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spk15: Good day and thank you for standing by. Welcome to the Precision Drilling Corporation 2023 Fourth Quarter Near-End Results Conference Call. I would now like to hand the conference over to LaVon Zdunic, Director of Investor Relations. Please go ahead.
spk11: Thank you and welcome to Precision's Fourth Quarter Earnings Conference Call and Webcast. Participating on today's call with me will be Kevin Neveu, our President and CEO, and Carrie Ford, our CFO. Earlier today, we reported strong fourth quarter results, which Kerry will review with you, followed by an operational update and outlook commentary from Kevin. Once we have finished our prepared comments, we will open the call to questions. Some of our comments today will refer to non-IFRS financial measures and will include forward-looking statements, 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. As a reminder, we express our financial results in Canadian dollars unless otherwise indicated. With that, I'll pass it over to Kerry.
spk10: Thanks, LaVon, and good afternoon. Precision's annual financial results show continued improvement from 2022 and reflect the focus on the 2023 strategic priorities that Kevin will address in his commentary. Annual highlights include revenue of $1.9 billion, a 20% annual increase, adjusted EBITDA of $611 million, a 96% increase, funds from operations of $533 million, an 89% increase, cash from operations of $501 million, a 111% increase, debt production of $152 million, and a $30 million of share repurchases while funding two acquisitions with cash or assumption of debt totaling approximately $100 million. and positive earnings per share every quarter during 2023 and for the past six consecutive quarters. In 2023, we closed the CWC acquisition on November 8th, and the Precision team has aggressively worked with our new colleagues at CWC to integrate the business to begin realizing synergies, including consolidating facilities, reducing administrative costs, and utilizing Precision's tech centers and supply stores to support the field. To date, we have achieved $12 million of the projected $20 million of annual synergies and expect to achieve most of the remainder in the first half of 2024. Moving on to our fourth quarter results, our fourth quarter adjusted EBITDA of $151 million included a share-based compensation charge of $13 million and transaction and severance charges of $6 million. Absent these charges, adjusted EBITDA would have been $170 million. In the U.S., drilling activity per precision averaged 45 rigs in Q4, an increase of four rigs from Q3 driven in part by the addition of acquired CWC rigs. Daily operating margins in the quarter absent impacts of IBC and turnkey were 11,802 USD in line with our guidance of 11,500 USD to 12,000 USD and consistent with Q3 levels. IBC revenue for the fourth quarter was 1,633 U.S. dollars per day, and for Q1, we expect minimal IBC revenue and normalized margins to range between 9,000 USD and 10,000 USD. The decrease in margins is mainly due to overhead costs spread over fewer activity days compared to Q4. In Canada, drilling activity for precision averaged 64 rigs, a decrease of two rigs from Q4 2022. Daily operating margins in the quarter were $15,740, an increase of approximately $1,800 from Q3 2023, and in line with our guidance of margins above $15,000 per day. For Q1, we expect margins to remain above $15,000 per day. Internationally, drilling activity for precision in the quarter averaged eight rigs and average day rates were 49,872 USD in line with the prior year. We expect 2024 activity levels will increase by approximately 40% over 2023 levels. I will remind the audience that capital expenditures in the international segment are typically lumpy with high CapEx at the front end of projects and lower normalized levels in subsequent years. For 2023, With recertification costs for the four Kuwait rig contracts and a bulk drill pipe purchase order for the region, international capital expenditures were over $50 million. For 2024, we expect capital expenditures to significantly decrease to normalized maintenance levels. In our C&P segment, adjusted EBITDA this quarter was $12 million, flat with our prior year quarter. Adjusted EBITDA was positively impacted by a 15% increase in well-service hours, reflecting partial impact of the CWC service rig acquisition. We expect results will improve in Q1 with increased rates and activity, the absence of Q4 transaction-related cost, and the realization of transaction synergies. Capital expenditures for the quarter were $79 million, and for the year, $227 million. Our capital expenditures were slightly higher than our guidance of $215 million due to timing of equipment deliveries. Our 2024 capital plan is $195 million and is comprised of $155 million for sustaining an infrastructure and $40 million for contracted upgrades and expansion. Sustaining an infrastructure CapEx of $155 million includes $40 million of long lead items. And I'd like to take a moment to comment on the strategic decision to purchase these long lead items because I believe it exemplifies Precision's ability to leverage our scale to reduce costs while positioning the company for growth opportunities. Due to our standardized fleet high activity levels across a broad geographic footprint and a mature supply chain function with core vendor relationships, we achieved a bulk purchase discount on these items and plan to utilize the equipment in either the US or Canadian fleet for potential upgrades or as critical spares. This also ties in with daily operating costs, which have increased for us and our peers over the past three years. The wage increases for our crews have been earned and well-deserved, and as a result, they are largely here to stay. Although the field labor portion of our daily operating costs is sticky, opportunities to lower costs exist. Identifying these opportunities and realizing cost savings has been and will remain a key focus area for the finance team, and we are working hand in hand with our operations, technology, supply chain, and equipment maintenance teams to reduce inflationary pressures, optimize equipment performance, and produce a lower and less volatile cost structure in the future. Moving to our contract book, as of February 5th, we had an average of 52 contracts in hand for the first quarter and an average of 43 contracts for the full year 2023. We now have 21 rigs on contract in Canada for 2024, reflecting an increasing number of customers seeking to lock up rigs ahead of LNG project startups. Moving into the balance sheet, As of December 31st, our long-term debt position net of cash was approximately $880 million, and our total liquidity position was over $600 million, excluding letters of credit. Our net debt to trailing 12-month EBITDA ratio is approximately 1.4 times, a decrease from 3.4 times at the end of 2022. Our average cost of debt is 7%. We plan to reduce debt by $150 million to $200 million in 2024 and have increased our long-term debt reduction goal from $500 million to $600 million between 2022 and 2026. As of December 31st, 2023, we have reduced debt by $258 million and have $342 million additional reduction necessary over the next three years to reach our goal. We began reducing debt in 2016 and every year we have provided guidance we have met or exceeded our targets. To date, we have had only a modest allocation of free cash flow for share repurchases. But as we approach our target debt levels of below one times, we are confident in our ability to increase our allocation to direct shareholder payments as a percentage of free cash flow. We plan to allocate 25% to 35% of free cash flow before debt repayments for share repurchases, and we'll expect to continue increasing this allocation in future years moving towards a target allocation of 50% of free cash flow before debt repayments by 2026. Moving on to guidance for 2024, we expect strong free cash flow for the year, but Q1 cash flow to be impacted by front-end loaded capex, a working capital build, our semi-annual interest payment, and year-end payments. We expect depreciation of approximately $290 million, cash interest expense of approximately $75 million, Cash taxes to remain low and our effective tax rate to be approximately 25%. SG&A of approximately $100 million before share-based compensation expense. And we expect share-based compensation charges for the year to range between $45 million and $55 million at an $80 share price. And the range may change based on the share price and the performance of precision stock relative to precision's peer group. Please note this is a preliminary estimate and we will provide updated guidance on our Q1 call following the settlement of past grants and issuance of new grants later this quarter. With that, I will hand the call over to Kevin.
spk19: Thank you, Kerry. Good afternoon. Well, we are very pleased with the strong fourth quarter and full year financial results and operational results delivered by the Precision team in 2023. As Kerry mentioned, the progress achieved over the past several years, improving our balance sheet, reducing our debt levels, while growing our revenue and cash flows positioned us with the financial flexibility to execute on a number of opportunistic financial actions to further enhance shareholder value. And Kerry described a few of those. Utilizing our strong free cash flow, we met or exceeded all of our financial priorities for the year, including debt reduction share buybacks. We completed two consolidated transactions. We invested in our fleet with high return projects for the Middle East, United States and Canada. Those investments included alpha technology expansion, evergreen emissions reductions projects, along with several rig capability upgrades and the reactivation of the rigs in Kuwait. So beginning with our international segment, in the fourth quarter, as Kerry mentioned, we reactivated our fifth rig in Kuwait on a five-year contract. This rig, combined with the four other rigs in Kuwait and our three operating rigs in the Kingdom of Saudi Arabia, will increase our activity in 2024 by 40% over 2023. With our well-established international infrastructure already generating strong returns, we expect this increased activity to flow through our income statement with essentially no increases in our fixed costs or overhead. And despite the recent announcements from the Kingdom of Saudi Arabia regarding capping oil production, we do expect further bidding activity and possible land rig additions targeting unconventional gas, in addition to those recently announced by other industry participants. We have one idle super triple rig in Kuwait and four other idle rigs in the region. In Kuwait, we have active bids for the idle rig and believe we have a high likelihood of contracting this rig in 2024. And we continue to bid on other international rig tenders in the region and believe we can support regional new country entries from our established base in Dubai. I believe we're well positioned to grow this business segment as the international land drilling industry continues to recover. Turning to the lower 48, we continue to work to expand our presence in oil basins and with the public E&P operators particularly. This has been a little more challenging than we expected as US rig activity has been essentially flat for several months with very few new rig deployment opportunities. There continues to be some contract churn and some operator high grading and our team has been tightly focused on those limited opportunities. However, it's important to understand the customer rig switching costs, which I've discussed in the past, When an operator decides to replace an existing rig for whatever reason, they usually need to pay a demobilization cost for the current rig and then mobilize the replacement rig. This mobilization or switching cost can reach anywhere from several hundred thousand dollars to over a million dollars, depending on the drilling locations and the proximity to the contractor's operating base. In addition to those hard mobilization costs, Your operator will have to be a little patient as the high graded rig and new crew come up the learning curve in that specific operator's practice. This switching cost coupled with the very firm drilling contractor market discipline we've seen over the past few years has meant that both rig rates and rig contracts tend to be stickier than most other OFS services. It also means that even for those of us pursuing the high grading opportunities, the drilling contractor may need to be very creative with initial day rates, escalation parameters, or performance incentives to catalyze those high grading opportunities. Our team has been successful sustaining our activity in the low 40s over the past couple of quarters. I do note a mistake on the Precision website earlier today, which posted Precision's U.S. activity at 37. It actually is 39 rigs as of today, and the website error has been corrected. That said, I'm not thrilled with 39 rigs running. With the pace of current customer bids, recently signed contracts, and planned activations, we expect we'll be back in the low 40s in the coming weeks. We expect to see our activity modestly increase further during the second quarter. Visibility beyond the next few months is a little less clear, but we continue to see positive leading indicators, including customer inquiries, LNG export project startups, exhausted ducks in the Permian, and an increasing focus on drilling inventory quality, and of course, the desire for longer reach laterals. We expect these factors will help to catalyze upgrading and high grading growth opportunities, particularly for our super triples with our alpha automation capabilities. No doubt we have some work to do as we continue to expand our presence in the oil plays while remaining well positioned for an improving gas macro. In our Canadian drilling and our well services businesses both delivered strong operational and financial performance throughout 2023 and are carrying that momentum on into 2024. Now for most of the last decade, the Canadian market has been constrained by hydrocarbon takeaway bottlenecks and constraints. As a result, the discount for Western Canada select oil has ranged in the $25 to $40 below WTI range. While the Alberta natural gas commodity price, ACO, has been a function of highly cyclic seasonal weather patterns and regional market energy needs, also limited by bottlenecks and takeaway capacity. Now I think most of us know that later this year, two major transmission projects, the Trans Mountain oil pipe and the Coastal GasLink natural gas pipe will begin full operation and serve to fully alleviate the Canadian constraints. WCS discounts are expected to moderate to high single-digit discounts, and LNG Canada exposes Canadian natural gas to the global LNG market. Our customers, the Canadian oil and gas operators, remain among the most disciplined E&P group in the world, yet they fully understand the long-term implications of this transformation Canadian market. We expect they will thoughtfully and carefully align their capital programs and balance their rig and well servicing demands to track the takeaway capacity of the market while continuing to generate stable cash flows and most importantly funding their shareholder return programs. This lays out a long-term thesis for the Canadian OFS market fundamentally supported by global energy prices with no constraints. Those Canadian oil and gas operators will remain highly disciplined and will utilize large-scale multi-well pad drilling programs where efficiency, safety, industrial scale, technology, and digital capabilities will define the development model. This also explains Precision's current market positioning in the Montigny and heavy oil plays and aligns perfectly with our strategy over the past several years. We can look back to the introduction of our Super Triple Rig last decade the introduction of our alpha automation system five years ago, and more recently, our evergreen emissions reduction solution just two years ago. These rig technology advancements enable large-scale optimized pad-style oil and gas developments perfectly. We also commissioned our 30th super triple rig in Canada earlier this quarter, and as we discussed on prior calls, this is a highly upgraded rig to full super triple capacity. The rig is equipped with a full suite of alpha automation, alpha apps, It's got our alpha clarity optimization system and a full suite of evergreen environmental solutions, easily making this the most advanced technology land rig in the world today. Oh, and one more item. The rig is equipped with three fully automated robotic arms to handle rig floor and racking board pipe handling operations. Now this is the first fully automated deployment of the NOV Atom racking board and rig floor robotic system. And in partnership with NOV and our customer, This is a fully functional and commercial deployment. While we believe we still have some modest field hardening work over the coming weeks, this is essentially a bolt-on robotic upgrade that we can install in any precision super triple rig to fully de-man the red zones on the rig floor in the pipe racking area and the racking board. I believe there is much more to come on this over the next few months, and we'll continue to update you. Today, we are operating 80 drilling rigs in Canada, which includes the recently acquired CWC Tele-Double rigs. Now, the Canadian Tele-Double drilling market remains oversaturated and highly fractured. Too many rigs, too many contractors, and the competition is intense. Now, precision scale, our highly skilled crews, vertical integration, and a procurement advantage allows us to improve the returns that CWC achieved on these rigs while we remain a price competitive and relative participant in this rig class. While precision is unlikely to be a further consolidator in this segment, it's our view that consolidation and rationalization in the tele-doubles rig market is essential for the long-term benefit of all stakeholders. Precision super triples that are pad-equipped super singles remain generally sold out, with customers increasingly locking in access to these highly capable rigs and crews with firm take-or-pay contract commitments. For comparison purposes, In the first quarter of 2021, nine Canadian Super Series rigs were contracted with take-or-pay term contracts. In 2022, this increased from nine rigs in 21 to 19 rigs. And now for the first quarter of this year, 24 rigs are contracted on firm take-or-pay terms, significant shift in the market. And this transformation towards take-or-pay term contracts improves our revenue visibility, it improves crude performance and stability, and it keeps those rigs off the market, supporting tight supply fundamentals for the non-contracted rigs. Looking forward, we expect to run 40 to 45 rigs throughout the spring, and then quickly ramp back up into the mid-60s during the summer, and again, higher levels closer this year in the fall, preparing for winter next year. Longer term, through the end of this year into next, it appears the rig demand will remain firm and likely tighten up further as the pipelines commence full operations. Our Alpha and Evergreen products, both in Canada and the US, continue to demonstrate broad market penetration. Our customers recognize the efficiency that Alpha delivers, with now 96% of our active super triple rigs running Alpha automation and Alpha apps. Our experience on automated drilling is growing quickly over 20 million feet and now for our Canadian analysts that's 6.1 million meters drilled with ELPHA in 2023 up 43 percent in 2022 despite the noted decline in U.S. drilling activity. Late last year we introduced a new tool face control app for directional drilling and since we've drilled 43 wells with over 3,000 autonomous slide sequences fully proven the value of the SAP to further automate the drilling processes now approaching 98% of the sequences being automated. Our evergreen emission solutions have strong customer support with currently 65% of our active super triple rigs currently running at least one evergreen system and customer commitments now booked to add evergreen solutions to a total of at least 90% of the super triple rigs as soon as we can install the systems. I remind you that these solutions include battery energy storage systems, diesel fuel and emissions monitoring apps, grid power connection systems, low emission lighting systems, and blended natural gas fuel systems. Our strategy to deploy products which provide meaningful reduction in rig emissions while reducing our customers' fuel costs and providing a solid investment for return for precision is a no-nonsense emissions reduction strategy. And I certainly wish that our government policymakers would take a similar approach to their policies on the emissions challenge. We believe both alpha and evergreen will be important as we look to continue strengthening our market presence in the U.S., Canada, and the international regions. Turning to our well service business in Canada, the integration of the CWC rigs and personnel was the key focus in the fourth quarter. And working their way through the synergies was a strong result for the combined team. Our well-serviced activity remained firm through the fourth quarter, and this has carried on the momentum into 2024. Now, we experienced a roller coaster of weather, first losing activity in mid-January due to extremely cold weather conditions in Western Canada, and then things turned too warm, causing some intermittent road bans, and with the unusually warm weather in late January, making some well locations inaccessible, again, negatively impacting the activity. Yet the combined business is performing very well. Today we're operating 83 service rigs with 11 of those on 24-hour operations, doubling the asset's revenue efficiency. Later this month, it looks like our activity will break past 100 operating rigs. Customer demand remains firm. And the outlook for the balance of the year looks good with a strong Canadian macro supporting customer activity. So turning to our strategic priorities. As we reported in our press release, we achieved all of our 2023 priorities, and we posted Precision's 2024 priorities. We believe it's important that our investors understand exactly how we intend to create shareholder value, and we'll continue to provide that quarterly update on our progress. I can also report that the feedback from our investors continues to be highly positive. Investors tell us they appreciate the transparency, and they ask us to please keep doing what we say we're going to do. So with that in mind, you can see from our longer-term guidance, we're shifting our priority towards increasing capital returns to shareholders while continuing to reduce debt, but with a more balanced approach. Over the next several years, we believe this will deliver very good shareholder returns. So on that note, I'll conclude by again thanking the people at Precision Drilling for their dedication, their hard work, the great safety results, and the great operating results in 2023. We look forward to a good year in 2024. I'll now turn the call Back to the operator for questions.
spk15: Thank you, ladies and gentlemen. If you have a question or 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 Aaron McNeil with TD Cowan. Your line is open.
spk05: Afternoon. I'm hoping for a bit more detail on the US Q1 margin guide. I guess I'm just wondering, you know, approximately how much of that sequential change is a function of higher costs, how much is downward pressure on price, and how much is a function of rig mix and the seasonal return of those CWC rigs? And I guess another adjacent question would be, do you see that you know, pressure persisting into subsequent quarters absent, you know, an uptick in activity.
spk07: Yeah, Aaron, this is Kerry here.
spk10: I'd say it's a combination of all of those. The one that we think has the biggest impact is the operating cost and just the fact that we were running 45 breaks on average in Q4 and we're going, you know, likely going to be running A lower number than that. We've got a bit more fixed cost with the CWC acquisition. And so it is going to be a little bit of a drag on margins in Q1.
spk08: And as we get activity a bit higher in the second quarter, we think that margins have an opportunity to expand.
spk05: Got it. You mentioned the Kuwait tender. You know, what's a realistic deployment timeline if you get that work? Or, you know, deployment timelines for other international rigs? that may not have as clear of a tender opportunity.
spk19: Aaron, good question. Certainly, even the bid cycles time can be measured in months and quarters, not necessarily days or weeks like we see in North America. The Quaid tender right now is actually in process. We've been through a couple of rounds of clarifications. If their prior history is an indication, I'd expect the awards could come within a quarter, maybe a little more, maybe a little less, with deployments occurring before the end of the year. Got it.
spk05: And what would the associated capex be for that if you were to win an award?
spk19: Yeah, it's not currently part of our plan, but it would likely be in the same range that we've had in the past, somewhere between probably $3 million to $8 million per rig, depending on the clarifications we're going through right now. Great. Thank you, Aaron.
spk15: Our next question comes from Kurt Haleed with Benchmark. Your line is open.
spk02: Hey, good afternoon. How's everybody doing?
spk19: Good, Kurt.
spk02: Okay, good. Appreciate the updates, as always. So I'm kind of curious on the coming back full circle on the Canadian market. You referenced, you know, contracted rates, you know, 24 in the first quarter, 23. I don't know, Kevin, where do you think that could go, you know, as we progress through the year? I know you and I have had discussions about, you know, E&P companies wanting to lock in rates, you know, for the export capacity, especially around LNG. So, I don't know. What's your best guess of where you think it might be able to go?
spk19: Yeah, you know, this has happened actually quite quickly, you know, just looking at the trajectory of contracting. I can tell you that we were a little surprised last year, like early 2023, to hear customers willing to take or pay contracts for long-term, be it one to two to three years, when historically in Canada, long-term contracts simply didn't exist. So now to have a book of a couple of dozen long-term contracts starting this year off is a great place to start. Kurt, it would be logical that any operator that's tied to a long-term LNG delivery contract would lock in rigs for a long term. And by long term, I mean two, three years. It starts looking much more like an industrialized process where you're trying to maintain consistency, predictability, repeatability over a long haul, and then using all your digital capabilities at lower cost. So I think to answer your question, I think once those projects start running, and once we see gas flowing, and once we see our customers become more comfortable with the long term nature of their supply contracts, I'd be surprised if the majority of the LNG rigs weren't tied to term ticker pay contracts in the range of two to four years.
spk02: Okay. I appreciate that. A follow-up question. Again, in the past, you thought it's good to see the adoption on the alpha automation and alpha apps. Can you give us an update as to what the incremental cash margin is on adding those apps to the rig?
spk10: Yeah, Kurt. So it's going to be on the bottom end, it's going to be about $1,500 a day. And then with apps and evergreen solutions, we've got rigs that are making closer to $4,000 a day with all of the additional ancillary products and services.
spk02: Okay. And then you referenced 75% of your rigs had some sort of, or your super triples had some sort of alpha apps on it. Is that evenly split between the U.S. and Canada?
spk19: Let me qualify that. So I think I said 95% of our rigs have alpha on. Okay. And I think I said 75% of our rigs have evergreen solutions on. And yeah, it's evenly split. Both are evenly split between both markets. I might also add that on evergreen, I've been quite surprised by the uptake in the US. There's maybe a little less environmental focus due to the lack of a carbon tax. but good customer take-up on both sides of the border, all due to the value we create through fuel savings.
spk02: Great. All right. Thanks, Kevin. Thanks, Kerry.
spk15: Thank you. Our next question comes from Luke LeBlanc with Piper Sandler. Your line is open. Hey, good morning.
spk03: Kevin, you kind of loosely touched on it with Kurt's question, but you've previously mentioned maybe moving some idle U.S. rigs to Canada. Could you just update us on that, maybe how you're thinking about industry and criminal demand in Canada shaping up with the Trans Mountain Pipeline expansion and Coastal Gas Link?
spk19: Yeah. Luke, you know, it's interesting. There's supply and demand forces pulling opposite directions. No question, the E&P base in Canada, United States, you know, Kuwait, anywhere, would rather see the market oversupplied. And I understand that. because they want to have oversupplied rig supply so that that keeps rates as low as possible. We need, as a drilling contractor, we need to have the market technically supplied. We need the rigs to be fully utilized. We need day rates to generate returns that exceed our cost of capital. So it's incumbent on us to be really careful about not oversupplying the market. I do expect that as these projects start to function and operate, as the coastal gas link starts running, as Durant's Mountain Pipeline starts going. I expect rig demand will increase. I do think there might be a potential to bring up one or two more rigs from the U.S. depending on customer needs. But we'll be very careful not to set us up for returns on these assets that are less than our cost of capital. Okay, yeah, makes sense. Not much of an answer, but we're going to manage the market carefully.
spk03: Yeah, all good. And then on the U.S. side, You talked about at the current crude price, maybe increasing activity in the second half of the industry. And you just provide some details there around like what type of customer you think or indications from basins or what you're just kind of seeing from incremental demand into 2Q.
spk19: Yeah, look, you know, it's interesting. So our bid volume really hasn't changed much in the past couple of years. So lots of bid activity going on. Lots of drilling departments. looking at rigs, lots and lots of drilling departments looking at upgrading rigs and hydrating rigs. So that activity remains strong. That's a good indicator. We've got a bunch of M&A activity right now that hasn't cleared yet. And these consolidation transactions on the EMP side need to clear. The dust needs to settle. And the drilling programs need to be established kind of post-transaction. So it's just really hard to time how soon the market gets clear. I don't think the problem is $75 or $76 crude. I think the problem is volatility in the crude price that maybe can go into the 60s, maybe can go to the 50s. I mean, who knows when there's a risk on low price decline to the point when an operator feels comfortable increasing rig count by one or two rigs. So that's kind of the negative side of things. The positive side of things, we are watching duck counts. We're watching U.S. production kind of ramping up. unreasonably high compared to rig counts. There's certainly some optimization going on. It's probably our view that rig counts need to move up at least modestly to sustain production levels anywhere near this level over time. So I think we are expecting over time the rig counts ease their way up. But if you had, I don't know, say 20 of these transactions finalized and take 20 rigs out of circulation and then 30 companies add one rig, we're still up 10 rigs.
spk04: Yeah. Okay, got it. Yeah, appreciate it. Thanks, Kevin.
spk19: And, you know, those numbers I gave are just random decisions. Nothing we see right now points to rig count declines, or for that matter, imminently rig count increases.
spk16: Our next question comes from Makar Syed with ATB Capital Markets.
spk15: Your line is open.
spk13: Thanks for taking my question. Good afternoon, guys. Great quarter. Kevin, in the U.S. market, you know, some of your major competitors have guided to activity going up slightly quarter over quarter. I think your comments say that maybe rig activity could be a little bit down. What do you attribute that to? Is it just some gas versus oil or customer mix still? Or is it some of the M&A that you talked about that's happening in industry that's contributing to that?
spk19: Yeah, Makar, I think there's a few things. So, I mean, if I have your question correctly, you indicated that some of our peers have guided to rig counts modestly moving up. I did comment that we expect our rig count to modestly move up a little bit from the current 39, but maybe a bit more in the second quarter. But again, very modest movements. There's no question that we're still transitioning from being very gas focused a couple of years ago, which served us quite well during the pandemic. to pushing more into West Texas, more into the oilier basins. And, you know, it's tough when there's not a lot of new opportunities popping up. So we've got to be very good. We've got to have a good value proposition, great technology, and it's still a one rig at a time game. No question that it'll be a little tougher for us to do that than somebody who's got 50 or 60 rigs already running in the Permian Basin. So I think we're pushing uphill a little bit, but our guys understand that and they're working hard and they're doing a really good job.
spk13: Great. And then on automation, do you think that's going to develop into a trend, that type of equipment on drilling rigs in Canada, or is it still very early stages to see more of that type of equipment on drilling rigs?
spk19: You know, I can tell you a funny story about this, Waqar. I was in mechanical engineering school back in 1982 in my fourth year graduation, or fourth year senior year project was a request by a drilling contractor to find a way to automate the racking board. So back in 1982, the biggest challenge that a drilling contractor could bring to a technical engineering school was how do you automate the racking board to take that person off the racking board? It's taken 42 years, but I think we have a solution. And I'm pretty happy about this. It looks really good. It's not, you know, the cost isn't zero. There's going to be incremental costs, but it removes... It moves everybody from that red zone on the rig floor and the racking board. It bolts onto our super spec rig class. It doesn't require rig design. And, you know, we're supported by NOB, so the software and the programming is not, you know, it's not precision drilling trying to write software. This is industrial-grade robotic software being performed by a company which is also designing the same software for the offshore industry. So we feel really good about this relationship.
spk13: Great. And then... Just on the capital spending, $195 million, Kerry, could you provide a breakdown of how those dollars are going to be spent, domestic, international, and U.S.?
spk10: Sure. I would say less than 10% would be international, and then based on activity levels that we're currently seeing today, we'd probably have a pretty even split between Canada in the U.S. I think it could shift if we see higher activity in the second half of the year. We could see more CapEx in the U.S.
spk08: because that's probably where we'd have a few more higher dollar upgrade opportunities if we see a big jump up in the rig count.
spk19: And, Kerry, the portion of that capital that's long lead will actually just be for nowhere until we have an identified target? Correct.
spk13: And just a final question. Kevin, congrats on raising the capital return to shareholders for 2024. This 25% to 35% number, how do you think about that? Is it exclusively all return in the form of share buybacks? Or when should investors start to expect some dividend as well?
spk10: I think this year, Mukar, it's more than likely going to be all share buybacks. And then I think we're positioning the company and our cash flow profile to introduce some other ways to return capital to shareholders. But I think it's too soon to say exactly what format that's going to be.
spk15: Okay, great.
spk14: Well, thank you very much.
spk15: Thanks, Makar. Our next question comes from Keith Mackey with RBC Capital Markets. Your line is open.
spk06: Hi there. Just curious first, can you talk a little bit about what you're seeing in terms of the old leading edge rate question in the U.S.? Are things still in that $30,000 to $35,000 a day range, or has it moved one way or the other from there?
spk19: Keith, I think that's a fair way to categorize the market broadly is that $30,000 to $35,000 a day range. I think the discipline that we've been talking about for several quarters now remains intact. you know, I would believe that there are some small contractors that might try to bid at lower rates than that, but we really don't see that come across our bow very often.
spk06: Yeah, okay, got it. And just sticking with the tendering activity, can you just maybe speak a little bit to any trends you might be seeing in terms of rig spec in tenders, whether it's a digital or physical, is the required rig changing at all from what we would have been considered a super spec rig in recent years, particularly I'm thinking as some of the larger integrateds in the Permian look to drill longer and longer wells. Are you seeing a change in what rig they're looking for in these bids, and does that match up with kind of what you've got available in your fleet, or at least... what's within your upgrade capital spending for the next little bit?
spk19: The easy answer to the entire question is yes, but with a little more detail. All of our rigs that are available in the US right now are padwalking AC digitally controlled triples. The rig itself is fully capable. There might be a handful of rigs that require minor upgrades to handle the racking capacity of a long reach well, but for precision, That's a couple hundred thousand dollars per rig. It's really a minor upgrade to the rig to add five or 6,000 feet of racking capacity. The second upgrade that'd be required would likely be going from 5,000 PSI operating pressure to 7,500 PSI. That's probably about a million dollar upgrade for a rig that's not equipped with 7,500 PSI. And then typically, if you're going to 7,500 PSI for a long reach well, you might need to bolt on a third mount pump and a fourth generator That's more like a $1.5 million upgrade. We have idle rigs right now that are full spec. They have the racking capacity. They've got the fourth generator, third mud pump, 7,500 PSI. As we get deeper down the batting order, probably when we get past the next, after the next five or 10 rigs, we'd be doing some of those incremental upgrades. And some of that's in our planned capital and some of it's in our long lead time capital.
spk06: Okay. That's it for me.
spk15: Thank you very much, Kevin.
spk19: Great. Thanks.
spk15: And I'm not showing any further questions at this time. I'd like to turn the call back over to LaVon for any closing remarks.
spk11: Thanks, everyone, for joining our call today. On behalf of the Precision team, have a great afternoon. If there's any follow-up questions, you know how to reach me. Thank you.
spk15: Ladies and gentlemen, that concludes today's presentation. You may now disconnect and have a wonderful day. you Thank you. Good day and thank you for standing by. Welcome to the Precision Drilling Corporation 2023 Fourth Quarter New Year in Results Conference Call. I would now like to hand the conference over to LaVon Zdunic, Director of Investor Relations. Please go ahead.
spk11: Thank you and welcome to Precision's fourth quarter earnings conference call and webcast. Participating on today's call with me will be Kevin Neveu, our President and CEO, and Kerry Ford, our CFO. Earlier today, we reported strong fourth quarter results, which Kerry will review with you, followed by an operational update and outlook commentary from Kevin. Once we have finished our prepared comments, we will open the call to questions. Some of our comments today will refer to non-IFRS financial measures and will include forward-looking statements, 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. As a reminder, we express our financial results in Canadian dollars unless otherwise indicated. With that, I'll pass it over to Kerry.
spk10: Thanks, LaVon, and good afternoon. Precision's annual financial results show continued improvement from 2022 and reflect the focus on the 2023 strategic priorities that Kevin will address in his commentary. Annual highlights include revenue of $1.9 billion, a 20% annual increase, adjusted EBITDA of $611 million, a 96% increase, funds from operations of $533 million, an 89% increase, cash from operations of $501 million, a 111% increase, debt reduction of $152 million, and a $30 million of share repurchases while funding two acquisitions with cash or assumption of debt totaling approximately $100 million, and positive earnings per share every quarter during 2023 and for the past six consecutive quarters. In 2023, we closed the CWC acquisition on November 8th, And the precision team has aggressively worked with our new colleagues at CWC to integrate the business to begin realizing synergies, including consolidating facilities, reducing administrative costs, and utilizing precision tech centers and supply stores to support the field. To date, we have achieved $12 million of the projected $20 million of annual synergies and expect to achieve most of the remainder in the first half of 2024. Moving on to our fourth quarter results, Our fourth quarter adjusted EBITDA of $151 million included a share-based compensation charge of $13 million and transaction and severance charges of $6 million. Absent these charges, adjusted EBITDA would have been $170 million. In the U.S., drilling activity per precision averaged 45 rigs in Q4, an increase of four rigs from Q3 driven in part by the addition of acquired CWC rigs. Daily operating margins in the quarter absent impacts of IBC and turnkey were 11,802 USD in line with our guidance of 11,500 USD to 12,000 USD and consistent with Q3 levels. IBC revenue for the fourth quarter was $1,633 per day. And for Q1, we expect minimal IBC revenue and normalized margins to range between 9,000 USD and 10,000 USD. The decrease in margins is mainly due to overhead costs spread over fewer activity days compared to Q4. In Canada, drilling activity for precision averaged 64 rigs, a decrease of two rigs from Q4 2022. Daily operating margins in the quarter were $15,740, an increase of approximately $1,800 from Q3 2023 and in line with our guidance of margins above $15,000 per day. For Q1, we expect margins to remain above $15,000 per day. Internationally, drilling activity for precision in the quarter averaged eight rigs, and average day rates were 49,872 USD in line with the prior year. We expect 2024 activity levels will increase by approximately 40% over 2023 levels. I will remind the audience that capital expenditures in the international segment typically lumpy with high capex at the front end of projects and lower normalized levels in subsequent years for 2023 with recertification costs for the four kuwait rig contracts and a bulk drill pipe purchase order for the region international capital expenditures were over 50 million dollars for 2024 we expect capital expenditures to significantly decrease to normalize maintenance levels in our cmp segment adjusted bid dot this quarter was 12 million dollars flat with our prior year quarter. Adjusted EBITDA was positively impacted by a 15% increase in well-service hours, reflecting the partial impact of the CWC service rig acquisition. We expect results will improve in Q1 with increased rates and activity, the absence of Q4 transaction-related costs, and the realization of transaction synergies. Capital expenditures for the quarter were $79 million, and for the year, $227 million. Our capital expenditures were slightly higher than our guidance of $215 million due to timing of equipment deliveries. Our 2024 capital plan is $195 million and is comprised of $155 million for sustaining and infrastructure and $40 million for contracted upgrades and expansion. Sustaining and infrastructure CapEx of $155 million includes $40 million of long lead items. And I'd like to take a moment to comment on the strategic decision to purchase these long lead items because I believe it exemplifies Precision's ability to leverage our scale to reduce costs while positioning the company for growth opportunities. Due to our standardized fleet, high activity levels across a broad geographic footprint, and a mature supply chain function with core vendor relationships, we achieved a bulk purchase discount on these items and plan to utilize the equipment in either the U.S., or Canadian fleet for potential upgrades or as critical spares. This also ties in with daily operating costs, which have increased for us and our peers over the past three years. The wage increases for our crews have been earned and well-deserved, and as a result, they are largely here to stay. Although the field labor portion of our daily operating costs is sticky, opportunities to lower costs exist. Identifying these opportunities and realizing cost savings has been and will remain a key focus area for the finance team, and we are working hand-in-hand with our operations, technology, supply chain, and equipment maintenance teams to reduce inflationary pressures, optimize equipment performance, and produce a lower and less volatile cost structure in the future. Moving to our contract book, as of February 5th, we had an average of 52 contracts in hand for the first quarter and an average of 43 contracts for the full year 2023. We now have 21 rigs on contract in Canada for 2024, reflecting an increasing number of customers seeking to lock up rigs ahead of LNG project startups. Moving into balance sheet, as of December 31st, our long-term debt position net of cash was approximately $880 million, and our total liquidity position was over $600 million, excluding letters of credit. Our net debt to trailing 12-month EBITDA ratio is approximately 1.4 times, a decrease from 3.4 times at the end of 2022. Our average cost of debt is 7%. We plan to reduce debt by $150 million to $200 million in 2024 and have increased our long-term debt reduction goal from $500 million to $600 million between 2022 and 2026. As of December 31st, 2023, we have reduced debt by $258 million and have $342 million additional reduction necessary over the next three years to reach our goal. We began reducing debt in 2016, and every year we have provided guidance, we have met or exceeded our targets. To date, we have had only a modest allocation of free cash flow for share repurchases. But as we approach our target debt levels of below one times, we are confident in our ability to increase our allocation to direct shareholder payments as a percentage of free cash flow. We plan to allocate 25 to 35% of free cash flow before debt repayments for share repurchases, and we'll expect to continue increasing this allocation in future years, moving towards a target allocation of 50% of free cash flow before debt repayments by 2026. Moving on to guidance for 2024, we expect strong free cash flow for the year But Q1 cash flow to be impacted by front-end loaded CapEx, a working capital build, our semi-annual interest payment, and year-end payments. We expect depreciation of approximately $290 million, cash interest expense of approximately $75 million, cash taxes to remain low, and our effective tax rate to be approximately 25%. SG&A of approximately $100 million before share-based compensation expense. And we expect share-based compensation charges for the year to range between $45 million and $55 million at an $80 share price. And the range may change based on the share price and the performance of precision stock relative to precision's peer group. Please note this is a preliminary estimate, and we will provide updated guidance on our Q1 call following the settlement of past grants and issuance of new grants later this quarter. With that, I will hand the call over to Kevin.
spk19: Thank you, Gary. Good afternoon. Well, we are very pleased with the strong fourth quarter and full year financial results and operational results delivered by the Precision team in 2023. As Kerry mentioned, the progress achieved over the past several years, improving our balance sheet, reducing our debt levels, while growing our revenue and cash flows positioned us with the financial flexibility to execute on a number of opportunistic financial actions to further enhance shareholder value. And Kerry described a few of those. Utilizing our strong free cash flow, We met or exceeded all of our financial priorities for the year, including debt reduction share buybacks. We completed two consolidated transactions. We invested in our fleet with high return projects for the Middle East, United States, and Canada. Those investments included alpha technology expansion, evergreen emissions reductions projects, along with several rig capability upgrades and the reactivation of the rigs in Kuwait. So beginning with our international segment, in the fourth quarter, as Kerry mentioned, we reactivated our fifth rig in Kuwait on a five-year contract. This rig, combined with the four other rigs in Kuwait and our three operating rigs in the Kingdom of Saudi Arabia, will increase our activity in 2024 by 40% over 2023. With our well-established international infrastructure already generating strong returns, we expect this increased activity to flow through our income statement with essentially no increases in our fixed costs or overhead. And despite the recent announcements from the Kingdom of Saudi Arabia regarding capping oil production, We do expect further bidding activity and possible land rig additions targeting unconventional gas, in addition to those recently announced by other industry participants. We have one idle super triple rig in Kuwait and four other idle rigs in the region. In Kuwait, we have active bids for the idle rig and believe we have a high likelihood of contracting this rig in 2024. And we continue to bid on other international rig tenders in the region, and believe we can support regional new country entries from our established base in Dubai. I believe we are well positioned to grow this business segment as the international land drilling industry continues to recover. Turning to the lower 48, we continue to work to expand our presence in oil basins and with the public E&P operators particularly. This has been a little more challenging than we expected as U.S. rig activity has been essentially flat for several months with very few new rig deployment opportunities. There continues to be some contract churn and some operator high grading, and our team has been tightly focused on those limited opportunities. However, it's important to understand the customer rig switching costs, which I've discussed in the past. When an operator decides to replace an existing rig for whatever reason, they usually need to pay a demobilization cost for the current rig and then mobilize the replacement rig. This mobilization or switching cost can reach anywhere from several hundred thousand dollars to over a million dollars depending on the drilling locations, the proximity to the contractor's operating base. In addition to those hard mobilization costs, your operator will have to be a little patient as the high graded rig and new crew come up the learning curve in that specific operator's practice. This switching cost coupled with the very firm drilling contractor market discipline we've seen over the past few years has meant that both rig rates and rig contracts tend to be stickier than most other OFS services. It also means that even for those of us pursuing the high grading opportunities, the drilling contractor may need to be very creative with initial day rates, escalation parameters, or performance incentives to catalyze those high grading opportunities. Our team has been successful sustaining our activity in the low 40s over the past couple of quarters. I do note a mistake on the Precision website earlier today, which posted Precision's US activity at 37. It actually is 39 rigs as of today, and the website error has been corrected. That said, I'm not thrilled with 39 rigs running. With the pace of current customer bids, recently signed contracts, and planned activations, we expect we'll be back in the low 40s in the coming weeks. We expect to see our activity modestly increase further during the second quarter. Visibility beyond the next few months is a little less clear, but we continue to see positive leading indicators, including customer inquiries, LNG export project startups, exhausted ducks in the Permian, and an increasing focus on drilling inventory quality, and of course, the desire for longer reach laterals. We expect these factors will help to catalyze upgrading and high grading growth opportunities, particularly for our super triples with our alpha automation capabilities. No doubt we have some work to do as we continue to expand our presence in the oil plays while remaining well positioned for an improving gas macro. In our Canadian drilling and our well services businesses both delivered strong operational and financial performance throughout 2023 and are carrying that momentum on into 2024. Now for most of the last decade, the Canadian market has been constrained by hydrocarbon takeaway bottlenecks and constraints. As a result, The discount for Western Canada select oil has ranged in the $25 to $40 below WTI range. While the Alberta natural gas commodity price, ACO, has been a function of highly cyclic seasonal weather patterns and regional market energy needs, also limited by bottlenecks and takeaway capacity. Now, I think most of us know that later this year, two major transmission projects, the Trans Mountain oil pipe and the Coastal GasLink natural gas pipe, will begin full operation and served to fully alleviate the Canadian constraints. WCS discounts are expected to moderate to high single-digit discounts, and LNG Canada exposes Canadian natural gas to the global LNG market. Our customers, the Canadian oil and gas operators, remain among the most disciplined E&P group in the world, yet they fully understand the long-term implications of this transformation in the Canadian market. We expect they will thoughtfully and carefully align their capital programs and balance their rig and well servicing demands track the takeaway capacity of the market while continuing to generate stable cash flows, and most importantly, funding their shareholder return programs. This lays out a long-term thesis for the Canadian OFS market, fundamentally supported by global energy prices with no constraints. Those Canadian oil and gas operators will remain highly disciplined and will utilize large-scale multi-well pad drilling programs where efficiency, safety, industrial scale, technology, and digital capabilities will define the development model. This also explains Precision's current market positioning in the Montigny and heavy oil plays and aligns perfectly with our strategy over the past several years. We can look back to the introduction of our super triple rig last decade, the introduction of our alpha automation system five years ago, and more recently, our evergreen emissions reduction solution just two years ago. These rig technology advancements enable large-scale optimized pad-style oil and gas developments perfectly. We also commissioned our 30th super triple rig in Canada earlier this quarter. And as we discussed on prior calls, this is a highly upgraded rig to full super triple capacity. The rig is equipped with the full suite of Alpha automation, Alpha apps. It's got our Alpha clarity optimization system and a full suite of evergreen environmental solutions, easily making this the most advanced technology land rig in the world today. Oh, and one more item. The rig is equipped with three fully automated robotic arms to handle rig floor and racking board pipe handling operations. Now, this is the first fully automated deployment of the NOV Atom racking board and rig floor robotic system. And in partnership with NOV and our customer, this is a fully functional and commercial deployment. While we believe we still have some modest field hardening work over the coming weeks, this is essentially a bolt-on robotic upgrade that we can install in any precision super triple rig to fully de-man the red zones on the rig floor in the pipe racking area and the racking board. I believe there's much more to come on this over the next few months, and we'll continue to update you. Today we are operating 80 drilling rigs in Canada, which includes the recently acquired CWC Tele double rigs. Now the Canadian Tele double drilling market remains oversaturated and highly fractured. Too many rigs, too many contractors, and the competition is intense. Now, precision scale, our highly skilled crews, vertical integration, and a procurement advantage allows us to improve the returns that CWC achieved on these rigs while we remain a price competitive and relative participant in this rig class. While precision is unlikely to be a further consolidator in this segment, it's our view that consolidation and rationalization in the tele-doubles rig market is essential for the long-term benefit of all stakeholders. Precision Super Triples and our pad-equipped Super Singles remain generally sold out, with customers increasingly locking in access to these highly capable rigs and crews with firm take-or-pay contract commitments. For comparison purposes, in the first quarter of 2021, nine Canadian Super Series rigs were contracted with take-or-pay term contracts. In 2022, this increased from nine rigs in 2021 to 19 rigs. And now for the first quarter of this year, 24 rigs are contracted on firm take-or-pay terms, significant shift in the market. And this transformation towards take-or-pay term contracts improves our revenue visibility, it improves crew performance and stability, and it keeps those rigs off the market, supporting tight supply fundamentals for the non-contracted rigs. Looking forward, we expect to run 40 to 45 rigs throughout the spring. and then quickly ramp back up into the mid-60s during the summer, and again, higher levels closer this year in the fall, preparing for winter next year. Longer term, through the end of this year into next, it appears the rigged demand will remain firm and likely tighten up further as the pipelines commence full operations. Our alpha and evergreen products, both in Canada and the U.S., continue to demonstrate broad market penetration. Our customers recognize the efficiency that Alpha delivers, with now 96% of our active super triple rigs running Alpha automation and Alpha apps. Our experience on automated drilling is growing quickly, with over 20 million feet, and now for our Canadian analysts, that's 6.1 million meters drilled with Alpha in 2023, up 43% in 2022, despite the noted decline in U.S. drilling activity. Late last year, we introduced a new tool face control app for directional drilling. And since we've drilled 43 wells with over 3000 autonomous slide sequences, fully proven the value of this app to further automate the drilling processes now approaching 98% of the sequences being automated. Our evergreen emission solutions have strong customer support Currently, 65% of our active super triple rigs currently running at least one evergreen system. And customer commitments now booked to add evergreen solutions to a total of at least 90% of the super triple rigs as soon as we can install the systems. I'll remind you that these solutions include battery energy storage systems, diesel fuel and emissions monitoring apps, grid power connection systems, low emission lighting systems, and blended natural gas fuel systems. Our strategy to deploy products which provide a meaningful reduction in rig emissions while reducing our customers' fuel costs and providing a solid investment for return for precision is a no-nonsense emissions reduction strategy. And I certainly wish that our government policymakers would take a similar approach to their policies on the emissions challenge. We believe both alpha and evergreen will be important as we look to continue strengthening our market presence in the U.S., Canada, and international regions. Turning to our well-service business in Canada, the integration of the CWC rigs and personnel was the key focus in the fourth quarter, and working their way through the synergies was a strong result for the combined team. Our well-service activity remained firm through the fourth quarter, and this has carried on the momentum into 2024. Now, we experienced a rollercoaster of weather, first losing activity in mid-January due to extremely cold weather conditions in Western Canada, and then things turned too warm, causing some intermittent road bans And with the unusually warm weather in late January making some well locations inaccessible, again, negatively impacting the activity. Yet the combined business is performing very well. Today we're operating 83 service rigs with 11 of those on 24-hour operations, doubling the asset's revenue efficiency. Later this month, it looks like our activity will break past 100 operating rigs. Customer demand remains firm. And the outlook for the balance of the year looks good with a strong Canadian macro supporting customer activity. So turning to our strategic priorities, as we reported in our press release, we achieved all of our 2023 priorities and we posted Precision's 2024 priorities. We believe it's important that our investors understand exactly how we intend to create shareholder value and we'll continue to provide that quarterly update on our progress. I can also report that the feedback from our investors continues to be highly positive. Investors tell us they appreciate the transparency and they ask us to please Please keep doing what we say we're going to do. So with that in mind, you can see from our longer-term guidance, we're shifting our priority towards increasing capital returns to shareholders while continuing to reduce debt, but with a more balanced approach. Over the next several years, we believe this will deliver very good shareholder returns. So on that note, I'll conclude by again thanking the people at Precision Drilling for their dedication, their hard work, the great safety results, and the great operating results in 2023. We look forward to a good year in 2024. I'll now turn the call back to the operator for questions.
spk15: Thank you, ladies and gentlemen. If you have a question or comment at this time, please press star 1-1 on your telephone. If your question has been answered or you wish to move yourself from the queue, please press star 1-1 again. We'll pause for a moment while we compile our Q&A roster.
spk17: Our first question comes from Aaron McNeil with TD Cowan.
spk15: Your line is open.
spk05: Afternoon. I'm hoping for a bit more detail on the US Q1 margin guide. I guess I'm just wondering approximately how much of that sequential change is a function of higher costs, how much is downward pressure on price, and how much is a function of rig mix and the seasonal return of those CWC rigs? I guess another adjacent question would be, do you see that, you know, pressure persisting into subsequent quarters absent, you know, an uptick in activity?
spk07: Yeah, Aaron, this is Kerry here.
spk10: I'd say it's a combination of all of those. The one that we think has the biggest impact is the operating cost and just the fact that we were running 45 breaks on average in Q4 and we're going, you know, likely going to be running A lower number than that. We've got a bit more fixed cost with the CWC acquisition. And so it is going to be a little bit of a drag on margins in Q1.
spk08: And as we get activity a bit higher in the second quarter, we think that margins have an opportunity to expand.
spk05: Got it. You mentioned the Kuwait tender. You know, what's a realistic deployment timeline if you get that work or, you know, deployment timelines for other international rigs? that may not have as clear of a tender opportunity.
spk19: Aaron, good question. Certainly, even the bid cycles time can be measured in months and quarters, not necessarily days or weeks like we see in North America. The Quaid tender right now is actually in process. We've been through a couple of rounds of clarifications. If their prior history is an indication, I'd expect the awards could come within a quarter, maybe a little more, maybe a little less, with deployments occurring before the end of the year.
spk05: Got it. And what would the associated capex be for that if you were to win an award?
spk19: Yeah, it's not currently part of our plan, but it would likely be in the same range that we've had in the past, somewhere between probably $3 million to $8 million per rig, depending on the clarifications we're going through right now. Great. Thank you, Aaron.
spk15: Our next question comes from Kurt Haleed with Benchmark. Your line is open.
spk02: Hey, good afternoon. How's everybody doing?
spk19: Good, Kurt.
spk02: Good, good, good. Appreciate the updates, as always. So I'm kind of curious on the coming back full circle on the Canadian market. You referenced, you know, contracted rates, you know, 24 in the first quarter, 23. I don't know, Kevin, where do you think that could go, you know, as we progress through the year? I know you and I have had discussions about, you know, E&P companies wanting to lock in rates, you know, for the export capacity, especially around LNG. So, I don't know. What's your best guess of where you think it might be able to go?
spk19: Yeah, you know, this has happened actually quite quickly, you know, just looking at the trajectory of contracting. I can tell you that we were a little surprised last year, like early 2023, to hear customers willing to take or pay contracts for long-term, be it one to two to three years, when historically in Canada, long-term contracts simply didn't exist. So now to have a book of a couple of dozen long-term contracts starting this year off is a great place to start. Kurt, it would be logical that any operator that's tied to a long-term LNG delivery contract would lock in rigs for a long term. And by long term, I mean two, three years. It starts looking much more like an industrialized process where you're trying to maintain consistency, predictability, repeatability over a long haul, and then using all your digital capabilities at lower cost. So I think to answer your question, I think once those projects start running, and once we see gas flowing, and once we see our customers become more comfortable with the long term nature of their supply contracts, I'd be surprised if the majority of the LNG rigs weren't tied to term ticker pay contracts in the range of two to four years.
spk02: Okay. I appreciate that. A follow-up question. Again, in the past, you thought it's good to see the adoption on the alpha automation and alpha apps. Can you give us an update as to what the incremental cash margin is on adding those apps to the rigs?
spk10: Yeah, Kurt. So it's going to be on the bottom end, it's going to be about $1,500 a day. And then with apps and evergreen solutions, we've got rigs that are making closer to $4,000 a day with all of the additional ancillary products and services.
spk02: Okay. And then you referenced 75% of your rigs had some sort of, or your super triples had some sort of alpha apps on it. Is that evenly split between the U.S. and Canada?
spk19: Let me qualify that. So I think I said 95% of our rigs have alpha on. Okay. And I think I said 75% of our rigs have evergreen solutions on. And yeah, it's evenly split. Both are evenly split between both markets. I might also add that on evergreen, I've been quite surprised by the uptake in the US. There's maybe a little less environmental focus due to the lack of a carbon tax. But good customer take-up on both sides of the border, all due to the value we create through fuel savings.
spk02: Great. All right. Thanks, Kevin. Thanks, Kerry.
spk15: Thank you. Our next question comes from Luke LeBlanc with Piper Sandler. Your line is open. Hey, good morning.
spk03: Kevin, you kind of loosely touched on it with Kurt's question, but you've previously mentioned maybe moving some idle U.S. rigs to Canada. Could you just update us on that, maybe how you're thinking about industry and criminal demand in Canada shaping up with the Trans Mountain Pipeline expansion and Coastal Gas Link?
spk19: Yeah. Luke, you know, it's interesting. There's supply and demand forces pulling opposite directions. No question, the E&P base in Canada, United States, you know, Kuwait, anywhere, would rather see the market oversupplied. And I understand that. because they want to have oversupplied rig supply so that that keeps rates as low as possible. We need, as a drilling contractor, we need to have the market technically supplied. We need the rigs to be fully utilized. We need day rates to generate returns that exceed our cost of capital. So it's incumbent on us to be really careful about not oversupplying the market. I do expect that as these projects start to function and operate, as the coastal gas link starts running, as Duran's Mountain Pipeline starts going. I expect rig demand will increase. I do think there might be a potential to bring up one or two more rigs from the U.S. depending on customer needs. But we'll be very careful not to set us up for returns on these assets that are less than our cost of capital. Okay, yeah, makes sense. Not much of an answer, but we're going to manage the market carefully.
spk03: Yeah, all good. And then on the U.S. side, You talked about at the current crude price, maybe increasing activity in the second half of the industry. And you just provide some details there around like what type of customer you think or indications from basins or what you're just kind of seeing from incremental demand into 2Q.
spk19: Yeah, look, you know, it's interesting. So our bid volume really hasn't changed much in the past couple of years. So lots of bid activity going on. Lots of drilling departments. looking at rigs, lots and lots of drilling departments looking at upgrading rigs and high-grading rigs. So that activity remains strong. That's a good indicator. We've got a bunch of M&A activity right now that hasn't cleared yet. And these consolidation transactions on the EMP side need to clear. The dust needs to settle. And the drilling programs need to be established kind of post-transaction. So it's just really hard to time how soon the market gets clear. I don't think the problem is $75 or $76 crude. I think the problem is volatility in the crude price that maybe can go into the 60s, maybe can go into the 50s. I mean, who knows when does the risk on low price decline to the point when an operator feels comfortable increasing rig count by one or two rigs. So that's kind of the negative side of things. The positive side of things, we are watching duck counts. We're watching U.S. production kind of ramping up. unreasonably high compared to rig counts. There's certainly some optimization going on. It's probably our view that rig counts need to move up at least modestly to sustain production levels anywhere near this level over time. So I think we are expecting over time the rig counts ease their way up. But if you had, I don't know, say 20 of these transactions finalized and take 20 rigs out of circulation and then 30 companies add one rig, we're still up 10 rigs.
spk04: Yeah. Okay, got it. Yeah, appreciate it. Thanks, Kevin.
spk19: And, you know, those numbers I gave are just random decisions. Nothing we see right now points to recount declines or, for that matter, imminently recount increases.
spk15: Our next question comes from Makar Syed with ATB Capital Markets. Your line is open.
spk13: Thanks for taking my question. Good afternoon, guys. Great quarter. Kevin, in the U.S. market, you know, some of your major competitors have guided to activity going up slightly quarter over quarter. I think your comments say that maybe rig activity could be a little bit down. What do you attribute that to? Is it just some gas versus oil or customer mix still? Or is it some of the M&A that you talked about that's happening in industry that's contributing to that?
spk19: Yeah, Makar, I think there's a few things. So, I mean, if I have your question correctly, you indicated that some of our peers have guided to recounts modestly moving up. I did comment that we expect our recount to modestly move up a little bit from the current 39, but maybe a bit more in the second quarter. But again, very modest movements. There's no question that we're still transitioning from being very gas focused a couple of years ago, which served us quite well during the pandemic. to pushing more into West Texas, more into the oilier basins. And, you know, it's tough when there's not a lot of new opportunities popping up. So we've got to be very good. We've got to have a good value proposition, great technology, and it's still a one rig at a time game. No question that it'll be a little tougher for us to do that than somebody who's got 50 or 60 rigs already running in the Permian Basin. So I think we're pushing uphill a little bit, but our guys understand that and they're working hard and they're doing a really good job.
spk13: Great. And then on automation, do you think that's going to develop into a trend, that type of equipment on drilling rigs in Canada, or is it still very early stages to see more of that type of equipment on drilling rigs?
spk19: You know, I can tell you a funny story about this, Waqar. I was in mechanical engineering school back in 1982 in my fourth year graduation, or fourth year senior year project was a request by a drilling contractor to find a way to automate the racking board. So back in 1982, the biggest challenge that a drilling contractor could bring to a technical engineering school was how do you automate the racking board to take that person off the racking board? It's taken 42 years, but I think we have a solution. And I'm pretty happy about this. It looks really good. It's not, you know, the cost isn't zero. There's going to be incremental costs, but it removes... It moves everybody from that red zone on the rig floor and the racking board. It bolts onto our super spec rig class. It doesn't require rig design. And, you know, we're supported by NOB, so the software and the programming is not, you know, it's not precision drilling trying to write software. This is industrial-grade robotic software being performed by a company which is also designing the same software for the offshore industry. So we feel really good about this relationship.
spk13: Great. And then... Just on the capital spending, $195 million, Kerry, could you provide a breakdown of how those dollars are going to be spent, domestic, international, and U.S.?
spk10: Sure. I would say less than 10% would be international, and then based on activity levels that we're currently seeing today, we'd probably have a pretty even split between Canada in the U.S. I think it could shift if we see higher activity in the second half of the year. We could see more CapEx in the U.S.
spk08: because that's probably where we'd have a few more higher dollar upgrade opportunities if we see a big jump up in the rig count.
spk19: And, Kerry, the portion of that capital that's long lead will actually just be for nowhere until we have an identified target? Correct.
spk13: And just a final question. Kevin, congrats on raising the capital return to shareholders for 2024. This 25% to 35% number, how do you think about that? Is it exclusively all return in the form of share buybacks? Or when should investors start to expect some dividend as well?
spk10: I think this year, Wakar, it's more than likely going to be all share buybacks. And then I think we're positioning the company and our cash flow profile to introduce some other ways to return capital to shareholders. But I think it's too soon to say exactly what format that's going to be.
spk15: Okay, great.
spk14: Well, thank you very much. Thanks, Makar.
spk15: Our next question comes from Keith Mackey with RBC Capital Markets. Your line is open.
spk06: Hi there. Just curious first, can you talk a little bit about what you're seeing in terms of the old leading edge rate question in the US? Are things still in that $30,000 to $35,000 a day range or has it moved one way or the other from there?
spk19: Keith, I think that's a fair way to categorize the market broadly is that $30,000 to $35,000 a day range. I think the discipline that we've been talking about for several quarters now remains intact. you know, I would believe that there are some small contractors that might try to bid at lower rates than that, but we really don't see that come across our bow very often.
spk06: Yeah, okay, got it. And just sticking with the tendering activity, can you just maybe speak a little bit to any trends you might be seeing in terms of rig spec in tenders, whether it's a digital or physical, is the required rig changing at all from what we would have been considered a super spec rig in recent years? Particularly, I'm thinking as some of the larger integrateds in the Permian look to drill longer and longer wells. Are you seeing a change in what rig they're looking for in these bids? And does that match up with kind of what you've got available in your fleet or at least a what's within your upgrade capital spending for the next little bit?
spk19: The easy answer to the entire question is yes, but with a little more detail. All of our rigs that are available in the U.S. right now are padwalking AC digitally controlled triples. The rig itself is fully capable. There might be a handful of rigs that require minor upgrades to handle the racking capacity of a long reach well, but for precision, That's a couple hundred thousand dollars per rig. It's really a minor upgrade to the rig to add five or 6,000 feet of racking capacity. The second upgrade that'd be required would likely going from 5,000 PSI operating pressure to 7,500 PSI. That's probably about a million dollar upgrade for a rig that's not equipped with 7,500 PSI. And then typically, if you're going to 7,500 PSI for a long reach well, you might need to bolt on a third mount pump and a fourth generator That's more like a $1.5 million upgrade. We have idle rigs right now that are full spec. They have the racking capacity. We've got the fourth generator, third mud pump, 7,500 PSI. As we get deeper down the batting order, probably when we get past the next – after the next five or ten rigs, we'd be doing some of those incremental upgrades. And some of that's in our planned capital, and some of it's in our long lead time capital.
spk06: Okay. That's it for me.
spk15: Thank you very much, Kevin.
spk19: Great. Thanks.
spk15: And I'm not showing any further questions at this time. I'd like to turn the call back over to LaVon for any closing remarks.
spk11: Thanks, everyone, for joining our call today. On behalf of the Precision team, have a great afternoon. If there's any follow-up questions, you know how to reach me. Thank you.
spk15: Ladies and gentlemen, this concludes today's presentation. You may now disconnect and have a wonderful day.
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