Precision Drilling Corporation Q2 FY2025 earnings call

• Second quarter financial results exceeded expectations with adjusted EBITDA of $108 million, revenue of $407 million, net earnings of $16 million, etc.
• In the U.S., drilling activity averaged 33 rigs in Q2, with operating days increasing 13% and daily operating margins exceeding guidance. For Q3, normalized margins are expected between USD 8,000 and USD 9,000 per day.
• In Canada, drilling activity averaged 50 rigs in Q2, with daily operating margins increasing and Q3 margins expected between $12,000 and $13,000. Different segments in Canada have varying performances, such as Montney, heavy oil, and telescoping doubles rig segment.
• In the U.S. Lower 48 drilling business, 36 rigs are operating, up from 27 in February, with increases in various regions like Haynesville, Marcellus, etc.
• Strategic priorities include reducing debt by $700 million between 2022 and 2027, maximizing free cash flow through cost reductions and technology initiatives, and growing revenue in existing product lines through contracted upgrades, etc.

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 the guidance of $7,000 to $8,000 per day. For Q3, normalized margins are expected to be between USD 8,000 and USD 9,000 per day. In Canada, drilling activity averaged 50 rigs in Q2, an increase of 1 rig from Q2 2024. Daily operating margins in the quarter were $15,306, an increase of $883 from Q2 2024. Q2 margins included revenue from 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 the guidance of $12,500 to $13,500 per day. For Q3, daily operating margins are expected to be between $12,000 and $13,000. Internationally, drilling activity averaged 7 rigs in the quarter. International average day rates were USD 53,129, an increase of 4% from the prior year due to rig mix. In the 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.

• Expect strong free cash flow for 2025, with depreciation of approximately $300 million, cash interest expense of approximately $65 million. Cash taxes are expected to remain low and effective tax rate to be approximately 25% to 30%.
• SG&A is expected to be approximately $95 million before share-based compensation expense. Share-based compensation charges for the year are expected to range between $15 million and $35 million.
• Debt reduction target for 2025 remains at $100 million, and 35% to 45% of free cash flow before debt principal payments will be allocated to share repurchases.

• Macro uncertainties such as tariff discussions and potential deterioration of U.S. and Canada trade relations.
• Telescoping doubles rig segment is oversupplied and highly price competitive with rates trending to cyclic lows.
• Seasonal fluctuations in industry activity.

Q: 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.

A: 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.

Q: Derek Podhaizer with Piper Sandler asks about the U.S. side, split between publics and privates and cadence of rigs going back to work in gas basins.

A: 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. 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.

Q: Aaron MacNeil with TD Cowen asks about reconciling prepared comments with contract disclosures, number of incremental rig upgrades this quarter, contract durations, etc.

A: 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.

Q: Keith MacKey with RBC Capital Markets asks about capital allocation and target debt metrics, shifting of capital allocation when closer to debt load.

A: 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: '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.

Q: Waqar Syed with ATB Capital Markets asks about upgrades in U.S. rigs, whether they bring rigs at par with top-tier rigs in a basin or are unique.

A: 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.

Q: John Daniel with Daniel Energy Partners asks about U.S. nat gas customers seeking term contracts and willingness to lock in.

A: 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.

Q: John Gibson with BMO Capital Markets asks about breakdown of upgrades by geography or basin and number of rigs on sidelines in Haynesville.

A: 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. Kevin A. Neveu: Large high single digits.