Precision Drilling Corporation (NYSE:PDS) Q2 2025 Earnings Call Transcript

Precision Drilling Corporation (NYSE:PDS) Q2 2025 Earnings Call Transcript July 30, 2025

Operator: Good day, and thank you for standing by. Welcome to the Precision Drilling Corporation 2025 Second Quarter Results Conference Call and Webcast. I would now like to hand the conference over to Lavonne Zdunich, Vice President of Investor Relations. Please go ahead.

Lavonne Zdunich: Thank you, operator. Welcome, everyone, to Precision Drilling’s Second Quarter Conference Call and Webcast. Today, I’m joined by Kevin Neveu, Precision’s President and CEO; and Carey Ford, our CFO. Yesterday, we reported our second quarter results. To begin our call today, Carey will review these results, and then Kevin will provide an operational update and outlook commentary. Once we finished our prepared comments, we will open the call for questions. Please note that some comments today will refer to non-IFRS financial measures and include forward-looking statements, which are subject to a number of risks and uncertainties. For more information on financial measures, forward-looking statements and risk factors, please refer to our news release and other regulatory filings available on SEDAR+ and EDGAR. As a reminder, we express our financial results in Canadian dollars unless otherwise stated. With that, I’ll pass it over to you, Carey.

Carey Thomas Ford: Thank you, Lavonne. Precision’s Q2 financial results exceeded our expectations for adjusted EBITDA, earnings and cash flow. Adjusted EBITDA of $108 million was driven by strong drilling activity in Canada, improved activity in the U.S. and steady cash flow generation from our drilling operations in the Middle East as well as our Completion and Production Services business. Our Q2 adjusted EBITDA included a share-based compensation charge of $4 million and additional revenue of $7 million related to customer- funded upgrade projects in Canada. Without these items, adjusted EBITDA would have been $105 million. Revenue was $407 million, a decrease of 5% from Q2 2024. Net earnings were $16 million or $1.21 per share, representing Precision’s 12th consecutive quarter of positive earnings.

Funds and cash provided by operations were $104 million and $147 million, respectively. In the U.S., Precision’s drilling activity averaged 33 rigs in Q2, an increase of 3 rigs from the previous quarter, with operating days increasing 13%. Daily operating margins in Q2, excluding the impacts of turnkey and IBC, were USD 9,026, an increase of USD 666 from Q1, and well ahead of our guidance of $7,000 to $8,000 per day. For Q3, we expect normalized margins to be between USD 8,000 and USD 9,000 per day. This includes anticipated rig activations in Q3. Daily operating costs in the U.S. were lower than the first quarter due to improved fixed cost absorption with higher activity levels and fewer onetime items. Our reported daily operating costs included costs associated with reactivating 4 rigs during the quarter, negatively impacting operating costs by $648 per day.

In Canada, Precision’s drilling activity averaged 50 rigs, an increase of 1 rig from Q2 2024. Our daily operating margins in the quarter were $15,306, an increase of $883 from Q2 2024. Our Q2 margins included revenue associated with upfront customer payments for rig upgrades amounting to $1,440 per day. Without this payment, Q2 margins would have been $13,866, slightly ahead of the high end of our guidance of $12,500 to $13,500 per day. For Q3, our daily operating margins are expected to be between $12,000 and $13,000. Internationally, Precision’s drilling activity in the quarter averaged 7 rigs. International average day rates were USD 53,129, an increase of 4% from the prior year due to rig mix. In our C&P segment, adjusted EBITDA this quarter was $10 million, down 18% compared to the prior year quarter.

Adjusted EBITDA was negatively impacted by a 23% decrease in well service hours, slightly offset by higher margins. Capital expenditures for the quarter were $53 million, including $27 million for upgrade and expansion and $26 million for maintenance and infrastructure. Our full year 2025 capital plan has been increased from $200 million to $240 million and is comprised of $150 million for sustaining and infrastructure and $86 million for upgrade and expansion. Our original 2025 plan was $225 million and was subsequently reduced in April as a result of heightened market uncertainty around tariff discussions and potential deterioration of U.S. and Canada trade relations. Since our last conference call, oil and gas prices have increased, broad public indices, including the OSX, are up in the 10% to 20% range and year-over-year rig counts are either stable or up in many of our key operating basins, including the Haynesville, Marcellus, Montney and Canadian heavy oil.

The improved outlook and increased activity in several of our core geographic areas has resulted in a material increase in customer demand for upgrades to rigs versus 3 months ago. As of July 29, we had an average of 38 contracts in hand for the third quarter and an average of 39 contracts for the full year 2025. Moving to the balance sheet. Our Q2 cash flow momentum continued, with strong cash flow supporting debt reduction of $74 million and share repurchases of $14 million. As of June 30, our long-term debt position net of cash was approximately $644 million, and our total liquidity position was approximately $530 million, excluding letters of credit. Our net debt to trailing 12-month EBITDA ratio is approximately 1.3x, and our average cost of debt is 6.9%.

Moving on to guidance for 2025. We expect strong free cash flow for the year, depreciation of approximately $300 million, cash interest expense of approximately $65 million. Cash taxes, we expect to remain low and our effective tax rate to be approximately 25% to 30%. We expect SG&A of approximately $95 million before share-based compensation expense. And we expect share-based compensation charges for the year to range between $15 million and $35 million at a share price range of $60 to $100, and the charge may increase or decrease based on the share price and performance relative to Precision’s peer group. Our debt reduction target for 2025 remains at $100 million, and we plan to allocate 35% to 45% of the free cash flow before debt principal payments to share repurchases.

With $91 million of debt reduction and $45 million of share repurchases through June 30, we are well on our way to achieving another annual capital allocation goal. We are committed to reducing debt by $700 million between 2022 and 2027 and achieving a normalized leverage level below 1x. Since 2022, we have reduced debt by $525 million. With that, I will turn the call over to Kevin.

Kevin A. Neveu: Thank you, Carey, and good morning to those of us in Calgary, and good afternoon, if you’re east of us. As Carey mentioned, second quarter results were stronger than we anticipated with excellent free cash flow and better-than-expected margins. We locked in additional term contracts in the United States and Canada, and we experienced strong customer demand for our Super Triple rigs in every gas basin in North America, all this coupled with continued customer demand for our pad-equipped Super Single operating in Canadian heavy oil and thus opening opportunities to invest in further rig enhancements, providing revenue and earnings growth opportunities for Precision. Our outlook for the balance of 2025 and into next year has substantially improved from our conference call in late April.

While macro uncertainties persist, customer interest in gas-directed drilling has taken shape, with several operators planning to expand drilling programs with Precision, and this is very encouraging. Currently, we are operating 36 rigs in the United States, well up the normal of 27 rigs in late February. And I’ll come back to our U.S. segment in a few moments. Last quarter, with all the macro uncertainties, you’ll recall that Precision implemented a fixed cost reduction program, and we suspended $25 million of unplanned or planned upgrade capital spending. Since then, firm customer demand supported by term contracts, increased rates on some contracted rigs and customer prepayments have encouraged us to restore the $25 million of upgrades, and we’ve identified an additional $15 million of further good upgrade investment opportunities.

As Carey mentioned, we now plan to spend a total of $86 million of rig upgrades as part of our 2025 capital spending plans, and I’ll provide more color on these investments later in my comments. Even with this increased capital plan, we’ll easily achieve our 2025 debt reduction and share repurchase targets. We’ll continue with aggressive cost management. We will continue to seek prefunding of capital upgrades, and you can expect strong execution on all aspects of cash flow management from the Precision team. Now turning to Precision’s Canadian business segment. This distinguishes us from virtually every other NAM-focused energy service provider. Now all of you know that Precision is the largest driller in Canada. But I really want to draw your attention to our market presence in the Montney and heavy oil.

And I’ll begin with the Montney, which is categorized as a natural gas play located in Northwestern Alberta and Northeastern British Columbia. And we’ve been reminding our investors for several years now that while this is a gas play, it’s also an important liquids play. Now recently, one of our largest customers at their Investor Day referred to the Montney as a world-class gas play, but with the most remaining oil inventory of any play in North America. This clearly aligns with Precision’s view of the Montney and provides long-term visibility for rig demand in this play. Now it’s well understood that Precision has been focused on the Montney since its beginning. and we have 30 Super Triple Alpha rigs currently in the region, with 26 running today, in line with last year’s activity levels.

These rigs offer the drilling efficiency of Alpha- automated, high-specification triples, coupled with pad-walking, batch-drilling capabilities. These rigs were designed for the Canadian environment, digitally controlled, fully winterized with small footprints and reduced truckload counts for optimized mobility in the seasonally challenging Canadian market. During the second quarter, we operated 26 of these rigs through the Canadian breakup period and expect our fleet should be fully utilized at the end of the first quarter of next year as it has in the past several winters. With LNG Canada Phase 1 operating and shipping cargoes, full operational ramp-up is expected over the next several months into early next year. When Phase 1 reaches rated capacity, we expect industry rig demand may increase by 5 rigs or more.

For Precision, we expect this will lean to 100% utilization of our Super Triples evolving from just winter drilling season and year-round pad activity to meet those increasing customer needs. We also believe that we may have opportunities to mobilize additional rigs back to Canada from the U.S. Some of those customer conversations and negotiations are underway right now, and we’ll provide further updates as those negotiations progress. Now we’ve experienced a similar trend with stronger-than-expected heavy oil customer demand over the past year following the start- up of the Trans Mountain expansion. During the second quarter, we reported the highest utilization of our Super Single rigs, higher of any second quarter for the past decade, with 24 of these rigs drilling straight through the breakup period.

Currently, 16 of our Super Single rigs are equipped with pad drilling systems, which facilitate high-efficiency, multi-well pad drilling and offer our customers the optimum economics for heavy oil drilling performance. We deployed 2 of these pad upgrades during the first quarter and will deliver a third, the 17th, later in the third quarter. The capital investments for these rig upgrades are covered by customer contracts and, in some cases, upfront cash payments. The efficiency these rigs offer our customers warrant day rate premiums of several thousand dollars per day above conventional non-pad rigs. And these upgraded rigs are well positioned to run through the seasonal breakup and deliver year-round operations for our customers and year- round revenue for Precision.

Overall, Canadian activity this summer has been a little slower to rebound compared to last year, and we can link this directly to a handful of smaller operators cautiously managing the macro uncertainty surrounding oil, while our larger-scale, top half of our customer mix are actually running slightly more rigs compared to this time last year. Now specifically, the telescoping doubles rig segment market, which is focused broadly on light oil plays and smaller operators in Southern Saskatchewan and Central Alberta and touching into Montney and heavy oil, has seen the largest reduction in customer demand with industry activity down almost 30% from last year in this rig class and with Precision operating 7 fewer rigs. As we’ve mentioned before, this rig class is oversupplied and highly price competitive with rates trending to cyclic lows.

Now before I leave Canada, I’ll touch on our Well Service segment, where second quarter activity was down year-over-year, more in line with long-term seasonal breakup trends. I’ll remind the listeners that most of our Well Service work is linked to oil and less to gas. Last year, we experienced a surge in customer demand, mostly linked to the TMS expansion mentioned earlier. This year, we see less customer urgency, reducing their workover pace, at least temporarily, as they control their lease operating expenses. We believe this segment will see customer demand improvement as some of the macro uncertainties are resolved. Precision’s scale, operational excellence and safety performance remain key differentiators in our Well Service group, particularly for the large-cap public operators.

And despite lower industry utilization, our pricing and margin performance remains firm. Now turning to the Lower 48 drilling business. As I mentioned earlier, we have 36 rigs operating, up from a low of 27 back in February, and we have 3 additional rigs contracted to activate over the next few weeks, and we’re extremely pleased to be regaining activity in the face of broad market uncertainty. And I’ll walk through these increases on a region-by-region basis. So since February, we’ve added 2 rigs in the Haynesville. We’ve added 3 rigs in the Marcellus, and we have a fourth scheduled to start up shortly. We have 2 rigs in the Gulf Coast, all targeting gas. We’ve also added 4 rigs in the DJ and Rockies, where our ST-1200 is the perfect rig for the suburban drilling locations north of Denver.

We continue to experience a lot of contract churn in the oil plays, and we’re operating 2 fewer rigs in the Permian, consistent with broad industry trends. Now I’ll close my comments on Lower 48 by mentioning that contract churn with our oil-directed rigs, particularly in West Texas, will continue. And while customer interest in the Haynesville and Marcellus is encouraging, we have ongoing customer discussions for potential rig activations late this year and into 2026. There’s no question that LNG export capacity additions and data center power demand expectations are driving customer sentiment for natural gas operators. In our International segment, as Carey mentioned, we continue to operate 5 rigs in Kuwait and 2 rigs in the Kingdom of Saudi Arabia.

These rigs are largely contracted for the next several years, and we’ll continue to explore opportunities to activate our idle rigs in the region, and we’re also looking closely at the other emerging shale drilling opportunities, and we’ll provide further updates should be successful on these opportunities. So turning to our strategic priorities. I’d like to provide a detailed midyear update. So first, as Carey mentioned, we retired $91 million of debt, almost achieving our target of $100 million by only midyear. Also, Carey mentioned that we’ve returned capital to shareholders by repurchasing $45 million of shares, and we’re on our way to achieving this target also. Turning to our second priority, which is to maximize free cash flow. Now we mentioned that we implemented the fixed cost and SG&A cost reduction plan back in April, and our Q2 results demonstrate the immediate impact of those cost reductions.

We continue to successfully manage our global procurement efforts and offset the cost impacts of the steel and other product tariffs. We have several technology initiatives utilizing AI and digital twins to analyze machine data and reduce maintenance costs and unplanned downtime for mud pumps, top drives and reciprocating engines. Our remote operating center provides real-time hardware and software support for our rigs to reduce downtime, minimize maintenance costs. And all of these initiatives are executed by the Precision teams based in Houston, Calgary, Dubai and in our 23 field support bases. I’m proud of their efforts and the results are clear in our financial performance in the first half of this year, and the momentum will continue through 2025.

Our third priority was to grow revenue in existing product lines through contracted upgrades, optimizing pricing and rig utilization and opportunistic tuck-in acquisitions. And earlier this year, this priority looked very challenging, yet we remain ready. Customer demand has remained surprisingly resilient for Canadian heavy oil pad rig upgrades along with hydraulic capacity upgrades on other Super Single rigs. These investments have been supported by a variety of advanced payments, increased day rates and term contracts and will impact approximately 10 of our Super Single rigs. Our EverGreen solutions reduce diesel fuel consumption, reduced rig emissions and reduced daily operating costs for our customers. We expect to add EverGreen systems to 36 rigs this year, including mass lighting kits and hydrogen catalyst systems.

EverGreen solutions are priced as an a la carte addition to the rig rate and pay out within a few months. Customer demand for extended reach gas drilling in the Haynesville and Marcellus has driven opportunities for capacity upgrades to our ST-1500 rigs, including larger mud pumps, higher-torque top drives, racking and hoisting capacity increases, and these upgrades will impact approximately 12 rigs. We have also established preferred driller agreements with several key customers, whereby we provide most or all drilling services at optimized rates with rig performance incentives and incentives for additional rig utilization. All of these initiatives are designed to provide and enhance our competitive advantage, provide revenue and earnings growth, improve revenue visibility while delivering returns well in excess of our cost of capital, and we’ll continue to seek opportunities to further invest in our fleet and further develop customer partnerships.

So I’ll now conclude my comments by thanking the whole Precision team for another quarter of excellent business execution, and I’ll also thank all of our stakeholders for their continued support. Operator, we’re now ready for questions.

Q&A Session

Operator: [Operator Instructions] Our first question comes from Derek Podhaizer with Piper Sandler.

Derek John Podhaizer: I guess maybe let’s just start on the U.S. side. Obviously, some really nice growth that we’re seeing in the Northeast and the Haynesville gassy window down in the Gulf. Maybe could you help us understand a little bit whether the split is between publics and privates? And then thinking ahead into the end of the year into next year, I guess, what’s the cadence? Or maybe can you help quantify for us the number of rigs that we could expect to go back to work into these gas basins?

Kevin A. Neveu: Derek, that’s a really key question, actually. And I think what we’re seeing here is the history of the industry where the privates always lead when the industry is turning. The privates aren’t trying to manage public expectations. They’re making good investment decisions. So there’s no question that our gas-based work right now is tilted towards private companies throughout both the Marcellus and the Haynesville.

Derek John Podhaizer: Got it. And then maybe just how many rigs potentially you think from here? I know you have a couple of lined up, but as we work towards the end of the year and into 2026, are the privates not looking that far ahead as far as that incremental activity?

Kevin A. Neveu: That’s also a big question. So I’ll tell you, first of all, we’ve got some expectations I pressed on the sales team in the U.S. and they’ve got a couple of benchmark targets we’re looking at to try to get our activity higher so we can have better scale operations and leverage our fixed costs better. But we’ve kind of targeted getting to 40 and then maybe 45 rigs over time. And obviously, gas will play an important part of that rise and managing churn on the oil rigs. So should oil prices stay in the range we’re seeing today, which is not too bad, I think those targets make pretty good sense. If we go through another recycle and the oil price dipping down to low $60s, well, then all bets are off. And I think churn will increase and be certainly more challenging for us. So if you do that math on that, hopefully, we’ll look to find another 5 to 7 rigs in gas over the next several quarters.

Derek John Podhaizer: Got it. No, that’s helpful. I appreciate the color. And then just as a follow-up and maybe more of an educational question for myself. When you ran down the Canadian market, you talked about the double-rig segment, and it’s oversupplied, you have undisciplined pricing, pricing pressure. I guess taking a step back, what’s the long-term thinking for this part of the market where your other 2 parts of Canada seem very, very tight with good secular tailwinds. But in this double-rig segment, it looks to be less than that. So maybe just some thoughts around what you strategically could do around with the double-rig segment.

Kevin A. Neveu: Derek, so a couple of years ago, we acquired CWC, which actually increased our doubles fleet quite a bit. And I still think consolidation is a really important feature for oil service, especially as the operators have gotten larger. There’s a bit of a scale mismatch right now where the operators have gotten larger quickly and the services industry is still playing catch-up a bit on scale. On the triples and singles business in Canada right now, that match is much better. So there’s really kind of 2, 3, maybe 4 drillers that run most of the triples in Canada. We’ve got good scale matching between the suppliers, us and the operators. On the singles side, I think there’s 14 contractors that are in the tele-double business, maybe more.

And that’s just too fractured. So I do think that the singles or the tele-double space needs to consolidate in Canada. With the market share we have right now, we’re likely not going to be that consolidator. But I do think there’s other people in this market that could help consolidate that market and bring a bit more discipline and help get a better scale matching between services and operators. Carey, do you have anything to add to that?

Carey Thomas Ford: Yes, I actually don’t. I think that characterizes it pretty well.

Operator: Our next question comes from Aaron MacNeil with TD Cowen.

Aaron MacNeil: Kevin, I’m hoping you can help me reconcile the prepared comments with the contract disclosures. So again, in Q1 disclosures, 38 average rigs under contract in 2025, now it’s 39, so 1 incremental. On a Q4 basis, there’s 3 additional rigs, 3 incremental and maybe some of the contracts don’t take effect until 2026. So who knows? But of the 22 rig upgrades you note in the press release, how many would be incremental this quarter versus what was disclosed last quarter? And what’s sort of the contract durations that you’re achieving with these upgrades? Or are some of these spec-in nature part of a larger market share capture strategy?

Carey Thomas Ford: Aaron, this is Carey. I think I can help you out. I’m not going to provide as much disclosure detail as I think you’re asking for, but I think I can provide some good context to answer your question. So first of all, the 22 rigs that we mentioned on upgrades, not all of those have been signed yet. That’s what we expect, and that matches with our capital plan of $240 million. So there are some that we expect to sign that don’t show up in the contract book yet. The second point is most of these contract upgrades are going to be kind of in the $1 million to $5 million range per rig. So a lot of these upgrades that we’re doing don’t require a 2-year contract to recoup the cost of the upgrade capital and the underlying value of what we call the opportunity cost of the rig.

A lot of these upgrades, we’re able to recoup the returns we need in 6 months to 1 year. For the larger dollar amounts, we do need 1- to 2-year contracts, and we are getting those on the higher-dollar upgrades. The other thing I would say is that some of the business that we have is with existing customers where it’s contracted and where the rig is contracted and we provide the upgrade for a rig that’s already contracted and the day rate just goes up. So you actually wouldn’t see the contract increase because the contract term is not changing. The day rate is just increasing to give us a return. And then the final comment I’d make is, what we disclosed this quarter is we had $7 million of revenue for 2 — there’s actually 2 different customers paying us upfront for rigs that we are upgrading.

And there is no contract associated with that, and that’s why we ask for an upfront payment to cover the cost of the upgrade. So it’s a little bit different than past cycles where you build a rig and you get a 3-year contract or a 4-year contract and it shows up in the contract book. We’re very happy with the returns we’re getting. We’re getting contracted coverage on just about all the capital that we’re deploying, but it is a little bit different than past cycles.

Aaron MacNeil: Fair enough. And that actually leads into my next question. You mentioned the customer-funded upgrades. Do you have any of those penciled in for the future? And how should we think about that impacting go-forward margins?

Carey Thomas Ford: We won’t guide to any more. We don’t have any to disclose right now, but it is something that we’ve seen in the past. We just haven’t had very many that are this large in one particular quarter, which is why we broke it out.

Operator: [Operator Instructions] Our next question comes from Keith MacKey with RBC Capital Markets.

Keith MacKey: Just a quick clarification on the $40 million of incremental capital for those 22 rigs. That program is all to be spent in 2025, right? Like, just what I’m asking is, is there a 2026 portion related to those 22 rigs that we’ll also see? Or is the $40 million it as far as upgrading these rigs?

Carey Thomas Ford: Yes, Keith. So I’ll first say that the 22-rig upgrades span the entirety of 2025. So we’re not announcing 22 additional rig upgrades this quarter, those were contemplated in our original 2025 capital plan. They just materialized at a little bit faster degree than what we expected. All of the spend for this year will be for rigs that will be delivered in 2025 or just about all of it. So some of the rigs will be delivered in November, December this year, so we won’t get EBITDA generation from those upgrades. But think about that $240 million spend largely being directed at rigs that will be delivered this year.

Kevin A. Neveu: I’ll just clarify one comment. So we didn’t originally intend for 22-rig upgrades at the beginning of the year. So that’s increased from earlier in the year based on some of the opportunities we’ve seen coming forward. And the projected investment in the EverGreen products has gone up also in this increase.

Keith MacKey: Got it. Okay. That’s helpful. And just on the capital allocation and the target debt metrics, we’re certainly getting much closer to those levels and you’re ahead of your midyear debt reduction target now. So as we think about you getting closer to your ultimate debt load, how do you think about capital allocation shifting at that time between shareholder returns, growth and further debt reduction repayment at that time?

Kevin A. Neveu: So Keith, we haven’t given much guidance beyond getting to our total debt reduction plan of $600 million by the end of next year, which we will…

Carey Thomas Ford: $700 million.

Kevin A. Neveu: $700 million by the end of next year, which we will achieve…

Carey Thomas Ford: 2027.

Kevin A. Neveu: ’27, thank you. Thanks, Carey, for clarifying me.

Carey Thomas Ford: Big numbers we’re dealing with here.

Kevin A. Neveu: Yes. But what I would tell you is that, if we see good opportunities to invest in our rigs, like we’ve seen over the last few weeks, that’s one of the best places for us to place our capital. If we can get a less than 2-year payback on a $3 million or $4 million upgrade or a less than 1-year payback on a $1 million upgrade, those are outstanding investment opportunities. That, I’d say, stays near the top of our priority list. Paying down debt is the top of the priority list. Shareholder returns fit in there. So we’ve got 3 priorities that are all important, and we’re not going to sacrifice debt repayment or either shareholder share buybacks or capital or vice versa.

Carey Thomas Ford: Yes. I think that’s exactly right. And we’ve got $175 million remaining on our long-term debt reduction plan with 2.5 years to go. So we can accelerate that. We can spread it out over the entire time period. It can give us more flexibility to increase returns to shareholders. And as Kevin said, if the opportunities come to us to get good returns on our capital investment, we’ll invest in our fleet.

Operator: Our next question comes from Waqar Syed with ATB Capital Markets.

Waqar Mustafa Syed: First of all, congrats on an excellent quarter. In terms of the upgrades that you’re doing on the rigs in the U.S., with these upgrades, do you bring these rigs at par in terms of capabilities with some of the other top-tier rigs in a particular basin? Or following the upgrades, these will be kind of unique-type rigs in every basin?

Kevin A. Neveu: Waqar, it’s a little hard to gauge that because there’s been a little less disclosure by industry peers around what rig capabilities are. So it’s hard to say for sure. What we do know is that I think we’re getting to kind of peak hook loads and peak draw works capacities and peak mud pump sizes. So I think that certainly, we’ll be at the point of the arrow on rig capability. Now everything I’ve just said there is kind of making the hammer bigger. So larger mud pumps is more horsepower; larger draw works, more hoisting capacity; larger, heavier mass would be more rocking capacity, more casing capacity. It’s all important. But when you couple that with the Alpha automation, I think that becomes a unique service package where you can fully automate that and deliver consistent predictable reports. Now we know that other drillers have various levels of automation. We don’t think any other level of automation is as comprehensive from spud to release as Alpha.

Waqar Mustafa Syed: Sure. And then in terms of the type of wells that these rigs would be drilling, is that like these 4-mile laterals or horseshoe-type wells? Or what is it that clients hope to achieve with these rigs?

Kevin A. Neveu: So we are drilling 4-mile laterals right now. We’re drilling some horseshoe-bend 4-mile laterals. But I can tell you that every drilling engineer that’s drilling deeper wells wants rig capacity to drill farther. So even though some of these rigs that we’re upgrading aren’t necessarily going to be drilling 4-mile laterals, the drilling team wants that ability down the road. So I think these are being designed to drill Haynesville or Marcellus and do the longest 3 horizontal wells that’ll likely be economic for the near future.

Operator: Our next question comes from John Daniel with Daniel Energy Partners.

John Matthew Daniel: I hope I didn’t miss this on the call. But Kevin, in your U.S. customers in the nat gas markets, are they seeking term contracts today? And what’s your willingness to lock in? And if they’re looking to do term contracts, what’s the typical duration they’re seeking?

Kevin A. Neveu: John, great question. And it’s the same question our Board asked us yesterday in the discussion around capital. I would tell you that we probably have opportunity to take longer terms if we choose, but the rates would be lower. So I’d say we’re trying to balance optimizing the day rate with duration that returns our capital. So higher day rates and maybe a little shorter term. But I’ll tell you the terms we’re looking at are in the 1- to 2-year range.

John Matthew Daniel: Okay. Fair enough. And then last one for me. Your 2 U.S. Well Service players since you’re not competing down here anymore, they’ve announced the introduction of electric workover rigs. I’m just curious at this point if any of the Canadian operators are starting to ask you guys about electrifying your fleet.

Kevin A. Neveu: On the well service side, no. Interestingly, we talked about EverGreen upgrades. So we’ve had more interest in high-line powered drilling rigs that will be electric as most electric rigs are, but high-line powered. But there’s not a lot of interest on the well service side in Canada yet. There’s such an excess capacity of functional service rigs in Canada that the likelihood of a newbuild service rig in Canada, newbuild new technology service rig, is still probably several years out.

Operator: Our next question comes from John Gibson with BMO Capital Markets.

John Gibson: Congrats on the strong quarter here. Just wondering if you could provide a breakdown either by geography or basin for where the upgrades are targeted of those 22 rigs.

Carey Thomas Ford: So I mentioned it a bit in my comments, John, on where we’re seeing a bit firmer demand and, in some cases, growth. And so it’s the basins where we have a really strong presence, which would be the Haynesville, Marcellus, Montney and Canadian heavy oil. That’s where the bulk of the upgrades are going.

John Gibson: Got it. And last one, how many rigs do you still have sitting on the sidelines in the Haynesville?

Kevin A. Neveu: Large high single digits.

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

Lavonne Zdunich: Well, that concludes our conference call for today. Our next formal update will be in October, but we are always available to answer questions from now until then. And with that, I will sign off. Thanks for joining.

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