Precision Drilling Corporation [PDS] Conference call transcript for 2022 q1
2022-04-30 14:23:05
Fiscal: 2022 q1
Operator: Good day and thank you for standing by. Welcome to the Precision Drilling Corporation 2022 First Quarter Results Conference Call and Webcast. At this time, all participants are in a listen-only mode. After the speakers' presentation, there will be a question and answer session. Please be advised that today's conference is being recorded. I would now like to hand the conference over to your speaker today, Carey Ford, Senior Vice President and Chief Financial Officer. Please go ahead.
Carey Ford: Thanks, Shannon, and good afternoon. Welcome to Precision Drilling's first quarter 2022 earnings conference call and webcast. Participating with me today is Kevin Neveu, President and Chief Executive Officer. Precision reported its first quarter results through a press release earlier this morning. Please note that the financial results are in Canadian dollars unless otherwise indicated. Also, please note some of our comments today will refer to non-IFRS financial measures and will include forward-looking statements regarding Precision's future results and prospects, which are subject to a number of risks and uncertainties. Please see our news release and other regulatory filings for more information on financial measures, forward-looking statements and risk factors. Prior to Kevin providing an operational outlook and update, I will review our first quarter financial results. Our first quarter results reflect a very good start to the year with increasing activity, day rates and margins and leading-edge indicators pointing to even stronger financial results in the second half of the year. Although the first quarter business performance improved dramatically from the first quarter 2021, our adjusted EBITDA of $37 million decreased 32% from the first quarter 2021. The decrease in adjusted EBITDA primarily results from a $48 million share-based compensation accrual charge without which adjusted EBITDA would have been $84 million. Revenue was $351 million, an increase of 49% from Q1 2021. In the U.S., drilling activity for Precision averaged 51 rigs in Q1, an increase of six rigs from Q4. And daily operating margins in the quarter, absent any turnkey or idle-but-contracted impact were US$5,672 essentially flat from Q4 2021. The normalized margins are slightly lower than the guidance provided due to additional staffing of rigs to build hot crews and start-up costs during the quarter. For Q2, we expect normalized margins to increase approximately $1,500 per day. With repricing of spot market rigs, improved fixed cost absorption and technology pull-through, we expect normalized margins to continue expanding through the second half of the year. In Canada, drilling activity for Precision averaged 63 rigs, an increase of 21 rigs from Q1 2021. Daily operating margins in the quarter were $8,865, an increase of $759 from Q1 2021 and $881 sequentially. Higher than guided margins were supported by higher day rates, strict cost control and greater fixed cost absorption, absent the CEWS impact from the prior year, margins would have been approximately $2,000 a day higher than Q1. For Q2, we expect margins absent of CEWS and onetime cost recoveries to be up approximately $500 per day compared with last year due to improved pricing and fixed cost absorption. For reference, daily operating margins in Q2 2021, absent CEWS and onetime recoveries were $5,247. Internationally, drilling activity for Precision in the current quarter averaged six rigs. International average day rates were US$50,235 approximately US$2,500 lower than the prior year due to expiration of drilling contracts. In our C&P segment, adjusted EBITDA this quarter was $6.5 million, down 16% compared to the prior year quarter. Adjusted EBITDA was positively impacted by 9.6% increase in well service hours and improved pricing, reflecting improved industry activity and higher demand for our services. But the results for 2022 included zero CEWS subsidy payments compared to approximately $2 million in Q1 of last year. Of note, well abandonment work represented 16% of our operating hours in the quarter. Capital expenditures for the quarter were $36 million, and our full year 2022 guidance has increased from $98 million to $125 million, comprised of $72 million for sustaining and infrastructure and $53 million for upgrade and expansion, which relates to anticipated contracted rig upgrades and investments supporting Alpha Technologies. As of April 28, we had an average of 41 contracts in hand for the second quarter and an average of 39 contracts for the full year 2021. We have signed 27 term contracts year-to-date. Moving to the balance sheet. While our Q1 results reflect negative cash flow and a revolver draw, the second quarter working capital unwind and revolver pay down is happening in real time, and we expect to pay down the majority of Q1 through revolver draw by this summer. As of March 31, our long-term debt position net of cash was approximately $1.2 billion, and our total liquidity position was over $430 million, excluding letters of credit. Our net debt to trailing 12-month EBITDA ratio is approximately 6.7x and average cost of debt is 6.3%. We expect our net debt to adjusted EBITDA before share-based compensation expense to be closer to 3x by year-end and to decline further into 2023 toward our goal of below 1.5x. We remain in compliance with all of our credit facility covenants in the first quarter with an EBITDA to interest coverage ratio of 2.7x. We are committed to reducing debt by over $400 million between 2022 and 2025 and allocating 10% to 20% of free cash flow before principal payments directly to shareholders. Our debt reduction target for 2022 is $75 million. For 2022, we expect to generate free cash flow through operations and expect to benefit from working capital release in Q2 with lower activity during Canadian spring breakup and to catch up with customer collections. From year-end 2021 to year-end 2022, we expect working capital to build by approximately $50 million or $40 million lower than the bill we incurred in Q1. Our guidance for 2022 remains the same for depreciation of approximately $270 million and SG&A at $65 million to $75 million -- to $70 million before share-based compensation expense. We expect cash interest expense to be approximately $80 million for the year and cash taxes to remain low with our effective tax rate to be approximately 5%. That concludes my opening comments. I'll hand the call over to Kevin.
Kevin Neveu: Thank you, Carey, and good afternoon. As Carey mentioned earlier, customer demand for our high-performance high-value services is strong and continues to grow. We're seeing this strength in all our business segments in all our geographies. Our fleet utilization continues to improve and the rates we charge for our services are likewise responding. This is most evident in the lower 48 with the tightening supply of Super Triple rigs became apparent to our customers and led to a step change in rig rates late in the quarter. Leading-edge rates, excluding Alpha for our ST-1500 rigs equipped to drill long reach horizontal wells have trended into the low US$30,000 per day range, and customers have been willing to sign term contracts at these higher rates to secure access to the rigs over the course of the next 6 to 12 months and in some cases, longer. There's no question that the customers have a rising sense of urgency is to expect high-spec rig shortages later this year. Since our last conference call, we've added 19 term contracts with a handful of those signed most recently the leading-edge rates I mentioned earlier. Today, we have 55 rigs operating in the United States, up from 48 at the beginning of the year. With our contracted rig activations and further ongoing customer negotiations, we see a path to continue this growth trajectory through the year and our visibility into 2023 is taking shape. Turning to Canada. For the first quarter, we experienced strong customer demand matching 2018 activity levels. Importantly, our customers extended the winter drilling program as well into the traditional spring breakup period, driving first quarter activity up almost 50% from last year. Even today in the midst of spring breakup, we have 33 rigs operating compared to 21 this time last year, continuing the trend. Our customer discussions and bookings point to a strong second half, which will be starting almost a month early with several rig activations scheduled for as soon as the first week of May and ramping up from there. We expect Q3 activity will surpass the winter season for only the second time in memory, and this will be the busiest second half since 2014. As I mentioned in our Q1 call, customer demand for rigs in the heavy oil play known as the Clearwater in Marten Hills is gaining momentum. We see strong demand for Precision's unique Super Single rig and particularly our pad walking Super Singles, which we expect to be fully utilized this summer and through the fall. SAGD and other conventional heavy oil demand is also strong and will drive our Super Single utilization to its highest level since 2014. And I'll remind you that our Canadian fleet includes 55 Super Single rigs. Our Canadian pad equipped Super Triples are also fully booked for the balance of the year as the Montney and Deep Basin natural gas activity remains strong. While we see some rigs -- did see some rigs relocate from the BC side to Alberta due to the Blueberry First Nations ruling, we have indications from our customers that BC could see rig activity rebound later this year, and it's next to putting further demand on the Super Triples. This is a very tight market with a strong customer demand and limited rig supply. In Canada, we began the process of implementing cost and price increases over a year ago, but customer resistance has been challenging. For many of our customers' rate discussions we are having today, after several years of weak industry demand is uncharted territory. These customer pricing discussions are continuing as we seek to reprice rigs for the second half of 2022. During the first quarter, we rejected several opportunities to reactivate rigs due to lower-than-desired customer rate expectations. The best pricing signal we can send to our customers is rejecting work at rates below our required thresholds. Over the last dozen years in Canada, Precision has invested in 28 Super Triple rigs, 25 Super Singles rigs and our $40 million Nisku technology center with a fully functioning advanced technology training rig. We've clipped those Super Triple rigs with AlphaAutomation. We trained over 50 Alpha expert drillers and 30 Alpha expert rig managers. With these assets, technologies and people, Precision delivers the safest, fastest, most cost-effective and best quality wells our Canadian customers have ever drilled. The value proposition we offer today is vastly better than any prior rebound cycle, and I fully expect to generate the returns from these investments that our investors deserve. In Kuwait and Saudi Arabia, we also see a rapidly improving market. As I mentioned in the press release, all three active rigs in Saudi Arabia have been renewed for a five-year period with pricing and margins consistent with the prior contract. In Kuwait, the rig tender we have been anticipating for several months was released late in the first quarter. This will be a typically extended process involving several months of tendering and contracting steps. The tender includes requirements for several classes of rigs in multiple quantities. Our three idle Kuwait super-spec rigs perfectly meet the complex requirements of the deep drilling rig classes and believe we'll have an excellent opportunity to contract our idle rigs for activation later this year. However, the rig deployment timing will be fully dependent on our customer's scheduling. Precision's technology offerings, including Alpha Digital Solutions had a recently introduced EverGreen environmental solutions continue to demonstrate strong customer appeal. Over half our Super Triples are now equipped to the AlphaAutomation and all Alpha rigs currently deployed are earning commercial revenues. Precision's app library continues to grow with 18 commercial apps and our Alpha optimization of advisory service gaining a strong customer following. Precision's EverGreen battery energy storage system and our fuel and emissions monitoring app are both commercially deployed on several rigs, and we expect these products will continue to gain broad customer appeal as our customers look to reduce GHG emissions. Interestingly, several EverGreen product solutions have a negative green cost premium and that the energy cost savings generated utilizing the EverGreen solution exceeds the price premium we charge, a highly favorable outcome for an energy transition solution. This, of course, encourages our customers to continue down the path to net zero. We mentioned in our press release, the deployment to an EverGreen electric grid-powered rig to the Ithaca campus of Cornell University. This is an exciting geothermal project to explore the opportunity for Earth Source Heat as a zero emissions heating source for the Cornell University. We're thrilled to be part of this DOE-funded project and look forward to helping derisk the zero emission energy opportunity. Precision's well servicing segment continued the pace that began last year with strong first quarter activity, up 8% from last year over the same period. And with 28 service rigs operating today, we're continuing this trend. Our team is very effectively managing the material cost inflation and fuel cost increases we've experienced. However, the labor challenge has proven much more difficult and is limiting industry well service activity. During the first quarter alone, we experienced demand anywhere from 10 to 20 rigs greater than our ability to grew rigs. We have substantially increased our recruiting efforts and with the recently announced hourly labor rate increases, we expect to narrow the rig supply gap as the year progresses. Overall, this business is performing exceedingly well. Our teams worked well to increase rig rates appropriately, and we expect to continue to generate strong cash flows. So I'll conclude by thanking all the employees of Precision Drilling for their hard work, their strong safety performance and excellent results they produced for our stakeholders. I'll now turn the call back to the operator for questions.
Operator: Our first question comes from Taylor Zurcher with Tudor, Pickering, Holt.
Taylor Zurcher: Kevin and Carey, first one is on the pricing within the U.S. market. Kevin, I think I heard you say leading-edge rates for some of the higher-end rigs in the low 30s, excluding Alpha, so add Alpha and you're getting pretty close to the mid-30s on a leading-edge basis. And man, what a difference a couple of years makes. But my question is, if -- against that pricing backdrop, assuming the market stays tight through 2023, which it likely will, is there any reason why your fleet in the U.S. isn't generating mid-teens type daily margins, excluding turnkey and other lumpy items at some point in 2023?
Carey Ford: Taylor, so this is Carey. I'd say that you could see a portion of the fleet generate that type of margin. But remember that our operating costs have moved up about $2,000 to $2,500 per day. So the $30,000 or $31,000 or $32,000 day rate up today is similar to a $28,000 or $29,000 day rate from 2018, which is where we saw the day rates get to kind of the last up cycle. When you tack on AlphaAutomation, you would be getting to margins kind of in the low to mid-teens.
Taylor Zurcher: Okay. Got it. And I had a follow-up in the -- go ahead.
Kevin Neveu: Just add to that for a moment. I think that it's -- we don't expect day rates to stabilize in this raise. We think if the supply stays tight, repricing opportunities as the year progresses, could rates move further up.
Taylor Zurcher: Well, that's encouraging. Okay. And a follow-up there, Carey, you're talking a little bit about the cost structure. In the press release, you were talking about how you've oversized some crews to prepare for the activity ramp here in 2022. And I'm just curious, I mean, as I look at it, it sounds like those crew sizes will probably naturally go back to more normalized levels moving forward as more rigs go back to work, such that what's been a cost headwind for you over the past couple of quarters might turn the other way. I'm just curious if I'm reading that correctly.
Carey Ford: It will turn the other way, but I want to stress the magnitude of it. We guided to a $500 a day increase in margins from Q4 to Q1 in the U.S., and we delivered flat margins and the reason why was about half of that would have been the over crewing of rigs. We call trying to create hot crews and the other half of that would have been just start-up costs. We activated three or four rigs in Q1, and we experienced start-up costs in the $200,000 to $250,000 per rig. So I think it will not having those extra crew members will reduce operating costs a little bit, but it's just going to be a couple of hundred bucks a day.
Operator: Our next question comes from Aaron MacNeil with TD Securities.
Aaron MacNeil: I know the 1500s always seem to attract the headlines, but there's been a good pickup in some of the U.S. plays that is historically been well suited for the 1200 horsepower triple. So I'm wondering if you could maybe just give us a sense of how utilization and pricing has trended for that asset class.
Kevin Neveu: Aaron, it's Kevin. The trend on those rigs is kind of similar to the 1500s, recognizing it's a little less expensive rig to operate, little smaller rig. So it's trending along the same direction, not quite as tight on the supply side as the 1500s. So we're not getting -- we're not seeing day rates that are approaching 30,000 yet, but we're certainly getting into that mid-20s range for those rigs, which we're pretty happy with. And most of those rigs also have Alpha on top and the opportunity to add Alpha, if we don't have the Alpha right now.
Carey Ford: Yes. I think the utilization of those rigs, we've got 18 in our fleet, and I believe we've got about 12 working right now. So we're moving up into that 70% to 80% utilization level, which will give us more pricing power over time.
Kevin Neveu: Aaron, I was going to remind you that we did bring one of those rigs up to Canada last year when the market was looking pretty strong in Canada. I'm not sure we do that again. I think that they'll put -- the opportunities in the U.S. might look better over time. Certainly, when you factor in the exchange rates and the rates in the U.S. right now, I think that we could see those rigs fully utilized later this year.
Aaron MacNeil: Okay. Understood. I certainly noted the comments on the 19 new contracts, leading-edge day rates and durations of, I think you said 6 to 12 months, Kevin. But with rates where they are, I mean, doesn't the conversations start to turn to whether you can lock in those high prices into longer-term contracts? Or do you have to have a major upgrade to a multiyear contract?
Kevin Neveu: I'd say that there's still a fair amount of caution kind of on all sides of the energy industry right now. Not wanting to get over our , not wanting to commit to too much. While we do have some customers looking out beyond 12 months, we've signed a couple of contracts beyond 12 months. I'd say that there's still a fair amount of just care and caution around, again, not making huge capital commitment, it's not making a huge contract commitments that might extend out kind of too far in the future. So I just read it as capital discipline is still quite important across the E&P space and certainly it is for us. And that certainly is holding back customers from contracting into years where their budgets aren't approved yet.
Aaron MacNeil: Okay. Understood. Maybe if you'll indulge me, I'll sneak one more in. I can appreciate that there might be some reluctance to reverse course on your capital allocation framework that you announced in January, but stocks nearly doubled since that time. So I guess the question is, would it not make more sense to just continue to focus on debt reduction for the time being?
Carey Ford: Yes. So Aaron, I think we put a four-year capital allocation plan in place so that we have a little bit of flexibility to manage through the cycles, both with needs for cash like we experienced in the first quarter when we're building working capital and spending some CapEx. And then also to where we can kind of pick and choose our times to buy back shares. So we're -- as we said on the press release and my opening comments, that plan is in place. We will continue to execute on that plan, but it's not going to be the same capital allocation every quarter over the next four years.
Operator: Our next question comes from Waqar Syed with ATB.
Waqar Syed: Kevin, you announced some developments on the geothermal front and one of your competitors also announced today some investments in geothermal. It could be a coincidence or is there some acceleration in geothermal developments that you're seeing? Or is it still kind of the same kind of growth rate? Just want to see whether there's something going on behind the scene of acceleration in demand for geothermal.
Kevin Neveu: Certainly, I think that 2022 will be much busier than 2021 on geothermal front, and probably '23 is going to be busier than '22. So I mean we're in a world which is putting a lot of capital towards energy transition write-down. I think geothermal is one of those solutions is going to be part of the energy transition mix. So short answer is certainly rising levels of interest, nothing remotely close to displacing rig activity on the oil and gas side yet. But I think having involvement in these projects is important. It's important from showing we're doing our part perspective, but it's also important because I think there will be some solutions here. And I'm a big believer that this -- that using geothermal just for heat, not for power conversion or for steam, but using it as a heating source might be an economic solution. So we're quite excited about this Ithaca project I mentioned on campus.
Waqar Syed: Okay. And then in the U.S., maybe you expect your active rig count to be by the end of the year?
Kevin Neveu: Waqar, a little hard to say, but if you kind of project forward the growth we've had so far, we'd be probably getting close to 60 by the end of the second quarter, maybe hitting 60, maybe not quite hitting 60. And I could see us with what I see right now today, probably having that go up by another five rigs a quarter for the second half of the year. Assuming the customer interest we see today remains and the macro stays in place, and I hate to have to qualify every forecast these days, but it seems like comment on the forecast, there's some major macro change.
Waqar Syed: Yes. Yes. And in terms of your operating cost, labor cost and all, do you see upward pressures still going forward? Do you think for this year, at least, you've captured the inflation from labor perspective?
Kevin Neveu: I would say, be right. I'd say that between kind of rising absorption as we get more rigs active, and I think are kind of leveling probably of our crew salaries and things like that. We might have seen the peak of inflation. It might be managed under control at this point. Carey, do you have any comments there?
Carey Ford: Just that if there are further wage increases in the year, they'll be passed through within the contract.
Kevin Neveu: I think the one thing that really kind of helps the drilling industry out is that in the drilling industry, we're not building and don't plan to build, don't see any opportunity and any reason to even think about building new rigs. But if there is a build cycle going on, that would cause all kinds of supply chain issues. But we're just operating a rig fleet, which is still operating at activity levels lower than most of the past 10 years. So the supply chains are pretty good. I think inflation is under control. I don't see a lot of things that rise right now. They're going to impact rig operations in a meaningful way. Now if we're wrong, we'll be, again, pushing prices upwards. I think we already -- we've got a contract book that allows us, gives us flexibility to reprice rigs and whatever the market cost is at the time.
Waqar Syed: So yes, to the same, let me ask you on that. Like in terms of getting engines or mud pumps, things like that, for reactivation or just for replacement on existing fleets, you're not seeing any issues at all in getting that? And what kind of inflation are you seeing on equipment?
Kevin Neveu: So I haven't actually checked the price of a new engine recently, and I know Caterpillar, one of the largest suppliers is suffering some inflation. And unless we get into some kind of major upgrade program, I just don't see us out there buying large numbers of engines. I think that we've got a fleet of rigs right now that in this environment and what we see going forward, that our normal maintenance procedures and repairs and upgrades on engines will handle within our current inventories. On the mud front, if we were to upgrade five more rigs, that's five mud pumps extra drop in the bucket.
Operator: Our next question comes from John Gibson with BMO Capital Markets.
John Gibson: Just in terms of leading-edge rates. I'm just wondering how do they compare to prior peaks? And then maybe if you could walk through how cost compared as well. I guess what I'm trying to get at is net-net out profitable or leading-edge rates right now relative to prior upturns. And I guess, where could they get to moving forward?
Kevin Neveu: Carey, why don't you start, and I'll just come and bind.
Carey Ford: Yes. Sure. So I think when we had prior peaks and, call it, 2014 or 2018 or 2017, 2018, rigs got to $28,000 or $29,000 a day. And so you had an operating cost of right around $14,000 in those time periods. You had a 50% field margin. Right now, operating costs with wage increases and a little bit higher cost of operating the rig, operating costs are going to be at a $16,000 to 16,500. So if you're assuming a 50% margin, you're going to be at $32,000, $33,000 a day. So I think that's -- they're comparable. The top line looks a lot different. But on the margin, from a dollar standpoint, they're pretty comparable and from a margin percentage standpoint, they're almost exactly comparable.
John Gibson: I guess moving forward then if we do see a bit of a bump in rates, is it fair to assume that you could get above that 50% fuel margin or see even significantly above it?
Kevin Neveu: I think it's possible. I think when you -- technology and some of the things that will move outside the contract or have already moved outside the contract, I think margins are going to have a little bit more runway. What I would say is that I think we've hit these rates quite early. And the market has changed from the last peak. It's changed in that -- really the only rigs that are going to be drilling on these types of large development type pads are going to be super-spec rigs. So you're not seeing any drag from non-super-spec rigs on the rates. Back in 2014, it wasn't a perfect market when it came to super-spec today it is.
John Gibson: Fair enough. And last one for me. Last call, you talked about having somewhere in the range of 200 bid request in the U.S. So if we fast forward a few months, obviously, the world has changed. What are bidding inquiries like today in the U.S.? And then have these bid requests largely translated into new rig additions better or worse than you expected a few months ago?
Carey Ford: So this is a non-GAAP metric. I say that jokingly. The bid book hasn't declined in size. And I'd say that the hit rate is starting to increase modestly.
Operator: Our next question comes from Cole Pereira with Stifel.
Cole Pereira: Just wanted to go back to day rates from a spot market versus contract perspective. And so at a high level, so for example, if leading-edge day rates are US$30,000 a day in the spot market right now, I mean, is there sort of a rule or anything or how we should be thinking about what it would pay to contract that rig for six months or something like that? I'm just trying to think about the discount between the spot and locking in rigs.
Kevin Neveu: Cole, I think that there is really zero discount from a strategy standpoint with our pricing. There might be a discount tied to a customer that got multiple rigs or they were with us back in 2020 when it was quite slow. But from a conversion of spot to term, I wouldn't view that as a reason to discount price to our customer.
Cole Pereira: Okay. Perfect. No, that's helpful. And maybe coming back to some of the questions about 2023 revenue per day in margin. So I mean if drilling fleeting edge day rates stay in the low $30,000 a day, I mean, as you get some of the churn through your contracting, is it reasonable to think we could see that reported day rate hit $30,000 a day sometime in 2023? Or would it probably be high 20s? I know you don't give guidance. I'm just trying to sort of feel out the differences there.
Kevin Neveu: So I'll make a couple of comments and let Carey kind of pipe in whenever he wants to here. But I'd say that I do expect most rigs of this class to be trending into that range as they reprice over time. And so we won't get a full price in every single repricing opportunity. There are certain reasons why we might do it one or two steps over a period of time. But I do think that if you're looking at a year out from now, I'd expect the leading-edge rates probably will have moved up. And the average rate will have moved up quite a bit. And so it's likely you could see the average rate in the $30,000 range and leading rates could be higher than that yet. The momentum on rates hasn't really backed off yet because we're into a real tight phase with rigs right now.
Cole Pereira: Okay. Great. That's helpful. So what's the comment -- go ahead.
Kevin Neveu: To add a couple of comments to that. I think that the term I'm going to use for Precision, I think you'll hear it from most of the public drillers are that we are extremely disciplined around our capital returns right now, whether it's investing in an upgrade on the rig or whether it's trying to get the returns for the rigs we have right now that are already out there in the field. But I think the discipline that we're seeing in the marketplace right now is likely the best I've seen in my career, which it's almost 40 years now. And you've got large public drillers in both markets, Canada and the U.S., that are highly focused on generating returns for their shareholders as our customers have been. And I think their discipline is not going to weaken as time goes forward. It's going to firm up.
Carey Ford: Yes. And I would just add maybe what's causing a little bit of uncertainty of where the race will stop when they rise is the replacement cost of these rigs is much higher today than what they were originally built for. So the rates that made the economics go around and when the rig was built wouldn't work today if you're going to try to build a new rig. It's with kind of the infrastructure to build new rigs not really being in place and commodity price inflation and labor inflation, the replacement cost would just be significantly higher than it would have been in 2014 and '15.
Cole Pereira: Okay. Great. That makes sense. And turning to drill pipe. I mean, a lot of commentary from some of your peers on that, talking about one-year lead times. I mean, just sort of curiosity, how much, call it, months of inventory do you typically keep on hand?
Kevin Neveu: You might recall that last conference call we talked about a drill pipe order replaced last August. And we just had a bit of a sense of the shortage or tightness market coming. We certainly didn't expect what's been the tragedy that's been going on in the Ukraine right now and that is impacting steel. But we did get ahead of this a bit. We did make a large purchase last year of inventory drill pipe. So there's zero lead time on that. We took delivery of that in the third and fourth quarter of last year. As we began taking those deliveries, we placed additional orders in the fourth quarter. We placed additional orders for pipe in the first and second quarter of this year. So we think we're dancing kind of ahead of that one-year lead time that you've heard about -- talked about in some other calls over the last few days. And I think that we've got the pipe we need to run our business.
Cole Pereira: Okay. Great. That's helpful. And just out of curiosity, I mean, any instances in whether in Canada or the U.S. where you've seen the inability of an E&P to get casing impact any of your drilling operations?
Kevin Neveu: Cole, we have. We've seen that mainly with small operators that are kind of drilling well to well and not able to plan or buy in volume. With the larger players who, like us, have been placed orders in advance and had a sense of these things coming, we have not seen that creep up. We have a small turnkey business, which is part of our disclosure this period, and we see some of the challenges getting casing. Typically, what we're drilling in turnkey tends to be bigger bore wells, deeper gas wells in the Gulf Coast region, where the shortages are a little less pronounced in the common -- more common sizes being used for oil and gas right now.
Cole Pereira: Okay. Got it. So if I wanted to qualify your comments, fair to say that certain customers are having that issue, but it's not material at a larger scale. Is that fair?
Kevin Neveu: Certainly, not material on a larger scale for our activity right now. It could be plus or minus one rig. And that could grow. I mean we don't have the visibility on what our customers are buying for casing. But I'd also say that I think it's going to be short-lived. I think that there's an opportunity here for the pipe companies to get things fired up to make probably some pretty good margins. And while there might be a lag of a couple of quarters, I think we'll catch up.
Operator: Our next question comes from Keith MacKey with RBC Capital Markets.
Keith MacKey: I just wanted to, Kevin, go back to some of your comments about Canada shaping up to be the second -- the busiest second half since 2014, though customers are still trying to grind you on rates, it sounds like. Can you just maybe walk through how the discussions are going? What realities you are kind of trying to bring into the conversation with customers? And then what that ultimately means do you think for your second half cash margins? I know the rig mix is quite a bit different than it would have been in 2014, but you would have had much higher cash margins back in those days. So maybe a lot to unpack there, but any commentary on that would be helpful.
Kevin Neveu: Sure, Keith. And it's actually a pretty insightful question. Our customers have worked really hard over the past several years in Canada going back to 2014 to really fine tune their cost structure to become as efficient as they become. They've gotten -- they've taken the whole notion of capital discipline deep to heart, and they've restructured their businesses to deliver capital discipline to their investors. And part of that was getting very aggressive on the costing side, getting very aggressive on the contracting side and institutionalizing that. And they've done a great job with that, and their investors should be very proud of their work the E&Ps have done managing their costs. Well, they've done that in an environment where rig demand was weak and often declining. So managing that capital discipline in a market where rig demand is increasing. And in fact, in some areas, rig demand exceeds supply. I think it's something they need to get up to speed on. And we're trying to help them up to speed on that. We're certainly working to demonstrate the efficiency of the rigs. I kind of went through a litany of the things we've done since that last cycle around improving our rigs with super stack rigs, with Alpha on the rigs and training our guys to run it and execute it very well. There's no question. We're delivering a much better value proposition than we were back in that previous peak. And I think it's our job to help our customers understand that and recognize they need to pay more for it. So you've got these two competing forces. We've invested the rigs in our people and have a higher value proposition. They've worked really hard to lower their costs and manage down in a very soft market. And ultimately, market dynamics play out here and supply and demand works, and I expect rates will move up.
Keith MacKey: Got it. No, that's helpful. And then just secondly, turning to the U.S. If you talk about 60-ish rigs by the end of Q2 and then adding five per quarter in the second half, would you expect your maybe basin mix in the U.S. to stay roughly the same? Or can you see that changing from current levels if we think about those as 45-or-so percent Permian, maybe 25% Haynesville and then I know there's some Northeast in there, which is maybe a little bit more constrained takeaway capacity wise than some of the other areas. But just curious if you can help us kind of walk through where you expect to see some of those rig additions.
Kevin Neveu: I'd say probably focused more towards oil, more towards the Permian. But quite surprisingly, one of the contracts we've signed recently includes customer paying for mobilization of a rig from -- Carey, remind me, the rigs coming out of...
Carey Ford: I think it's Wyoming.
Kevin Neveu: Wyoming and Colorado and moving back to the Marcellus. That's an expensive move. And you couple that move cost with the day rates that we're able to achieve right now, and that's a pretty meaningful move back to the Marcellus. So I'm surprised by that, but we do see a lot of strength in the Permian.
Carey Ford: Yes. We've also seen a few more rig contracts signed recently for the Eagle Ford.
Kevin Neveu: Yes.
Keith MacKey: Got it. Very good. And just finally, maybe circling back to one of the other questions. How protected are you from a standby fee perspective or anything like that? If your -- if rigs see delays that are caused by customer supply chain issues, is that -- is there fees written into the contracts that kind of give you some protection? Or has the market not been there?
Kevin Neveu: On every term contract rig Canada or U.S., they're take-or-pay contracts. So either they take it and use it or else they pay us down by feet. If it's a well to well rig, once that well completes, then it might be looking for work somewhere else.
Operator: Our next question comes from Josef Schachter with Schachter Energy.
Josef Schachter: Carey, you mentioned replacement costs of the rigs are much higher. Can you -- if you're doing a Super Triple with all the Alpha products hooked up, what would be the cost to create a new rig right now? Just to get an idea of where that number has to go to.
Carey Ford: Yes. So we haven't priced this out. We -- but I can tell you what it was in 2014 and '15. So we were building Super Triple 1500 AC rigs for about $20 million. And then over the next few years, we started upgrading them with walking systems and higher pumping capacity, higher racking capacity, AlphaAutomation. So you probably get to a $25 million asset in those 2014 and 2015 dollars. You can look at what's happened with wages and copper prices and steel prices over the time -- over the last seven or eight years and then also look at the fact that we're building 20 rigs a year during that time period. So we really had an assembly line style process to construct these rigs. And those assembly lines and supply chains just aren't there. So it's not going to be 20% or 30% higher. It's going to be significantly higher than it would have been back in 2014 and 2015.
Josef Schachter: Are we looking at US$40 million or more?
Kevin Neveu: It could be in that price range. It feels we were back into a production build cycle. We might save a few percentage points, but you're not going to take kind of a $40 million rate and make it $30 million by running back into production. It's going to be a lot more expensive. I think you're thinking about it the right way.
Josef Schachter: Yes. So if you take a rig that's parked right now and upgrade it to meet the standards that are needed in the Permian or the Montney, are we talking about $5 million, $10 million? What would be the kind of number would be? And how long would it take to take a rig from the different part and get it ready to be used in the industry?
Kevin Neveu: Josef, we have about 12 to 15 rigs that we call -- we call them Super Triples, but they're not AC Super Triples, they're DC SCR Super Triples. So they've got a lot of the features we have on our Super Triples, but they have a kind of an analog power system, which is referred to as SCR rig. To convert those to digital AC rigs and capture all the other bells and whistles, probably in the $10 million range, maybe US$10 million to US$12 million for those rigs. So we could convert some of our DC SCR Super Triples to AC digital Super Triples, probably on the average of around $10 million to $12 million per rig.
Carey Ford: But there's a limited number though.
Kevin Neveu: Yes, we have 12 of those are in U.S. fleet.
Josef Schachter: Okay. So if we're looking at -- with more optimism that, as you mentioned earlier, the lead rates and the states are getting into the 30s. And if you might need to have more money for CapEx, wouldn't it be something -- again, I'm going to count to -- I've gone through these cycles. Wouldn't it be -- given the stock has gone up 10x or 12x from the low of two years ago, wouldn't it make sense to raise some equity here 2 million to 3 million shares, gets sort of a pristine strong balance sheet and then have the ability to talk to the customers saying, look, you want us to build your rig, you got to pay us and they'll see that they can't beat you up because you have such a strong balance sheet.
Carey Ford: Yes. I would say that we see no need to raise equity mainly because we've got all the assets that we need. We talk about one of our priorities this year is maximizing operating leverage and that's getting all the assets we have to work and pushing day rates on those. That's where we see the biggest growth in EBITDA for our business. And then when we look at the cash flow of the business, the outlook for second half of this year and into 2023, cash flows are going to be very strong and can fund any kind of CapEx needs that we think that will come before us, along with paying down debt and repurchasing shares. So I think that for the funding needs, the business will fund itself. And in terms of needing to build any new rigs, we don't see a need to do that. And the day rates required, if we're talking about a build cost being significantly higher, the day rates would need to be maybe 30% higher than where leading-edge rates are today. So I don't think the market is right. The market isn't there to fund -- the day rates are not high enough to economically fund a new build. So we don't think that we'll see any in the industry for a period of time.
Josef Schachter: Okay. And last one for me. There's been a nice -- you got the nice pickup in the margin in Canada, as you mentioned, $8,865, up from $8,106 a year ago and $8,013 in Q4. Do you see Canada getting to $10,000 earlier margin in Canadian dollars and of course, to see US$10,000, Canada reaching a $10,000 number before the U.S.?
Carey Ford: It's certainly possible for both markets by late this year, early next year. That's hard to say. Canada is closer now. But as the rig mix, we've got all of our Super Triples fully utilized. We've got rates going up on that segment of the fleet, but then we'll be reactivating a lot more Super Singles and the margins there are just a little bit lower than the Super Triple. So we'll see how that mix plays out. But I think they're both on track to reach those margin levels, both the U.S. and Canada.
Operator: And I'm currently showing no further question at this time. I'd like to turn the call back over to Carey Ford for closing remarks.
Carey Ford: Thank you, everybody, for joining our Q1 2022 conference call. Appreciate your time today, and we look forward to talking to you again in July.
Operator: This concludes today's conference call. Thank you for participating. You may now disconnect.
