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.

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.

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…

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…

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

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?

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.

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?

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.

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.

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?

Yes, I actually don't. I think that characterizes it pretty well.

Our next question comes from Aaron MacNeil with TD Cowen.

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?

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.

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?

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

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?

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.

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.

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?

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...

$700 million.

$700 million by the end of next year, which we will achieve...

2027.

'27, thank you. Thanks, Carey, for clarifying me.

Big numbers we're dealing with here.

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.

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.

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

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?

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.

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?

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.

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

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?

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.

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.

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.

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

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.

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.

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

Large high single digits.

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

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.

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