Precision Drilling Corp (PDS) 2020 Q3 法說會逐字稿

Ladies and gentlemen, thank you for standing by and welcome to the Precision Drilling Corporation 2020 Third Quarter Results Conference Call and webcast. (Operator Instructions)

I would now like to introduce your host for today's conference call, Mr. Dustin Honing, Manager, 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 Neveu, 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 CEWS 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 cost from the guidance provided at the beginning of the year. Cost reduction and cash preservation will continue to be priorities throughout our organization.

Precision's participation in the CEWS program continued in Q3. We recognized $8 million in CEWS 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 amounts of the support that the program will provide.

In the U.S., drilling activity for Precision averaged 22 rigs in Q3, a decrease of 8 rigs from Q2 2020. Daily operating margins in the quarter were USD 12,297, a decrease of USD 2,901 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 USD 2,896 per day versus nil in Q3. Absent impacts from IBC, early termination and turnkey, daily operating margins would have been approximately USD 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. Margins were supported by a strict focus on operating costs and CEWS assistance payments. Absent the CEWS' 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 CEWS 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 6 rigs, 2 fewer than Q2 2020.

International average day rates were USD 54,887 per day, up approximately USD 100 from Q2 and $3,654 from the prior year, benefiting from the active rig mix during the current third quarter. All 6 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 well 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 well 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 the 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 21, 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 USD 97 million on our revolving credit facility, which matures in November 2023. We utilized 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 21, our senior note balances were as follows: notes due 2023, USD 293 million; notes due 2024, USD 271 million; and notes due 2026, USD 358 million. 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 3.8x, and our average cost of debt is 6.5%.

For the remainder of this year, we do not expect to -- 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 U.S. and Canada. Liquidity remains a top priority, but we'll 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 2.9x. 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 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, and thank you, Carey. Well, here at 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 am 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'll 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 free cash flow and the remarkable progress in our Alpha technology rollout. I thank the whole of Precision team for their dedication, commitment and the results they 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 rig requirements will increase at least modestly from the lows of 2020. Furthermore, we have several clients now inquiring about longer-term contracts, and we'll have more on this in a few minutes.

Regarding our financial strategic objectives of leveraging our scale and generating free cash flow, 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 in 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 free 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 AlphaApp 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 AlphaApps, always with the goal of producing a consistent, repeatable, lowest-cost wellbore construction program for our customers.

With 6 AlphaApps already commercial, our growing customer following and a dozen more in various stages of field testing, we see the opportunity to continue to grow the AlphaApp 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 AlphaApps. 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 customer is using and paying for Alpha range from super majors through our midsized customers to even our smallest private 1 rig E&P customer.

Half of our American fleet -- 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 and 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 and 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 current -- 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've previously commented, the Montney and Duvernay gas plays in Canada remain our best region. Precision enjoys strong market share due to our industry-leading fleet of Super Triple pad walking 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 with -- 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's scale is a competitive advantage. Even with the challenged 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 5 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, and with little need for capital investment, we will continue to generate strong free cash flow to the benefit of our investors. And furthermore, Precision will remain in a very strong competitive position when this market improves.

In the U.S., our activity has modestly lagged the guidance we provided on our second quarter earnings call. The commodity price volatility during the quarter delayed some projects. But today, we can report 25 rigs running and 7 others on IBC. 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 the 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 to continue -- that Precision will gain market share during this time.

The AlphaApps 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, and 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, wellbore 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 3 idle ultra spec rigs in Kuwait, and 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 have put in place a couple of years ago. Despite anemic customer demand and continued competitive pressures, we continued 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 various -- funding various abandonment projects, and that's up from just a handful we talked about on our July earnings call.

So today, we have 7 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 well 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 share- 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.

(Operator Instructions) Our first question comes from Taylor Zurcher with Tudor, Pickering, Holt.

My first question is on the comment you made, Kevin, about some of your customers in the U.S. or at least a trend towards wanting longer-term contracts and trying to lock in some of these lower rates on a leading-edge basis. And 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 E&Ps and smaller E&Ps? 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.

Yes. 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 -- 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 3 or 4 or 5 contractors. We're not really dealing with non-super spec rig competition right now. So I think it's a fairly disciplined market. And we feel pretty good about where oil pricing is sitting now. And I think as we see this demand continue to strengthen, we'll remain disciplined.

Fair enough. And my follow-up is on the balance sheet. You've continued to generate really strong free cash flow and accelerate the debt paydown targets or progress. When it comes to the incremental debt paydown from here, should we expect further debt paydown to be more coming from cash on the balance sheet? Or are you comfortable continuing to draw on the credit facility to at least retire some additional debt in the near term?

Taylor, it's Carey. So I would just say that we have a lot of optionality. I mentioned last quarter that we expected 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 then we'll look at each situation and pull one of those levers.

Next question comes from Aaron MacNeil with TD Securities.

Just flipping back and forth between your Q2 and Q3 disclosures, and 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 think might be helpful?

So Aaron, it's Kevin. I think first of all, if we're announcing a contract it will likely be 6 months in term or longer. And I think we're leaning towards a shorter end. Right now, we don't lock in at a lower rate. We'd rather have some optionality on higher rates in the future. So I'd point you towards the shorter end of the range. Typically, those are 6-month, 1 year, 2 years. I'm pretty sure we haven't -- it's not quite true; the average will be probably in the 1-year range.

Okay. That's helpful. Follow-up for me: There's been quite a bit of consolidation recently among U.S. E&Ps and I'm obviously relying on third-party data here, but the 4 large transactions recently announced, you were previously working for 6 of the 8 companies involved in those transactions as recently as January. You're not working for any of those companies today. But from a market share perspective, do you consider your relationships with some of the combined entities now secondary to some of your competitors? And are you at all concerned that your market share might be negatively impacted as these larger companies comprise an increasing percentage of overall spending in activity?

I don't think the transactions are going to affect our market share. Certainly, the rapid downturn did impact our market share. And 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. It was a function of them cutting their program.

As we 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.

Yes, Aaron, can I just -- I would also add that our value proposition in terms of optimization and efficiency and being able to scale our operation, 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.

Got you. 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 news for later in the year. But what I would tell you is that debt reduction is not going to come off of 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 answer is, we'll be on the path to reducing debt and improving equity value for our equity holders for a long time.

Our next question comes from Kurt Hallead with RBC.

Kevin, it's pretty constructive commentary. 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 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 consolidated market dynamics.

So I don't know, how do you gauge that? And what kind of discussions -- what kind of insights could you give us around some of the discussions you've been having with your customers, both in terms of pace and potential magnitude of improved activity?

Kurt, I think the answer is obviously complex. Lots of -- there are actually quite a few customers we're talking to right now, and that's a little different from even our Q2 conference call where it was 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 3 or 4 public large drilling contractors. So 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 7,500 psi, pad walking, large racking systems. And technology is in every single conversation.

So that's not the -- there simply aren't that many other drilling contractors that are going to have those conversations. So it's -- 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 a little less focused on share, but market share ends up being a result of 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 you can get any kind of bigger than that. How do you foresee the possibility of additional consolidation in the Canadian drilling market?

It's a bit like U.S. in that there's 5 drillers. We said they have a -- 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 get cannibalized and eventually become nonmarketable. 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. 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. Our market says right now it needs 5. 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 Montney, Duvernay and the Deep Basin. There's really just 3 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 that -- 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 to 2019 timeframe, there was one very large consolidating transaction and there were 2 or 3 other kind of next step down consolidating transactions. So there haven't been a lot of deals. But as Kevin said, there's probably more to come.

(Operator Instructions) Our next question comes from Cole Pereira with Stifel.

So we've all kind of heard a lot of commentary around U.S. oil producers 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 conversations with some of your gas clients in the U.S. 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 we're -- 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 2020 for our rig additions from the trough, I'd say probably 2/3 gas, 1/3 oil.

Got you. That's helpful. 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. And 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. We can -- those rigs can be fired up on a couple of days' notice. So far with the pricing in place right now, it's -- discussions are slow. Hence, my comments in the prepared comments around kind of grouping heavy oil with other shallow plays in Canada. Typically, I break those out separately. But right now, demand seems to be soft.

But that could change. We could see a surge even later this year or early in January. So I can comment that there's been almost a 3-year gap in heavy oil drilling. We saw a little bit of a bump up early this year in the start of the winter season, actually such a bump up that it even caught us by surprise a little bit in January. But we know our customers need to replace production, they need to drill wells, but they're going to throttle that carefully with commodity prices.

Got you. Yes, that's good color.

Let me add more comment to that. I'm 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. If you 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 to 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 in G&A. Would it be fair to say, under that same kind of guys, 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 proportionately with rig activity. And think of it as kind of $1,500, $1,800 a day per drilling day.

Our next question comes from Blake Gendron with Wolfe Research.

I might have misheard, but I think you did mention attrition earlier on in the call in the prepared remarks. Maybe you didn't, but it's typically an on phrase we hear on the rig side and more so on the frac side. Just wondering how that's manifesting in the super-spec contingent maybe in the U.S., is this attrition of equipment? Is it attrition by obsolescence? Is it attrition just on the competitor side and just peers going out of business? 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 that 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 1,200 or 1,500 horsepower rig that is powered digitally through an AC system. It will have 3-month pumps configured for 7,500 psi. It'll do long-reach horizontal drilling, and we'll 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 really back -- just past the turn of the century back in 2002, 2003. So for sure, some of those rigs probably don't have 3-month 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 some 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 super-spec rigs is not limitless. And the location of the rig plays into the day rate we can get up. We've got a rig nearby a location that meets super spec we can, for sure, get a higher day rate than one that might be a basin away.

Yes. And I would just add, I think, Kevin's comments about attrition in -- both in U.S. and Canadian fleet has more to do with the 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. Wanted to focus on the shallow basins and the elasticity to oil. I thought it was interesting you said that these rigs are pretty highly cash-generative. All things considered, you leverage your scale against some smaller regional competitors. I'd imagine you have to be pretty competitive on price. So can you give us an idea, first, as to how cash-generative these rigs are relative to, say, some of the Deep Basin rigs that have a bit more visibility, but are more expensive to run on the super-spec side? And then your thoughts around activity levels in these basins relative to the oil price. So what is the elasticity in the Cardium and 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. But the operating cost is a bit lower and the maintenance capital spending is a bit lower. So given that 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 driller like Precision that has vertical integration through our supply chain, through our repair and maintenance systems and services, we could probably operate those rigs anywhere from $1,000 to $2,000 a day cheaper than most of our peers.

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

I know you don't want to get into exact day-rate discussions. But when you think about adding rigs across North America towards the end of the year and even in next year, would these mostly be rigs that are currently racked on-site or clearly new bid ops?

John, good question. In Canada, good likelihood some are racked on sites or racked most of the location. In the U.S. more likely the rigs are racked somewhere in the field, but not necessarily on location.

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

Yes, we are. The switching cost on the renewals is playing out quite nicely for us. So renewals, we're certainly able to get rate much closer to the prior rate than on a new start-up because if they move our rig off location, bring another rig onto location, they've got their moving cost in both directions, plus they've got the crew acclimation and training, getting up to speed, getting up the efficiency. So that does give us pretty meaningful advantage on renewals.

I think that we're about to publish a case study actually on the switching cost per rig. So that will be on our website shortly. You can look at that; [it] gives you good clarity on switching costs.

Okay. Sounds good. And then just last one for me. So you received $8 million in CEWS this quarter. Let's just say in a world without CEWS, but we're still dealing with COVID, how much would you -- 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?

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

I would tell you that the -- especially in our well service 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 and 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 it's -- there's a good benefit to that program right now, and we'll certainly take advantage of it.

The next question comes from Jeff Fetterly with Peters & Co.

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 Montney, 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 DJ Basin, 1 or 2 in the Permian and then the balance will be gas-directed.

In the gas-directed, is that predominantly (inaudible) --

[Angel] and Marcellus.

-- or is that Northeast?

It's both.

Okay. 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, is -- 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?

Well, I think that we've had a high activity level in that Montney, Duvernay region even right now. So most of the incremental rigs, we'll get a handful -- a couple more in the Montney, Duvernay with balance will be outside those Deep Basin regions.

And 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 side?

Well, Jeff, it did a little bit in -- back in January, February of this year, we had certainly a higher rig count this Q1 behind us, driven by SAGD and heavy oil drilling. And that's after 3 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 -- if the high end, closer to 60% or even getting over 60%, it will be because that delineation and SAGD drilling picks up. If we're at the lower end, closer to 50, it's because it doesn't.

Clarification on the rationalization side. So I know you 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.?

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 is well positioned. We think we're taking the right steps from an accounting productive to value the fleet properly. 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.

Yes. And Jeff, I'd just remind you, we've decommissioned over 200 rigs in the past 8 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 1 or 2 out of all the contractors. So we think 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. I think we've just disclosed annually 2021. So for annually, we have 18 total rigs under contract and 7 for the year. So obviously, it will be higher in Q1, as 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?

Yes. So I mean, I think that's part of the drilling business, Jeff. We've 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 in the spot market versus one that we're willing to enter into for a 6-month-to-2-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 6 months. A lot of our new contracts have been existing rigs that are rolling over into new contracts.

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

Thank you all for joining today's call. We 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.