Precision Drilling Corporation

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

Welcome to Precision's Third Quarter Earnings Conference Call and webcast. Participating on today's call with me will be Kevin Neveu, President and CEO, and Kerry Ford, our CFO. Earlier this morning, Precision reported strong third 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. Before I pass the call over to Kevin and Kerry, I would like to remind listeners of our CWC energy services acquisition, which we announced in early September. This acquisition will position Precision as the premier well service provider in Canada and bolster our drilling operations in both the US and Canada. With the acquisition, Precision adds to its marketed fleet 62 service rigs and seven drilling rigs in Canada, plus 11 drilling rigs in the US, which includes seven AC triples. We expect this acquisition to close within the next couple of weeks and generate accretive cash flow on a per share basis in 2024. With that, I'll pass it over to Kerry.

Thank you, Yvonne. Precision's Q3 financial results reflect the resiliency of our high-performance, high-value business model and organizational focus on cash flow and return of capital, meeting our expectations for adjusted EBITDA and further strengthening our balance sheet. During the quarter, adjusted EBITDA of $115 million was driven by healthy drilling activity, improved pricing, and strict cost control. and included a share-based compensation charge of $31 million. Without this charge, adjusted EBITDA would have been $146 million, which compares to normalized EBITDA of $126 million in Q3 2022, an increase of 16%. Margins in Canada were higher than guidance, resulting from stronger-than-expected pricing and cost recoveries, higher ancillary revenues, and improved cost performance. In the U.S., margins were lower than guidance, largely due to an increase in operating costs driven by increased repair and maintenance costs and lower fixed cost absorption, as we're maintaining higher overhead in anticipation of increased activity in the first part of 2024. In the U.S., drilling activity for precision averaged 41 rigs in Q3, a decrease of 10 rigs from Q2. Daily operating margins at Q3, excluding the impacts of turnkey and IBC, were $11,941, a decrease of $1,563 from Q2. For Q4, we expect margins, excluding the impacts of turnkey and IBC, to be in line with Q3 margins in the $11,500 to $12,000 range. In Canada, drilling activity for precision averaged 57 rigs, a slight decrease of two rigs from Q3 2022. Daily operating margins in the quarter were $13,913, an increase of $1,830 from Q2 2023. For Q4, our daily operating margins are expected to average over $15,000, an increase of over $1,000 from Q3 levels due to ancillary winter equipment and improving prices. We continue to build our North American contract book with Q4 2023 drilling rigs of 57 under take or pay term contracts on average for the fourth quarter of 2023. In addition, we recently signed several term contracts for work commencing early in 2024. Internationally, drilling activity for precision in the quarter averaged six rigs. International average day rates were $51,570 U.S. dollars. an increase of 3% from the prior year due to rig mix. We recently activated our fourth rig in Kuwait and expect the fifth rig to be activated in the next few weeks. We expect earnings in our international business to increase approximately 50% from 2023 to 2024. Moving to our C&P segment, adjusted EBITDA this quarter was $14 million, down slightly compared to the prior year quarter with 10% fewer wealth servicing hours offset by higher pricing and margins. Moving to the balance sheet, we were committed to reducing debt by over $500 million between 2022 and 2025 and achieving a normalized leverage level of below one time. Our debt reduction target for 2023 is $150 million, and we plan to allocate 10% to 20% of free cash flow before principal payments directly to shareholders. During the quarter, we reduced debt by $26 million and have now reduced debt by $126 million year to date. Upon closing the CWC acquisition, we will assume CWC debt, make cash payments to CWC shareholders, and incur transaction costs, all totaling in the $60 million to $70 million range. Despite incurring these cash costs, we still expect to meet our annual debt reduction target of $150 million, pointing to robust cash flow expectations in the fourth quarter. As of September 30th, our long-term debt position net of cash was approximately $915 million, and our total liquidity position was $621 million, excluding letters of credit. Our net debt to trailing 12-month EBITDA ratio is approximately 1.7 times, and our average cost of debt is approximately 7%. We expect our net debt to adjust to EBITDA ratio to be below 1.5 times by year-end, with net debt of approximately $900 million and a run rate interest expense of approximately $65 million. Our full-year 2023 capital plan has increased from $195 million to $215 million, largely a result of signing term contracts with upgrade capital paid back inside of the term of the contract. For several of these contracts, we received cash up front from the customer. Additional annual guidance for 2023, which does not consider impacts from the CWC acquisition, includes appreciation at $290 million and SG&A at $90 million before share-based compensation expense. We expect cash interest expenses to be approximately $80 million for the year and cash taxes to remain low with an effective tax rate of approximately 25%. Year-to-date, we have had share-based compensation charges of $22 million. As previously stated, we expect our 2023 share-based compensation expense to range between $20 million and $40 million for the share price range of $60 to $100, with the potential to increase or decrease another $15 million based on relative share price performance and a multiple between zero and two times. With that, I will now turn the call over to Kevin.

Thank you, Carrie, and good afternoon. I'm pleased with our third quarter results with improved revenue and cash flow compared to the same period last year, despite lower industry activity in North American markets. I commend everyone in Precision's organization for their precise execution and safety, excellent operational performance, strict financial discipline, and the continued focus on cash management, which was demonstrated across all Precision business segments during the quarter. I continue to be very encouraged by the support of commodity price fundamentals, but also by the strict capital discipline evident across this industry. And this discipline begins with the investors' expectations for shareholder returns and a continued assistance for industry capital discipline. Our customers are functioning very well in this environment. They are not responding to short-term commodity price signals or volatility. They are managing budgets and staying well within cash flow. And most importantly, they're focusing on efficiency and performance. And nowhere is this more important than our Canadian segment, where broad industry activity is down 6% during the third quarter compared to last year, as our customers remain highly disciplined, staying within fixed budgets. Yet, our 29 Super Triple rigs are fully utilized this year, compared to 25 at the same time last year. And to remind you, we'll be adding one more Super Triple to our fleet on January 1st through an upgrade we announced late last year. Today, we're also running 32 super singles, and this would be the highest Q3 utilization for this rig class since early last decade. In light of the high super spec rig demand, we have customers anxious to commit to firm, take-or-pay term contracts securing rig access. Currently, our Canadian book includes 27 rigs under term contracts, and 17 of those have two-year-plus terms. I want to remind you that in the Canadian market, Term take-or-pay contracts were traditionally exceedingly rare. Notably, we recently booked several customer contracts, which include padwalking and depth-extending upgrades, and those rigs are required for the winter 2024 drilling season, and this necessitated increasing our current year capital budget, as Kerry described earlier. I'll also reiterate Kerry's comments that the capital will pay back within the contract period, and the enhanced margins will continue for the duration of the rig's operational life. Also, for several of these contracts, customers provided us with advanced cash payments up front as we work hard to minimize our cash outflows. Our outlook for Canada remains uniquely strong. Early in 2024, two major hydrocarbon pipe projects will be started up. The Coastal GasLink pipe set to deliver natural gas to the LNG Canada project and Trans Mountain expansion, adding almost 700,000 barrels per day of oil export capacity. For Canada, these projects are absolute game-changers, resulting in significantly improved upstream commodity prices for our customers, deep bottlenecking production, and providing global market access for Canadian energy. Now, I see these independent projects as complementing each other, and that is to say that the liquid condensate produced by the Montigny gas wells is sold commercially as diluent to the heavy oil producers to enable heavy oil shipping through pipelines So this significantly improves the economics for the mountainy gas producers who are ultimately focused on the LNG exports over the longer term. Concurrently, the increased oil export capacity of TMX will serve to reduce the Western Canada Select price discount, significantly improving economics for heavy oil customers. So for precision, the result is that the natural gas drilling in the mountainy is growing to meet the imminent needs of LNG Canada, and heavy oil drilling has rebounded to levels not experienced 2014 and all of this is evidenced in our record super triple demand and our strong super single demand so this is truly a game changer for Precision's Canadian drilling market with term contracts providing revenue stability reduced seasonality with pad rigs drilling throughout breakup market visibility extending beyond seasonal commodity price volatility and all of these factors setting us up to deliver sustainable shareholder returns commensurate with our asset base and and providing opportunities for further expansion in our Canadian footprint. Today, we have 68 rigs running, actually up one from our press release, which was reporting yesterday's activity, and we expect to be in the low 70s before the Christmas pause. Customer planning for winter suggests a strong and fast start to 2024, with customer demand exceeding 23 levels. We look forward to the addition of the CWC drilling rigs and crews, and we expect that Precision's combined activity this winter could be up 10% to 15% from last year. Leading-edge day rates for our super triples are now in the mid-30s and for our conventional super singles in the mid-20s, while our pad-equipped super singles have now moved up into the low 30s thousands per day range. In particular, excess customer demand for Precision's ELFA-equipped super triple rigs is seemingly in the range of seven to 10 additional rig opportunities we're considering. I think the likelihood that we secure A customer-paid redeployment of at least one or two supertribals from the US to Canada later next year is increasing. With our super singles, the demand tends to be more seasonal, with winter being the peak season where demand could outstrip our rig availability by 10 or more rigs. So we expect these market demand signals may lead to additional opportunities for customer-funded upgrades for pad drilling, and longer reach horizontal capabilities, and certainly stimulate further customer interest in take or pay term contracts so they can secure access to the rigs. Now turning to the lower 48, the capital discipline I've described in Canada is at work in every U.S. basin. In the near term, it's meant that natural gas drilling has slowed down over the course of 2023, and the increases in oil targeted drilling we expected earlier this year have failed to materialize as our customers continue to tightly manage their drilling budgets. However, we continue to see customers optimizing drilling efficiency by high-grading rigs, focusing on pad drilling, and extending lateral lengths. This focus on efficiency is also continuing to drive customer interest in our alpha automation platform, our alpha apps, and it's driving interest in our evergreen best battery energy storage systems and other diesel fuel saving solutions. Today, we have 44 rigs operating in the U.S. and seem to be in the trough. Customer indications and interest indicate an increase in activity as budgets reload for 2024, and we expect to see some of these rigs activated later this year. During the third quarter, we continue to experience strong customer interest in our Alpha equipped Super Triple rigs. Since the beginning of the year, we've added five public E&Ps to our customer list and increased our share with two others as we transition to more oil-based work and less private company exposure. Now, super spec rig supply remains in tight availability. During the third quarter, we secured a paid upgrade commitment from a customer to cover the cost of increasing the horizontal depth capability of a precision super triple. And during the year, we've executed 12 other similar upgrades. And these upgrades include enhancements to the mud pumping capability, the drill pipe racking capacity, and targeting longer reach horizontal wells. And some of these also include evergreen enhancements to improve the fuel efficiency of the rig We expect to see more of these customer-paid upgrades emerging in 2024. Rig pricing and leading edge rates remain stable, as the most capable high-specification rigs remain in tight supply, and pricing discipline remains a core strategy across the SuperSpec land market industry. I'm very excited to add the eight CWC rigs and crews currently operating in Wyoming. We see the Powder River Basin as an excellent opportunity for Precision to expand our U.S. in 2024. Now turning to our international business, as Kerry mentioned, we activated our fourth rig in Kuwait during the third quarter and expect the fifth rig to start up in early to mid-November. Both rigs are activating several weeks later than we previously guided, and these delays were entirely due to client planning delays, not precision issues. The capital spending to reactivate those rigs is largely complete, and the five-year contract for each rig will commence when the rig begins operations. By mid-November, we'll have all five rigs in Kuwait operating and three rigs in the Kingdom of Saudi Arabia running for a total of eight rigs, and we'll continue to bid all five idle rigs opportunities across the Arabian Gulf. In our well-servicing segment, Canadian industry well-servicing activity noticeably slowed during the third quarter as our customers digested the costs and increases related to services inflation, labor costs, and material costs. We see a backlog of previously planned activity building up and are now beginning to see a significant increase in activity and expect this to continue into next year. I'm also very encouraged by the strong performance we see in the CWC Well Services Group and look forward to integrating the people of CWC and their operations into our business later this quarter. So to wrap up my comments today, I'm thrilled that despite a weaker market than most would have expected, Precision is on track on all three strategic priorities We also created the financial flexibility to execute a meaningful Canadian consolidation transaction, and we continue to have the flexibility to invest in our fleet to meet customer-backed rig upgrade opportunities. And with that, I'll now turn the call back to the operator for your questions.

Thank you, ladies and gentlemen. If you have a question or a 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. Our first question comes from Aaron McNeil with TD Cowan. Your line is open.

Afternoon, and thanks for taking my questions. Kevin, I can appreciate that there's a lot of value in keeping your promises on the debt reduction, especially in light of the track record over multiple years, but sort of putting that aside, how does debt reduction compete today for capital with the NCIB, given the prevailing valuation and

how should we think about that in the context of your strategic priorities for next year yeah go ahead jerry aaron uh so i'll take that one you know debt reduction still remains front and center and we've put out very specific targets for 2023 and then the two years following this year so we're committed to doing that as we have more free cash flow we we should be able to expand the amount that we allocate towards share repurchases. This year, it's 10 to 20% of our pre-cash flow, which would put it kind of in the 15 to $30 million range of share repurchases. Next year, if our cash flow outlook improves, we should be able to increase that.

Got it. And Kerry, I know you gave guidance for Q4 margins in the US in your prepared remarks, but I'm hoping you can sort of give us a better sense of the moving parts? I mean, you mentioned the higher staffing levels. You mentioned R&M. Like, how much of that was, you know, I don't want to call it one time, but maybe of normal, and what's sort of recurring?

Yes. So, I think if you think about Q3 and Q4, top line, there won't be a whole lot of movement. And the costs that we incurred in Q3, a lot of those will repeat in Q4. So, that's That goes into the margin guidance that we provided. As Kevin mentioned, our Q2 call, we were going to have the rig count kind of moving up and down a little bit around this kind of low 40s level. And that means there's a bit more rig churn than we typically have, which causes a little bit more cost. And as I mentioned, we're carrying a bit more overhead than we typically would at this activity level, because we do think that activity is going to increase. But for your guidance, I would point to a similar operating cost in Q4 that we had in Q3.

Got it. Okay. Thanks. I'll turn it back.

Thanks, Aaron.

Our next question comes from Luke Lemoine with Piper Sandler. Your line is open. Hey, good afternoon.

Kevin, I believe you talked about seven to ten additional opportunities in Canada, and maybe you can move one to two U.S. super triples into Canada. When you're looking at opportunities like that, are these kind of two-year terms that you're targeting to make the move from the U.S. to Canada, or how are you thinking about that?

Luke, that's a great question, and it's a real important strategy question for us as we think about it. And, you know, some of these opportunities might not be for a full year of work. It might be for the winter or maybe for the summer. So we'll look at that very carefully and determine what we think is best. What we'd look for, though, number one, is that the operator needs to be paying a leading edge market rate. We've in the past talked about that being around $37,000 per day. We've talked about the operator needing to pay the full mobilization cost. And you can think about that being around a million dollars to move the rig up and get it ready to work in Canada. So there's a lot of requirements we'll have on our customers if that rig is going to move up. But we also don't want to be a situation where we oversupply the market. So we'll think very carefully to make sure that we think it's sustainable work and that there's a long horizon of work for that rig. So we'd want a contract that was one to two years in duration, but we'd want to have good visibility and work beyond that. Now, what I'd say is that with the LNG project coming on right now in Canada, we are expecting additional rig demand to meet the requirements of that project. And that's why we're targeting kind of something like one or two rigs, we think. the market can probably handle. And perhaps we're light. Maybe it can handle a third or fourth rig. We'll take it one by one.

Okay. And then just still in Canada, I believe CWC has some non-utilized rigs. What's the outlook on those going back to work?

So their fleet is primarily what are classified as tele-double rigs. Those are generally shallower rigs that are triples and maybe a little deeper than some of our super singles. They're commonly used in central, southern Alberta, and Saskatchewan. It's an area that Precision hasn't had a lot of focus in the past. We've been really focused on the resource plays, the conventional heavy oil, and the . But we'll certainly bring the SWC team on ranks just to see how they've worked. You know, they've been very effective in the winter season. They've had often all of those rigs running during the winter, all six rigs running quite commonly. So, you know, to see us running all six CWC rigs and maybe pulling through a few more of the precision tele-doubles would be a very good outcome. And we think that the sales team from CWC can bring some strong market intelligence on that market segment for us.

Okay. If I could sink one more in real quick. On the U.S. side, I think you said you have 44 rigs operating and some could be reactivated later this year. You know, we've seen momentum, you know, the embarrassed count the last few weeks, especially on the Permian, just on a daily basis. where do you think kind of your rig count could be maybe, you know, six months from now or three to six months in the U.S., just kind of based on conversations you're having and what you're seeing?

Yeah, you know, I think we'll be in a fresh budget year come January, and certainly we've already got customer indications there'll be more rigs going to work. You know, we're playing that against a couple of these large acquisitions that have been announced recently between Exxon and Chevron. You know, everyone knows that Exxon you know, three plus two equals four, not five. So there's going to be a slight rig count reduction with those transactions. But other ENPs right now, they're looking to replace ducts and kind of get back into ensuring they can sustain production. It does feel like rig counts are moving up next year. You know, whether that's 50 or 75 rigs is a bit hard to project. But if we picked up our share of that and what we see in our pipeline right now, adding the the eight rigs that are operating right now with CWC, we could have a rig count, you know, back in the low 60s pretty quickly.

Okay. Perfect. Thanks, Kevin.

Great. Thank you.

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

Hey, good afternoon.

Hey, Kurt.

Hey, Kevin. I know you guys referenced here on the press release and your commentary that know about a potential doubling of profitability in the international uh market um is that uh you know you're it looks like you're adding what one one plus rig you know one and a half two rig on average you know going into into next year so it doesn't seem like it's going to be all volume driven per se so is there a significant step up in in kind of day rate and cash margin you expect from from these rigs that you're going to be bringing online

So, Kurt, there's a couple things there. We're going to average a little bit less than six rigs this year, and then next year we'll average eight for the full year. The two rigs we're adding are higher margin than the other rigs that are running on average, and we also incurred a bit of cost reactivating these last two rigs that won't recur next year. So, mixing all of that together, we think that an increase in 50% – now, that's a 50% increase. It's not a doubling increase. And EBITDA, it's just a 50% increase. So going from six to eight puts a bit more profitability.

Okay, that's great. Appreciate that clarity. And then, Kevin, kind of follow up for you as you referenced the, you know, increased term contract dynamics happening, you know, in Canada and, you know, 27 rigs now on term contract. You know, crystal ball it, you know, in the next one to two years given the dynamics around you know, LNG and heavy oil, as you referenced. What do you think that 27 could become?

You know, I have to preface everything with macro. You know, the macro can affect everywhere all the time. But assuming the macro doesn't have some, you know, massive shift like a pandemic or another war, but we're dealing with the Canadian market as it is today with Trans Mountain Pipeline coming on, and the Coastal GasLink project, and then likely follow on approval of phase two for LNG Canada. So if we're running 30 rigs today, that could be as much as mid-30s, three or four years down the road. Could even be a low 30s just by the end of next year. So we could see that rig count go from 30 to 32 or 33 next year. And up beyond that could be 35 or it could be 40 rigs kind of down the road. I don't think we're building new rigs. I think we've got opportunities to upgrade existing rigs like we did for the one-rigger moving into Canada on January 1st. To give you a sense of the capital needs for that, we could probably upgrade one of our older SCR rigs to a full super spec for the range of $10 to $15 million, far less expensive than building a new winterized rig. So I don't think we would need a ton of capital to see our rig count in Canada go up. quite a bit if the LNG projects continue as they look and heavy oil continues to remain strong.

That's great. Really appreciate the color. Thank you.

Thank you. Our next question comes from Keith McKee with RBC Capital Markets. Your line is open.

Hi. Good afternoon. First question is just on the U.S. Now, Kevin, we know that your rig count over the last year or so had been more private company weighted, and you talked about adding six public companies this year and increasing your share with two. Just curious, what do you think is the right customer mix for PD in the U.S. in terms of publics, privates, et cetera? And what do you think needs to happen in order for you to get there?

Yeah, Keith, I think that sort of changes with time a little bit. I do think that as U.S. LNG exports start to ramp up in 2024 and 2025, we might be a little less worried about private equity style E&P companies if they're drilling for gas, if there's a stronger LNG export market. So if I look back at FY 2020, FY 2021, having that private company exposure and gas exposure was excellent for precision. Now, at this point in time today, having more public company exposure, having exposure to the majors, super majors, having more oil exposures, what we're targeting, and we're delivering on that. It's not, you know, we can't make these changes in a week or two. It takes a quarter, two quarters, three quarters. But our customer mix at the end of this year will look vastly different than it did at the beginning of the year. And I'm really pleased with the progress our sales team is making on that.

Yeah, got it. Appreciate the color. And maybe one for Kerry. What are you seeing in terms of maintenance capex per rig or maintenance capex per day? I guess, more specifically on your US fleet. Has there been much inflation from that 1500 a day level that we used to always quote or where are things trending there?

Yes. So there has been inflation. We've quoted on prior conference calls that the maintenance capital cost per day was trending closer to $2,000. Now it's closer to the mid-2000s, but I would point out that that includes drill pipe replacement. And in a lot of cases, we are getting customers to pay for excess wear on drill pipe. And so it's showing up as a higher cost in maintenance capex, but then we're recouping it in margin.

Got it. Okay, so drill pipe and some other things. What are, besides drill pipe, what have been kind of the big drivers in terms of the maintenance capital number increasing?

So it would be mud pumps, mud pump maintenance, engines, top drive, all the critical components on the rig. The repair costs have gone up. If you think about R&M, you've got consumable components when you do repairs, which have a little bit of inflation in them, and then you have labor. And just labor yourself across the board, and that's what's driving it. Yeah, got it.

And just one last one. On any activations that you might see in the U.S., are we talking about any substantial capital requirements to bring any of those rigs back, or are they all pretty warm still?

Likely not much maintenance capital. We might have a little bit of operating expenses. And if there's upgrades associated with the reactivation, there'd be some upgrade capital. But you make the correct point that a lot of these rigs were working six months or a year ago, and they're not going to be the same type of reactivations that we had to put forward at the end of 21 and beginning of 22. Okay. Thanks very much.

Our next question comes from Cole Pereira with Stiefel. Your line is open.

Afternoon all. I just want to start on the margin front in the U.S. So it sounds like some of the costs there are going to reoccur in Q4. Is there anything transitory that is in both Q3 and Q4? Or in the event that the rig count in the U.S. doesn't increase, is that kind of a reasonable run rate going forward? Just as from your last call, I mean, your rig count in the U.S. is down a little bit, but the margin outlook is quite a bit lower.

Right, so I think that the cost will trend down a bit more in Q1, regardless of whether we increase our rig count. If you think about it, if you have a lower rig count, you're absorbing a bit more fixed costs, but also if you have a high maintenance cost on a rig, if you have a critical component that needs to be replaced, it just shows up more prevalent in the average operating costs if you're running fewer rigs. And so we've had a few of those where we just had a higher R&M cost on a particular rig, and it just shows up a little bit more in the daily operating costs because of it. So we do think that there's a bit of transitory costs in there, and we should see it trending down a bit more if you want.

Okay, got it. And then coming back to shareholder returns, you talked about it a little bit. And there's obviously a few different ways activity can go next year, but free cash flow should be pretty strong in any reasonable scenario. I mean, from your standpoint, is it, you know, you maybe think about paying down, call it $150 million of debt or something in that range and should have a lot left over. And then you think about growth capex and kind of put the rest in the buyback?

Yes, so we'll put forward our capital allocation targets at the beginning of next year. I think in general you're thinking about it right, correctly, Colt. We will continue our debt reduction schedule. We will have capital allocated towards share buybacks. And then I would look at our growth capital the same way that we've always looked at it. We're going to look for opportunities to spend, upgrade capital, match the contracts where we get that capital paid back. And to the extent that there's opportunity to do that in the market, we'll pursue it.

Got it. Thanks. And you've done a few of these bulletins now. How do you think about further consolidation just as part of the overall PD strategy?

You know, I think we've demonstrated over the past couple of years that if we can be opportunistic, we will. But really clearly, it's not one of our top three strategic priorities. So I don't think we're going to pivot and all of a sudden become highly acquisitionally focused. We like the stability of a strong balance sheet. But Kerry, do you have anything to add to that?

Sure. It's important to note that when we executed the hierarchic acquisition, we were able to remain committed to our debt reduction target for 2021 and 2022. And if you look at what we communicated on this conference call that we're going to complete the CWC acquisition and still meet our debt reduction targets for this year, it shows you where our priorities are to get the balance sheet in order. And we're in a favorable place right now where we've got some flexibility where we can do some of these tuck-in acquisitions. But debt reduction is still going to be the number one focus of the company for the next year or two.

Got it. Okay, that's all for me. Thanks. I'll turn it back.

Thank you, Cole.

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

Thank you. Carrie, do you expect shortfall revenues in Q4?

Yes, they'll be similar to what we reported in Q3 in that kind of $6 million range, U.S.

And when do they fall off? Is Q4 going to be the last quarter for those, or do you expect them next year as well?

We might have a little bit at the beginning of next year, but the bulk of this level of IBC revenue will fall off in Q4 or after Q4. Okay.

And then as the CWC rigs get on the payroll next year in the U.S., how would those impact your daily operating costs and daily rig rates?

I think it's a little bit too early to talk about how that's going to impact our daily operating margins and rates. We're planning to close the acquisition here in the next couple of weeks, and we'll be able to talk about that a bit more clearly.

Okay. So let's assume then without CWC, on your own fleet, when do you expect U.S. margins to bottom?

Well, they could be bottoming right now. We're not seeing much of a change from Q3 to Q4. It just depends on whether the rig counts continues to trend up in Q1.

Okay.

Well, Carl, I might answer that kind of focused on what you model for rig count next year, but if you're modeling rig count to move up in Q1, then I think that margins are bottomed.

That's good to hear. And then, Kevin, You touched upon these big mergers that are happening. It was mentioned in one case that they would be looking at these four-mile type laterals, and some other companies have talked about those as well. What type of rig would be required to drill that? I imagine not every simple triple rig can do that. There may be you know, even a further subset within supertriples that would do that. So maybe could you talk about like what exactly, what type of equipment would be required on a rig?

Yeah, a little bit I can. So we've drilled some three-mile laterals. We've actually drilled a couple of four-mile laterals. They've been in shallower plays, not the deeper plays. But any time you extend the length of the well or the vertical depth of the well, either one, You're increasing the required hook load capacity for the rig, so you need to have the mast has to either be strong enough or be reinforced to be strong enough. You're increasing the amount of pipe you need to build a rack in the mast, so you have to increase the racking capacity of both the racking board and the substructure to support that pipe. And now that you've got more pipe, it's more weight, so everything has to support that weight. And then because you're drilling farther and you're adding more pipe in the ground, you need more hydraulic horsepower. So typically going from two pumps to three pumps or going from 1,600 to 2,000 horsepower a month pumps. So most of these rigs in our fleet, all of these changes for us are kind of bolt-ons. We can bolt-on a mast upgrade. We can bolt-on a racking capacity upgrade. We can slide in a third pump, slide in a fourth generator. So the rig doesn't become obsolete. But these are capital increases, so to add a third pump and a fourth generator is over a million dollars. To upgrade the mass capacity to handle more pipe might be, in our case, might be less than a half million dollars. If you want to do all of these things together for one of our rigs, it's probably the range of anywhere from three to five million. And the other component is the top drive usually has to have a higher torque capacity, so there's a bit of work to do on the top drive.

Thank you very much. That's all I have.

Great. Thank you, Makar. Our next question comes from Sean Mitchell with Daniel Energy Partners. Your line is open.

Thanks, guys, for taking my question here. You guys have got the three rigs in Saudi, the fourth and fifth rig in Kuwait. Any thoughts around exploring other international markets? I know Luke hit Canada and U.S., but we haven't really talked about are there other opportunities international that you guys are looking at and any colors you can add?

Sean, we've been clearly focused on maximizing our footprint in Kuwait and Saudi, so for sure those two countries. We've been bidding around the Gulf. We think we can support rigs in Qatar, Bahrain, maybe Abu Dhabi, places like that. from the base of operations we have either in Saudi or Kuwait and our regional offices in Dubai. So we think the entire Gulf region's open to us. We're not looking really aggressively outside the Gulf. We have had inquiries from Argentina, we've had inquiries from Central Africa. I'm not anxious to see us in six or seven different countries around the world, but if we had a one-off chance to put a rig somewhere a really good day rate, we'd look at that.

Okay.

Thank you. Thanks, Sean. 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.

On behalf of the team here at Precision, I'd like to thank people for joining us today, and that concludes our conference call. Thank you.

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