Thank you and welcome to Precision’s second quarter earnings conference call and webcast. Participating on today’s call with me will be Kevin Neveu, our President and CEO; and Carey Ford, our CFO. Earlier – last night, we reported strong second quarter results, which Carey will review with you, followed by an operational update and outlook commentary from Kevin. Once we have finished our prepared comments, we will open the call to questions. Some of our comments today will refer to non-IFRS financial measures and will include forward-looking statements, which are subject to a number of risks and uncertainties. Please see our news release and other regulatory filings for more information on financial measures, forward-looking statements and risk factors. As a reminder, we express our financial results in Canadian dollars unless otherwise indicated. With that, I’ll pass it over to Carey.

Thank you, Lavonne. Precision’s Q2 financial results exceeded our expectations for revenue, adjusted EBITDA, earnings, and cash flow. The resiliency of our high-performance, high-value business model, geographic diversification, and organizational focus on cash flow and return on capital drove our financial results. Precision’s demonstrated commitment to strengthen our balance sheet continues with year-to-date debt reduction and share repurchases of $103 million and approximately $40 million, respectively. For 2024, we expect to reduce debt by $150 million to $200 million and utilize 25% to 35% of free cash flow before debt repayments to repurchase shares. Longer term, we plan to reduce debt by $600 million between 2022 and 2026, with approximately $240 million remaining over the next 2.5 years. We expect to achieve a leverage level below 1x net debt to EBITDA and increase our direct shareholder returns towards 50% over that time period. The progress on these capital allocation targets is clear, and the longer-term trend remains in place as we’ve reduced debt by over $1.3 billion since the beginning of 2016. Moving on to Q2 performance. The U.S. drilling rig count has declined 15% over the past year, and while this data point is typically used as a proxy for broader oilfield service activity and financial performance, this is not the case for Precision as we have achieved year-over-year growth in consolidated Q2 revenue, driven by substantial growth in international drilling, Canada drilling, and completion and production services. Q2 EBITDA of $115 million included a share-based compensation charge of $10 million. Without this charge, adjusted EBITDA would have been $125 million. Net earnings were $21 million or $1.44 per share, representing the eighth consecutive quarter of positive earnings for Precision. Funds provided by operations and cash provided by operations were $112 million and $174 million, respectively. Margins in both Canada and the U.S. were higher than guidance, resulting from stronger-than-expected pricing and cost recoveries, higher ancillary revenues, and improved cost performance. In the U.S., drilling activity for Precision averaged 36 rigs in Q2, a decrease of two rigs from the previous quarter. Daily operating margins in Q2, excluding the impacts of turnkey and IBC, were U.S. $10,838, a decrease of U.S. $219 for Q1. For Q3, we expect margins to be stable and above U.S. $10,000 per day. In Canada, drilling activity for Precision averaged 49 rigs, an increase of seven rigs or 18% from Q2 2023. Daily operating margins for the quarter were $14,423, an increase of $2,220 from Q2 2023. For Q3, our daily operating margins are expected to be between $13,500 and $14,000 per day, with higher fixed cost absorption and improved pricing largely offsetting the impact of rig mix. Internationally, drilling activity for Precision in Q2 averaged eight rigs, a 61% increase over Q2 2023. International average day rates were U.S. $55,301, an increase of 9% from the prior year due to rig mix. In our C&P segment, adjusted EBITDA this quarter was $12.4 million, up 66% compared to the prior year quarter. Adjusted EBITDA was positively impacted by a 44% increase in well service hours, the integration of the CWC acquisition, and improved pricing. C&P results were further supported by Precision’s rental business, which has realized an increased demand and utilization for centrifuge equipment on Super Triple rigs for customers in the Montney. Our contracted rig fleet continues to support our outlook with average annual rigs under contract for 2024 of 17 in the U.S., 23 in Canada, and eight internationally. Moving on to balance sheet. As of June 30, our long-term debt position net of cash was approximately $800 million and our total liquidity position was over $540 million, excluding letters of credit. Our net debt to trailing 12-month adjusted EBITDA ratio is approximately 1.5x and our average cost of debt is approximately 7%. We expect our net debt to adjusted EBITDA ratio to be approximately 1.25x by year-end when we expect net debt to be between $700 million and $750 million and our run rate interest expense at that time will be approximately $50 million. Moving on to guidance for 2024. Depreciation is expected to be approximately $290 million, cash interest approximately $75 million. Cash taxes are expected to remain low and our effective tax rate is expected to be approximately 25%. SG&A is expected to be approximately $100 million before share-based compensation expense and we expect share-based compensation charges for the year to range between $40 million and $60 million at a share price range of between $80 and $120 per share, and the charge may increase or decrease by up to $20 million based on the share price performance relative to Precision’s peer group. Given Precision’s share price performance year-to-date, we have increased the upper end of our guidance from $100 to $120 per share to provide increased visibility for our investors. With that, I will now turn the call over to Kevin.

Thank you, Carey, and good morning. As Carey mentioned, we are very pleased with the strong cash flow our business is generating and we’re thrilled with the progress we made with our international and Canadian units, while our U.S. segment is stable, activity is a little slower than we would like. In the Lower 48, customer demand appears to have troughed. The combined drag effects of capital discipline, low natural gas prices, operator consolidation, and delayed drilling plans seems to have bottomed out. And we’re noting an increase in customer conversations regarding drilling programs and plans or considerations to pick up rigs and modestly increase activity later this year and into 2025. As the E&P consolidation transactions draw to a close and those operators commence the integration of the drilling teams, we expect the drilling contractor mix to shrink to fewer and larger, more capable drillers rather than the fractured vendor base used by many of those acquisition targets. Some of this contractor rationalization is already underway, and we are encouraged by the sophisticated customer interest in our Alpha Automation, safety performance, and overall rig performance. We believe Precision is very well positioned to grow market share over the next several quarters. We also see some of these acquired drilling teams falling out of the transactions, reforming with private equity and looking to utilize the most technologically advanced drilling rigs they can find. One of the rigs we added this month was contracted to one of these new private equity startups, and the drilling team is well familiar with Precision's capabilities. Encouragingly, we are also in discussions with several of our Haynesville customers who are in the early stages of planning and anticipating increasing LNG export demand. The Haynesville is a region that has traditionally been a stronghold for Precision’s Super Triple rigs. We currently have six available rigs in the region and it seems plausible we will have some additional reactivations before year-end. Currently, in the U.S. we have 38 rigs operating and expect to hold in the upper-30s through the third quarter with a modest increase, perhaps to the low-40s in the late fall. Super Triple leading edge rates have remained stable in the low-30s per day. However, we did activate a couple of legacy CWC rigs in Wyoming and while these are AC rigs, they are not super spec and as a result, the day rates are a little bit lower. Turning to our International segment, Precision's activity revenue EBITDA will increase approximately 50% as compared to last year. While we have no new contracts to report, we remain very active bidding our idle rigs. I will remind listeners that we have three active rigs in Saudi Arabia. These are deep high-capacity drilling rigs operating in the strategic Manefa oil field for Aramco. The rigs have been on long-term contracts since 2010 and are currently contracted up for several more years. In Kuwait, we have five Super Triple 3,000 horsepower ultra-large drilling rigs all operating on long-term contracts. We renewed most of the rigs last year, including spending the maintenance capital last year to recertify those rigs. We expect a long runway of strong and sustained free cash flow from international rigs and will continue to bid our idle rigs, including potential redeployed U.S. rigs, but only at rates that meet our return expectations and deliver free cash flow over the full contract duration. Our Canadian businesses both drilling and well servicing are performing at the highest levels in over a decade. Starting with our Canadian Drilling Group to update you, we have activated three more rigs today, raising our active rig count to 77 from the 74 mentioned in our press release last night. Customer demand has been substantially stronger than we anticipated earlier this year, and we have been more than pleasantly surprised by the acceleration in heavy oil drilling across the full spectrum of Clearwater, Manville, conventional heavy oil, and SAGD. The Precision Super Single rig is a clear market leader with 26 different heavy oil customers using our rigs. Our Canadian Super Single rig fleet includes 48 rigs with 43 running and a third of those are pad equipped, significantly increasing the value for our customers and for Precision. Now, as a refresher for the listeners, the Precision Super Single rig was specifically designed for shallow to medium depth, high efficiency, slant, and horizontal drilling and has its origins in the early 1990s. Between 2010 and 2016, we built out and upgraded our current fleet of 48 fully standardized Super Single rigs. All Precision's Super Singles are manufactured or upgraded in our in-house manufacturing facilities in Calgary and Nisku. Our comprehensive vertical integration on the Super Single underpins the low operating cost we maintain. This high-efficiency design is based on a mechanical drive system with hydraulic controls that enables precise horizontal drilling control and extremely precise wellbore placement. These rigs also incorporate fully mechanized drilling and pipe handling operations. Super Singles are safe, efficient, and highly reliable, with the lowest operating costs of any rigs in our fleet. These rigs can be moved well to well in under one hour and pad to pad in just a few hours, requiring as few as 21 truckloads, almost ten fewer than similarly rated Tele-Doubles. The rigs can be easily upgraded to increase drilling torque, increase hydraulic capacity, or add pad walking systems for significantly less capital than any competitive rig. This combination of versatility, precision drilling capabilities, safety, and efficiency has made our Super Single rig the market leader in all complex, shallow-to-medium depth drilling applications from Manitoba to Northeastern British Columbia. While we do not break down our revenue and margins by rig type, I'm confident to quote base margins in the range of $7,000 to $14,000 per day, with the upper end of the range typical for pad equipped Super Singles. This overlaps with our triple margins, which start in the $12,000 range and move up from there. During the second quarter, Precision's Evergreen team introduced two new evergreen products which improve fuel efficiency, reduce emissions, and improve the safety and versatility of our Super Single rigs. We began rolling these products out to the field and have equipped nine rigs with our hydrogen injection combustion catalyst system, which offers our customers fuel savings and emissions reductions in the 6% to 8% range. Further, Precision's high mass lighting system has also been adapted to our Super Single rigs, and we've deployed four of these to the field. We expect both of these evergreen systems to roll out across the full Super Single fleet over the next 12 months, adding over $500 per day of additional incremental margin. Leveraging this across our Super Single fleet results in a $6 million to $7 million annualized incremental margin run rate. Now, turning to our Super Triples and the Montney gas condensate play in Canada, our current fleet of 30 rigs is virtually fully committed, with just a few windows available in activity this quarter, which we expect to fill with short-term customer programs. Rates remain strong in the low- to mid-30s for the base rig, with Alpha Automation in evergreen and other extras pushing those rates in the mid- to upper-30s. I mentioned earlier that we've been somewhat surprised by surging customer demand in heavy oil following the TMX opening. It seems we may experience a similar Montney surge once LNG Canada is fully commissioned and shipping LNG at capacity this time next year; it's conceivable that the market may be several rigs short. Recent customer contracting activity and particularly the contract duration customers are seeking seem to support the notion of a prospective rig shortage. And as I've mentioned in the past, we have idle fully winterized Super Triple rigs in a DJ basin and will consider redeploying some of those rigs to Canada if the contracted rates are in the upper-30s and the customers pay the full mobilization cost. We expect to have better visibility on this opportunity later this year and into 2025. As I mentioned earlier, we have 77 active rigs today and expect to be in the range of 75 to 80 through August and could see our rig activity trend further upwards in September and through the fall as our customers prepare for what looks like a very busy 2025. In our Canadian well servicing operations, we see much of the same customer demand and fundamentals. Additionally, government-mandated well abandonment activity is a 22% and growing wedge in that business. We have fully integrated the CWC fleet into Precision, and the results are clear in our average rates, our margins, and our total activity. Now well servicing activity can be heavily influenced by weather, namely rain and by forest fires. Through the second quarter now into July, on any given day, we may have had anywhere from five to 20 rigs delayed or postponed due to those issues. Typically, if these deferrals are material, it will push demand later into the fall when drier and lower fire conditions normally persist. Today we're operating 71 service rigs and expect to be in the range of 70 to 85 rigs for the balance of the third quarter, and expect the higher end of that range may trend closer to 95 in the fourth quarter. So, to wrap up, we have many Precision employees who listen in on this earnings call, and we encourage our staff to do so. I want to thank all the Precision people who once again delivered a strong quarter of safety performance for their intense focus on operational efficiency and their outstanding efforts on cost control. Great work to the PD team, and thank you all. I'll now turn the call back to the operator for questions.

Thank you, ladies and gentlemen. Our first question comes from Kurt Hallead with Benchmark. Your line is open.

Hey, good morning, everybody.

Good morning, Kurt.

Good morning, Kurt.

Good afternoon if you're in Houston. So, Kevin, things really playing out, as you mentioned, better than expected in Canada despite obviously some dynamics at play with wildfires. So, I don't know, can you just give us an update on what you think kind of triggered this acceleration, if you will, in overall customer activity? And then I know you referenced some additional things that are coming up for 2025, but is the customer base at this juncture as concerned about a shortage of rigs as you seem to be?

I'll start with kind of why I think we're a little surprised by the activity, and I think what we underestimated. First of all, the math for our customers works out quite well right now. They're realizing somewhere between $77 and $80 a barrel U.S. minus the Canadian discount, which has shrunk with the opening of Trans Mountain expansion. So they're realizing somewhere typically around $65 U.S. for oil. When you convert that to Canadian dollars, it's between $90 and $100, depending on the range. So it's the highest realized returns they made on oil in a long time. But I think what this really means now is that they've got certainty of export capacity, and there's no uncertainty they're not relying on train cars to move oil out. They've got a pipeline flowing, and they can move the oil. So I think besides having a firm and better price than they've ever realized in the past, they also have certainty of export capacity. So I think when you reduce the risk and the uncertainty and increase the price, it unlocked more drilling demand than we expected. So that's been clearly our experience in the oil side and my comments on LNG Canada opening up. So there's an awful lot of drilling that's gone on over the past three years in the Montney. Most of its been funded by the condensate that's produced by those wells. And that condensate gets sold into, actually the heavy oil market to help ship heavy oil down the pipeline. So condensate has driven the economics. The gas has actually kind of oversupplied the system, but they built up an inventory of gas supply now for the opening of LNG Canada. No question about that. But we're sensing that once that plant gets running and sustained operations, they'll need to continue drilling and probably increase drilling. So that's why we're sensing that there's probably going to be a further step up in rig demand once that plant's running, which would be about mid-next year when it's at full capacity. When we combine that with the behavior of our customers around trying to contract rigs, lock them in, maybe windowing right now, but getting the rigs going again on January 1st, it really seems like there's behavior pushing towards increased activity in 2025.

Okay, that's great color. Now maybe a follow-up to that would be. I think in the past calls and discussions, you've mentioned the prospect for some of these rigs that are going to be filling that LNG export capacity to be booked on some sort of long-term contract dynamic. I think you referenced there might be kind of a limit to how many of those rigs might ultimately be on long-term contract. Could you just give us an update on your thoughts with that?

Yes, Kurt, that contracting strategy has got two parts. It's got our willingness to contract rigs and the customer's desire to take contracts. I'd say that the Canadian industry has been really cautious over the past decade. They've been through a lot with commodity prices and pipeline constraints, and they're finally getting a bit of room to run right now. But as a result, Canadian customers have been reluctant to sign too many long-term contracts because of the long-term uncertainty that they faced in the past ten years. Well, that is changing now. We see certainly for development drilling, the Montney more and more of a trend for long-term contracts. So they're more willing to sign the contracts they might have been a few years ago. And we want to remain and keep some of the fleet with optionality for increased rates. So we're not anxious to tie up the entire fleet with long-term contracts. But a blend of half the rigs contracted, half the rigs exposed, maybe a little more contracted, is kind of how we look at things.

That's great color. Thank you.

Great. Thanks, Kurt.

Thank you, Kurt.

Our next question comes from Luke Lemoine with Piper Sandler. Your line is open.

Yes. Good morning.

Good morning, Luke.

Kevin, last call you talked about in U.S. land the visibility and timing of the rebound just being a little bit unclear. And then you just talked about activity troughing now. So your views changed a little bit. It sounded like the customer conversations around rig adds were basically due to new capital formation along with Haynesville as next year. And I guess, first, anything to point out there, any other factors? And then second, you talked about your rig count in the U.S. maybe increasing from the high-30s to low-40s from 3Q to 4Q. Do you think that's representative of the overall super spec rig count, or maybe specific to Precision?

Luke, I think for us a couple of rigs moves us from 38 to 40. So it's not a big market indicator. So I think keep that in mind. Even if we had three rigs without 41, so that doesn't really mean the whole industry is changing. I do think between now and the end of the year, it's likely that the larger drillers, and I think we're in that bucket, gain rigs, and some of the smaller drillers may lose rigs as some of these consolidation transactions complete and they rationalize their fleets. So I think you could see any one of the larger drillers pick up a few rigs and two, three, four rigs, not 50 rigs, be clear on that. Just through the kind of conclusion of these consolidation transactions. If you layer in for us, one or two rigs in the Haynesville, which isn't a big move, now you're at 42, 43 rigs. So the path to get 43 isn't that complicated. But I don't see the market moving and adding 50 or 60 rigs between now and the end of the year. So I don't think that three or four rigs for precision means 10% of the market.

Okay. And then, Carey, in the press release, you talked about looking for opportunities to lower costs. Could you maybe elaborate on that, especially on the U.S. drilling side and maybe what that can mean?

Yes, I'll hit that from a couple different points. So we've talked a bit in the past about weighing a bit more fixed costs in our U.S. business than we have in the past. Just, we're operating six different operating regions and running 38 rigs. So we've got fixed costs to spread over a few days. So that's been a little bit of a headwind of margins. On the items we can control, we've really had a focus on repair and maintenance expense and working with our vendor list and optimizing centralized purchasing and optimizing third-party labor on a rig. We're looking at all avenues to address reducing costs on our rigs, and we saw some of that performance really start to show up in the second quarter, and we expect to maintain that performance throughout the year.

Okay, great. I'll turn it back.

Great. Thanks, Luke.

Our next question comes from Aaron MacNeil with TD Cowen. And your line is open.

Hi, everyone. Thanks for taking my questions. Carey, we've had two quarters now where margins have come in generally better than the guide. And I guess the question is, is your Q3 margin guide similarly sort of conservative in your view?

I think what we want to do is provide some guidance for the market that is realistic that we can meet and hopefully exceed. I think on the Canadian market, we have a dynamic that we haven't really had in the past several years where we're getting, as Kevin mentioned, a lot more Super Single work and some Tele-Double work. And so when you get that rig mix blend into the fleet average, the pricing is a little bit lower, margins are a little bit lower, so it's a little bit less predictable. We think that we can beat the guidance that we provided, but want to err a little bit on the conservative side just because of that new dynamic. And then in the U.S. same thing, I think that if a rig count remains flat or decreases a bit, we're wearing a bit more fixed cost per rig. And if it increases on kind of Kevin's potential, getting to the low-40s, I think we're wearing a little bit less fixed cost. So the margin should be a little bit better. So I think, in short, there are some moving parts. So we want to make sure that we're providing realistic margin guidance for the market.

Makes total sense. And I think this one might be for you as well. But excuse the napkin math here, but at least on my estimates, you're sort of on pace to hit the lower end of the 25% to 35% share buyback target. I mean, is that sort of. Maybe you can't guide to this if it's consistent with your view, but like, is that sort of the intention, or do you think we'll maybe see you ramp up the share buyback pace in the second half of the year?

Yes. So we are intentionally not prescriptive on how we're going to, what side of the range we're going to be on for the share buybacks. I think it depends on how much cash the business generates and also where the shares are trading in the market. In my comments, I mentioned that we've bought back about $40 million worth of shares year-to-date. That includes some shares that we bought back in the month of July. And if you kind of double that and look at the midpoint of our debt reduction range, I think we'd actually be at the high end of the 25% to 35% range. So I think we’re definitely going to be within that range and where we are within that range will depend on both the cash flow and then where the shares trade between now and the end of the year.

Makes sense. I’ll turn it back. Thanks, guys.

Okay, thanks.

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

Thank you for taking my questions. Kevin, you’ve seen a number of M&A transactions in the market with your peers. Some have decided to expand their pressure pumps and become more kind of providing full services in the U.S. Others have increased exposure to the Middle East; little bit acquisitions have happened as well. How do you see Precision kind of evolving over the next, like, three to five years? Do you remain focused on what you do now? Or do you think that five years from now Precision could be offering more businesses?

Waqar, that’s a great question. In fact, something we talk about with our Board pretty much every Board meeting and especially during our strategy sessions. So it is nice to have options kind of going forward. We’ve been so focused on debt reduction for the past decade that has been kind of our top priority and be really clear with our annual priorities. But we did do a couple of tuck-in acquisitions that worked out quite well. We did the High Arctic deal two years ago and then CWC last year; those worked out well. So I think that as we go forward, we’ll keep our eyes open. We’ll be opportunistic. If we can transact and do another tuck-in type, another or more tuck-in style acquisitions that supplement our current businesses, I think we’d be anxious to do that. A couple of comments. We have no strategic objectives right now around acquisitions. We don’t need to make a big bet internationally. We don’t need to go buy a block of business in any geography in North America; we have those blocks. We’re not looking to grow well servicing in the U.S. We’re looking to grow well servicing in Canada to grow drilling in the U.S. So I think we’d stick with our knitting right now, which is drilling and well servicing in Canada, drilling in the U.S. And if we can find good tuck-in opportunities that we can do at least neutral on leverage or de-levering and accretive, we’d be thrilled to do it.

Makes sense. And then, Carey, you mentioned as a goal being below 1x net debt-to-EBITDA ratio and then maybe expanding cash return to shareholders to about 50% of free cash flow. In your view, from a timing perspective, when do you think you’re going to get there? And then that 50% return of cash to free cash flow to shareholders, what would it look like? Would this still be buybacks or a combination of buybacks and dividends? Or how do you intend to proceed there?

Well, first of all, I think we’re kind of taking one thing at a time. So we’ve got our guidance for this year, and then our guidance through 2026. So we definitely are going to be looking to increase that allocation of our free cash flow directly to shareholders. This year, it’s going to be share buybacks. We’ll look at all options in the coming years as we get closer to that leverage level, but nothing to report on today. I think in terms of timing on when we can get to below 1x, I think it’s a lot sooner than we thought. I mentioned in my comments that by the end of the year, we expect to be kind of around 1.25x. And assuming we can continue the strong cash flow performance and EBITDA generation in 2025 that we’ve produced so far this year, we should be below 1x at some point next year.

Sounds good. Well, thank you very much, and congrats on a great quarter.

Thanks, Waqar.

Thank you.

Our next question comes from Jamie Kubik with CIBC. Your line is open.

Yes. Good morning, guys. Thanks for taking my question here. I just have a question on the Canadian market here a bit. Kevin and Carey, you do reference LNG directed drilling remaining very active in Canada. But the AECO and Station 2 gas markets on a forward basis are expected to be very weak for the next several months in Canada. Respecting the Precision’s rig count is north of 70%, can you talk a bit more on the dynamic in the Canadian market here? And if operators have been discussing potentially deferring drilling activity given the pricing outlook is so weak, can you just expand a little bit around that market, if you could?

Yes, I can. I don’t want to speak to specific customer comments because they’ll know who they are, and they’ll know what they said. So we hear a lot, no question about that. I think our rig count today has actually run rig higher than a year ago, drilling in the Montney. I think it is. I also know that we’ve got a couple of operators that are slowing down drilling programs this year but are asking us to have that rig for them for January 1. So I think you’re getting to the point now where there’s enough gas to meet the demand when they start operating. But I think as I plan for kind of full-scale run operations next year, they probably need those rigs back. So I did mention that we’ve got a few windows of rig availability right now in Q3. We expect to fill this up with other customers. And I’d also comment that I don’t think we’re drilling a single dry gas well. I think all of these wells produce condensate that still drives the economics of the well.

Okay, that’s good. That’s all for me. Thank you.

Thank you.

Our next question comes from John Gibson with BMO Capital Markets. Your line is open.

Morning all. Maybe touching on your international rigs and just sort of presence obviously going to be up 50% year-over-year, which is outstanding. Can you provide details on the daily margins on those rigs and maybe some further details on potential rig activations that you referenced in the press release. Have they moved closer or further from prior quarters?

Yes. So – hey John, I think on the international margin, we don’t disclose the margins just because we have two customers in the international market. So we’d like to keep that confidential. But I would say that they are a little bit better than mid-cycle margins what we would experience in North America. And when you think about kind of the dynamics, we’re getting five-year contracts on those rigs. And so, the payback period and the IRR on the rigs is going to be just a little bit lower than what we would require in North America because there’s more certainty and a longer-term horizon.

And last one, just on any update on the potential reactivations of the outstanding rigs in your international regions?

Yes, John, no, we have no news right now, nothing to report other than we were unsuccessful on a tender in Saudi Arabia. The rates were well below the levels we never upgrade we can deploy too, but we understand some people making strategic decisions. It’s just – that’s their call. I do think that we have opportunities that we’ll continue pursuing in Kuwait, in Saudi Arabia, and in the region right now. And I think we’ll be successful, I think, but I don’t see anything happening likely during the third quarter, maybe during the fourth quarter.

Okay. Great. Last one for me. Sorry if I missed this. Could you touch on day rates and margins on the Super Single class of rigs in Canada? I mean, it looks like you gained some market share here. I’m just wondering what drove this and if you’ve been able to push pricing higher on this cost of rigs?

Yes. I’m not sure we’ve actually gained any market share because our market – it’s really hard to tell exactly, but our market share is still seem to be in the same range. And we’re mainly competing with rigs that probably aren’t quite as efficient. So we can get a little higher day rate. I gave guidance on the margins in the range of $7,000 to $14,000 a day. You can assume that the pad rigs are going to be the top half of that range and the non-pad rigs will be the bottom half of the range. I suggested that a third of the rigs are pad-style rigs. The upgrade cost to convert a rig to pad style is quite low compared to the triples. And I expect we’ll have several more of those Super Singles that are non-pad converted pad rigs probably in the second half of this year.

Okay, great. Awesome quarter. I’ll turn it back. Thanks.

Great. Thanks a lot, John.

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

Hey, guys. Thanks for having me on. Just one question. One of the frequent complaints I get from private well service guys in the U.S. is the cost of insurance and the ability to get it. I’m just curious if that same dynamic is at play in Canada? And is that going to create some opportunities for more tuck-ins?

John, that’s a really tricky question. I just came back from our insurance renewals in the spring; we go to London, we do a comprehensive insurance renewal with our insuring group. I would tell you that I think that larger service companies will scale right now have very good access to insurance, but the rates have gone up. I would say that smaller and the smaller you get access to insurance gets trickier and more expensive. The insurance industry is dealing with a lot of their investors and they’re being pushed not to ensure this industry. We see that. We sat with several insurers who used to cover Precision who won’t cover oil and gas again. So the market size is decreasing. And those that are in the space want to focus on the lower risk larger, more capable companies. So I think that’s a real risk for a small company. I would tell you that I think any large service provider that’s kind of multi-basin 10s or 100s of assets will have access to insurance, and it may be tougher for smaller companies.

Okay. Is it your sense that the customers are being smart and auditing this?

For every contract we have, we have to have proof of insurance. We typically go through that liability assessment with our clients.

Fair enough. That’s all I got. Thanks, guys.

Great. Thanks, John.

And I’m not showing any further questions at this time. I’d like to turn the call back over to Lavonne for any closing remarks.

On behalf of the Precision team, I would like to thank everyone for joining in on our call today and wish you a great day. Thank you.

Ladies and gentlemen, this does conclude today’s presentation. You may now disconnect and have a wonderful day.