Precision Drilling Corporation

Ladies and gentlemen, thank you for standing by and welcome to the Precision Drilling Corporation 2020 Third Quarter Results Conference Call and Webcast. At this time, all participants are in the listen-only mode. After the speaker's presentation, there will be a question-and-answer session. To ask a question during the session, you'll need to press star 1 on your telephone. If you require any further assistance, please press star 0. I would now like to introduce your host for this conference call, Mr. Dustin Honing, Manager of Investor Relations and Corporate Development. You may begin.

Thank you, Kevin, and good afternoon, everyone. Welcome to Precision Drilling's third quarter 2020 earnings conference call and webcast. Participating today on the call with me are Kevin Nebu, President and Chief Executive Officer, and Carey Ford, Senior Vice President and Chief Financial Officer. Through our news release earlier today, Precision reported its third quarter 2020 results. Please note these financial figures are in Canadian dollars unless otherwise indicated. Some of our comments today will refer to non-IFRS financial measures such as EBITDA and operating earnings. Please see our news release for additional disclosure on these financial measures. Our comments today will include forward-looking statements regarding Precision's future results and prospects. We caution you that these forward-looking statements are subject to a number of risks and uncertainties that could cause actual results to differ materially from our expectations. Please see our news release and other regulatory filings for more information on forward-looking statements and these risk factors. Carey will begin today's call by discussing our third quarter financial results. Kevin will then follow by providing an operational update and outlook. With that, I'll turn it over to you, Carey.

Thank you, Dustin. Our third quarter financial results reflect the execution and progress on our strategic priorities set out at the beginning of 2020, including reducing debt through free cash flow and maximizing financial results through leveraging our high performance, high value fleet and scale of operations. Our third quarter adjusted EBITDA of 48 million decreased 51% over the third quarter of 2019. The decrease in adjusted EBITDA primarily results from a sharp decrease in drilling activity in North America and a slight decrease in our international operations. Also included in adjusted EBITDA during the quarter is 2 million of severance costs and 8 million of Q's assistance payments. Absent these items, EBITDA would have been $42 million for the quarter. We are on track to achieve our guidance of a 35% reduction in fixed costs comprised of overhead and G&A and expect cash savings for the year to be $150 million. We expect to achieve a $35 million reduction in annualized G&A costs from the guidance provided at the beginning of the year. Cost reduction and cash preservation will continue to be priorities throughout our organization. Precision participation in the Q's program continued in Q3. We recognized $8 million in Q's assistance in Q3 and expect to participate in this program at similar levels in Q4. As a reminder, this Canadian government program supports economic activity in all sectors of the economy and has allowed us to retain several positions within our organization by offsetting wage expense with support payments. Although the government has announced a commitment to extend this program through June 2021, they have not communicated the amount of the support the program will provide. In the US, drilling activity for precision averaged 22 rigs in Q3, a decrease of eight rigs from Q2 2020. Daily operating margins in the quarter were 12,297 US dollars, a decrease of 2,901 US dollars from Q2. Q3 margins were positively impacted by IBC revenue and turnkey margins, offset by higher daily operating costs due to lower fixed cost absorption. In addition, in Q2, we recognized early termination revenue of US$2,896 per day versus nil in Q3. Absent impacts from IBC, early termination, and turnkey, daily operating margins would have been approximately US$2,015 per day lower than Q2. For Q4, we expect margins to be supported by contracted rigs and IBC revenue and to generally be flat with Q3 levels. In Canada, drilling activity for precision averaged 18 rigs, a decrease of 24 rigs from Q3 2019. Daily operating margins in the quarter were $8,506 per day, an increase of $3,834 from Q3 2019. were supported by a strict focus on operating costs and Q's assistance payments. Absent the Q's impact, margins would have been $6,270 per day or $1,598 per day higher than Q3 last year. For Q4, we expect margins absent of Q's to be down slightly from last year, with strict cost control offsetting the overhead burden arising from lower activity. Internationally, Drilling activity for precision in the current quarter averaged six rigs, two fewer than Q2 2020. International average day rates were $54,887 per day, up approximately $100 from Q2, and $3,654 from the prior year, benefiting from the active rig mix during the current third quarter. All six of our rigs are contracted through 2021, and we expect financial performance to remain consistent through that period. In our C&P segment, adjusted EBITDA this quarter was $3.9 million, down 14.2% compared to the prior year quarter. Adjusted EBITDA was negatively impacted by a 55% decline in wealth service hours as a result of lower industry activity during the quarter. We expect results will improve in Q4, primarily a result of increased industry activity and additional work supported by the Canadian government's $1.7 billion wealth site abandonment and rehabilitation program. Capital expenditures for the quarter were $3 million, and our 2020 capital plan remains $48 million, a decrease of approximately 50% from the beginning of year guidance. The 2020 capital plan is comprised of $30 million for sustaining and infrastructure and $18 million for upgrade and expansion. As of October 21st, we had an average of 34 contracts in hand for the fourth quarter and an average of 42 contracts for the full year 2020. Moving to the balance sheet, we continue to reduce both absolute and net debt levels, primarily through free cash flow generation. Year-to-date, we have reduced our debt levels by $125 million through redemptions and open market purchases. Of note, we have drawn $97 million on our revolving credit facilities We utilize this facility to reduce our overall interest costs, preserve a strong cash balance, and to provide flexibility for continued debt repayment through 2022. As of October 21st, our senior note balances were as follows. Notes due 2023, 293 million U.S. dollars. Notes due 2024, 271 million U.S. dollars. And notes due 2026, 358 million U.S. dollars. As of September 30, 2020, our long-term debt position net of cash was approximately $1.2 billion, and our total liquidity position was over $700 million. Our net debt to trailing 12-month EBITDA ratio is approximately 3.8 times, and our average cost of debt is 6.5%. For the remainder of this year, we expect to continue generating free cash flow through operations and do not expect Incremental Benefit from Working Capital Release as activity is increasing in both the US and Canada. Liquidity remains a top priority, but we will continue to look for opportunities to reduce leverage. We remain on track to meet our longer-term debt reduction goal of $700 million between 2018 and 2022, and have already reduced debt by over $500 million since the beginning of 2018. We remain in compliance with all of our debt covenants with an EBITDA to interest coverage ratio of 2.9 times. And for 2020, we expect depreciation to be approximately $320 million. We now expect SG&A to be $55 million before share-based compensation expense. This guidance compares to the 2020 guidance provided in February of $90 million and in Q2 of $60 million. We expect cash and interest expense to be approximately $100 million for the year and to have an annual run rate of approximately $90 million going forward post Q3. We expect cash taxes to remain low and our effective tax rate to be in the 20% to 25% range. With that, I'll hand the call over to Kevin. Good afternoon. Thank you, Carey.

Well, to hear your precision, we are simply grinding through the toughest downturn in the history of the oil and gas industry. and while difficult at the time, I'm pleased that the swift and aggressive actions we took to address this downturn have resulted in better than expected financial results. I'm also very pleased that we continue to make strong progress towards our 2020 strategic goals, which I remind you were set well before the pandemic crisis began. It is the people of precision, most who do not have the option to work from home, who have continued to drive the strong operational results, the excellent pre-cash flow and the remarkable progress in our alpha technology rollout. I thank the whole of the Precision team for their dedication, commitment, and the results they've produced. That said, it seems like the worst may be behind us. We're beginning to see indications from our customers that their 2021 drilling plans and brick requirements will increase, at least modestly, for the lows of 2020. Furthermore, we have several clients now inquiring about longer-term contracts. We'll have more of this in a few minutes. Regarding our financial strategic objectives of leveraging our scale and generating free cash flow and reducing debt, as Carey detailed, We've made very good progress during the third quarter. What I want to add is that the entire precision organization is aligned on limiting our cash outflows, minimizing our spending, reducing our costs, leveraging our scale, and driving system efficiencies. All hands are focused on maximizing free cash flow. And I believe that our current fixed cost structure is optimized, and these efficiencies are evident in our financial results. As we look forward to the prospect of increasing activity With our current structure, we believe we can triple rig utilization with only nominal increases in fixed cost and G&A expenses. The operational torque and precision's earning capability has never been better, and we will demonstrate that earnings torque as activity improves in the coming quarters. With no foreseeable need to build new rigs, our pre-cash flow profile is strong, our long-term debt reduction targets are achievable, and importantly, our ability to generate strong shareholder value is well-structured. Regarding our third strategic priority to leverage our alpha technology platform, we remain fully on track to achieve this goal. Our strategy of working with industry partners to develop the apps, write the code, and debug the software while precision focuses on field deployment and customer value creation is really paying off in this downturn. The front-end fixed costs associated with the technology development are spread out among several partners, while precision's technology costs are largely captured in our rig support infrastructure, and we are essentially fully variable and linked to the revenues we achieve. Our partners see this technology development as key to their strategy, and the resources applied across our technology partnerships have not been impacted by the downturn. Now let me take a few minutes to update you on our alpha app progress. During the drilling and well construction process, there are hundreds of routine sequences, control actions, and decisions that the rig crew execute and repeat over and over. Most, if not all, of these processes can be controlled in a more efficient, repeatable, and consistent manner with or through an algorithm. These algorithms are set up as alpha apps, always with the goal of producing a consistent, repeatable, lowest cost wellbore construction program for our customers. With six alpha apps already commercial, are growing customer following and a dozen more in various stages of field testing. We see the opportunity to continue to grow the Alpha App universe to virtually every process, function, or activity related to the drilling operation. If you go to our website, you'll see several customer case studies detailing the successes achieved with Alpha Apps. In most cases, we are delivering double-digit percentage cost reductions or reducing drilling times on a days-per-well basis. The value of Alpha reducing costs for our customers is inarguable. The customers using and paying for Alpha range from super majors through our mid-sized customers to even our smallest private one-rig E&P customer. Half of our North American fleet is currently running Alpha. By the end of next year, 2021, I expect all of our operating super spec rigs will have Alpha delivering value to our customers and earning commercial returns for precision in our partners. Now, it's unimaginable that any customer will not want the cost benefit of these digital technologies as they continue to look ways to lower their costs. We expect Alpha will continue to drive our near-term market share growth and position us very well for the eventual recovery in land drilling. Now, turning to our markets, I'll start with Canada, where we are currently in the midst of a muted fall seasonal rebound in activity. Currently, we have 26 rigs running and 10 more scheduled to mobilize over the next couple of weeks. We expect our activity will trend to the upper 30s later this quarter. Natural gas in NGLs will drive customer demand into 2021 as the oil recovery takes longer. It's still early to project our expectations for the winter season, but our customers seem more optimistic than even just a few weeks ago. At this point, we're expecting activity peaking in the 50 to 60 range, for precision, but a lot can change between now and January. The recently announced approval of the NOVA gas transmission expansion will be a positive catalyst for the Canadian drilling as it further solves takeaway constraints in the Western Canada sedimentary basin. As we previously commented, the Montigny and Duvernay gas plays in Canada remain our best region. Precision enjoys strong market share due to our industry-leading fleet of super-triple padwalking rigs, This is a market which is also highly rational from a competition perspective, with just a couple of competitors in this rig class. All of our rigs are on multi-well pads, and our market penetration with alpha is increasing as our customers explore the capabilities of alpha to reduce overall well cost. I expect most, if not all, super triple rigs in Canada will be running alpha in 2021. The shallow oil regions in Canada, namely the Cardium, Viking, Southern Saskatchewan, and even heavy oil remain depressed. While activity has modestly improved from second quarter lows, this segment remains oversupplied, highly competitive, and rate challenged. Precision scale is a competitive advantage. Even with the challenge pricing, our shallower rigs deliver solid free cash flow. We expect this business segment to recover over the longer term, but only when oil prices improve. In the meantime, I expect substantial industry rationalization as fleet cannibalization and financial stress runs its course. And the industry is already restructuring in that while 24 drilling contractors are registered with the CAODC, over 80% of the rigs running today are from just five contractors. Overall, we believe the Canadian market offers precision a unique opportunity set. With our scale, our super triple rig fleet, our strong market share, Thank you for joining us. We have confirmed bookings which should bring our activity up to near 30 rigs running by the end of the year. We expect that momentum to continue into 2021. As I mentioned earlier, we are seeing a customer trend with asks that are shifting to longer contract terms with those customers trying to lock in lower market rates well into 2021. This is a very good market signal that our customers expect activity and rates to move up. But let us be clear, we don't see this as a full recovery. It is, however, a modest rebound We believe that if commodity prices, that's both oil and gas, hold in their current range, U.S. activity in 2021 will trend upwards. We are thinking that will be in the range of 15% to 20% above current levels. And we continue to expect the precision will gain market share during this time. The alpha app success I discussed earlier has been across our full U.S. customer base. We think all customers engaged in development drilling on multi-well pads will take a hard look at our alpha capability as they reactivate rigs. This will help drive our U.S. market share gains. So while rig demand is modestly improving, a full industry recovery will not occur until global oil demand recovers to near pre-pandemic levels and commodity prices move upwards to at least the mid-$50 range for WTI. Our customers, like ourselves, are highly focused on generating free cash flow and returning that cash to their investors. Higher commodity prices will improve customer cash flows, enable our customers to increase drilling while still demonstrating strong fiscal discipline. We believe the predominant themes of cost management, operational efficiency, well-bore manufacturing, and pad drilling are not going away. We also believe that our alpha technology suite combined with our super triple rigs will provide our customers with the value they need to continue to deliver to their investors. In our international drilling segment, as Carey said, Our rigs and contracts in Kuwait and Saudi Arabia remain steady. We are seeing a slow return to office by the national oil companies and are expecting that the increased bidding activity we are seeing should soon provide opportunities to reactivate some of our idle rigs. The most likely are the three idle ultra-spec rigs in Kuwait. We believe these rigs could be reactivated in early to mid-2021. But as with our North American market, the international recovery will be largely dependent on stronger oil prices. Turning to our well service business, we continue to benefit from our scale and the lean and mean cost structure we put in place a couple of years ago. Despite anemic customer demand and continued competitive pressures, we continue to generate free cash flow in this segment during the third quarter. The winter outlook has substantially improved with both more visibility on customer spending and the initial deployment of the $1.7 billion Canadian Well Reclamation Program. During the third quarter, Precision was successful, receiving almost 800 application approvals for funding various abandonment projects, and that's up from just a handful we talked about on our July earnings call. So today, we have seven incremental well service rigs working on well abandonments, and expect this number to climb to about 15 incremental rigs later this quarter. This program is creating jobs for our field workers, it's addressing the industry-wide problem of role abandonments, and for us, providing a solid base of activity in what was a deeply challenged sector. So to wrap up, all of us at Precision have worked very hard through the pandemic and the industry slowdown to preserve the value and service capabilities of our company for the benefit of all our shareholders and stakeholders. I believe the Precision team continues to deliver a remarkable result on all fronts, putting us in a very strong position to sustain our business through the downturn, ultimately positioning us firmly for the inevitable rebound when the world reopens. Thank you to all the people at Precision for the great work and all you are contributing. I'll now turn the call back to the operator for questions.

Ladies and gentlemen, if you have a question or comment at this time, please press the star then the one key on your touchtone telephone. If your question has been answered or you wish to move yourself from the queue, please press the pound key. Our first question comes from Taylor Zurcher with Tudor Pickering Holt.

Hey, good afternoon and thank you. My first question is on the comment you made, Kevin, about some of your customers in the U.S., or at least the trend towards wanting longer-term contracts and trying to lock in some of these lower rates on a leading-edge basis. I'm just curious, is there any sort of bucket of customer type that is leading that charge? Is it a diverse kind of array of bigger EMPs and smaller EMPs? And finally, any color on where the rates for some of that longer-term work is likely to shake out? Because I suspect it's going to shake out a little bit higher than the true leading-edge spot market rate.

Yeah, Taylor, I'd say first of all, to kind of address the first part of the question, we're kind of seeing it on a diverse mix of customers. Generally, it's customers that probably cut a little deeper than they needed to cut during the downturn. And now they've got, you know, they realize they can still demonstrate good fiscal discipline, but activate a few more rigs. So I think that's the common theme. Certainly, it's an opportunity by our customers to try to capture and lock in lower rates for a longer period. We see that trend. I really don't want to get into rates on today's call at any level. I would tell you that we do see very good market discipline right now. The competitive mix is quite limited. Really, just three or four or five contractors. We're not really dealing with... Thank you for joining us.

Thank you for joining us.

We expect it to be free cash flow positive before working capital benefit for every quarter this year, and that happened in Q3. We expect it to happen in Q4, and if you look at where analyst estimates are for next year, likely every quarter next year. So we'll have the optionality to use free cash flow from operations, cash on the balance sheet, and our revolver, and we'll look at each situation and pull one of those levers.

Awesome. Thanks for the responses.

Thanks, Taylor.

Our next question comes from Aaron McNeil with TD Securities.

Hey, guys. I'm just flipping back and forth between your Q2 and Q3 disclosures. I think you said you had signed 10 contracts year-to-date with Q2, and now it's 18. Obviously, I know you don't want to talk about rates, but can you give us a sense of term length, customer type, or other factors that you might consider? you think might be helpful?

So, Aaron, it's Kevin. I think, first of all, if we're announcing a contract, it'll likely be six months in term or longer. And I think we're leaning towards a shorter end right now. We don't want to lock in at a lower rate. We'd rather have some optionality on higher rates in the future. So I'd point you towards a shorter end of the range. Typically, those are six months, one year, two years. I'm pretty sure we haven't... Well, it's not quite true. The average will be probably in the one-year range.

Okay, that's helpful. Follow-up for me, there's been quite a bit of consolidation recently among USCMPs, and I'm obviously relying on third-party data here, but the four large transactions recently announced, you were previously working for six of the eight companies involved in those transactions as recently as January. You're not working for any of those companies Thank you very much.

I kind of go back and look at the Anadarko Occidental transaction. We had a strong position with Anadarko. The rigs were performing very well. Had Oxy not cut their drilling program, we likely would have those rigs still running today. So I don't think that was a function of the acquisition. I think it was a function of them cutting their program. As you look at the transactions that are in the market right now today, we think we're well positioned both with the companies that are being sold and the employees that were there, but also the buying companies. And don't expect any market share shifts that adversely affect our business from these transactions.

Eric, I would also add that our value proposition in terms of optimization and efficiency and being able to scale our operations really lends ourselves towards the larger E&P players. So we think The bigger some of these companies get, the more that they will be attractive to precision services.

Gotcha. Okay. Last question for me, more as it relates to kind of a 2021 outlook. Typically, you provide your strategic priorities, your CapEx, maybe December or early January. But in terms of your strategic priorities for next year, When do you think you'll release them and do you think they'll be materially different from the debt reduction, operational execution, and technology priorities you focused on this year?

So I won't front run the news for later in the year, but what I would tell you is that debt reduction is not going to come off our priority list for at least a couple more years. I'd also comment that our work around operational efficiency, operational effectiveness, leveraging our scale, That's not going to lose any attention anywhere, probably ever in our future, but certainly not in the next few years. The short answer is we'll be on the path to reducing debt and improving equity value for our equity holders for a long time yet.

Thanks, guys. I'll turn it over.

Thank you.

Our next question comes from Kurt Felide with RBC.

Hey, guys. How's everything going?

Good, Kurt. How are you today?

I'm doing all right. Doing all right, thanks. As should you with the stock up on the day, all right? So, hey, Kevin, that's pretty constructive commentary. You know, I had one of your peers on a conference call earlier today also talk about some positive momentum on the drilling front with some visibility. out into the early part of 2021. Obviously that commentary was specific to the U.S. So it sounds like there's some agreement generally in the overall direction of the market in the U.S. I think the other comment that came out that was pretty consistent with what you said was pretty good pricing discipline on that front. And this competitor effectively suggested that day rates were looking to stick somewhere north of $20,000 a day. So maybe with that as a backdrop, Kevin, as you go out into next year and we see some improvement in overall drilling activity, I know there's some general concerns out in the marketplace about some of these drilling contractors maybe getting a little bit too anxious to put some idle rigs back into the market and maybe not having the same level of discipline that you'd expect out of a fairly – Thank you for joining us.

Q2 conference callers, just a handful of customers. We're talking to quite a few customers. But generally, the competitors that we're seeing right now kind of fall into the top three or four public large drilling contractors. So, you know, we're really not coming up against any of the smaller contractors. These are all going to be development drilling programs. They're all super spec rigs that are 7500 PSI, padwalking, you know, large racking systems, and technology is in every single conversation. There simply aren't that many other drilling contractors that can have those conversations. The competitors we're dealing with are quite disciplined. I think we know each other quite well in the marketplace. We each have our value proposition. I think we all are looking to drive EBITDA and drive returns for our investors and Little less focused on share, but market share ends up being a result of the things we're doing.

Okay, that sounds good. So in the context of the overall Canadian market, how do you try to assess the opportunity kind of going forward, right? I mean, you're the biggest player in the market, unlikely in getting kind of bigger than that. How do you foresee the possibility of additional consolidation in the Canadian drilling market?

You know, it's a bit like the U.S. in that there's five drillers. I think it's 84% of their active rigs in Canada right now. There's going to be rationalization one way or another. I think the first phase is rigs can be cannibalized and eventually become non-marketable. I think... You may see a few small companies either sell to someone trying to create some scale. So I don't think you see larger public companies driving consolidation early in this kind of recovery period or even through this downturn in Canada. I think the larger companies have positions that are strong and they feel pretty good about it. Certainly we do. We don't plan to do anything in the Canadian market other than kind of maximize free cash flow. But I don't know that we need to have 25 drilling contractors in Canada. The market says right now it needs five. I think that's the way things play out. If you look at the deep basin where we're making most of our money right now, that's Montigny-Drivenet and the deep basin, there's really just three contractors that have super triple rigs. And I think we're probably the only contractor right now that's running a mature, sustained automation and technology program. So I think competition is going to drive a smaller and smaller set of people who can compete. And then you may see some kind of at the lower end of the scale consolidation trying to create scale. But that scale doesn't solve the asset liability those companies will have or the technology problem gap they're going to have.

And Kurt, I'll add that that's kind of the look going forward, but in the 2016 and 2019 Again, ladies and gentlemen, if you have a question or a comment at this time, please press the stars and the one key on your touchtone telephone.

Our next question comes from Cole Pereira with Stiefel.

Hey, afternoon, guys. So we've all kind of heard a lot of commentary around US oil producers, you know, spending minimal growth capex until WTI hits, call it maybe $50. With some of the recent strength in NYMEX gas, can you just talk about how conversation with some of your gas clients in the US have been going and how you might see some of those dynamics playing out from an activity standpoint in 2021?

Sure, Cole. If you just kind of look back even to our Q2 conference call, even back then we talked about the expected increase in activity to be driven largely by gas. With 25 rigs running today, I think our gas mix has moved up a little bit from where it was earlier this year. So clearly kind of this early move we've been seeing in the U.S. has been driven by gas. And I think we'll pick up a couple of oil rigs yet between now and the end of the year. So I think... Most of what we'll see in 2024 rig additions from the trough, I'd say probably two-thirds gas, one-third oil.

Gotcha. That's helpful. Thanks. Moving on to Canada, as we just think about Q1, you guys have always had a great market share on some of the oil sands coring work. Can you maybe just share how some of that is firming up for the quarter just with the lower oil price quote?

It seems to be starting out a little bit slow, and our customers seem to be waiting to see if they might get a better bid on oil later in the season. And those decisions could be delayed even as late as the first week of January. Those rigs can be fired up on a couple days' notice. So far, with the pricing in place right now, discussions are slow. Hence my comments and the prepared comments around... Thank you for joining us. We know our customers need to replace production. They need to drill wells, but they're going to throttle that carefully with commodity prices.

Gotcha. Yeah, that's good color.

Let me add one more comment to that. I was just thinking as I said that, though, but what's happening is there is a backlog of drilling that's building and building, and when commodity prices do bump up just a little bit, there's going to be a surge of heavy oil stratification drilling, and Like all of these oil and gas drilling gaps, when you stop exploring and stop drilling for a sustained period of time, that creates a larger and larger rebound on the backside. So those wells are going to get drilled. And if they don't get drilled this year, they might get drilled next year, but there will be a larger recovery period if we delay through this year. Sorry for the long answer.

No, that's great detail. Carey, you made a comment earlier that... If you triple your rig count, you don't see much of a change to fixed costs and G&A. Would it be fair to say under that same kind of guise that you would see maintenance capital staying in that 30 to 35 range, if that makes sense?

No. So maintenance capital would be completely correlated with activity levels. So we would see our maintenance capital go up proportionally with rig activity. And think of it as kind of $1,500 to $1,800 a day. for Drilling Day.

Okay, got it. That makes sense. That's all for me, guys. Thanks for the questions. I'll turn it back. Thank you, Cole.

Our next question comes from Blake Jindra with Wolf Research.

Hey, thanks. Thanks. Good afternoon, guys. I might have misheard, but I think you did mention attrition earlier on in the call and the prepared remarks. Drilling Corporation, Carey Thomas Ford, Lavonne Zdunich, and how do you expect it to evolve? Could we presumably see maybe more obsolescence as well construction and design continues to scale and things like floor clearance and other specs are more important?

Blake, we really didn't address the quality or the age or the relevance of the super spec fleet and I guess what makes it even more complex, there really is no agreed upon definition of what constitutes super spec. For sure I can guarantee that all of the AC rigs in the U.S. are not leading edge super spec. So I'll throw a definition out there I'll speak to for a second. And what we view at Precision right now is leading edge spec, super spec rig would be a 12 or 1500 horsepower rig that is powered digitally through an AC system. It will have three mud pumps configured for 7,500 PSI. It'll do long-reach horizontal drilling. It will have a pad-walking system to walk in X, Y directions. Now, I can tell you, not all of our AC rigs meet every checkmark on that, but the amount of capital to make it do that is de minimis for our fleet. When you look across the U.S. fleet of AC rigs, some of those rigs were built, you know, really back just past the turn of the century, back in 2002, 2003. So for sure, some of those rigs probably don't have three mud pumps and 7,500 PSI in the racking capacity. So I guess you could call it technical obsolescence for some of these rigs where the age of the rig plus the upgrade cost probably makes them obsolete. We haven't done that analysis on the U.S. rig fleet in several months, certainly not through this downturn, but I think that's something we'll do in 2021 so we understand how the fleet looks as the market begins to rebound. It does seem like there is no The supply of leading-edge SuperSpec rigs is not limitless. And the location of the rig plays into the day rate we can get. If we've got a rig nearby a location that meets SuperSpec, we can for sure get a higher day rate than one that might be a basin away.

I would just add, I think Kevin's comments about attrition in both the U.S. and Canadian fleet has more to do with financial constraints of competitors. where if they don't have the funds to keep rigs well maintained and to buy new critical components when they wear out, typically they will take them off of idle rigs and effectively leaving those idle rigs as not workable.

Understood. I must have misheard or misconstrued what I heard. I wanted to focus on the shallow basins and the elasticity to oil. I thought it was interesting you said that these rigs are Thank you for joining us. in the Cardium of the Viking and Saskatchewan, these shallower basins. Your best guess, I know it's seasonal, but it would be helpful to maybe understand how your customers might be thinking right now.

Okay, I'll take the first part of that on the cash generation of the shallower rigs. So the day rates are going to be a little bit lower than what we would see with the super triples that are working in the Montney and the DuVernay rigs. but the operating cost is a bit lower and the maintenance capital spending is a bit lower. So even though the day rates are lower than the super triples, we get a better cash or comparable cash return on some of those shallower rigs.

And when you layer in the scale effect of a large drill of precision that has vertical integration through our supply chain, through our repair and maintenance systems and services, we can probably operate those rigs Anywhere from $1,000 to $2,000 a day, cheaper than most of our peers.

Got it. Thanks, guys.

Our next question comes from John Gibson with BMO Capital Markets.

Thanks, and good afternoon, guys. I know you don't want to get into exact dairy discussions, but when you think about adding rigs across North America towards the end of the year and even next year, would these mostly be rigs that are currently racked on site or purely new bid ops?

John, good question. In Canada, good likelihood some are racked on site or racked close to location. In the U.S., more likely the rigs are racked somewhere in the field and not necessarily on location.

Okay, great. And are you still seeing a large difference between renewal and new bid ops in terms of pricing?

Yeah, we are. You know, the switching cost on a renewal is playing out quite nicely for us. On renewals, we're certainly able to get a rate much closer to the prior rate than on a new startup because renewals They move our rig off location, bring another rig onto location. They've got the moving costs, both directions, plus they've got the crew acclimation and training, getting up to speed, getting up to efficiency. So that does give us a pretty meaningful advantage on renewals. I think that we're about to publish a case study actually on the switching costs for rigs. It'll be on our website shortly. You can look it up because you have good clarity on switching costs.

Okay, sounds good. And then just last one for me. So you received $8 million in queues this quarter. Let's just say in a world without queues, but we're still dealing with COVID, how much do you think you could recover of this $8 million in terms of just further cost improvements that you would have undertaken had you not received them?

Yeah, I don't think – we're not going to point to an exact number, but it would be meaningful. Okay.

I would tell you that especially in our well-serviced group and in the field, we've been able to run a bunch of small little projects in-house that we wouldn't have done otherwise. We've created jobs for blue-collar workers in the field and in our yards, and I'm really happy about that. So I'm happy with the effectiveness of the program and the fact that we get a bit of maintenance work done that's important for us too. So there's a good benefit to that program right now, and we'll certainly take advantage of it.

Okay, great. Thanks, and I'll turn it back.

Thank you.

Our next question comes from Jeff Patterley with Peterson Company.

Good afternoon, guys. A couple of random questions on the drilling side. In terms of the incremental rig adds, I know you talked about the gas-oil mix earlier, but more specifically, both on the U.S. and the Canadian side, where do you see those incremental rigs going?

So we'll, in Canada there'll be a couple more rigs activating in Montigny, Duvernay, and then the balance will be spread around the province. So I don't have the numbers right in front of me. And in the U.S., a couple in D.J. Basin, one or two in the Permian, and then the balance will be gas directed.

And the gas directed, is that And on the Canadian side, as you move to a peak rig count in Q1 in that 50 to 60 range as you talked about, are most of the incremental rigs going to be in oil or call it regions outside of the Montney, Duvernay and Deep Basin or is there going to continue to be that bias?

I think that we've had a high activity level in the Montigny-Dupernay region even right now. So most of the incremental rigs will get a handful, a couple more in the Montigny-Dupernay, but the balance will be outside those deep basin regions.

In the delineation reference you made before about some pent-up demand, do you think that starts to show up in your Q1 activity on the super single sites?

Well, you know, Jeff, it did a little bit back in January, February of this year. We had certainly a higher rig count this Q1 behind us, driven by, you know, SAGD and heavy oil drilling. And that's after three years of really low drilling levels. So I would tell you that the likely swing in drilling this coming 2020 winter season, 2021 winter season, If we're at the high end, closer to 60 or even getting over 60, it'll be because that delineation and safety drilling picks up. If we're at the lower end, closer to 50, it's because it doesn't.

A clarification on the rationalization side. So I know you're referenced to the Canadian side specifically, but how do you think about your fleet in terms of productivity and rationalization on a go-forward basis?

both Canada and U.S. You know, this downturn has come so quickly and so sharply that we really haven't changed our strategic view on our fleet. We think our fleet's well positioned. We think we're taking the right steps from an accounting perspective to value the fleet properly. You know, as the dust settles on 2021 budgets and we kind of get a sense of what the recovery looks like longer term, if there's any changes to the fleet orientation, we'll certainly let the market know.

Yeah, and Jeff, I just remind you, we've decommissioned over 200 rigs in the past eight years. And if you look at utilization levels, if you just look at, let's say, pre-pandemic Q4, Q1, the utilization level of our fleet in Canada was the highest of all the contractors. And in the U.S., I believe we were either one or two out of all the contractors. So we think it's, at least compared to the rest of the drilling contractor universe, it's the most relevant.

And last thing, on the U.S. side, what is your contract coverage for Q1 of 2021?

Let's see. We actually have not disclosed that. I think we just disclosed annually 2021. So for annually, we have 18 total rigs under contract and seven for the year. So obviously it'll be higher in Q1 and these are just contracts in hand today and as we move closer towards the end of the year and into Q1 we'll be building up that contract book.

And so how do you think about mitigating the day rate impact on your U.S. fleet given your contract profile is dropping as significantly as it is set to as of today?

Yeah, so I mean I think that's part of the drilling business, Jeff. We've We obviously significantly reduced our cost structure. We focused on our field operating cost. We have managed our existing contract book, and on new rig opportunities, we'll balance both the day rate that's available on the spot market versus one that we're willing to turn it into for a six-month, two-year contract.

I guess what I'm also trying to get at there is, to the question earlier about some rigs that are racked, on location or the difference in pricing between greenfield spot and renewals. Is there a meaningful number of those 24 rigs that you have under contract for Q4 that you think are likely to roll over onto a new contract to build that 2021 number and therefore protect you from leading edge?

That's a big part of it. We've seen that happen here over the past six months. A lot of our new contracts have been and existing rigs that are rolling over into new contracts.

Thanks for the call. I appreciate it. Thanks, John.

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

Thank you all for joining today's call. Look forward to speaking with you when we report our 2020 year-end results in February.

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