of Saudi Arabia. We are expecting upcoming tenders for our 3 idle rigs in Kuwait and believe we have a good chance of success on those tenders. This may result in rig activations later this year. These rigs will require some equipment recertifications, and I would expect capital spending on the order of $3 million to $5 million per rig, which we'd expect to recover inside the first few months of rig operation. We're seeing increased tender activity in the Arabian Gulf region through several NOCs and expect this could result in further rig activation opportunities early next year. It seems that much of the rig tendering sequencing is linked to the timing of the relaxing of the oil export limits. As always, the national oil company tender process tends to be lengthily, but results in similarly lengthily contract terms, something we ultimately desire. With the improving outlook across all of our business segments, I'll return to the people at Precision who are critical to every aspect of our services. Thank all of you for your hard work, perseverance and excellent risk management over the last several quarters. So I'll now turn the call back to the operator for questions.

(Operator Instructions)

And your first question comes from the line of Ian MacPherson from Piper Sandler.

Kevin and Carey, congratulations on the debt refi, that's a great news for you all financially and operationally. So good to see that. I was intimated, Kevin, by your leading-edge U.S. day rate data points. Just wanted to clarify, are those base day rates excluding a la carte add-ons for the Alpha suite?

Correct. Those are base day rates for the base Super Triple rig excluding technology add-ons.

Okay. Yes, that's certainly improving higher than we would have recently expected. And you mentioned the consolidation of your customer base across Canada and the U.S. But there's also been some consolidation in your space in Canada, which I think makes that competitive framework even -- probably a little bit tighter than it is in the U.S. Are you seeing accelerating pricing power more so in Canada than in the U.S. at this point? And any -- would you lean further out in time to hazard where pricing is going in both markets by the end of the year?

Ian, I think that's a very good question, first of all. But the transactions for consolidation in Canada and the one in the U.S. also haven't closed yet, but we expect them to close soon. I do think that brings an appropriate level of rational thinking to the market space. And the way I say that is the -- in Canada, for example, the Montney play in the Deep Basin and Duvernay are unconventional resource plays with large pad horizontal drilling. These are very much industrialized operations. They require drillers of scale with high-quality technology-driven assets to operate those as economically as possible. So I think that this rationalization we're seeing among the customer base and being echoed in the supply base is constructive. It creates -- frankly, it does create a better pricing environment for our services, but probably a more appropriate pricing environment for the services we provide. But I think the core driver right now for pricing in Canada has been just industry overall demand and then some of the labor tightness tightening up the supply side. So I think those 2 combinations are driving the near-term pricing. But we do expect to see very rational behavior over the long term on -- particularly on the Deep Basin in Canada. And I think the same thing will develop in the U.S. as that consolidation play takes place also.

Your next question comes from the line of Taylor Zurcher with Tudor, Pickering and Holt.

First question, Kevin, you talked about the Canada market backdrop has clearly improved, and you talked about how you -- we might see a similar dynamic as what's going on in Canada right now, eventually play out in the U.S. In the U.S., we're still well below pre-pandemic levels. And so just hoping you could give us a little bit more color on the dynamics at play that you see in the U.S. maybe over the next 12 months? And maybe any suggestion on timing as to when we might get back to sort of pre-pandemic type levels in the U.S.?

Taylor, I think the #1 answer I'm going to focus on is that the investor desire for returns and discipline is not going to go away in the U.S. and it hasn't gone away in Canada either. But I do think what happens is that as our customers hedges roll over into the much more constructive strip that we see today versus 6 months ago or a year ago, I think that's going to free up more cash flow. I think it's going to allow additional debt repayments, additional investor returns and the room for modest increases in capital spending like we've seen in Canada.

Again, the pivot in Canada isn't a substantial pivot in spending. It's a modest pivot in spending. But when spread among 30, 40, 50 companies, if you have 50 producers in the U.S. to add 1 rig, that's a meaningful step-up in demand for super-spec rigs in the U.S. So I think you'll see a dynamic emerge in the U.S. with modest increases in spending, 1 rig additions here and there, that across the fleet adds up to 50, 60, 75 rigs maybe between now and at the end of the year. And that puts a very strong pull on the super-spec fleet, especially when you bake in kind of regional dislocations, the Permian might have excess super-spec rigs, but most of the basins don't.

Yes, makes sense. Good to hear. And my follow-up maybe for you, Carey. You talked about robust cash flow for the back half of the year. I suspect with the seasonality in Canada and as the U.S. activity continues to trend higher, that working capital likely becomes a drag on cash in the back half of the year. So just wondering if you could kind of button up how we should be thinking about that robust cash flow outlook translating into free cash flow and getting to the midpoint of your debt reduction range would take about $50 million to $60 million of incremental debt pay down? When we think about robust cash flow, should we expect $50 million to $60 million as being kind of the right number to think about for the back half of the year?

Yes, Taylor, I appreciate the question. So we don't typically give guidance for EBITDA for -- we'll give enough information so you can calculate that, but I can walk you through some of the guidance we do provide. So I pointed out we have only $22 million of cash interest in the second half of the year. So that will be helpful to cash flow. We've given our capital guidance where we've got another $30 million or so that we're going to spend on capital expenditures. And those will really be the 2 main draws of cash. The working capital build since we exited Q2 with such a strong activity in Canada, won't be the typical seasonal working capital build that we would see. We think probably it will be $5 million or $10 million of working capital build and likely that's offset somewhat by used asset sales that we typically do in normal course.

Your next question comes from line of Aaron MacNeil with TD Securities.

Dustin, congrats on the new gig. My first question is on the rig move from Colorado to the BC Montney. I assume the customer is paying for the full mode, but wanted to confirm. I'm also wondering if the rig already has the AlphaAutomation technology embedded, and if it will, when the rate kicks off under the contract? And then from a pricing perspective, just based on the -- where you describe current day rate ranges, how should we think about the pricing on this specific contract, given that you entered into a multiyear contract not a short-term contract?

Yes. I'll make a couple of comments. I'm pretty sure the customer will identify himself if he's listening to our call. So I want to be cautious with how much transparency I give out. But the mobe cost is inside the contract, meaning that the customer is paying the cost of the mobe. The rig is equipped with Alpha digital technologies and the customer is quite pleased with the performance of Alpha digital technologies. There will be some recertification costs as we bring the rig back into Canada. We'll spend under $2 million to the recertifications on the rig. I think, I hit all the points. I think -- Aaron, I think I answered all your questions, but if I missed one, let me know.

Just on the -- with the -- I guess, is the pricing materially different, given that it's a multiyear contract versus the rates you described?

I would say that the pricing is structured to give us a return on our investment that we think is well above our cost of capital and in the appropriate long-term range. I mean -- the bottom line is it's not a -- they're not walking a low market price for the long term. It's a price that we're happy with and that we've negotiated carefully with the customer and delivers us a good return.

Yes. And Aaron, I'd also add, we're not executing this move for strategic reasons. It's -- we're getting an appropriate financial return.

Should I interpret the rig move is just a signal that there's extremely limited capacity in this asset class in Canada?

I think so. I think that -- I think the demand could move up further, maybe another 2 to 4 rigs into 2022. And I don't think we'll be successful in all 4 of those or 3 of those or whatever it turns out to be. But we would expect that if we mobilize further rigs, the cost of mobilization is covered by the customer.

And how many 1200s are in the U.S. and idle or otherwise able to move up to Canada?

So I can tell you how many 1200s we have in the U.S. We have, after this one, I think we have about 15 1200s and several of those are working them. I think utilization would be over 50%, but we do have enough idle ones to satisfy the demand that Kevin just outlined.

Got it. And then final question for me, Carey. Can you give us a sense of what your expectations are for the wage subsidy for the balance of the year just because those mixed signals on whether the program is wrapping up or not or...

Yes. Right now, we're saying, for the whole year, and we expect around $25 million. So that would mean in Q3 -- if it wraps up in Q3, that will be $6 million or $7 million. $6 million or $7 million.

Your next question comes from the line of J.B. Lowe from Citi.

Question, I think, Kevin, you were just -- you were mentioning something about potential rig reactivations being in the mid-teens. Can you just clarify what -- which geographies you're talking about?

So actually, J.B., I submit to upper teens, so I'll be clear on that. We see rates moving up, and we see rates moving up for a couple of reasons. Labor is getting tight. And it seems that industry reactivation costs are moving up a little bit. You can hang your hat on the guidance. Carey gave for our activation cost in that $150,000 to...

$200,000.

$200,000 range. But I think industry-wide, there may have been some cannibalization of idle assets, but it seems that industry-wide that activation number seems to be a little bit higher. So that's causing a better pricing discipline among the industry. So we're seeing that price that cold rig activation cost or the price go up a little bit to mid- to upper teens. I think that applies pretty much across any oily basin right now and the gas basins are kind of fully utilized.

Yes. This would be the U.S. market, J.B., if that was -- what you're asking.

Got you. Got you. Okay, cool. My other question was just could you -- I know Ian kind of touched on this with asking about the grades if they include the Alpha suite or not. Could you break out potentially like what were your total Alpha suite revenue was in 2Q or like a percentage of your total revenue or anything like -- anything to give us some guidepost on how much that's really impacting the P&L at this point?

Yes. So far, J.B., we've given guidance on what we're getting per item ordered per service utilized. So it's $1,500 a day for AlphaAutomation, and then we're charging on apps anywhere from a $250 a day, up to $2,000 a day per app. And then we have additional fees for AlphaAnalytics. We have not yet provided any guidance on what the consolidated revenue number is. That's something that we would likely do in the future. But for Q2 and Q3, it's unlikely that we provide that guidance.

Your next question comes from the line of Cole Pereira with Stifel.

So I wanted to start with Carey's comments on U.S. drilling margin. So I just want to be clear. You kind of see margins moving kind of flat to up after Q3. So I would interpret that the additional activations coming on in Q4 and Q1 in the U.S. are offset by higher economies of scale and higher pricing. Did I kind of get that correct?

Yes. You've got that exactly correct. And what we've said there is that we think that margins are bottoming this summer. And that probably means that at some point in July or August, is when we're going to see margins bottom where average margins in Q3 are on par with average margins in Q2.

Okay. Great. That's super helpful. And a lot of concerns about labor tightness kind of around the Canadian oilfield services market. I mean, do you guys worry at all that the labor issues might kind of put a lid on the rig count heading into Q1? Or how do you think about that?

Cole, I think it's going to be a struggle, and there's a number of things driving that right now. The drillers have actually in pretty much every other rebound cycle that's always been quite sharp, the drillers have found a way to restaff rigs, I'm quite comfortable that we will restaff our rigs. I know there's probably a few PD people listening to doing that work right now, and they're working pretty hard to find crews.

But between our brand and our recruiting, our training, I expect we'll be successful. And I don't think it will put a lid on our activity. Obviously, if a customer wants a rig for 1 well for 7 days, we might not do that. But any kind of meaningful program, we -- I think we'll be able to staff up our crews for that. Industry-wide, I think it will vary. Certainly, I can kind of go back to over to 1980s, this one might be one of the tougher environments I've seen for recruiting. Again, fortunately, our brand carries a lot of weight out there.

Okay. Great. That's helpful. And I mean with the additional upgrade CapEx, can you just provide a little color exactly on what that is? And with the increase in -- small increase in maintenance CapEx, fair to assume that's just because of a more robust Canadian outlook?

Yes, I think that's a little bit higher activity expectations in both markets would be the maintenance capital and then the upgrade capital is a combination of additional AlphaAutomation systems and contracted upgrades for customers, things like a third-month pump.

(Operator Instructions)

Your next question comes from the line of Waqar Syed with ATB Markets.

Again, congrats, Dustin on the move. I've enjoyed working with you, and thank you for all your help you provided to me during your stay at -- in IR. Thanks a lot.

Thanks, Waqar.

Carey, just one -- first, a quick modeling question. For the rig that's moving to Canada, the rig mobilization costs. Are you going to take a lump sum kind of cost in Q3? Or is this the cost going to be spread over the term of the contract?

So it -- so the revenue that we're going to be getting for that move to cover that move will be spread over the course of the contract, but I actually don't know right now what -- how we're going to account for the cost. I can get back to you on that.

Okay, sure. Secondly, you have 6 rigs working in the Middle East right now. Kevin, do you expect incremental rigs to generate some revenues this year?

Waqar, it's a little hard to say. Certainly, the tenders are dragging a little longer than we would have thought even just a month or 2 ago. Nothing is changing that. I think I can comment that vaccination rates in Kuwait and Saudi Arabia are extremely high. Fully restaffing offices seems to be on the agenda following the current Eid holiday right now, which just wrapped up. I think there is likelihood we can activate some rigs and quite before the end of the year, but it's -- it might be November, December and then rolling into January.

So is it the COVID issue that's keep preventing them from awarding the contract or is it more the current OPEC plus quota, which has eased now?

Yes. The simple answer might be yes to your question in that. I think it's both. I think it's hard to make a strategic decision the international oil company when you're still operating remotely or partly remotely.

Right.

But I also think that they are -- they understand their production depletion curves quite well. They're shutting in capacities. And drilling activity in both countries is down for oil, and they need the time to restart with when they expect their -- the wells that they've got shut in to come back on again. So it's going to be, I think, a pretty careful model about when to bring those rigs back on.

Now Saudi Aramco has a contract to build 50 additional rigs over the next, I believe, 10 years. Do you think they have need for current idle rigs there or they will continue to just bring in these new builds into the market?

So there are tenders right now that are in the regions, including some in Saudi. Some of those are IPM tenders, some are direct drilling tenders as an active tender in Saudi that we're working on for a while. I think we've got opportunities to activate some of our idle rigs. And that could be in Saudi or it could be in other Arabian Gulf perimeter countries.

Okay. And do you have Alpha suite of services running on any of the international rigs?

No, we don't. And we've been careful to deploy Alpha, where we can well -- support it well. We want to make sure we can go out and have 99.9% uptime. I would say that we'll be ready to start introducing Alpha internationally in 2022.

Your next question comes from the line of Sean Mitchell with Daniel Energy Partners.

I'm going to hit the hot topic here again, labor just one more time. I want to understand, as we move into the back half of '21, and it sounds like at least according to your work and some of the work we've done, we agree with you that the rig count will continue to rise. How do you think about labor today if you had to crew 1 rig or 2 rigs versus having to crew 5 or 10, what's the lead time for crew and a rig today versus 1 rig versus 5 rigs, for example?

Yes, Sean. So typically, when we started working with our customers, we'll have anywhere from 2 weeks to a month or in the -- I mentioned we have 3 contracts we signed in the U.S. on those 3 rigs. I think, 1 rig activates in either in late July, early August, and then the next 2 activate a month or 2 behind that. So we'll have plenty of time to build those crews out. The rig managers and drillers already worked for Precision. So the leadership teams are on staff right now, working on a rig somewhere else.

So we'll pull those guys to the rigs that are being reactivated and then we'll backfill the positions they leave opened and we'll recruit for the positions we need to fill. We've got a very sophisticated staffing model and a really sophisticated recruiting model. We typically keep anywhere from 500 to 1,000 people on kind of a callback list. I'd admit we've worked our way down that callback list a long ways. And now we're out recruiting kind of beyond that list. I can tell you that in both U.S. and Canada, the next 5 rigs that we need to activate and we have crews identified for. Beyond that, we need to continue building crews up.

So for each market, 5 rigs for Canada, 5 for the U.S. Identified crews, identified leadership and be able to execute. Beyond that, we'll rely on our recruiting training methods. I don't want to underplay how much work it is. We have a really dedicated team in Houston, a very strong team in Nisku that do the recruiting and do the training, and they work really hard to do this, but the results are excellent. They deliver great results for us.

(Operator Instructions)

And Mr. Honing, we have no more questions at this time.

Great. Well, thank you all for joining today's call. We look forward to speaking with you when we report third quarter results in October. Operator, you may disconnect.

This concludes today's conference call. Thank you for participating. You may now disconnect.