Precision Drilling Corporation

Good day and thank you for standing by. Welcome to the Precision Drilling Corporation 2021 Second Quarter Results Conference Call and Webcast. At this time, all participants are in a listen-only mode. After the speaker's presentation, there will be a question and answer session. Thank you, Maddie, 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 your 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 wealth service division. As you all know, Dustin has managed PD's investor relations efforts very well over the past two and a half 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 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 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 investing. During the quarter, we received $9 million of Q's assistance payments. As a reminder, the Q's program supports employment in Canada, and Precision has utilized this program to preserve jobs within our organization. The Q's 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 $6,752, a decrease of $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 227 U.S. dollars lower than Q1. During the quarter, we activated six rigs, and the reactivation expense remained in the $150,000 to $200,000 range for 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 Q's impact, margins would have been $5,247 or $1,378 higher than Q2 last year. For Q3, we expect margins absent of Q's and one-time 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 margins of Q3 2020 absent queues and one-time recoveries were $6,270. Internationally, drilling activity for precision in the quarter averaged six rigs, and international average day rates were $54,269 U.S. dollars 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, CUSE 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 infrastructure and $22 million for upgrade and expansion. which relates to anticipated investments supporting alpha technologies and contracted customer upgrades. As of July 22nd, 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 $400 million U.S. offering of senior notes due in 2029 with a coupon of 6.78%. and an extension of a 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 30th, 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 5.8 times 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 two times. 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 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. 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 in 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 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 and a half has been extremely challenging for industry, and especially the people who work here at Precision. The pandemic health challenges, the lockdowns, the industry layoffs, and 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 two months, we have fully restaffed our corporate offices in Houston and Calgary, and I thank our people for the excellent work they've performed in their roles remotely over the past year, and I appreciate the challenges they continue to face every day. We are in the beginning stages of what's emerging as a strong industry recovery, and we rely on a hardworking and loyal precision team to execute our business, support our customers, and help drive the results our investors and stakeholders expect. While Terry fully covered off our recent debt financing activities, I'll just add that I am 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 two times EBITDA will create substantial value for our investors. It should be clearly 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 reinvestment for the foreseeable future. So turning to our regional markets, I believe that rebounding customer demand we see in Canada in the Canadian segment has broad 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-serviced business, second quarter activity was over seven times 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 two-thirds of the demand we see comes from publicly listed producers. This group 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 producers' scale and efficiency. And now with the improving commodity fundamentals, with firm ACO guests, 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 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 the public producer's 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 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 a customer to a long-term contract which includes the cost to mobilize a Precision Super Triple rig from Colorado to northeastern B.C., further strengthening our market position in the Montigny Plain. I think we'll have additional opportunities for ST-1200 rig redeployments to Canada as our customers look to 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 seemingly discourage workers from re-entering 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 great 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 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 was 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 work overspending 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 are all driving demand. Labor constraints are hitting this industry segment hard, primarily due to the call out and thus 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-serviced sales team is charged with marching our 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 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 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. 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 crewed up rig or acquire someone else's running and crewed 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 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. Now 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 alpha automation are becoming well understood and accepted by all customers, and we are seeing wide-scale customer adoption. Our alpha automation days were up 30% sequentially despite the reduced seasonal activity in Canada. And now with 16 commercial alpha apps, we saw alpha app revenue almost double in the second quarter versus the first quarter. Alpha analytics is also gaining strong customer acceptance, with sequential utilization also stepping up over 70%. Notably, during the second quarter, we contracted three 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 alpha automation, alpha apps, and alpha analytics product suite. We view this as a technology-driven market share gain. Clearly, digital enablement is a theme we're hearing from virtually every customer today. and there's no question that our Alpha Technology Suite delivers strong digital value and our Alucard 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 that the Precision E-Team, a cross-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 zero 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 the international business segment, as Carey mentioned, activity was stable during the second quarter, with three rigs operating in Kuwait and three rigs operating in the Kingdom of Saudi Arabia. We are expecting upcoming tenders for our three 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 to $5 million per rig which we 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 was linked to the timing of the relaxing of the oil export limits. As always, the National Oil Company tender process tends to be lengthy, but results in similarly lengthy contract terms, something we ultimately desire. With the improving outlook across all of our business segments, I return to the people in 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 now turn the call back to the operator for questions.

As a reminder, to ask a question, you will need to press star 1 on your telephone. To withdraw your question, press the pound key. Please stand by while we compile the Q&A roster. And your first question comes from the line of Ian McPherson from Piper Sandler.

Thanks. Good afternoon, Kevin and Carey. Congratulations on the debt refi. That's a great coup for us. for you all financially and operationally. So good to see that. I was intrigued, 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. It was a base day rate for the base super triple rig, excluding technology add-ons.

Okay. Okay. Yeah, 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? Yeah. Would you lean further out in time to hazard where pricing is going in both markets by the end of the year? 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, you know, the... In Canada, for example, the Montigny play and 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 does create a better pricing environment for our services. but probably a more appropriate pricing environment than 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 two combinations are driving the near-term pricing, but we do expect to see very rational behavior over the long term, 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.

That's great. Thanks, Kevin. I'll pass it over. Thank you.

Your next question comes from Taylor Zucker with Tudor Pickering and Holt.

Hey, thanks, guys. My first question, Kevin, you talked about the Canada market backdrop has clearly improved, and you talked about and how 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 number one answer I'm going to focus on is that the investor desire for returns in 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 six 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. and one rig, that's a meaningful step up in demand for super-spec rigs in the U.S. So I think you'll see Thank you very much.

You talked about robust cash flow for the back half of the year. I suspect with the seasonality in Canada and as 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 that would take about $50 to $60 million of incremental cash that pay down. When we think about robust cash flow, should we expect 50 to 60 million as being kind of the right number to think about for the back half of the year?

Yeah, Taylor, I appreciate the question. So we don't typically give guidance for EBITDA. 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'll 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 two main draws of cash. The working capital build since we exited Q2 with such strong activity in Canada won't be the typical seasonal working capital build that we would see. We think probably it'll be $5 or $10 million of working capital build and likely that's offset somewhat by used asset sales that we typically do in normal course. Got it. That's it for me. Thanks for the answers.

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

Hey, guys. Thanks for taking my questions, and Dustin, congrats on the new gig. My first question is on the rig move from Colorado to the BC Motley. I assume the customer is paying for the full mode but wanted to confirm. I'm also wondering if the rig already has the Alpha Automation Technology Embedded, and if it will, when the rate kicks off under the contract. And then from a pricing perspective, just based on where you described current day rate ranges, how should we think about the pricing on this specific contract, given that you entered into a multi-year contract, not a short-term contract?

Yeah, 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 MOB cost is inside the contract, meaning that the customer is paying the cost of the MOB. 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, and we'll spend... under $2 million to do the recertifications on the rig. I think I answered all your questions, but if I missed one, let me know.

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

I would say that the pricing is structured to give us a return on investment that we think is – Well above our cost of capital and in the appropriate long-term range. Sure. The bottom line is it's not a, you know, they're not walking in 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.

Yeah, and Aaron, I'll add, we're not executing this move for strategic reasons. We're getting an appropriate financial return.

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

I think so. I think that demand could move up further, maybe another two or four rigs into 2022. And I don't think we'll be successful in all four of those or three of those or whatever it turns out to be. But we would expect that if we mobilize further rigs, that 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. I mean, the 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 there's mixed signals on whether the program's wrapping up or not?

Yes, right now we're saying for the whole year we expect around $25 million. So that would mean in Q3, if it wraps up in Q3, that'll be $6 or $7 million. Yeah, $6 or $7 million. Understood. That's all for me. I'll turn it over. Thanks.

Thanks, Kevin.

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

Hey, guys. How you doing?

Good, J.B. How are you? I'm pretty good. The question, I think, Kevin, you were mentioning something about potential rig reactivations being in the mid-teams. Can you just clarify which geographies you're talking about?

So, actually, GBS admits upper teens. 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 costs in the $150,000 to $200,000 range. But I think industry-wide, there may have been some cannibalization of vital assets, but it seems that... industry-wide, that activation number seems to be a little bit higher. So that's causing a better pricing display among the industry. So we're seeing that price, that cold rig activation cost price go up a little bit to mid-to-upper change. I think that applies pretty much across any oily basin right now, and the gas basins are kind of fully utilized.

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

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

Yeah, so far, JB, we've given guidance on what we're getting per item ordered or per service utilized. So it's $1,500 a day for alpha automation, and then we're charging on apps anywhere from $250 a day up to $2,000 a day per app. And then we have additional fees for alpha analytics. We have not yet provided any guidance on what the consolidated revenue number is. It's something that we'll likely do in the future, but for Q2 and Q3, it's unlikely that we'd provide that guidance. Okay. All right.

Thanks, guys. Thank you.

Your next question comes from a line of Cole Pereira with Stifle.

Hey, afternoon, everyone. I just want to start with Carey's comments on U.S. drilling margins. So I just want to be clear, you kind of see margins moving kind of flat 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 got that exactly correct. And what we 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 to where average margins in Q3 are on par with average margins in Q2.

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

You know, Cole, I think it's going to be a struggle and there's, you know, a number of things driving that right now. The drillers have Thank you for watching. I don't think it'll put a lid on our activity. Obviously, if a customer wants a rig for one well for seven days, we might not do that. But any kind of meaningful program, I think we'll be able to stuff up our crews for that. Industry-wide, I think it'll vary. Certainly, I can kind of go back to the 1980s. This 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. Thanks. And I mean, with the additional upgrade capex, can you just provide a little color exactly on what that is? And with the small increase in maintenance capex, it's fair to assume that's just because of a more robust Canadian outlook?

Yeah, 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 alpha automation systems and contracted upgrades for customers. It seems like a third mud pump.

Gotcha. Okay, perfect. That's all for me. Appreciate the color. Thanks, guys. Thank you, Cole. Thanks, Cole.

As a reminder, to ask a question, you will need to press star 1 on your telephone. The next question comes from mine, Waikar Saeed with ATB Markets.

Thank you very much. And, 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 in IR. Thanks a lot. Thanks, Waikar. Carey, just one first 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 the cost going to be spread over the term of the contract? So the...

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 how we're going to account for the cost. I can get back to you on that.

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

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 two ago. Nothing's 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's likelihood we could activate some rigs in Kuwait 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 preventing them from awarding the contract, or is it more the current OPEC plus quota, which is eased now?

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 in a national oil company when you're still operating remotely or partly remotely. Right. But I also think that they understand their production depletion curves quite well and their shut-in capacities. And drilling activity in both countries is down for oil, and they need to time the restart. with when they expect their 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 would continue to just bring in these new builds into the market?

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

Okay. And do you have an 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.

Okay, great. Thank you very much, Kevin. Appreciate the answers. Thank you, Ricardo.

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

Hi guys, thanks for taking my question.

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 one rig or two rigs versus having to crew five or ten? What's the lead time for crewing a rig today versus one rig versus five rigs, for example?

Yeah, Sean, so typically when we start working with our customers, we'll have... Thank you for joining us. to the grids that are being reactivated, and then we'll backfill the positions they leave open, 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 Fabrics that we need to activate, we have crews identified for. Beyond that, we need to continue building crews up. So for each market, Fabrics for Canada, five for the U.S. Identified crews, identified leadership, and able to execute. Beyond that, we'll rely on our recruiting training methods. Got it. Thank you. I don't want to underplay how much work that is. We have a really dedicated team in Houston, a very strong team in NISCU that do the recruiting, do the training, and they work really hard to do this, but the results are excellent. They deliver great results for us. Thanks. Great. Thank you. Thanks, John.

If you'd like to ask a question, you will need to press star 1. 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.

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