Precision Drilling Corporation

Good day and thank you for standing by. Welcome to the Precision Drilling Corporation 2023 second quarter conference call. I would now like to hand the conference over to LaVon Sedunic, Director of Investor Relations. Please go ahead.

Thank you, Operator. Welcome to Precision Drilling's second quarter conference call and webcast. Today, I am joined by Kevin Neveu, Precision's President and CEO, and Kerry Ford, our CFO. Earlier today, we reported our second quarter results. To begin our call today, Kerry will review these results, and then Kevin will provide an operational update and outlook commentary. Once we have 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 CDAR and EDGAR. As a reminder, we express our financial results in Canadian dollars unless otherwise stated. Kerry, over to you.

Thanks, Lavonne. Precision Q2 financial results exceeded our expectations for revenue, adjusted EBITDA earnings, and cash flow. The resiliency of our high-performance, high-value business model, an organizational focus on cash flow and return on capital, drove our financial results and progress in strengthening the balance sheet. We have not yet reached our desired capital structure, but in the middle of 2023, we crossed a few milestones, including total debt below $1 billion, a net debt to TTM EBITDA below two times, well below two times, and cumulative debt reduction of over $1.1 billion since the beginning of 2016. Now I'll move on to Q2 performance. Adjusted EBITDA of $142 million was driven by healthy drilling activity, improved pricing, and strict cost control, and included a share-based compensation charge of $3 million. Without this charge, adjusted EBITDA would have been $145 million, which compares to a normalized EBITDA of $75 million in Q2 2022, representing an increase of 93%. Margins in the U.S. and Canada were higher than guidance, resulted from stronger than expected pricing and cost recoveries, higher ancillary revenues, and improved cost performance, in addition to $5 million in idle but contracted revenue. In the U.S., drilling activity for precision averaged 51 rigs in Q2, a decrease of nine rigs from the previous quarter. Daily operating margins in Q2, excluding the impacts of turnkey and idle but contracted revenue, were $15,455, an increase of $1,276 from Q1. For Q3, we expect margins to be approximately $15,000. In Canada, drilling activity for precision averaged 42 rigs, an increase of 5 rigs or 12% from Q2 2022. Daily operating margins in the quarter were $12,203, a decrease of $1,355 from Q1 for Q2, sorry, from Q1 2023. For Q3 2023, our daily operating margins are expected to increase by approximately $500 in Q2 levels with improved pricing offsetting rig mix. We continue to build our North American contract book with Q4 2023 drilling rigs under take or pay term contracts increasing 50% in the U.S. and over 60% in Canada versus three months ago. Internationally, drilling activity precision in the current quarter averaged five rigs. International average day rates were $50,551, a decrease of 7% from the prior year due to rig mix. In our C&P segment, adjusted EBITDA this quarter was $8 million, up 55% compared to the prior year quarter. Adjusted EBITDA was positively impacted by a 31% increase in well service hours and improved pricing. C&P results were further supported by Precision's rental business, which has realized an increased demand and utilization for equipment on our super triple rigs for customers in the Montney. Moving into the balance sheet, we are committed to reducing debt by over $500 million between 2022 and 2025 and achieving a normalized leverage level below one times. Our debt reduction target for 2023 is $150 million, and we plan to allocate 10% to 20% of free cash flow before principal payments directly to shareholders. During the quarter, we reduced debt by $178 million and utilized $8 million to repurchase shares. As of June 30th, our long-term debt position net of cash was approximately $940 million, and our total liquidity position was $580 million, excluding letters of credit. Our net debt to trailing 12-month EBITDA ratio is approximately 1.7 times, and our average cost of debt is approximately 7%. We expect our net debt to adjusted EBITDA ratio to be approximately 1.25 to 1.5 times at year end when we expect debt to be below $900 million and our run rate interest expense to be approximately $60 million. Our annual guidance for 2023 includes depreciation of $290 million and SG&A at $90 million before share based compensation expense. Our full year 2023 capital plan remains at $195 million. we expect cash interest expense to be approximately $80 million for the year and cash taxes to remain low with an effective tax rate of approximately 25%. For 2023, we expect share-based compensation expense to range between $20 million and $40 million for the share price range of $60 to $100 in Canadian dollars. The annual share-based compensation accrual could increase or decrease another $15 million based on relative share price performance and a multiple applied between zero and two times. Year-to-date, we have had a recovery and share-based compensation expense of $9 million. With that, I will turn the call over to Kevin.

Thank you, Gary, and good afternoon. As Kerry highlighted, I am also thrilled with the rapid progress we are achieving against our debt reduction and capital structure objectives. This progress is underpinned by the strong operating cash flows we are producing and should continue to produce. I'm equally thrilled with our recent contracting successes in both the United States and Canadian markets, and more on that in a moment. Now, as some of the listeners may know, Precision has a large employee shareholder base, many of whom listen in on our earnings calls. I'd like to recognize and thank every member of the PDE team who are all dedicated to providing the safe, high-value services our customers expect from PDE, while also tightly managing our costs, optimizing our margins, and producing strong operating cash flows to the benefit of all PD shareholders. The results of the hard work achieved the highest second quarter cash flow in the company's history. Bravo to the PVD team. So I'll start with our Canadian segment, which I've been highlighting for several quarters, but really stood out during the seasonally slow second quarter, traditionally known as breakup. The Canadian market for conventional oil and gas drilling has radically transitioned over the past several years, and is perhaps now the best it has been. And by best, I mean the most stable and healthy that I've experienced during my career. No longer is the summer-fall drilling program pinned on the eco gas price realized in April-May. We now have visibility one, two, and in some cases three years out for Canadian drilling activity. The Trans Mountain project, the Line 3 expansion, and the coastal gasoline pipes are solving the basin takeaway constraints which have hung over the Canadian industry for the past decade. You can look through Precision's customer list and find many directly linked to LNG Canada and others who have recently announced long-term LNG gas sales contracts through the Gulf of Mexico. Precision's Super Triple Fleet, which is fully utilized in Canada, is linked to the global LNG market, not seasonal eco-volatility. And then Western Canada Select Discount is narrowed. And combined with a weak Canadian dollar, our heavy oil and SAGD customers are benefiting with improved cash flows and have returned to the drill bit, resulting in strong demand for our super singles. But probably most importantly, our customers have become adept at operating in a tightly constrained and capital discipline framework. They are not relying on capital market access to fund drilling programs, but our self-funding drilling remaining well inside their cash flows. They have improved focus on balance sheets, and they are operating shareholder focused returns based corporate strategies and this capital discipline has transitioned the way our customers think about drilling they've taken the focus off pure day rates they're focusing on comprehensive overall drilling cost efficiency when they develop their drilling plans for both gas and heavy oil development projects we're experiencing increased demand for pad drilling and seeing increasing pad sizes all aimed at this cost efficiency essentially Pad drilling has become the industry standard and led to full utilization of our padlocking rigs, where we continue to see customer demand exceeding our supply. On larger pads, these rigs can work straight through spring breakup, smoothing our revenues and improving our cost efficiency. This drive for capital efficiency also encourages customer adoption of our alpha digital solutions, and with all but a couple of our super triples running in Canada now operating the alpha system. So currently we have 58 rigs in Canada running, marginally less than we previously guided, and primarily due to just one operator reducing their drilling program. With a stable oil price, the reduced Canadian differentials, and the soon to be commissioned TMX and Coastal GasLink pipelines, our outlook for the second half in Canada remains firm. We expect 100% utilization of both our 29 super triples and our pad super singles, and strong utilization for our remaining 31 super singles, We should see rig activity in the high 60s or low 70s in the third and fourth quarter, setting up for a very strong start to 2024. Notably, during the second quarter, we had 10 long-term ticker pay contracts, with some of those stretching out three years. Most of these were contract renewals with operators seeking to lock in access to those rigs over the longer term. This is another key Canadian market change whereby customers are now committing to contracting rigs on a ticker pay basis, when in prior periods customers would only commit to this take-your-pay style contract when supporting drilling contractor capital investments for upgrades or new builds. This shift significantly stabilizes our activity levels and our financial performance for our Canadian segments. Today, 20 of our 29 Canadian Super Triples are contracted with take-your-pay terms, and we still see customer demand well in excess of our available rig supply. We have said we might consider mobilizing additional rigs to Canada from the DJ Basin or Marcellus. It seems this opportunity may emerge later this year or in 2024. Turning to rates, our leading-edge rates in Canada for our Super Triple 1200s are now approaching the mid-30s for the base rig, while our pad super singles are now in the mid-20s. Alpha Automation is installed and running on approximately 90% of our Canadian Super Triples and continues to deliver solid performance results and meaningful value for our customers. It remains incumbent on precision to continue to manage our costs and improve our day rates as we seek out financial returns exceeding our cost of capital. We've made good progress so far, but we still have a ways to go. Turning to our well servicing business, it performed exceptionally well during the second quarter, despite industry activity lower than last year. The regional diversification we achieved with the high Arctic acquisition supported strong activity levels through breakup, specifically in our thermal operations which remain a key strategic focus for our well-service team. Our expanded scale has noticeably improved our operating leverage, providing a strong catalyst for free cash flow growth in this business. We are expecting a busy second half of the year, and with industry-wide crewing constraints continuing to limit industry capacity, we believe the outlook for well-servicing looks very good for the second half. Now, in the U.S., as Kerry outlined, our utilization is trending a little lower than we guided, as a result of the weakened natural gas prices and the uncertain oil prices experienced in the first half of the year. However, as Brent and WTI have firmed up over the past few weeks, customer inquiries for oil targeted rigs has accelerated. We recently contracted nine rigs for Q4 and early 2024 startups. If the current oil price range is sustained, perhaps we're in the trough of customer demand with an upward bias later this year into 2024, where demand is noticeably strengthening. Super spec rig supply remains very tight despite the reduced overall industry activity, and very importantly, pricing discipline remains a common theme among our industry peers. Currently, we have 43 rigs operating and two on paid standby. Through the first half of this year, we've been prioritizing defending margins over pursuing market share. We've turned down several opportunities with rates below our thresholds, and we'll continue to do so. We do expect our utilization will remain around this level, through the third quarter with upwards trend in the fourth quarter in 2024, as I described earlier. Precision's current leading edge rates are super triple 1500s or in the low to mid 30s with some fully included rig rates approaching $40,000 per day. And those are for customers that are seeking immediate activations. At current quantity price levels, we see super spec rig demand trending towards near full utilization next year. And it appears our customers are also anticipating the same market dynamic, as they are seeking to lock in the best rigs at what appears to be market-leading rates. We are bidding on several contracts that have been awarded contracts with rates in the upper to mid to upper 30s for rigs starting operation later this year and early 2024. And virtually all of our operating rigs in the U.S. have alpha automation, delivering, again, improved customer performance while enhancing our field rates and margins. Now, turning to our evergreen products for a moment, our evergreen solutions continue to generate very strong customer interest. Precision's evergreen solutions are no-nonsense, high-value, cost-saving additions applicable to virtually every PD rig, with the added benefit of reducing GHG emissions. This is a win-win-win project in the very early stages of market penetration. For example, we have 10 battery energy storage systems deployed and expect to add three more before the end of the year. have several more systems in the final stages of customer approval right now customer uptake of our evergreen products has spread from canada to the dj basin and is now expanding with customers the permian and marcellus also exploring these products we'll have more to report on the evergreen product line in the coming quarters and finally turning to our international business currently we have six rigs running as terry mentioned three in kuwait and three in saudi arabia The final two Kuwait rigs are nearing completion in the recertification process and barring any customer delays, both rigs should be running in the next several weeks. We have five additional idle rigs in the region and continue to pursue interesting opportunities to tender those rigs for several different projects. We will keep you updated on our progress as information becomes available. And that concludes our prepared comments. I will now turn the call back to the operator for questions.

Thank you, ladies and gentlemen. If you have a question or a comment at this time, please press star 11 on your telephone. If your question has been answered, you wish to move yourself from the queue, please press star 11 again. We'll pause for a moment while we compile our Q&A roster.

Our first question comes from Luke LeBlanc with Piper Stanley. Your line is open.

Hey, good afternoon. Kevin, pretty positive comments about the U.S. rigs that are being signed to begin in 4Q. Can you talk about the shape of the U.S. rig count, and do you think 4Q jumpstarts to 24? And then I just wanted to confirm, as you said, super-stack rig demand could be at full utilization next year.

You know, we're actually quite surprised by how quickly our customers seem to be ramping up. They're thinking about 2024. It's primarily oil-based, but we've had Also, I think one or two rigs that look likely to be contracted into gas, primarily in the Marcellus. But just looking at the profile right now, quick influx of lots of inquiries. We've signed the nine contracts we mentioned. Primarily oil, primarily either large cap or kind of IOC style ENPs. They're definitely planning to wrap up activity into 2024. And we're effectively kind of repositioning from the Hainesville into the Permian right now and really shifting our customer mix from what was largely private equity a year ago now to a lot of large cap publics and IOCs in the Permian. And so as we watch that kind of play itself out, if we just look at the inquiries we have today, they'll look like they'll turn into rigs. They're not all for precision, probably for the industry. That's where I'm thinking that over the course of 2024, you could see that super stack rig market fully utilized.

Got it. And then on Canada, you're sold out on super triples and singles, and you talked about moving some from the U.S. What kind of duration can you get on these contracts? I know overall you talked about, you know, seeing one to three years in Canada at some term. Are you towards the higher end to move those from the U.S. to Canada, or how should we think about that?

Well, the way you should think about that is, number one, we want to see the marginal rate in that upper 30s range. So that's really important. And the customer has to pay for that move in addition to the day rate. So whether he signs a two-year contract and pays for it over two years or signs a one-year contract and pays for it over one year, I'm kind of indifferent. But we do want to take or pay contract with fixed days. We want to have some certainty of revenue. We want to have a base rate for that base rig in the upper 30s. And we want the MOB costs fully compensated. paid for by the customer. So I'd say it's a fairly high bar compared to today's market, but the market's evolving quickly.

Yeah, got it. All right, thanks a bunch, Kevin. Great, thank you. One moment for our next question.

Our next question comes from Eric McNeil with TD Cowan.

Your line is open.

Hey, everyone. Thanks for taking my questions. Kevin, if there's 27 rigs under contract in the U.S. in Q4, what's the average duration? And if 43 are currently active, can you sort of characterize the remaining 16 or so rigs? I guess I'm wondering what sort of contract structures are they operating under, I assume, well-to-well? Are they up for renewals? Do you have visibility towards continued work? There's obviously always churn, but Just trying to understand how solid the current activity level is in the U.S. today.

Hey, Aaron. This is Kerry. The contract book we've had over, call it the last 18 months, has been anywhere from six months to three years. But up until, I would say, a few weeks ago, the majority of the contract durations were six months. And we've seen... more requests for one- and two-year contracts, and we've recently entered into several one-year contracts. So I think it's trending a little bit longer duration, and we're not really seeing as many customers looking for three or four WEP programs. They're longer-term programs. So I think it's a good indicator of future activity.

And the rigs that are sort of working today, but don't have long-term contracts associated with them.

Yeah, so those will either go into long-term contracts or they're going to switch hands to customers that are more interested in contracts.

And some of those renew on a well-developed basis with the same customer over and over.

Correct. Got it. You've highlighted the relative strength of the Canadian market again this quarter. If we compare a you know, generic or average 1,500 horsepower super triple in the U.S. with a, you know, generic 1,200 horsepower super triple in the Montney, which one's generating a higher rate of return today? And do you expect those rates of return to change at all?

Aaron, that's essentially how we arrived at that upper 30s Canadian rate that rigged in Canada. So our costs in Canada are in Canadian dollars. Our rates are in Canadian dollars. So the operating margin at upper 30s would be about the same that we're achieving in the U.S.

on those rigs, on those 1,200 rigs in the DJ basin.

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

Thank you. One moment for our next question.

Our next question comes from a car side with ATB Capital.

Your line is open.

Thank you. Kevin of Cary, the IBC revenues in Q3, would those still be around that $5 million, $6 million mark?

It would probably be one or two rigs. I don't know if it would be that high, but it would be one or two rigs that we have on IBC.

And how many rigs were in Q2?

I think we had two rigs.

Oh, you had two rigs as well. Okay. All right. And then, you know, so if you look at the U.S. clean kind of day rate or revenue per day in Q2, roughly around $34,400. And the leading edge mentioned is in the low, you know, $30,000 to mid-30s. Is the leading edge in line with where the revenue number is, or is it below what your revenue per day was for Q2?

I think we've got a couple things going on here. We have a little bit of softness going into Q3, continue from Q2, and then we're seeing strengthening in Q4. So if you're talking about going back to Kevin's opening comments about where the leading edge rate is for Q4 and Q1, bookings, we've got some rigs that are pricing as high as $40,000 all in. So that is one leading edge rate. And then if we're talking about where we've been quoting leading edge rates for the last three months, I would say we've been saying kind of low to mid 30s. And we reported day rates of a little over $35,000 a day in Q2. So they're kind of in line, I think, in this market.

Okay. So the $15,000 a day margin guidance for Q3, is that kind of the new floor or there is potential for margins to decline further into Q4 and Q1?

Well, part of what we have going into Q3 is just a little bit lower activity. So we have some more fixed cost absorption. We have fewer rigs varying the same similar fixed costs. So that's part of the margin squeeze. And then if we see more demand and higher rates in Q4 and Q1, we'll see the margins go back up.

Wow, that's pretty good.

And in terms of incremental demand in the Middle East, How do you see that? When do you expect maybe – you still have about five rigs idle in the Middle East in international markets. How many could go back to work and over what time frame?

yeah i'm going to be a little vague on the guidance there uh we've got active bids for silver rigs right now um i'd say that the most likely rig to go back to work first would be the one auto rig in kuwait and it may go back to work in kuwait or saudi arabia it's a it's essentially an ac super spec style rig in a 2000 horsepower size but i wouldn't expect that rig to be activated before the beginning of next year the earliest and uh we've been participating in a number of other tenders in the middle east throughout several countries that just keep sort of getting punted down the road or delayed or slow played. So it's really hard to assess what the national oil companies' thinking are around reactivating these tenders and turning those tenders into contracts.

And so let's assume that you win a contract for a rig. From the day of announcement to the day that they're on revenues, Is it like a six-month lag or less or more?

It would be in the three- to six-month range, and it would just depend on how much recertification work we'd have to do and what their schedule was. They generally think about these things in that anywhere from three months to one year, depending on the tender.

And what kind of incremental capex may be required to activate those rigs?

Well, it could be as little as a few million, like maybe 8 to 10 million rigs. or it could be as much as 20 to 25 million, depending on the scope of work we have to do to meet the standard. But the day rates would be designed to recapture that capital within the first operating year of the contract.

Great. Thank you very much. This is all very helpful. Great.

Thanks, Makar.

One moment for our next question. Our next question comes from Keith Mackey with RBC Capital Markets.

Your line is open.

Hi, good afternoon. I just wanted to start out. Many have been trying to, of course, kind of call the bottom on the U.S. rig count and determine where it ultimately goes from there. Now, Kevin, from your prepared comments and in some of the, of course, Q&A sessions, It sounds like you believe that we are close to there, given the comment around super spec utilization being fully utilized in the U.S. through 2024. But can you just maybe give us a bit more clarity on why you think that the – or A, how close we are to the bottom in the U.S. rig count in terms of activity for the industry, and then B – What gives you really the confidence? What are the two or three factors that you think will lead that rig count to ultimately be, or the super spec rigs to ultimately be near at full utilization?

Keith, that's actually a very complex question, so I'll do my best here and maybe, Kerry, you can pipe in too if you have any more thoughts. So what I'm sure of is that Q2 wasn't the bottom. I'm sure of that. What I'm also sure of is that about 90 days after the bottom, you look back and say, yep, for sure that was the bottom. So there's a lot of uncertainty around trying to call it in advance. I think what we're looking at right now is we saw this surge of inquiries come in when the oil price stabilized. We've got commodity prices looking pretty good today. I mean, we need to see a month or two or three of this to be really confident. But it does seem like the problem wasn't $72 crude or $74 crude. The problem was WTI dropping into the 60s and coming back out of the 60s. That uncertainty held back plans that have been in place even late last year to add rigs. I mean, the inquiries we're looking at today were ones that we were actually contemplating back in November, December of last year. Now they've come to fruition that the price seems to have stabilized. So certainly the market's feeling better than it did even just a few weeks ago. It would be hard to imagine that in a, world of $75, $80 WTI, but the rig count goes down much further. So I was cautious in my comments around our rig count. We're at 43 today. I said we'll be in this area through the third quarter. We could drop down a couple. We're going to defend price, not utilization. So if we have a renewal coming up where somebody wants to keep that rig but cut the price by $5,000 a day, we'll walk away. So I wouldn't be surprised if our rig count were to drift a little lower. but also if it stays flat and this level moves up, that wouldn't surprise me either. How's that for hedging my bets?

I think that covers it off pretty well. Maybe just on the new contracts that you've signed, sounds like given the pricing you've sort of directionally talked about, it sounds like you've been pretty successful despite the increased availability of super spec rigs in the market. You've been fairly successful at getting decent pricing. Now, can you just talk about why that is? Do you get a sense that these rigs are for customers who are drilling net new wells into 2024, or have these rolled off from some other contractor and you've managed to pick them up?

So these are net new wells that we would have been talking to customers about a year ago, last November, December. their 2023 plans they just got pushed back but but i'd say a second part these are also customers who wouldn't be looking at some of the small drillers to do that works we don't see the um you know the small drilling contractors that have a couple of super stack rigs as a competitor these are really going to be focused on the top three or four drilling contractors the customers are looking like i was describing earlier in canada how our customers are shifting away from just pure rate and looking at full value. So I can tell you every one of these rigs that we've contracted has alpha running on the rig from day one. That's an important factor for these customers. They also have our clarity data solutions on these rigs where they want to get high frequency data from us. So these are sophisticated customers looking for a sophisticated drilling program and the leading edge day rates just maybe a little less important than having the digital capabilities and the safety and the support we can provide.

Got it. And one more if I can squeeze it in. It looks like there's in Canada maybe five or so rigs doing direct LNG type of drilling. Now, how much more rig activity do you think is required for the current or to fill the current phase of LNG? Are we kind of there or do we need to see a few more rigs go to work, and is that working its way into your discussions as well?

So it's probably more than five rigs that we have tied to LNG. I think the number might be closer to 15 or 20 if you include everybody who's a partner in LNG Canada that we're drilling for and any other company that's announced LNG exports through the Gulf Coast. So I think it's a larger number. But I can tell you we're adding another rig in January. That's the upgrade we talked about a couple quarters ago. It starts January 1st. I would be surprised if three to five more rigs are not required to satisfy the first two trains of LNG Canada. Now, that work will get done one way or another. If we don't bring rigs out of the U.S. to satisfy that or our competition doesn't do it, there may be some increased tele-double work. But the efficiency gains on a triple, on a three-well pad or larger, are just too hard to argue with. Our customers are still focused on capital efficiency, but that will drive them into the triple direction away from the tele-devils or the larger pads for the LNG-style customers.

Yeah, got it. Thanks very much.

Great. Thank you.

One moment for our next question. Our next question comes from Cole Pereira with Stiefel. Your line is open.

Hi, all. So obviously on the Canada front, the contract is quite the change in behavior from the E&P side. Do you just get the sense that some of the producers are getting very worried about rig availability, just given some of the LNG tailwinds? And can you talk about, you know, the length of some of the contracts that you've recently signed in Canada?

Yeah, cool. Worried might be the wrong word. I think what they're trying to do is ensure they have the same crew, the same rig for a long period of time. So it's a very collaborative effort. I know I've been involved in some of these discussions myself with our customers, but they've been highly collaborative, trying to make sure they can have the same drillers, the same rig managers, have very consistent, predictable operations this year, next year, the year after. Contract durations have ranged from one year to a maximum of three years. The average is probably somewhere between one and two years for the contracts. So I wouldn't say our customers are worried. I'd say they're really focused on making sure they can control their operations with rigs and crews they know and trust and have confidence in.

Got it. Thanks. And on the U.S. side, you talked about some of the publics and super majors getting a bit more active over the next few quarters. How have conversations with some of the private producers been recently acknowledging the fact that the rampant crew, it seems like, has really been just the past week or two?

Yeah, so I think the difference is that the publics we're talking to and that we've been contracting with likely were looking to add rigs earlier in 2023, and that didn't happen. So they had plans ready, and when the price got in the right range for them, they're ready to go quickly. I think that the smaller companies don't do that kind of advanced planning, don't have that kind of structure, and they may wait a little longer and work with their private boards to get through some early cash flow. and then start looking to add rigs.

Got it. That's all for me. Thanks. I'll turn it back.

Great.

Thanks, Cole.

One moment for our next question.

Our next question comes from Kurt Halid with Benchmark. Your line is open.

Hey, good afternoon, everybody.

Hey, Kurt.

So, Kevin, I just wanted to follow on a little bit on the supply-demand dynamics in Canada. You kind of referenced in the call, you know, you think demand is exceeding supply and, you know, that could potentially lead to some rigs moving up from the U.S. to satisfy that demand. So, just kind of curious as you might, you know, give some context around what do you think the shortage of rig capacity is right now in Canada?

yeah uh kurt uh i kind of go back to what i what i know for sure at the beginning of the winter in 2023 we had demand for five rigs that we couldn't satisfy and didn't satisfy we know a couple of those were handled by tele doubles drilling a little less efficiently and then following that um the blueberry resolution happened to bc that seemed to push another three four five rigged demand customers come to us. We actually moved rigs back into BC. That seemed to push things forward. In discussion with clients today, looking forward, it seems like most of that is still out there. And whether that's five rigs or seven rigs, it's a little hard to tell for sure. You know, I do think that will put a bit of a pull on If you look at the basin right now, there's probably already 15 tele-doubles drilling montany wells right now, or there has been historically. Some operators like the lower rig cost, but most operators are drilling medium to larger pads, do the economics pretty quickly and determine that even at a $35,000 or $37,000 a day day rate, a rig that can drill a well 40% faster makes a lot of sense. So I think that map will work its way through the system. I'll be shocked if any rig targeting LNG sales gas is anything less than a triples rig. So, you know, I think five to seven rigs is kind of how we see it, which is why we think we might be pressed to bring one or two rigs up in the U.S. maybe late this year, next year, early next year. Okay. Maybe more.

Okay.

All right. And obviously you gave the economics as to what would incentivize precision to make that happen so it just now comes down to the sense of urgency at the EMP company level uh so we'll have to see how that shakes out um okay so the uh the the other question I had was you know you kind of referenced uh you know some longer term contracts and obviously this is a unique situation um for Canada uh so the question would be you know how many How many precision rigs do you think could be on, you know, three-year type contract if that's the duration, you know, as you kind of look at the needs for the, as the LNG pipelines are coming on? Just kind of, just want to see if this is just a kind of a unique dynamic or if there's a growing, a definitive growing need to lock in rigs for longer term.

You know, we had, we had a number of discussions with customers about two and three-year terms. I would say that we were reluctant to lock in too many rigs in those longer terms because we were still trying to get rates up a little more. And I made the comment that we want to get back to out-earning our cost of capital, which we think is an appropriate thing to do for a business that's so capital intensive like ours. But we still think rates in Canada need to move up a little further. Our customers have worked with us quite well and I'm really pleased with the job that our sales team has done and our customers have accepted increases. Uh, but, uh, but I'm not prepared to walk into these rates for, uh, two or three years down the road.

Yeah. Okay. Sure enough. So, uh, follow up question here on, on the alpha, uh, uh, ads and software and everything else. So it seems like there's definitely a, a growing, uh, market penetration and an adoption rate. What, what, you know, what can you talk to in terms of, you know, the stickiness in, in, in the dynamic of, of the alpha? So.

know once it's on a rig does does an emp company say well again that was kind of a nice little toy but you know i don't need it anymore so it's going to give some perspective on you know what you're getting feedback from the from the emps uh we haven't had any customers turn off alpha uh and stop paying for it they're all renewing contracts paying for it we're on these long-term contracts we signed in canada and the us uh every single rig that we signed on these long-term contracts includes alpha I'll tell you what we're actually really focusing on right now is I think we have a an app library of about 30 apps and Our app utilization has been a little less than we'd like. So we're really focusing now on Working with our customers testing out apps showing them and try to prove the value of each app I think we have a pretty good runway to get wider scale app adoption and over the next few quarters. We've got a number of apps that really help assist drilling performance, drilling consistency, drilling repeatability, even as simple as measuring emissions. And they all make good sense. We just need to do a better job fully proving that value out to our wide customer base.

And remind me, if you may, what's the average rate that you get for deploying these apps on a rig?

If you remember, it's about $1,500 a day for the base system. And then the apps would be anywhere from $200 a day to about $1,000 a day per app.

So it's like almost evolving into a software as a service type of business. Is that fair?

Well, sort of. But remember, what I'd be clear on is we're not selling software. We are selling a drilling operation. And we're trying to really support our ability to drill wells efficiently, safely, consistently, predictability repeatedly. So the software is designed and intended to support that service, not be a product on its own.

Got it. Okay. That's great. Appreciate the color. Great.

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

Thank you, everyone, for joining our conference call today. If you have any follow-up questions, please do not hesitate to contact me. Thank you.

Ladies and gentlemen, this does conclude today's presentation.

You may now disconnect and have a wonderful day. you Thank you. Thank you. Thank you.

Good day and thank you for standing by. Welcome to the Precision Drilling Corporation 2023 second quarter conference call. I would now like to hand the conference over to LaVon Sedunic, Director of Investor Relations. Please go ahead.

Thank you, Operator. Welcome to Precision Drilling's second quarter conference call and webcast. Today, I am joined by Kevin Neveu, Precision's President and CEO, and Carrie Ford, our CFO. Earlier today, we reported our second quarter results. To begin our call today, Kerry will review these results, and then Kevin will provide an operational update and outlook commentary. Once we have 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 CDAR and EDGAR. As a reminder, we express our financial results in Canadian dollars unless otherwise stated. Kerry, over to you.

Thanks, Lavonne. Precision Q2 financial results exceeded our expectations for revenue, adjusted EBITDA earnings, and cash flow. The resiliency of our high-performance, high-value business model, an organizational focus on cash flow and return on capital, drove our financial results and progress in strengthening the balance sheet. We have not yet reached our desired capital structure, but in the middle of 2023, we crossed a few milestones, including total debt below $1 billion, a net debt to TTM EBITDA below two times, well below two times, and cumulative debt reduction of over $1.1 billion since the beginning of 2016. I'll move on to Q2 performance. Adjusted EBITDA of $142 million was driven by healthy drilling activity, improved pricing, and strict cost control, and included a share-based compensation charge of $3 million. Without this charge, adjusted EBITDA would have been $145 million, which compares to a normalized EBITDA of $75 million in Q2 2022, representing an increase of 93%. Margins in the U.S. and Canada were higher than guidance, resulted from stronger than expected pricing and cost recoveries, higher ancillary revenues, and improved cost performance, in addition to $5 million in idle but contracted revenue. In the U.S., drilling activity for precision averaged 51 rigs in Q2, a decrease of nine rigs from the previous quarter. Daily operating margins in Q2, excluding the impacts of turnkey and idle but contracted revenue, were $15,455, an increase of $1,276 from Q1. For Q3, we expect margins to be approximately $15,000. In Canada, drilling activity for precision averaged 42 rigs, an increase of 5 rigs or 12% from Q2 2022. Daily operating margins in the quarter were $12,203, a decrease of $1,355 from Q1 for Q2, sorry, from Q1 2023. For Q3 2023, our daily operating margins are expected to increase by approximately $500 in Q2 levels with improved pricing offsetting rig mix. We continue to build our North American contract book with Q4 2023 drilling rigs under take or pay term contracts increasing 50% in the U.S. and over 60% in Canada versus three months ago. Internationally, drilling activity precision in the current quarter averaged five rigs. International average day rates were $50,551, a decrease of 7% from the prior year due to rig mix. In our C&P segment, adjusted EBITDA this quarter was $8 million, up 55% compared to the prior year quarter. Adjusted EBITDA was positively impacted by a 31% increase in well service hours and improved pricing. C&P results were further supported by Precision's rental business, which has realized an increased demand and utilization for equipment on our super triple rigs for customers in the Montney. Moving into the balance sheet, we are committed to reducing debt by over $500 million between 2022 and 2025 and achieving a normalized leverage level below one times. Our debt reduction target for 2023 is $150 million, and we plan to allocate 10% to 20% of free cash flow before principal payments directly to shareholders. During the quarter, we reduced debt by $178 million and utilized $8 million to repurchase shares. As of June 30th, our long-term debt position net of cash was approximately $940 million, and our total liquidity position was $580 million, excluding letters of credit. Our net debt to trailing 12-month EBITDA ratio is approximately 1.7 times, and our average cost of debt is approximately 7%. We expect our net debt to adjusted EBITDA ratio to be approximately 1.25 to 1.5 times at year end when we expect debt to be below $900 million and our run rate interest expense to be approximately $60 million. Our annual guidance for 2023 includes depreciation of $290 million and SG&A at $90 million before share based compensation expense. Our full year 2023 capital plan remains at $195 million. We expect cash interest expense to be approximately $80 million for the year and cash taxes to remain low with an effective tax rate of approximately 25%. For 2023, we expect share-based compensation expense to range between $20 million and $40 million for the share price range of $60 to $100 in Canadian dollars. The annual share-based compensation accrual could increase or decrease another $15 million based on relative share price performance and a multiple applied between zero and two times. Year-to-date, we have had a recovery and share-based compensation expense of $9 million. With that, I will turn the call over to Kevin.

Thank you, Kerry, and good afternoon. As Kerry highlighted, I am also thrilled with the rapid progress we are achieving against our debt reduction and capital structure objectives. This progress is underpinned by the strong operating cash flows we are producing and should continue to produce. I'm equally thrilled with our recent contracting successes in both the United States and Canadian markets, and more on that in a moment. Now, as some of the listeners may know, Precision has a large employee shareholder base, many of whom listen to our earnings calls. I'd like to recognize and thank every member of the PDE team who are all dedicated to providing the safe, high-value services our customers expect from PDE, while also tightly managing our costs, optimizing our margins, and producing strong operating cash flows to the benefit of all PD shareholders. The results of the hard work achieved the highest second quarter cash flow in the company's history. Bravo to the PVD team. So I'll start with our Canadian segment, which I've been highlighting for several quarters, but really stood out during the seasonally slow second quarter, traditionally known as breakup. The Canadian market for conventional oil and gas drilling has radically transitioned over the past several years, and is perhaps now the best it has been. And by best, I mean the most stable and healthy that I've experienced during my career. No longer is the summer-fall drilling program pinned on the ACO gas price realized in April-May. We now have visibility one, two, and in some cases three years out for Canadian drilling activity. The Trans Mountain project, the Line 3 expansion, and the coastal gasoline pipes are solving the basin takeaway constraints which have hung over the Canadian industry for the past decade. You can look through Precision's customer list and find many directly linked to LNG Canada and others who have recently announced long-term LNG gas sales contracts through the Gulf of Mexico. Precision's Super Triple Fleet, which is fully utilized in Canada, is linked to the global LNG market, not seasonal eco-volatility. And then Western Canada Select Discount is narrowed. And combined with a weak Canadian dollar, our heavy oil and SAGD customers are benefiting with improved cash flows and have returned to the drill bit, resulting in strong demand for our super singles. But probably most importantly, our customers have become adept at operating in a tightly constrained and capital discipline framework. They are not relying on capital market access to fund drilling programs, but are self-funding drilling remaining well inside their cash flows. They have improved focus on balance sheets, and they are operating shareholder focused returns based corporate strategies and this capital discipline has transitioned the way our customers think about drilling they've taken the focus off pure day rates they're focusing on comprehensive overall drilling cost efficiency when they develop their drilling plans for both gas and heavy oil development projects we're experiencing increased demand for pad drilling and seeing increasing pad sizes all aimed at this cost efficiency essentially Pad drilling has become the industry standard and led to full utilization of our padlocking rigs, where we continue to see customer demand exceeding our supply. On larger pads, these rigs can work straight through spring breakup, smoothing our revenues and improving our cost efficiency. This drive for capital efficiency also encourages customer adoption of our alpha digital solutions, and with all but a couple of our super triples running in Canada now operating the alpha system. So currently we have 58 rigs in Canada running, marginally less than we previously guided, and primarily due to just one operator reducing their drilling program. With a stable oil price, the reduced Canadian differentials, and the soon to be commissioned TMX and Coastal GasLink pipelines, our outlook for the second half in Canada remains firm. We expect 100% utilization of both our 29 super triples and our pad super singles, and strong utilization for our remaining 31 super singles, We should see rig activity in the high 60s or low 70s in the third and fourth quarter, setting up for a very strong start to 2024. Notably, during the second quarter, we had 10 long-term ticker pay contracts, with some of those stretching out three years. Most of these were contract renewals with operators seeking to lock in access to those rigs over the longer term. This is another key Canadian market change whereby customers are now committing to contracting rigs on a ticker pay basis, when in prior periods customers would only commit to this take-your-pay style contract when supporting drilling contractor capital investments for upgrades or new builds. This shift significantly stabilizes our activity levels and our financial performance for our Canadian segments. Today, 20 of our 29 Canadian Super Triples are contracted with take-your-pay terms, and we still see customer demand well in excess of our available rig supply. We have said we might consider mobilizing additional rigs to Canada from the DJ Basin or Marcellus. It seems this opportunity may emerge later this year or in 2024. Turning to rates, our leading-edge rates in Canada for our Super Triple 1200s are now approaching the mid-30s for the base rig, while our pad super singles are now in the mid-20s. Alpha Automation is installed and running on approximately 90% of our Canadian Super Triples and continues to deliver solid performance results and meaningful value for our customers. It remains incumbent on precision to continue to manage our costs and improve our day rates as we seek out financial returns exceeding our cost of capital. We've made good progress so far, but we still have a ways to go. Turning to our well servicing business, it performed exceptionally well during the second quarter, despite industry activity lower than last year. The regional diversification we achieved with the high Arctic acquisition supported strong activity levels through breakup, specifically in our thermal operations, which remain a key strategic focus for our well-service team. Our expanded scale has noticeably improved our operating leverage, providing a strong catalyst for free cash flow growth in this business. We are expecting a busy second half of the year, and with industry-wide crewing constraints continuing to limit industry capacity, we believe the outlook for well-servicing looks very good for the second half. Now, in the U.S., as Kerry outlined, our utilization is trending a little lower than we guided, as a result of the weakened natural gas prices and the uncertain oil prices experienced in the first half of the year. However, as Brent and WTI have firmed up over the past few weeks, customer inquiries for oil targeted rigs has accelerated. We recently contracted nine rigs for Q4 and early 2024 startups. If the current oil price range is sustained, perhaps we're in the trough of customer demand with an upward bias later this year in its 2024, where demand is noticeably strengthening. Super spec rig supply remains very tight despite the reduced overall industry activity, and very importantly, pricing discipline remains a common theme among our industry peers. Currently, we have 43 rigs operating and two unpaid standby. Through the first half of this year, we've been prioritizing defending margins over pursuing market share. We've turned down several opportunities with rates below our thresholds, and we'll continue to do so. We do expect our utilization will remain around this level, through the third quarter with upwards trend in the fourth quarter in 2024, as I described earlier. Precision's current leading edge rates are super triple 1500s or in the low to mid 30s with some fully included rig rates approaching $40,000 per day. And those are for customers that are seeking immediate activations. At current quantity price levels, we see super spec rig demand trending towards near full utilization next year. And it appears our customers are also anticipating the same market dynamic, as they are seeking to lock in the best rigs at what appears to be market-leading rates. We are bidding on several contracts that have been awarded contracts with rates in the upper to mid to upper 30s for rigs starting operation later this year and early 2024. And virtually all of our operating rigs in the U.S. have alpha automation, delivering, again, improved customer performance while enhancing our field rates and margins. Now, turning to our evergreen products for a moment, our evergreen solutions continue to generate very strong customer interest. Precision's evergreen solutions are no-nonsense, high-value, cost-saving additions applicable to virtually every PD rig, with the added benefit of reducing GHG emissions. This is a win-win-win project in the very early stages of market penetration. For example, we have 10 battery energy storage systems deployed and expect to add three more before the end of the year. We have several more systems in the final stages of customer approval right now. Customer uptake of our evergreen products has spread from Canada to the DJ Basin and is now expanding with customers in the Permian and Marcellus, also exploring these products. We'll have more to report on the evergreen product line in the coming quarters. And finally, turning to our international business, currently we have six rigs running, as Kerry mentioned, three in Kuwait and three in Saudi Arabia. The final two Kuwait rigs are nearing completion in the recertification process and barring any customer delays, both rigs should be running in the next several weeks. We have five additional idle rigs in the region and continue to pursue interesting opportunities to tender those rigs for several different projects. We will keep you updated on our progress as information becomes available. And that concludes our prepared comments. I will now turn the call back to the operator for questions.

Thank you, ladies and gentlemen. If you have a question or a comment at this time, please press star 11 on your telephone. If your question has been answered, you wish to move yourself from the queue, please press star 11 again. We'll pause for a moment while we compile our Q&A roster.

Our first question comes from Luke LeBlanc with Piper Stanley. Your line is open.

Hey, good afternoon. Kevin, pretty positive comments about the U.S. rigs that are being signed to begin at 4Q. Can you talk about the shape of the U.S. rig count, and do you think 4Q jumpstarts to 24? And then I just wanted to confirm, as you said, super-spec rig demand could be at full utilization next year.

You know, look, we're actually quite surprised by how quickly our customers seem to be ramping up their thinking about 2024. It's primarily oil-based, but we've had Also, I think one or two rigs that look likely to be contracted into gas, primarily in the Marcellus. But just looking at the profile right now, quick influx of lots of inquiries. We've signed the nine contracts we mentioned. Primarily oil, primarily either large cap or kind of IOC style ENPs. They're definitely planning to wrap up activity into 2024. And we're effectively kind of repositioning from the Hainesville into the Permian right now and really shifting our customer mix from what was largely private equity a year ago now to a lot of large cap publics and IOCs in the Permian. And so as we watch that kind of play itself out, if we just look at the inquiries we have today, they'll look like they'll turn into rigs. They're not all for precision, probably for the industry. That's where I'm thinking that over the course of 2024, you could see that super stack rig market fully utilized.

Got it. And then on Canada, you're sold out on super triples and singles, and you talked about moving some from the U.S. What kind of duration can you get on these contracts? I know overall you talked about, you know, seeing one to three years in Canada in terms. Are you towards the higher end to move those from the U.S. to Canada, or how should we think about that?

Well, the way you should think about that is, number one, we want to see the marginal rate in that upper 30s range. So that's really important. And the customer has to pay for that move in addition to the day rate. So whether he signs a two-year contract and pays for it over two years or signs a one-year contract and pays for it over one year, I'm kind of indifferent. But we do want to take or pay contract with fixed days. We want to have some certainty of revenue. We want to have a base rate for that base rig in the upper 30s. And we want the MOB costs fully compensated. paid for by the customer. So I'd say it's a fairly high bar compared to today's market, but the market's evolving quickly.

Yeah, got it. All right, thanks a bunch, Kevin. Great, thank you. One moment for our next question.

Our next question comes from Eric McNeil with TD Cowan. Your line is open.

Hey, everyone. Thanks for taking my questions. Kevin, if there's 27 rigs under contract in the U.S. in Q4, what's the average duration? And if 43 are currently active, can you sort of characterize the remaining 16 or so rigs? I guess I'm wondering, you know, what sort of contract structures are they operating under, assuming well-to-well? Are they up for renewals? Do you have visibility towards continued work? There's obviously always churn, but Just trying to understand how solid the current activity level is in the U.S. today.

Hey, Aaron. This is Kerry. You know, the contract book we've had over, call it the last 18 months, has been anywhere from six months to three years. But up until, I would say, a few weeks ago, the majority of the contract durations were six months. And we've seen... more requests for one- and two-year contracts, and we've recently entered into several one-year contracts. So I think it's turning a little bit longer duration, and we're not really seeing as many customers looking for three or four WAP programs. They're longer-term programs. So I think it's a good indicator of future activity.

And the rigs that are sort of working today, but don't have long-term contracts associated with them.

Yeah, so those will either go into long-term contracts or they're going to switch hands to customers that are more interested in contracts.

And some of those renew on a well-developed basis with the same customer over and over.

Got it. You've highlighted the relative strengths of the Canadian market again this quarter. If we compare a you know, generic or average 1,500 horsepower super triple in the U.S. with a, you know, generic 1,200 horsepower super triple in the Montney, which one's generating a higher rate of return today? And do you expect those rates of return to change at all?

Aaron, that's essentially how we arrived at that upper 30s Canadian rate that rigged in Canada. So our costs in Canada are in Canadian dollars. Our rates are in Canadian dollars. So the operating margin at upper 30s would be about the same that we're achieving in the U.S.

on those rigs, on those 1,200 rigs in the DJ basin.

Makes sense. I'll turn it back. Makes sense.

Thank you. One moment for our next question.

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

Thank you. Kevin of Cary, the IBC revenues in Q3, would those still be around that $5 million, $6 million mark?

It would probably be one or two rigs. I don't know if it would be that high, but it would be one or two rigs that we have on IBC.

And how many rigs were in Q2?

For IBC. Yeah, I think we had two rigs.

Oh, you had two rigs as well. Okay. All right. And then, you know, so if you look at the U.S. clean kind of day rate or revenue per day in Q2, roughly around $34,400. And the leading edge mentioned is in the low, you know, $30,000 to mid-30s. Is the leading edge in line with where the revenue number is, or is it below what your revenue per day was for Q2?

I think we've got a couple things going on here. We have a little bit of softness going into Q3, continue from Q2, and then we're seeing strengthening in Q4. So if you're talking about going back to Kevin's opening comments about where the leading edge rate is for Q4 and Q1, bookings, we've got some rigs that are pricing as high as $40,000 all in. So that is one leading edge rate. And then if we're talking about where we've been quoting leading edge rates for the last three months, I would say we've been saying kind of low to mid 30s. And we reported day rates of a little over $35,000 a day in Q2. So they're kind of in line, I think, in this market.

Okay. So the $15,000 a day margin guidance for Q3, is that kind of the new floor or there is potential for margins to decline further into Q4 and Q1?

Well, part of what we have going into Q3 is just a little bit lower activity. So we have some more fixed cost absorption. We have fewer rigs varying the same similar fixed costs. So that's part of the margin squeeze. And then if we see more demand and higher rates in Q4 and Q1, we'll see the margins go back up.

Wow, that's pretty good.

And in terms of incremental demand in the Middle East, How do you see that? When do you expect maybe – you still have about five rigs idle in the Middle East in international markets. How many could go back to work and over what timeframe?

Yeah, I'm going to be a little vague on the guidance there, Lukar. We've got active bids for silver rigs right now. I'd say that the most likely rig to go back to work first would be the one other rig in Kuwait. And it may go back to work in Kuwait or Saudi Arabia. It's essentially an AC super spec style rig in a 2000 horsepower size. But I wouldn't expect that rig to be activated before the beginning of next year, the earliest. And we've been participating in a number of other tenders in the Middle East. throughout several countries that just keep sort of getting punted down the road or delayed or slow played. So it's really hard to assess what the national oil companies' thinking are around reactivating these tenders and turning those tenders into contracts.

And so let's assume that you win a contract for a rig. From the day of announcement to the day that they're on revenues, Is it like a six-month lag or less or more?

It would be in the three- to six-month range, and it would just depend on how much recertification work we'd have to do and what their schedule was. They generally think about these things in that anywhere from three months to one year, depending on the tender.

And what kind of incremental capex may be required to activate those rigs?

Well, it could be as little as a few million, like maybe eight to ten million, or it could be as much as $20 to $25 million, depending on the scope of work we have to do to meet the standard. But the day rates would be designed to recapture that capital within the first operating year of the contract.

Great. Thank you very much. This is all very helpful. Great.

Thanks, Makar. One moment for our next question. Our next question comes from Keith Mackey with RBC Capital Markets.

Your line is open.

Hi, good afternoon. I just wanted to start out. Many have been trying to, of course, kind of call the bottom on the U.S. rig count and determine where it ultimately goes from there. Now, Kevin, from your prepared comments and in some of the, of course, Q&A sessions, It sounds like you believe that we are close to there, given the comment around super spec utilization being fully utilized in the U.S. through 2024. But can you just maybe give us a bit more clarity on why you think that the... A, how close we are to the bottom in the U.S. rig count in terms of activity for the industry, and then B... What gives you really the confidence? What are the two or three factors that you think will lead that rig count to ultimately be, or the super spec rigs to ultimately be near at full utilization?

Keith, that's actually a very complex question, so I'll do my best here, and maybe, Kerry, you can pipe in too if you have any more thoughts. So what I'm sure of is that Q2 wasn't the bottom. I'm sure of that. What I'm also sure of is that about 90 days after the bottom, you look back and say, yep, for sure that was the bottom. So there's a lot of uncertainty around trying to call it in advance. I think what we're looking at right now is we saw this surge of inquiries come in when the oil price stabilized. We've got commodity prices looking pretty good today. I mean, we need to see a month or two or three of this to be really confident. But it does seem like the problem wasn't $72 crude or $74 crude. The problem was WTI dropping into the 60s and coming back out of the 60s. That uncertainty held back plans that have been in place even late last year to add rigs. I mean, the inquiries we're looking at today were ones that we were actually contemplating back in November, December of last year. Now they've come to fruition that the price seems to have stabilized. So certainly the market's feeling better than it did even just a few weeks ago. It would be hard to imagine that in a world of $75, $80 WTI, but the rig count goes down much further. So I was cautious in my comments around our rig count. We're at 43 today. I said we'll be in this area through the third quarter. We could drop down a couple. We're going to defend price, not utilization. So if we have a renewal coming up where somebody wants to keep that rig but cut the price by $5,000 a day, we'll walk away. So I wouldn't be surprised if our rig count were to drift a little lower. but also if it stays flat and this level moves up, that wouldn't surprise me either. How's that for hedging my bets?

I think that covers it off pretty well. Maybe just on the new contracts that you've signed, sounds like given the pricing you've sort of directionally talked about, it sounds like you've been pretty successful despite the increased availability of super spec rigs in the market. You've been fairly successful at getting decent pricing. Now, can you just talk about why that is? Do you get a sense that these rigs are for customers who are drilling net new wells into 2024, or have these rolled off from some other contractor and you've managed to pick them up?

So these are net new wells that we would have been talking to customers about a year ago, last November, December. there are 2023 plans they just got pushed back but but i'd say a second part these are also customers who wouldn't be looking at some of the small drillers to do that works we don't see the um you know the small drilling contractors that have a couple of super spec rigs as a competitor these are really going to be focused on the top three or four drilling contractors the customers are looking like i was describing earlier in canada how our customers are shifting away from just pure rate and looking at full value. So I can tell you every one of these rigs that we've contracted has alpha running on the rig from day one. That's an important factor for these customers. They also have our clarity data solutions on these rigs where they want to get high frequency data from us. So these are sophisticated customers looking for a sophisticated drilling program and the leading edge day rates just maybe a little less important than having the digital capabilities and the safety and the support we can provide.

Got it. And one more if I can squeeze it in. It looks like there's, in Canada, maybe five or so rigs doing direct LNG type of drilling. Now, how much more rig activity do you think is required for the current or to fill the current phase of LNG? Are we kind of there or do we need to see a few more rigs go to work, and is that working its way into your discussions as well?

So it's probably more than five rigs that we have tied to LNG. I think the number might be closer to 15 or 20 if you include everybody who's a partner in LNG Canada that we're drilling for and any other company that's announced LNG exports through the Gulf Coast. So I think it's a larger number. But I can tell you we're adding another rig in January. That's the upgrade we talked about a couple quarters ago. It starts January 1st. I would be surprised if three to five more rigs are not required to satisfy the first two trains of LNG Canada. Now, that work will get done one way or another. If we don't bring rigs out of the U.S. to satisfy that or our competition doesn't do it, there may be some increased tele-double work. But the efficiency gains on a triple, on a three-well pad or larger, are just too hard to argue with. Our customers are still focused on capital efficiency, but that will drive them into the triple direction away from the Deli Devils or the larger pads for the LNG style customers.

Yeah, got it.

Thanks very much.

Great. Thank you.

One moment for our next question. Our next question comes from Cole Pereira with Stiefel.

Your line is open.

Hi all. So obviously on the Canada front, the contract is quite the change in behavior from the E&P side. You just get the sense that some of the producers are getting very worried about rig availability, just given some of the LNG tailwinds. And can you talk about, you know, the length of some of the contracts that you've recently signed in Canada?

Yeah, cool. Worried might be the wrong word. I think what they're trying to do is ensure they have the same crew, the same rig for a long period of time. So it's a very collaborative effort. I know I've been involved in some of these discussions myself with our customers, but they've been highly collaborative, trying to make sure they can have the same drillers, the same rig managers, have very consistent, predictable operations this year, next year, the year after. Contract durations have ranged from one year to a maximum of three years. The average is probably somewhere between one and two years for the contracts. So I wouldn't say our customers are worried. I'd say they're really focused on making sure they can control their operations with rigs and crews they know and trust and have confidence in.

Got it. Thanks. And on the U.S. side, you talked about some of the publics and super majors getting a bit more active over the next few quarters. How have conversations with some of the private producers been recently acknowledging the fact that the rampant crew, it seems like, has really been just the past week or two?

Yeah, so I think the difference is that the public we're talking to and that we've been contracting with likely were looking to add rigs earlier in 2023, and that didn't happen. So they have plans ready. And when the price got in the right range for them, they're ready to go quickly. I think that the smaller companies don't do that kind of advanced planning, don't have that kind of structure. And they may wait a little longer and work with their private boards to get through some early cash flow. bumps and then start looking to add rigs.

Got it. That's all for me. Thanks. I'll turn it back.

Great.

Thanks, Cole.

One moment for our next question. Our next question comes from Kurt Halid with Benchmark.

Your line is open.

Hey, good afternoon, everybody.

Hey, Kurt.

So Kevin, yeah, I just wanted to follow on a little bit on the supply-demand dynamics in Canada. You kind of referenced in the call, you know, you think demand is exceeding supply and, you know, that could potentially lead to some rigs moving up from the U.S. to satisfy that demand. So, just kind of curious as you might, you know, give some context around what do you think the shortage of rig capacity is right now in Canada?

yeah uh kurt uh i kind of go back to what i what i know for sure at the beginning of the winter in 2023 we had demand for five rigs that we couldn't satisfy and didn't satisfy we know a couple of those were handled by tele doubles drilling a little less efficiently and then following that um the blueberry resolution happened to bc that seemed to push another three four five rig demand customers come to us. We actually moved rigs back into BC. That seemed to push things forward. In discussion with clients today, looking forward, it seems like most of that is still out there. And whether that's five rigs or seven rigs, it's a little hard to tell for sure. You know, I do think that will put a bit of a pull on If you look at the basin right now, there's probably already 15 tele-doubles drilling montany wells right now, or there has been historically. Some operators, like the lower rig cost, most operators are drilling medium to larger pads, do the economics pretty quickly and determine that even at a $35,000 or $37,000 a day day rate, a rig that can drill a well 40% faster makes a lot of sense. So I think that map will work its way through the system. I'll be shocked if any rig targeting LNG sales gas is anything less than a triples rig. So I think five to seven rigs is kind of how we see it, which is why we think we might be pressed to bring one or two rigs up in the U.S. maybe late this year, next year, early next year. And maybe more.

Okay.

All right. And obviously you gave the economics as to what would incentivize precision to make that happen. So it just now comes down to the sense of urgency at the EMP company level. So we'll have to see how that shakes out. Okay, so the the other question I had was, you know, you kind of referenced, you know, some longer term contracts. And obviously, this is a unique situation for Canada. So the question would be, you know, how many How many precision rigs do you think could be on, you know, three-year type contract if that's the duration, you know, as you kind of look at the needs for the, as the LNG pipelines are coming on? It's kind of, I just want to see if this is just a kind of a unique dynamic or if there's a growing, a definitive growing need to lock in rigs for longer term.

You know, we had, we had a number of discussions with customers about two and three-year terms. I would say that we were reluctant to lock in too many rigs in those longer terms because we were still trying to get rates up a little more. And I made the comment that we want to get back to earning our cost of capital, which we think is an appropriate thing to do for a business that's so capital intensive like ours. But we still think rates in Canada need to move up a little further. Our customers have worked with us quite well and I'm really pleased with the job that our sales team has done and our customers have accepted increases. But I'm not prepared to walk into these rates for two or three years down the road.

Yeah.

Okay.

Sure enough. So follow-up question here on the alpha apps and software and everything else. So it seems like there's definitely a growing market penetration and adoption rate. What can you talk to in terms of the stickiness in the dynamic of the alpha? You know, once it's on a rig, does an E&P company say, well, you know, that was kind of a nice little toy, but, you know, I don't need it anymore. So it's going to give some perspective on, you know, what you're getting feedback from the E&Ps.

Kurt, we haven't had any customers turn off Alpha and stop paying for it. They're all renewing contracts, paying for it. We're on these long-term contracts we've signed in Canada and the U.S. Every single rig that we've signed on these long-term contracts includes Alpha. I'll tell you what we're actually really focusing on right now is I think we have a an app library of about 30 apps and Our app utilization has been a little less than we'd like. So we're really focusing now on Working with our customers testing out apps showing them and try to prove the value of each app I think we have a pretty good runway to get wider scale app adoption and over the next few quarters. We've got a number of apps that really help assist drilling performance, drilling consistency, drilling repeatability, even as simple as measuring emissions. And they all make good sense. We just need to do a better job fully proving that value out to our wide customer base.

And remind me, if you may, what's the average rate that you get for deploying these apps on a rig?

If you remember, it's about $1,500 a day for the base system. And then the apps would be anywhere from $200 a day to about $1,000 a day per app.

So it's like almost evolving into a software as a service type of business. Is that fair?

Well, sort of. But remember, what I'd be clear on is we're not selling software. We are selling a drilling operation. And we're trying to really support our ability to drill wells efficiently, safely, consistently, predictability repeatedly. So the software is designed and intended to support that service, not be a product on its own.

Got it. Okay, that's great. Appreciate the call.

Great. Thanks, Kurt. And I'm not showing any further questions at this time. I'd like to turn the call back over to LeVon.

Thank you, everyone, for joining our conference call today. If you have any follow-up questions, please do not hesitate to contact me. Thank you.

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