Precision Drilling Corp (PDS) 2023 Q3 法說會逐字稿

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 Lavonne Zdunich, 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 Carey Ford, our CFO.

Earlier this morning, Precision reported strong third quarter results, which Carey 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 Carey, 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 U.S. and Canada.

With the acquisition, Precision adds to its marketed fleet 62 service rigs and 7 drilling rigs in Canada, plus 11 drilling rigs in the U.S., which includes 7 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 Carey.

Thank you, Lavonne. 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 of 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 in Q3, excluding the impact of turnkey and IBC were USD 11,941, a decrease of USD 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 USD 11,500 to USD 12,000 range.

In Canada, drilling activity for Precision averaged 57 rigs, a slight decrease in 2 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 pricing.

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 6 rigs. International average day rates were USD 51,570, 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 well servicing hours offset by higher pricing and margins.

Moving to the balance sheet. We are committed to reducing debt by over $500 million between 2022 and 2025 and achieving a normalized leverage level of below 1x. 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 incurred transaction costs, all totaling in the $60 million to $70 million range.

Despite incurring the 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 30, our long-term debt position, net of cash, was approximately $915 million and our total liquidity position was $621 million, excluding lines of credit. Our net debt to trailing 12-month EBITDA ratio was approximately 1.7x and our average cost of debt is approximately 7%.

We expect our net debt-to-adjusted EBITDA ratio to be below 1.5x by year-end, with net debt of approximately $900 million and our 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 receive cash upfront from the customer.

Additional annual guidance for 2023 which does not consider impacts from the CWC acquisition include depreciation at $290 million and SG&A of $90 million before share-based compensation expense. We expect cash interest expense to be approximately $80 million for the year and cash taxes to remain low with 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 with a share price range of $60 to $100 with the potential to increase or decrease another $15 million based upon relative share price performance and a multiple between 0 and 2x.

With that, I will now turn the call over to Kevin.

Thank you, Carey, 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 our 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. I'll 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 reclass 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 2-year-plus terms. I'll remind you that the Canadian market term take-or-pay contracts were traditionally exceedingly rare.

Notably, we recently booked several customer contracts, which include pad walking 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 Carey described earlier. I'll also reiterate Carey's comments that the capital will pay back within the contract period and the enhanced margins will continue for the duration of the rigs operational life.

Also for several of these contracts, customers provided us with advanced cash payments upfront as we work hard to minimize our cash outflows. Our outlook for Canada remains uniquely strong. Early in 2024, 2 major hydrocarbon pipe projects will be started up. The Coastal GasLink pipe set to deliver natural gas to the LNG Canada project and the 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, debottlenecking 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 Montney 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 Montney 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 our heavy oil customers. So for Precision, the result is that the natural gas drilling in the Montney is growing to meet the imminent needs of LNG Canada and heavy oil drilling has rebounded to levels not experienced since 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 providing opportunities for further expansion in our Canadian footprint.

Today, we have 68 rigs running, actually up 1 from our press release, which was reporting yesterday's activity and 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 and we look forward to the addition of the CWC drilling rigs and crews and we expect that Precision's combined activity this winter going to 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 30,000 per day range. In particular, excess customer demand for Precision's Alpha equipped Super Triple rigs is seemingly in the range of 7 to 10 additional rig opportunities we're considering.

I think the likelihood that we secure a customer paid redeployment of at least 1 or 2 Super Triples in the U.S. 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 is driving interest in our EverGreen BESS battery energy storage systems and other diesel fuel savings 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 continued to experience strong customer interest in our Alpha with Super Triple rigs. Since the beginning of the year, we've added 5 public E&Ps to our customer list and increased our share with 2 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 Precision's 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 and we expect to see more of these customer paid upgrades emerging in 2024. Rig pricing and litigate rates remained stable as the most capable high-specification rigs remain at tight supply and pricing discipline remains a core strategy across the super-spec land market industry.

I'm very excited to add the 8 CWC rigs and crews currently we're operating in Wyoming, and we see the Powder River Basin has an excellent opportunity for Precision to expand our U.S. operations in 2024.

Now turning to our international business. As Carey mentioned, we activated our fourth rig in Kuwait during the third quarter and expect the fifth rig to start up 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 was largely complete and the 5-year contract for each rig will commence when the rig begins operations. By mid-November, we'll have all 5 rigs in Kuwait operating and 3 rigs in the Kingdom of Saudi Arabia running for a total of 8 rigs and we'll continue to bid all 5 idle rigs opportunities across European Gulf.

In our well servicing segment, Canadian industry well servicing activity noticeably slowed during the third quarter as our customers digested the cost and increases related to services inflation, labor costs and material costs. We see a backlog of previously planned activity building up and will now be willing to see a significant increase in activity and expect those 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 despite a weaker market than most would have expected, Precision is on track on all 3 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.

(Operator Instructions) Our first question comes from Aaron MacNeil with [TD Cowen].

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?

Go ahead, Carey.

So I'll take that one. The debt reduction still remains front and center and we put out very specific targets for 2023 and then the 2 years following this year. We're committed to doing that. As we have more free cash flow, we should be able to expand the amount that we allocate towards share repurchases.

This year, it's 10% to 20% of our free cash flow, which would put it kind of in the $15 million 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 Carey, I know you gave guidance for Q4 margins in the U.S. 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 I don't want to call it onetime, but maybe abnormal 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 goes into the margin guidance that we provided.

As Kevin mentioned on 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 with 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.

Our next question comes from Luke Lemoine with Piper Sandler.

Kevin, I believe you talked about 7 to 10 additional opportunities in Canada and maybe you can move 1 to 2 U.S. Super Triples into Canada. When you're looking at opportunities like that, are these kind of 2-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 some of these opportunities might not be for full year 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 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 costs. And you can think about that being around $1 million 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 in 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 want a contract, it was 1 to 2 years in duration, but we want to have good visibility on 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 1 or 2 rigs, we think the market can probably handle. And perhaps we're light, maybe you can handle a third or a fourth rig. We'll take it one by one.

Okay. And then just still on Canada, I believe CWC has 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 Montney.

But we'll certainly bring the CWC team on. We're anxious to see how they've worked -- they've been very effective in the winter season. They've had often all of those rigs running through the winter, all 6 rigs running quite commonly. So see us running all 6 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 of CWC can bring some strong market intelligence on that market segment for us.

Okay. If I could sneak one more in real quick. On the U.S. side, I think you said you had 44 rigs operating and some could be reactivated later this year. We've seen momentum in various count last few weeks, especially in the Permian, just on a daily basis. Where do you think kind of your rig count could be maybe 6 months from now or 3 to 6 months in the U.S.? Just kind of based on conversations you're having and what you're seeing?

Yes. I think we'll be in a fresh budget year from January and certainly, we've already got customer educations, there'll be more rigs going to work. We're playing that against a couple of these large acquisitions that have been announced recently between Exxon and Chevron. Everyone knows that 3 plus 2 equals 4, not 5. So there's going to be a slight rig count reduction with those transactions.

But other E&Ps right now, they are looking to replace DUCs and kind of get back into ensuring they can sustain production. It does feel like rig counts are moving up next year, whether that's 50 or 75 rigs, it's 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 8 rigs that are operating right now with CWC, we're going to have a rig count back in the low 60s pretty quickly.

Our next question comes from Kurt Hallead with Benchmark.

Kevin, I know you guys referenced here on the press release and your commentary about a potential doubling of profitability in the international market. Is that -- it looks like you're adding, what 1-plus rig, 1.5, 2 rigs on average going 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 kind of day rate and cash margin that you expect from these rigs that you're going to be bringing online?

So Kurt, there's a couple of things there. We're going to average a little bit less than 6 rigs this year. And then next year, we'll average 8 for the full year. The 2 rigs that 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 2 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 in EBITDA. It's just a 50% increase going from 6 rigs to 8rigs with a bit more profitability.

Okay. That's great. I appreciate that clarity. And then, Kevin, kind of a follow-up for you as you referenced the increased term contract dynamics happening in Canada and 27 rigs now on term contract. Crystal ball in the next 1 to 2 years, given the dynamics around LNG and heavy oil, as you referenced, what do you think that 27 could become?

I have to preface everything with macro. The macro can affect everywhere all the time. But assuming the macro doesn't have some massive shift like a pandemic or another war, but we're dealing with the Canadian market as it sits today with Trans Mountain pipeline coming on and the Coastal Gaslink project and then likely follow-on approval of phase 2 for LNG Canada.

So if we're running 30 rigs today, that could be as much as mid-30s, 3 or 4 years down the road, could even be in 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 1 rig moving into Canada on January the 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 million to $15 million, far less expensive than building a new winterized rig. So I don't think we'll need a ton of capital to see rig count in Canada go up quite a bit if the LNG projects continue as they look and heavy oil continues to remain strong.

Our next question comes from Keith MacKey with RBC Capital Markets.

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 6 public companies this year and increasing your share with 2. Just curious, what do you think is the right customer mix for PD in the U.S. in terms of public, private, et cetera? And what do you think needs to happen in order for you to get there?

Yes. 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 that are 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 exposure is what we're targeting. We're delivering on that. It's not, we can't make these changes in a week or 2. It takes a quarter, 2 quarters, 3 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.

Yes. Got it. Appreciate the color. And maybe one for Carey. What are you seeing in terms of maintenance CapEx per rig or maintenance CapEx per day? I guess more specifically on your U.S. fleet, has there been much inflation from that $1,500 a day level that we used to always quote? Or where are things trending there?

Yes. So there has been inflation. We had quoted on prior conference calls that the main 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 of drill pipe. And so we're -- 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 drives, all the critical components on the rigs, 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 labor is up across the board, and that's what's driving it.

Yes. Got it. And just one last one. On any activations that you might see in the U.S., is there -- 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 expense 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 6 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.

Our next question comes from Cole Pereira with Stifel.

I just want to start on the margin front in the U.S. So it sounds like some of the costs there were 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 they will -- the cost will trend down a bit more in Q1, regardless of whether we increase our rig count. There -- 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 critical components that need to be replaced, it just shows up more. It's more prevalent in the average operating cost if you're running fewer rigs.

And so we've got 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 some -- there's a bit of transitory costs in there and we should see that trending down a bit more in Q1.

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 that activity can go next year, but free cash flow should be pretty strong in any reasonable scenario. I mean, from your standpoint, is that you may be thinking about paying down, call it, a $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, Cole. The -- 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. And you've done a few of these bolt-ons now. How do you think about further consolidation just as part of the overall PD strategy?

I think we've demonstrated over the past couple of years that we can be opportunistic, we will, but really clearly, it's not one of our top 3 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 the strong balance sheet. But Carey, do you have anything to add to that?

Sure. It's important to note that when we executed the High Arctic acquisition, we were able to remain committed to our debt reduction target for 2021 and 2022. And if you look at what we're -- what we've communicated in 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 #1 focus of the company for the next year or 2.

Our next question comes from Waqar Syed with ATB Capital Markets.

Carey, do you expect shortfall revenues in Q4?

Yes, they will be similar to what we reported in Q3 in the kind of USD 6 million range.

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. Okay. And then as the CWC rigs get on the payroll in 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, there -- 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 count continues to trend up in Q1.

Waqar, I'd like to answer that kind of focused on what you model for rig count next year, but if you're modeling a rig count to move up in Q1, then I think that rates above that margins have bottomed.

Yes. That's good to hear. And then, Kevin, you touched upon these big mergers that are happening. And then it was mentioned in one case that they would be looking at these formal-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 Super Triple rig can do that. There may be even a further subset within Super Triples that would do that. So maybe could you talk about like what exactly -- what type of equipment would be required on a rig?

Yes, a little bit, I can. So we've drilled some 3-mile laterals. We've actually drilled a couple of 4-mile laterals. They've been in shallower place, not the deeper place. 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 rigs. 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 you've got more pipes, 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 you're typically going from 2 pumps to 3 pumps or going from 1,600 to 2,000 horsepower mud pumps.

So most of these rigs that -- in our fleet -- all of these changes for us are kind of bolt-ons. We're going to 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 $1 million. To upgrade the mast capacity to have a more pipe might be in our case in be less than $0.5 million.

And if you want to do all of these things together for one of our rigs, it's probably the [range anywhere from] $3 million to $5 million. And the other component is a top drive usually has to have a higher torque capacity. So there's a bit of work to do on the top drive.

Our next question comes from Sean Mitchell with Daniel Energy Partners.

You guys have got the 3 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 color you can add?

Sean, we've been clearly focused on maximizing our footprint in Kuwait and Saudi, so for sure those 2 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 is 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 6 or 7 different countries around the world. But if we had a one-off chance to put a rig somewhere at a really good day rate, we'd look at that.

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

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