Precision Drilling Corporation

Thank you, Michelle, and good afternoon. Before we begin our call, I'm pleased to introduce LaVon Zudunic, who joined Precision a little over a month ago as Director of Investor Relations. LaVon will be overseeing Investor Relations activities for Precision, and we are delighted to have her on our team. With that, I'll hand it over to LaVon.

Welcome to Precision Drilling's 2022 Second 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 second 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. Kevin, over to you for some introductory comments.

Thank you, LaVon, and good afternoon. For today's earnings call, I'd like to draw your attention to three key themes. First, customer demand for our super triple drilling rigs in our US and Canadian markets continues to strengthen, and with extremely limited industry supply, rates and margins continue to increase. Second, we continue to make excellent progress in maximizing operational leverage, tightly controlling our costs and expanding our margins. Our well-servicing acquisition will deliver cost synergies and field margin leverage, and all of our leading indicators are pointing to stronger financial performance for the remainder of this year and through 2023. And third, we are firmly on track to deliver on all 2022 strategic priorities, which includes scaling our digital and ESG offerings, generating free cash flow and strengthening our balance sheet, and reducing both debt and debt leverage. I'll now ask Kerry to review our second quarter financial results.

Thanks, Kevin. Precision's revenue in the second quarter was $326 million, 62% higher than the same period last year, while adjusted EBITDA of $64 million more than doubled from Q2 2021. On a normalized basis, adjusted EBITDA, if we exclude stock-based compensation and the wealth control event, was $75 million. The results reflect steadily increasing North American drilling activity and demonstrate our success in maximizing operational leverage to expand margins. Q2 drilling activity increased 41% in the US and 35% in Canada, compared to the same period last year, and day rates increased 25% in the US and 30% in Canada. During the quarter, we experienced a well control event on a turnkey project in the US. The crew followed proper procedures and was able to evacuate the well site safely with no injuries. We are appreciative of our field leadership's actions resulting in this safe outcome. As for the accounting for the event, We are recognizing a gain on disposal of approximately $4 million, the difference between the net book value and the insured value of the rig. We are booking zero revenue, a loss of $5 million for the cost of the job and the insurance deductible. We are writing off the net book value of the rig of $1 million through depreciation. For the associated well site cleanup and remediation costs, we are accruing $12 million in accounts payable and offsetting the payable with $16 million in insurance receivables, which covers the expected cleanup and remediation cost and the insured value of the RIG minus a $1 million U.S. dollar deductible associated with the turnkey child. The remediation process is ongoing, and any decreases or increases in cost will be reflected on Precision's balance sheet until insurance proceeds are received. For the quarter, the negative impact to adjust the EBITDA was $6.5 million Canadian dollars, and we expect this to be the only income statement charge associated with the event. We expect the cash impact of this event to be neutral once insurance proceeds are received. Moving to the U.S., our daily operating margins for the quarter, absent any turnkey or IBC impact, was $7,174, $1,505 higher than Q1, and in line with our guidance of a $1,500 per day increase. With repricing of spot market rigs, impact of alpha technologies, and improved fixed cost absorption, we expect normalized margins to increase by approximately 2,000 to 2,500 US dollars per day in Q3, resulting in average margins in the mid 9,000s per day for the quarter, and moving through $10,000 per day into the fourth quarter. As a reminder, on our Q2 call last year, we forecasted US field margins to bottom during the second half of 2021, which played out with daily margins hovering in the low to mid $5,000 per day through the first quarter of this year. With our forward guidance, we are projecting field margins to nearly double from Q1 to Q4 and continue to increase into 2023. In Canada, our operating margin was $7,736 per day in Q2. Excluding the impact of queues in 2021, our quarterly daily margin increased $2,489 per day and significantly exceeded our guidance of a $500 per day increase. Our strong margin performance was supported by higher day rates, alpha technologies, and increased labor and cost recoveries. Of note is our higher daily operating costs during the quarter. We have previously communicated inflationary impacts within our daily operating costs, mainly labor and repair and maintenance, And these factors have certainly driven costs higher on both sides of the border. In Canada, during the quarter, we incurred additional operating costs due to higher pass-through costs associated with our operations. We have had productive conversations with our customers about certain operating capital costs, such as excess wear on equipment and provincial taxes, and have agreed to pass through the higher costs, which has resulted in higher daily operating costs and higher day rates. For Q3, we expect daily operating margins to increase to $8,000 to $8,500 per day, a year-over-year increase of approximately $3,000 due to improved pricing, impact of alpha technologies, increased cost recoveries, and fixed cost absorption. For reference, daily operating margin in Q3 2021, excluding queues and one-time recoveries, was $5,303. Moving to our C&P segment, our revenue increased 60% to $33 million, while adjusted EBITDA was $5 million. These results were positively impacted by a 14% increase in wealth service hours and improved pricing as industry-wide shortage of high-quality assets and skilled labor is driving day rates up. Our recent wealth service acquisition provides needed consolidation within the wealth service industry. With our expected cost synergies of $5 million annualized and our ability to leverage our scale, We believe this is an accretive transaction with the potential to generate significant cashflow and support our debt reduction strategy. We expect the transaction to close in the coming days. We remain firmly committed to reducing debt by over $400 million between 2022 and 2025 with a target of $75 million this year. During the quarter, we reduced our senior credit facility balance by $70 million and ended the quarter with $52 million in cash and more than $540 million in available liquidity excluding letters of credit. Our net debt to trailing 12-month EBITDA ratio is approximately 4.5 times, and average cost of debt is 6.6%. We expect our net debt to adjust to EBITDA before share-based compensation expense to be closer to three times by year-end and decline further into 2023 toward our goal of below 1.5 times. With rising concerns about high-spec rig availability, customers are seeking longer-term commitments, and we are locking in higher day rates with take-or-pay term contracts. particularly for opportunities which require capital for rig upgrades. This is driving an improved outlook for Precision's free cash flow in the second half of the year into 2023. To deliver on our customer-backed rig upgrades, of which we expect over 20 during 2022, and certain drill pipe commitments, we are increasing our capital budget to $149 million for the year, up from $125 million. As a reminder, for our upgrades, we require full cash on cash payback within the term of the contract and rates of return well above our cost of capital. Moving on to our guidance for 2022, depreciation is expected to be $275 million. SG&A is expected to be approximately $75 million before share-based compensation expense. Cash interest expense is expected to be $80 to $85 million for the year. And cash taxes are expected to remain low, and our effective tax rate will be approximately 5%. I will now turn the call over to Kevin.

Thank you, Gary. There's no doubt that the customer demand and market tightness we discussed in our first quarter conference call is gaining momentum. We see this across all North American service lines. In the United States, we are currently operating 57 rigs with confirmed bookings and contracts. We expect activity to climb into the high 60s later this year. and virtually all precision super triple rigs will be active. Day rates continue to rise as the industry supply is very tight for this rig class, and customers sensing rig shortages are willingly locking in term contracts at the highest leading-edge rates. Since the beginning of this year, we've added 39 term contracts. Some of these involving rig upgrades, Kerry mentioned earlier, ranging from alpha automation to the addition of third pumps, fourth generators, and padlocking systems. Also included are several evergreen battery energy storage systems, two evergreen highline power systems, and the evergreen power management and emissions monitoring apps. As Kerry mentioned, all capital upgrades are backed by take-or-pay contracts, which will return the capital investment well within the contract term. Today, all of Precision's active triple rigs are drilling on multi-well pads, and virtually all have extended horizontal drilling capabilities. Over two-thirds of these rigs utilize alpha automation and alpha apps, and many are adopting alpha analytics to further enhance drilling performance. Leading edge day rates for these rigs is now approaching the mid-30s range, with the alpha digital services over and above that rate. With alpha and other ELACAR services, such as managed pressure drilling support, some bill rates now are in the high 30s to $40,000 per day range. Market pricing discipline remains a key tactical consideration, And during the quarter, we rejected several bid opportunities with customer pricing expectations below our desired thresholds. We remain keenly focused on improving day rates and margin levels, which will ensure an appropriate financial return on our fleet investment, something we've not seen in several years. As Kerry mentioned, our fleet ride margins bottomed early in the third quarter of last year. We've already recovered by approximately $1,500. We expect this margin recovery to pick up pace as leading edge rates and alpha automation revenues filter through our fleet. As you can see from our previously reported day rate trends prior guidance, the lag time for fleet averages to approach leading edge rates is typically six to nine months. As such, we project a strong cash flow profile for U.S. drilling business through 2023. Turning to our Canadian market, activity has rebounded to well above 2019 levels, supported by the strong oil and gas commodity prices. Currently, we are operating 61 rigs and have visibility to over 70 rigs later this quarter. I previously mentioned the Clearwater play, which emerged late last year, but we are seeing a strong rebound in conventional heavy oil, SAGD, and strengthening activity in most other oil and gas regions in Canada. The Precision Super Single Rig is a rig of choice in conventional heavy oil, SAGD, and the Clearwater region. and we expect our utilization to exceed 80%, with leading edge rates progressing into the low 20s for this highly cost-effective class. In the Mondrian Deep Basin, gas and liquids activity remains strong. Primitive delays in British Columbia have led to several operators diverting activity to Alberta in the midterm. Precision's Super Triple 1200 remains a clear rig of choice in the region, with well over half of the PAD triple market share. Currently, we're fully booked for a fleet of 28 Super Triples, and we see customer demand exceeding the available rig supply by several rigs for the first quarter of next year. While we do not believe that rising rig rates or even contract terms will stimulate new builds, the pricing tension on Super Triples will continue. This may also drive some incremental demand on the less efficient heavy tele-doubles as customers compete for the most efficient rigs available in the market. It remains possible that we could mobilize one or two more rigs to Canada from the DGA Basin as leading edge rates in Canada continue to push into the 30s for these rigs. Returning to a healthy, profitable, and self-funded service industry is essential for our customers and for our investors. Precision's market position in Canada dictates that we lead the industry recovery for rates, margins, and financial performance. As I mentioned in prior calls, our sales team is committed to pushing rates and marching precision back to profitability. And there's no question this has led to uncomfortable conversations with some customers who have grown accustomed to the excess services supply and entrenched price deflation of the last several years, especially through the pandemic. Precision's firm pricing discipline has meant rejecting some work where customer pricing expectations are simply too low or customers are unwilling to accept take or pay contracts to cover rig upgrades. This short-term impact is that we've given up market share on the order of 10 to 12 rigs for Q3, Q4 projects. However, this pricing discipline is essential as we remain committed to returning to profitability and sustaining a strong free cash flow profile. Customer adoption of alpha automation in Canada has caught up with our U.S. market penetration as the benefits of alpha are becoming widely accepted by our Canadian customers. Today, over 60% of our Canadian super triple rigs are running alpha, and we expect this will rise to over 80% by year end. We're experiencing strong customer demands in our well servicing business segment and are thrilled to be adding 250 highly regarded people in 51 marketed rigs from High Arctic branded as the Concord Well Servicing Group. With the 48 precision service rigs running this week, we are already hitting our Q1 peak and expect that with the Concord team, our combined activity level will be in the 80 to 85 range later this quarter. Our highest leading edge rates are pushing over $1,000 per hour and with several service rigs currently working 24-hour projects, we see a revenue profile that's very encouraging, yet we believe we still have a ways to go with pricing and utilization gains as this segment continues to recover. Now, I've been talking about the importance and value of consolidation in this business line for several years now, and it is very good to execute this deal and bring these fleets together. As mentioned in our press release, we expect short-term synergies valued in the $5 million range. I also believe that from a revenue and cash flow standpoint, and margin synergies will be much stronger over time. This acquisition will further demonstrate the operational leverage and scale value inherent to the precision business model. The shortage of skilled labor is stressing all parts of our economy, and the oil service sector is not immune. Now, Precision's recruiting and retention performance has been excellent in all regions, yet we note the emerging safety challenges associated with a larger component of our field crews, staffed with less experienced or green workers. And this safety challenge has been intensified by those customers who seem only focused on capital discipline, which then prioritizes speed and efficiency. The safety of our people and the integrity of our safety processes are far and away precision's top operational priority. And I mention this as it's imperative that the service providers and the customers remain tightly aligned on safety as a key priority in the field. Now turning to our international segment, the most important development is the large multi-rig tender we mentioned in our press release. This is a project we've been discussing for several quarters, and we expect to hear more over the coming weeks as the submitted tenders are now under evaluation by our customer. We remain confident that our idle rigs in Kuwait will be reactivated with long-term contracts later this year or early next year, and we continue to explore several other opportunities in the region for all of our idle rigs. Our business in the Kingdom of Saudi Arabia remains stable with our three operating rigs recently renewed for a further five-year period. Finally, regarding our debt reduction and capital return commitments, we remain firmly on track to deliver on both targets. We'll continue to carefully manage our cash flow and uses of cash to ensure we hit both our short-term and long-term debt reduction and capital return commitments. You can see this in our opportunistic contract-backed capital spending programs, the creative consideration payment terms for the wealth service acquisition, and our intense focus on pricing, costs, and margins. I'll wrap up by thanking the people at Precision for their hard work and the excellent results they are delivering. And I again welcome the 250 employees joining Precision in our well-serviced business. So I'll now turn the call back to the operator for questions.

As a reminder, to ask a question, you will need to press star 1-1 on your telephone. Please stand by while we compile the Q&A roster. Our first question comes from Aaron McNeil with TDS Securities. Your line is now open.

Hey, afternoon all. Thanks for taking my questions. Kevin, can you speak to what the capital commitment and scope of upgrade might be for the range of contracts you signed this quarter and maybe a particular focus on, you know, the handful of multi-year contracts that you signed? I guess, you know, to ask the question more specifically, Are those longer-term contracts a result of a higher upgrade cost, and where are you at sort of in terms of your marginal capital cost of reactivation?

I'll catch part of this, and Terry will pick up part of it, Aaron. So first of all, let me kind of cover what we're seeing in customer trends and contracting. I would say that the longer-term contracts are linked to longer-term customer spending plans. They're not linked to trying to extend the payback terms on a capital investment. We're targeting IRRs on these investments that are, as Terry said, well above our cost of capital, but really looking at payback terms that return that capital probably in most cases in less than a year. Despite contract terms, it might be 18 months or two years. The scope of the upgrades are typically in the $1 to $3 million range. If the rig needs a third pump, if it needs a fourth generator and a padlocking system, that would be the upper end of that range. call that three, and maybe in some cases four million if you're adding on alpha. Many of these, though, might just be like a third pump, fourth generator, or just an alpha upgrade. So there's a range, and the range is really from half a million to three or a little bit beyond three. Terry, do you want to discuss activation fees for a little bit?

Yes. So I'll just add that some of those upgrades also include evergreen products such as battery packs. So we've got that range of kind of half a million to three or four million And that's all going to be on the capital side. And then in the U.S. market, we continue to incur some cost on reactivating rigs. They've gotten a bit more expensive from the $150,000 to $250,000 range that we quoted most of last year and into the first part of this year. And now the rig reactivations are really kind of more in that $250,000 to maybe $500,000 range. So there's a bit more operating expense as we reactivate rigs in the U.S.

Understood. Kevin, on the paid alpha days, I was surprised to see they're only at 4% year over year. Was there anything unusual going on this quarter and do you expect to see growth in percentage terms over the balance of the year or?

Yeah, I think my guidance on increasing utilization should help to point you towards some of that growth. And we're getting to the point now where we're only adding, I think we added five alpha systems in the first quarter. So we're getting into the case where the base numbers are big enough that growth of 50% is going to be a little bit hard to expect going forward.

Understood.

There's no resistance. You know, if you bake in a little bit of seasonality in Canada, there's a bit of an explanation for some of that reduction. So just a few moving pieces in the second quarter. I think Q3 results should be a little more indicative of that trajectory.

Maybe I'll sneak one clarification question in as well. The $5 million in operating costs related to the well control event, even with the $1 million deductible, it just seems like a lot. What's actually in that

number you know if the remediations account for separately again it strikes me as a lot in the context of what a well might actually cost to drill aaron uh we're drilling turnkey wells in uh along the gulf coast in the typically gas wells and uh these wells could be anywhere in total cost from let's say one to one to ten million uh so what you're seeing in this case is kind of the full cost of the well At this point, we haven't begun to redrill or reenter this well. We're still finishing up the remediation. I'd expect that we'll go back in and sidetrack and redrill this well and finish it off and recover a significant portion of that, but we're not giving any guidance on that yet.

Got it. Understood. Thanks for taking my questions. I'll turn it over.

Thank you.

One moment, please, for our next question. Our next question comes from Waqar Saeed with ATB Financial. Your line is open.

Thank you for taking my question. Kevin, in terms of the well abandonment program, it looks like there's a lot of runway in Alberta. It requires a lot of additional work, but you also have the federal program that could end at some point. How do you see the, you know, well, abandonment program over the long term kind of play out, and how does this acquisition kind of fit into that?

Makar, good questions. There's several kind of moving pieces right now around abandonments. I think probably one of the more important things we didn't mention on the call is that the Alberta Energy Regulator is increasing the requirements on the operators to to invest in abandonment. So there's an increasing push forcing operators to manage those abandonments, to approve the abandonments and manage abandonments. We're seeing rising, I call it, core demand on abandonments over and above the funded program of the federal government administered by the province. So you've got Kind of three things playing together right now, really helping business, you know, higher commodity prices, stimulating some of that catch-up maintenance work. You've got this regulator requirement that's going to increase the amount of maintenance work to abandoned wells. And you've got the tail end of the federal abandonment program that's got to be spent between now and next February. So we see, you know, we see a lot of drivers kind of in the short term, but some longer-term drivers around, you know, company obligations to abandoned wells and then AER increasing requirements. Certainly, you know, we think that the business, the well servicing business has a very strong outlook with moderate to high commodity prices. Looking at the activity we have kind of booked for the fall and winter right now, I think our timing of this acquisition was key for us. And we're keen to get that rate count up into the 80s and maybe higher as we bring on more staff.

Okay. And certainly, you know, you have critical mass in Canada in wealth servicing. And how do you see your U.S. business? Is that a core business for you?

Well, you know, for us, we have kind of like a wedge or a sliver in North Dakota. It borders on Saskatchewan. You know, the assets are similar. The type of customers are similar. In fact, some of our Canadian customers work both sides of the border. So while it is U.S. revenue, it's to what we're doing in Canada. I view it as an adjacency rather than some strategic push into the U.S.

And, Kerry, the leading-edge margins look to be in the U.S. in $13,500 to $15,000 type kind of range. Is it still, you think, six to nine months to get the fleet to those kind of margins? Yes.

Yeah, I think, as Kevin said, we've got historical precedence. That usually is how long it takes to get the leading edge into kind of fleet averages. We've given guidance for – specific guidance for Q3. I think we've given some soft guidance for Q4. And then, you know, look for continuing guidance a quarter or two forward. You know, certainly for the super triple 1500s, we're seeing the fleet repriced to that leading edge rate, and then the 1200s are pricing a little bit lower. So I think certainly we've got some runway to get it meaningfully over $10,000, but I'll stop short of giving guidance on what the ultimate fleet average margin is going to be next year.

Sure. And just one final question. In terms of the rig involved in the well control incident, I understand that's a total write-off. What type of rig was involved?

It was one of our legacy 2000 horsepower rigs. It was upgraded. It had horizontal capabilities. And we have another rig in the fleet that we'll be bringing in to redrill that well and continue with our turnkey business.

Great. Thank you very much. Thank you.

Thanks, Makar.

Our next call comes from Cole Pereira with Stuffle. Your line is open. Please go ahead.

Afternoon, everyone. Kevin, you talked on it a little bit, but thinking about leading-edge Canadian day rates in the low $30,000 a day range, you know, so from your comments, is that enough, you think, to move a rig up from the DJ, or does it have to move a little bit higher? And from some of your discussions to date, where do you think these leading edge rates in Canada could go in the winter?

Well, Cole, those are really great questions. I've got at least 35 customers who would like to have the same answer. That said, that rig that we're talking about that could move up in the U.S. also has an opportunity cost tied to U.S. operations. So we would need to see a differential in rates that would cover the move cost at least. And I'd say that probably rates below 30,000 don't do that. But as you get into the 30s, if you have the opportunity to bring alpha on and things like that, then we're getting into the right territory.

Okay, got it. And you talked a little bit about in Canada, but just the significant tailwinds for USDA rates. I mean, are you concerned at all that other drillers could start thinking about new builds, or does it just not make sense as you can do a large-scale upgrade at a more economic rate?

Certainly, I think there's a pool of rigs in the U.S. We have some of those ourselves. Look at our fleet for just a moment. We have, beyond our current fleet of Super Troubles in the U.S., we have another 12 to 15 high-spec DC SCR rigs that have AC top drives, and the conversion cost to bring those rigs into kind of full super spec, we think about in the range of 12 to 14 million per rig. So that's substantially less than a new build. If day rates move up into the upper 30s for the rig itself, which the trajectory certainly appears that way, then we're probably looking at those upgrades sometime in calendar 2023 and stretching beyond that. I think the industry has probably collectively somewhere between 75 and 100 rigs that look like that. can do the same thing. So I think that we're still quite a ways away from a full on shortage of rigs. I'd also comment that precision drilling being a public company and most of our large scale peers are all public companies. This capital discipline theme remains fundamental to everything we're doing, and we certainly see that behavior among our peers. So I think there's a lot of reluctance to growing rig fleets and investing capital right now when capital is so scarce, and we're being valued based on the returns we can generate, not on the growth profile. So I just don't see new builds on the horizon. I do see potential for these moderately costed upgrades. And in a world where you can get $36,000 or $38,000 a day for a rig, which if it's drilling wells in 10 days, that's really not a big incremental cost on the well. I think we have another 12 to 15 rigs we can bring into play next year.

Okay, got it. That's helpful. Thanks. That's all from me. I'll turn it back.

Thank you.

As a reminder, please press star 11 on your telephone to ask a question. And our next question comes from Keith Mackey from RBC.

Hi, good afternoon and thanks for taking my questions. Just wanted to start out on the RIG contracts and the additions coming into the field the second half of this year. It looks like your current customer mix in the US is predominantly private company weighted, a little bit more gas weighted than oil. Can you just comment on where and what types of customers these upcoming rigs might be working for?

I'd say probably a more blended mix of both publics looking forward, privates. The publics have been more reluctant to add rigs. And we've certainly seen, you know, year-to-date industry-wide and precision, for sure, much more traction on the private side of the business. And I can even tell you, kind of looking forward at our bid book, which still remains quite strong, It's still primarily comprised of ones and twos. We don't see any huge shifts into growth yet. We do see public EMPs looking to start to focus on recovering and rebuilding or balancing their completions with their drilling. So I think we'll see a few rigs starting to creep back in through public drillers or public EMPs that need to start to rebuild their inventory of declining ducts. So I'd say it's really oily-weighted looking forward and more public-weighted looking forward.

Got it. Thanks for that, Kevin. Maybe just turning to the capital, so 149 now for 2022. Maybe if you could just comment on your average maintenance capital per rig, that'll give us a bit of a baseline to get into 2023. And then is there any growth capital associated with these latest contracts that will also spill into 2023?

Okay. So, Keith, this is Kerry. We haven't given guidance for a 23 spend. We'll do that later this year. We'll give an indication of what that looks like. But in terms of the maintenance, think about it as about $1,600 to $1,800 per activity day is what our maintenance capital costs are trending for.

Got it. Perfect. And then, yeah, just on the latest contracts, is all of that capital spent this year, like the incremental budget for this year, or is there some that will spill into next year? We just have to kind of assume for ourselves how much that is based on the per-rig upgrade and so forth.

Yeah, so the outlook that we gave for the $149 million, the upgrade capital will all be spent this year, the per-rigs that will be going to work. at the end of this year. There may be some drill pipe in the maintenance that we pre-purchased that we'll take delivery of at the end of the year that's for 2023 activity. And in terms of the upgrades, they're all rigs that are going to go to work before the end of the year.

Okay. Thanks. That's helpful. That's it for me. Back to the operator.

Thanks, Keith. Thanks, Keith.

Thank you. And again, if you would like to ask a question, please press star 1-1 on your telephone. Okay, our next question comes from John Daniel. Sir, your line is open.

Hey, great. Thanks for squeezing me in, guys. Sorry for being slow to queue up. Hey, Kevin, I'm going to – hopefully you'll be willing to take this one, but looking to your crystal ball, where do you think that your rig count in the U.S. could reasonably peak next year? And a range is fine. I'm just trying to get a feel for if it's low 70s, high 70s, low 80s, just sort of what your gut tells you at this point.

Yeah, as I was describing kind of a last question around these next round of upgrades, I think it's quite likely that the industry is upgrading DCSER rigs to AC and making those rigs super spec rigs. I think we'll be participating in that. And I could see us easily upgrading anywhere from 5 to 15 of those rigs next year. So that would be activity, I think, into the mid-80s. Now, John, that's assuming I would call that all development drilling. right i think there's potential for some of our legacy rigs to be used for exploration drilling and delineation cell drilling so we could say we can't move a little higher but uh it's probably easier for me to get my arms around development drilling increasing uh but at some point we know these operators have to do some exploration work or some delineation work so i think there's opportunities for super triple rigs and upgrades and super triple rigs and get those leading edge day rates But I also think we'll see some bridging opportunities for some of the vertical rigs to do delineation work or kind of low spec horizontal drilling. Right.

And if they wanted, if you started to see the inquiries for that next call at 5 to 15, you know, we keep hearing about lead time issues throughout, you know, all of the companies we talk to. What would be the time required to get that first one out when you get the call next year?

Yeah, I actually think the call probably comes late this year. But I would say that late on, our type of upgrade is probably something like three to four months. Okay. And we still have some inventories of products we can use and pull off some of the rigs that aren't running if we need to to get those rigs faster. We've got some priority positions with some of our vendors. I think bill pipe would be a critical path, but I feel pretty good about the AC systems and the generators and the pumps and top drives.

John, this is Kerry. I would just add in that if that does happen, that seems like a lot of capital for growth, but the implied day rates in that type of environment would generate a significant amount of cash flow where we would be able to fund those upgrades within cash flow for the year and still have cash flow that would meet our debt reduction goals.

That's a good problem. Okay. A bit of a softball, not intended to be a softball, but more of an educational question for me, but On alpha automation, I mean, you guys have made great progress over the last several quarters. And I would assume with more and more and more systems, you've got much better data about the rig performance, those with it versus those without it. Can you just remind us, elaborate a little bit on sort of the differences you've seen to date and where it might go?

You know, so a couple of things. For sure, we can validate the time savings the value of the base platform alpha automation. I'd say that different customers have valued apps differently. They just have different programs that certain apps work for them. Some don't. Yeah. But like, like most apps and whether it's apps in your phone, some people prefer Google maps, some prefer Apple maps. I get that. And we're seeing that kind of emerging on the app side. But I would tell you that I think that if you look out, look out three or four years, It's hard to imagine that every development drilling rig on a pad isn't using automation. Whether it's our system or somebody else's system, every single rig should be using automation. Every single rig should be using some basket of apps that that operator thinks are appropriate for their program.

But you can see, I presume, a demonstrable difference in performance between those without versus those with or no?

Well, here's what I'll say. Certain operators... with intense engineering and company man oversight can convince themselves that they can make the rig run as fast as that driller working really fast at his peak performance. It is really hard for a driller to be 100% on 12 hours a day, 10 days in a row. Yeah. You know, software eliminates all of that human uncertainty. And what we have seen is that we can get that best well every single time with every driller. We don't have to have the best driller. We don't have to have the driller fully rested. Right. Okay. And we've got case studies that demonstrate that quite clearly.

That's what I was asking. Okay, cool. That's all I needed. Guys, hey, thank you for including me.

Great. Thanks a lot, John.

I would now like to turn the conference back to LaVonne for closing remarks.

Thank you to everyone for joining and participating on our call. If you have any follow-up questions, please don't hesitate to reach out to Terry or myself. With that, we will sign off. Have a great day.