PRECISION DRILLING Corp Q3 FY2020 Earnings Call

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 0 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 the 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 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, and 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 2.9x. 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. Here at Precision, we are navigating through one of the toughest downturns in the history of the oil and gas industry. Although this period has been challenging, I'm happy to report that the swift and decisive actions we took to combat this downturn resulted in better-than-expected financial outcomes. I'm also glad to see that we are making significant strides toward our 2020 strategic goals, which were established well before the pandemic started. The hardworking team at Precision, many of whom cannot work from home, has been key to our strong operational results, excellent free cash flow, and impressive progress in rolling out our Alpha technology. I appreciate the entire Precision team for their dedication and the results they have achieved. It appears the worst may be behind us, as we're starting to see signs from our customers indicating an increase in their drilling plans and rig requirements for the rest of 2020. Several clients are also inquiring about longer-term contracts, which I will discuss further shortly. In terms of our financial strategic objectives, we are effectively leveraging our scale and generating free cash flow while reducing debt, as Carey mentioned. We made solid progress in this area during the third quarter. I want to emphasize that Precision is unified in limiting cash outflows, minimizing expenditures, reducing costs, maximizing free cash flow, and enhancing system efficiencies. I believe our current fixed cost structure is optimized, as reflected in our financial performance. Looking ahead, we think we can achieve a threefold increase in rig utilization with only minor increases in fixed costs and general and administrative expenses. The operational efficiency and earning potential of Precision have never been stronger, and we anticipate demonstrating this capability as activity ramps up in the coming quarters. With no immediate need to build new rigs, our free cash flow outlook is robust, our long-term debt reduction goals are within reach, and we are well-positioned to generate significant value for our shareholders. Regarding our strategic goal to leverage our Alpha technology platform, we remain on course to achieve this objective. Our collaboration with industry partners to develop applications, write code, and debug software while focusing on field deployment and adding customer value is proving effective during this downturn. The fixed costs associated with technology development are shared among various partners, while Precision's tech costs are largely linked to our rig support infrastructure, thus being variable in nature and tied to our revenues. Our partners view this technology development as essential to their strategies, and our efforts in this area have not been hindered by the downturn. Now, let me take a moment to update you on our AlphaApp progress. During the drilling and well construction process, there are numerous routine sequences and decisions that the rig crew executes repeatedly. Most of these processes can be done more efficiently and consistently using algorithms, which we have set up as AlphaApps, with the aim of producing cost-effective wellbore construction programs for our customers. With six AlphaApps already in use, growing customer interest, and many more in various testing stages, we see the potential to expand the AlphaApp scope to nearly every process related to drilling operations. Our website showcases several customer case studies highlighting the successes achieved with AlphaApps, where we typically deliver substantial cost reductions and improved drilling times. The savings offered by Alpha technology is undeniable, appealing to a wide range of customers from supermajors to smaller independent operators. Currently, half of our North American fleet is utilizing Alpha technology, and I anticipate that by the end of 2021, all of our operating super-spec rigs will be employing Alpha, benefiting our customers and generating returns for Precision and our partners. I believe it is unlikely that any customer would overlook the cost advantages provided by these digital technologies as they seek ways to control expenses. We expect Alpha will contribute to our market share growth in the near term and position us favorably for the eventual recovery in land drilling. Now, let’s shift to the markets. I'll begin with Canada, where we are experiencing a modest rebound in activity for the fall season. We currently have 26 rigs operational with another 10 set to mobilize in the coming weeks. We anticipate that our activity will rise to the upper 30s later this quarter. Natural gas and NGLs will drive demand into 2021, as the recovery in oil takes longer. While it's still early to firmly predict our winter season expectations, customer sentiment appears more optimistic than just a few weeks ago. We're forecasting that our activity could peak in the range of 50 to 60 rigs, although conditions may change between now and January. The recent approval of the NOVA Gas Transmission expansion will positively impact Canadian drilling by resolving takeaway constraints in the Western Canada sedimentary basin. As we've noted before, the Montney and Duvernay gas plays continue to be our best regions. Precision holds a strong market share due to our leading fleet of Super Triple pad walking rigs in a highly rational competitive landscape with only a few competitors in this rig class. All our rigs operate on multi-well pads, and our market penetration with Alpha is growing, as customers explore its capacity to lower overall well costs. I expect that most, if not all, Super Triple rigs in Canada will run Alpha in 2021. Conversely, the shallow oil regions in Canada, such as the Cardium, Viking, Southern Saskatchewan, and heavy oil areas remain sluggish. While activity has improved modestly from the lows of the second quarter, this segment continues to be oversupplied and highly competitive, presenting pricing challenges. Precision's scale provides a competitive edge, enabling our shallower rigs to maintain solid free cash flow, and we anticipate this segment will recover when oil prices rise. In the interim, I foresee significant industry rationalization as fleet reductions and financial challenges unfold. Currently, even though there are 24 drilling contractors registered with the CAODC, over 80% of the rigs in operation are owned by just five contractors. Collectively, we believe the Canadian market presents Precision with a unique set of opportunities. With our scale, Super Triple rig fleet, and strong market share, we will continue to generate robust free cash flow for our investors without needing substantial capital investment, thus allowing Precision to maintain a strong competitive position as the market improves. In the U.S., our activity levels have not quite matched the guidance we set during our second quarter call, as commodity price fluctuations during the quarter postponed some projects. As of now, we have 25 rigs running and 7 additional rigs in the process of being mobilized. We have confirmed bookings that should bring our operational count close to 30 rigs by year’s end, and we expect momentum to carry into 2021. I previously mentioned a trend where customers are shifting towards longer contract terms to secure lower market rates extending well into 2021, which signals positive expectations for activity and rates rising. However, we do not perceive this as a full rebound, but rather a moderate recovery. If commodity prices, for both oil and gas, remain stable, we foresee U.S. activity in 2021 trending upward in the range of 15% to 20% above current levels. We also anticipate that Precision will capture market share during this period. The success of AlphaApps, which I highlighted earlier, has been evident across our entire U.S. client base. We believe that all customers involved in development drilling on multi-well pads will be keen to assess our Alpha capabilities as they reactivate rigs, which will promote our U.S. market share growth. While rig demand is showing modest improvement, a full recovery of the industry will hinge on a return to pre-pandemic global oil demand levels and rising commodity prices, ideally reaching at least the mid-$50 range for WTI. Our customers, like us, are focused on achieving free cash flow and rewarding their investors. Higher commodity prices will enhance customer cash flows, allowing for increased drilling while maintaining financial discipline. We are confident that themes of cost management, operational efficiency, and innovative drilling methods are here to stay. We also believe that our Alpha technology, combined with our Super Triple rigs, will deliver the value our customers require to provide for their investors. In our international drilling segment, our contracts in Kuwait and Saudi Arabia remain steady. We are observing a slow return to office operations among national oil companies and expect increased bidding activity to soon create opportunities for reactivating some of our idle rigs, particularly three ultra spec rigs in Kuwait, which we believe could be brought back online in early to mid-2021. However, similar to our North American market, international recovery will largely depend on higher oil prices. Regarding our well service business, we continue to benefit from our scale and the streamlined cost structure established in previous years. Despite low customer demand and ongoing competitive pressures, we managed to generate free cash flow in this segment during the third quarter. The winter outlook has improved significantly with greater clarity on customer spending and the early rollout of the $1.7 billion Canadian well reclamation initiative. In the third quarter, Precision successfully secured nearly 800 application approvals for various funding related to abandonment projects, a notable increase from just a few reported during our July earnings call. Consequently, we now have several well service rigs working on abandonment tasks, with this number expected to grow to around 15 additional rigs later this quarter. This program not only creates jobs for our field workers but also tackles the industry-wide challenge of well abandonments, providing us with a solid foundation of activity in what has been a very tough sector. In conclusion, everyone at Precision has worked diligently to preserve the value and service capabilities of our company throughout the pandemic and industry slowdown for the benefit of our shareholders and stakeholders. I believe that the Precision team has achieved remarkable results across all fronts, positioning us strongly to sustain our business through this downturn and prepare us for the inevitable rebound when the world reopens. Thank you to the entire Precision team for your hard work and contributions. I will now turn the call back to the operator for questions.

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, right?

Yes. To address the first part of the question, we're seeing a diverse mix of customers. Generally, these are customers who may have cut costs more than necessary during the downturn. Now they recognize that they can maintain good fiscal discipline while activating a few more rigs. This seems to be the common theme. There's certainly an opportunity for our customers to capture and secure lower rates for a longer period. We see that trend, but I prefer not to discuss rates in detail during this call. However, I can tell you that there is strong market discipline at the moment. The competition is quite limited, with only about three to five contractors in play. We are not facing competition from non-super spec rigs currently, which suggests a disciplined market. We feel positive about the current pricing situation, and as demand continues to strengthen, we will maintain that discipline.

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 pay down targets or progress. When it comes to the incremental debt paydown from here, should we expect further debt pay down 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. First of all, we're announcing a contract that will probably last for 6 months or longer, but we're leaning towards the shorter end. At this moment, we prefer not to lock in at a lower rate since we want to maintain flexibility for potentially higher rates in the future. So I'd suggest looking at the shorter end of the term. Generally, those typically last for 6 months, 1 year, or 2 years. I believe the average will likely be around the 1-year mark.

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 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. Pad Oxy not cutting 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 we don't expect any market share shifts that adversely affect our business from these transactions.

Yes, Aaron. 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?

I won't preview any upcoming news for later this year. However, I want to emphasize that reducing debt will remain a top priority for at least a couple more years. Additionally, our focus on operational efficiency, effectiveness, and leveraging our scale will continue to be a significant area of attention, likely indefinitely but certainly over the next few years. In summary, we will consistently work towards reducing debt and enhancing equity value for our shareholders for an extended period.

Our next question comes from Kurt Hallead with RBC.

Kevin, that’s a very constructive observation. I spoke with one of your peers on the conference call earlier today who also mentioned some positive momentum in drilling, with visibility extending into early 2021, specifically in the U.S. It seems there is general agreement on the market trends in the U.S. Another consistent point was the strong pricing discipline. This competitor indicated that day rates are likely to hold above $20,000. So, considering this information, Kevin, as we move into next year and anticipate improvements in overall drilling activity, there are some concerns in the market about drilling contractors possibly overzealously reintroducing idle rigs, potentially lacking the discipline expected in a consolidated market. How do you assess this situation? What insights can you share regarding your discussions with customers about the pace and potential scope of improved activity?

Kurt, the situation is clearly complex. We are currently in discussions with a number of customers, which is a change from our Q2 conference call where we were only engaging with a few. The competitors we encounter generally consist of the top 3 or 4 large public drilling contractors, and we aren’t facing many smaller contractors. All these opportunities are focused on development drilling programs that utilize super-spec rigs characterized by 7,500 psi, pad walking, and large racking systems. Technology plays a crucial role in every discussion we have, and few other drilling contractors engage in these types of conversations. The competitors we are up against display a high degree of discipline, and we all understand each other's strengths in the market. We each have our own value proposition and are primarily focused on driving EBITDA and returns for our investors, which inadvertently affects market share as a result of our initiatives.

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 can get any kind of bigger than that. How do you foresee the possibility of additional consolidation in the Canadian drilling market?

It's somewhat similar to the U.S. with five drillers involved. Currently, they have about 84% of their active rigs in Canada. There will be some rationalization taking place. Initially, some rigs may be cannibalized, eventually becoming nonmarketable. You might witness a few smaller companies either sell to others looking to gain scale. However, I don't expect larger public companies to lead the consolidation during this recovery phase or even in this downturn in Canada. The bigger companies have strong positions and are confident in them. We certainly are as well. Our intention is to focus on maximizing free cash flow in the Canadian market. It’s clear that we don't need 25 drilling contractors in Canada; the market indicates we need just five. In the deep basin, where we're generating most of our profits—specifically Montney, Duvernay, and the Deep Basin—there are really only three contractors with Super Triple rigs. Currently, we are likely the only contractor running a mature and sustained automation and technology program. Therefore, I believe that competition will reduce the number of companies capable of competing. We might also see some consolidation among smaller players trying to achieve scale, but simply achieving scale won't address their asset liabilities or technology gaps.

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.

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. Looking back to our Q2 conference call, we discussed the anticipated increase in activity, mainly driven by gas. With 25 rigs currently operating, our gas mix has improved slightly compared to earlier this year. This initial uptick we've noticed in the U.S. has been primarily due to gas. I believe we will also add a few oil rigs before the year ends. Overall, I estimate that around two-thirds of the rig additions we expect in 2020 will be gas, with one-third being 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 a little bit slow, and our customers appear to be waiting to see if they might receive a better offer on oil later in the season. Those decisions could be postponed until the first week of January. We can mobilize those rigs on short notice. Currently, with the existing pricing, discussions are slow. This is why I mentioned in my prepared comments about grouping heavy oil with other shallow plays in Canada. Normally, I would separate them, but demand right now seems to be weak. However, that could change, and we might see an increase in activity later this year or early January. There has been nearly a three-year gap in heavy oil drilling. We experienced a slight uptick early this year at the beginning of the winter season, which was somewhat surprising in January. We know our customers need to replace production and drill new wells, but they will manage that carefully due to 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.

Yes. 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 haven't really talked about the quality, age, or relevance of the super-spec fleet. What complicates matters is that there’s no widely accepted definition of what super-spec actually is. I can assure you that not all of the AC rigs in the U.S. are cutting-edge super-spec. To clarify, what we at Precision currently consider a leading-edge super-spec rig would be one with 1,200 or 1,500 horsepower powered digitally through an AC system. It would be equipped with 3-month pumps capable of handling 7,500 psi, ideal for long-reach horizontal drilling, and it would have a pad-walking system for movement in X and Y directions. While not all of our AC rigs meet every single requirement, the investment needed to upgrade them is minimal for our fleet. When examining the U.S. fleet of AC rigs, some of these were constructed back around 2002 or 2003. Therefore, it's likely that some of them lack 3-month pumps and the necessary racking capacity of 7,500 psi. You could classify this as technical obsolescence for certain rigs, where their age and upgrade costs may make them outdated. We haven't conducted an analysis of the U.S. rig fleet in a few months, particularly not during this downturn, but it's something we plan to do in 2021 to get a better understanding of the fleet as the market starts to recover. It appears that the supply of leading-edge super-spec rigs is not infinite. Additionally, the rig's location affects the day rates we can achieve. If we have a rig situated close to a location that qualifies as super-spec, we can definitely command a higher day rate compared to one that is further away.

Yes. I would just like to add that Kevin's comments about attrition in both the U.S. and Canadian fleets are primarily related to the financial limitations faced by competitors. They lack the funds to properly maintain rigs and to purchase new essential components when they become worn out. Typically, they will remove these components from idle rigs, effectively rendering those idle rigs unusable.

Understood. I must mishear or misconstrue 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 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 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 dairy 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 on 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 renewals is working in our favor. For renewals, we're able to secure rates much closer to the previous rate compared to new start-ups. If they relocate our rig, they incur costs in both directions, plus they need to acclimate and train the crew, which takes time to reach efficiency. This creates a significant advantage for us on renewals. I believe a case study has been published regarding the switching cost per rig, which will soon be available on our website for further clarity on switching costs.

Okay. Sounds good. And then just one last question from me. You received $8 million in CEWS this quarter. In a scenario without CEWS, while still managing the impacts of COVID, how much of this $8 million do you believe you could have recovered through additional cost improvements that you would have implemented without that support?

Yes. We're not going to point to an exact number, but it would be meaningful.

I would tell you that especially in our well service group and in the field, we've been able to run a lot of small projects in-house that we would have done otherwise, which has created jobs for blue-collar workers both in the field and in our yards. I'm really pleased about that. I'm satisfied with the effectiveness of the program and the fact that we’ve also accomplished some important maintenance work. There are significant benefits to that program right now, and we will 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 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 primarily in the 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, are most of the incremental rigs going to be an oil or call it, regions outside of the Montney, Duvernay and Deep Basin? Or is there going to continue to be that bias?

I believe we are currently experiencing a high level of activity in the Montney and Duvernay regions. Therefore, the majority of the additional rigs will be added in the Montney and Duvernay areas, while the rest will be deployed outside of 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, back in January and February of this year, we certainly had a higher rig count in the first quarter, driven by SAGD and heavy oil drilling. This follows three years of very low drilling levels. I would say that the likely change in drilling for the upcoming winter season will depend on how much SAGD drilling picks up. If we are at the higher end, closer to 60% or exceeding it, that will be due to increased delineation and SAGD activity. If we are closer to the lower end, around 50%, it will indicate that we haven't seen that pickup.

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 productivity perspective 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; in the U.S. I believe we were either 1 or 2 out of all the contractors. So we think it's 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?

We have not disclosed that information yet. The last disclosure we made was for the year 2021. Annually, we have 18 total rigs under contract and 7 for the year. It will be higher in Q1 since these are just the contracts we currently have. As we approach the end of the year and into Q1, we will be adding to our 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 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, 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.