Precision Drilling Corp (PDS) 2020 Q2 法說會逐字稿

Ladies and gentlemen, thank you for standing by, and welcome to the Precision Drilling Corporation Second Quarter 2020 Results Conference Call. (Operator Instructions) Please be advised that today's conference is being recorded. (Operator Instructions)

I would now like to hand the conference over to your speaker today, Mr. Dustin Honing, Manager of Investor Relations and Corporate Development. Thank you. Please go ahead, sir.

Thank you, Daniel, and good afternoon, everyone. Welcome to Precision Drilling's Second 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 second 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 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 second quarter financial results. Kevin will then follow by providing an operational update and outlook. With that, I'll turn it over to you, Carey.

Thanks, Dustin. I'd first like to cover several of the cost saving and cash preservation steps taken by the company to confront the sharp decrease in activity experienced in our sector. In March, we reduced staffing levels, implemented salary reductions throughout the organization, closed on profitable business lines, reduced CapEx, paused our share repurchase program and essentially eliminated all discretionary spending.

We prepared for an unprecedented drop in activity levels that ultimately materialized during the second quarter. We incurred an additional $6 million in severance and restructuring charges during the second quarter and expect the changes to generate an additional $14 million in savings annually from what we communicated in April.

Last quarter, we provided guidance of a 30% reduction in fixed costs comprised of overhead and G&A. And we now expect the reduction to be 35%. We expect cash savings for the year to now be up to $150 million compared to the previous guidance of over $100 million. Furthermore, we expect to exceed the $30 million reduction in annualized G&A target we provided in April. Cost reduction and cash preservation will continue to be priorities throughout our organization.

Additionally, Precision has been participating in the Canadian Employment Wage Subsidy program, which we refer to as CEWS. This Canadian government program supports economic activity in all sectors of the economy, and has allowed us to retain a number of positions within our organization by offsetting wage expense with subsidies. We expect to participate in this program at similar levels through the balance of the year.

I will now review some of the first quarter financial details -- sorry, second quarter financial details. Our second quarter adjusted EBITDA of $58 million decreased 28% over the second quarter of 2019. The decrease in adjusted EBITDA primarily results from a sharp decrease in drilling activity. Also included in adjusted EBITDA during the quarter is $6 million of severance and restructuring costs, $11 million in early termination revenue, $3 million of which would have been earned during the quarter and $9 million of CEWS payments. Absent these items, EBITDA would have been $47 million for the quarter.

In the U.S., drilling activity for Precision averaged 30 rigs, a decrease of 25 rigs from Q1 2020. Daily operating margins in the quarter were USD 15,198, an increase of USD 5,854 from Q1. Q2 margins were positively impacted by early termination revenue and IBC revenue. turnkey margins and lower daily operating costs. Absent impacts from IBC early termination and turnkey, daily operating margins would have been approximately USD 9,250 or approximately USD 1,000 higher than Q1. For Q3, we expect day rates and margins to be supported by contracted rigs and IBC revenue.

In Canada, drilling activity for Precision averaged 9 rigs, a decrease of 18 rigs from Q2 2019. Daily operating margins in the quarter were $9,042, an increase of $4,844 from Q2 2019. The margins were supported by a strict focus on operating cost and CEWS payments. Absent the CEWS impact, margins would have been $3,869, approximately $100 a day higher than Q2 last year. For Q3, we expect margins to be supported by rig mix and strict cost control. Internationally, drilling activity for Precision in the current quarter averaged 8 rigs, consistent with Q2 2020. International average day rates were USD 54,779, up approximately USD 500 from Q1 and over USD 3,000 per day from the prior year, benefiting from an active rig mix.

In our C&P segment, adjusted EBITDA in the quarter was negative $1.2 million, down $4 million compared to the prior year quarter. Adjusted EBITDA was negatively impacted by a $0.3 million restructuring charge and an 84% decline in well service activity, which was negatively impacted by wet weather and reduced customer budgets.

Capital expenditures for the quarter were $24 million. Our 2020 capital plan remains at $48 million, a decrease of approximately 50% from the beginning of the year guidance. The 2020 capital plan is comprised of $34 million for sustaining and infrastructure and $14 million for upgrade and expansion. As of July 22, we had an average of 35 contracts in hand for the third quarter at an average of 41 contracts for the full year 2020.

Since the beginning of the year, we have converted almost $120 million in receivables to cash and have had essentially no collection issues with all contracts performing. This, in large part, is due to the excellent performance of our credit and collections teams and the high quality of our customer base.

Moving to the balance sheet. We continue to reduce both absolute and net debt levels, primarily through free cash flow generation. In the first half of the year, we have reduced our high-yield note balances by $45 million through redemptions and open market purchases. As of June 30, 2020, our long-term debt position, net of cash, was $1.275 billion, and our total liquidity position was approximately $900 million. Our net debt to trailing 12-month EBITDA ratio is approximately 3.5x and our average cost of debt is 6.7%.

For the remainder of this year, we expect to continue generating free cash flow through operations as well as benefit from additional working capital release. Liquidity remains a top priority but we'll look for opportunities to reduce leverage, utilizing cash on hand and we'll evaluate using a limited portion of our revolving credit facility for debt purchases to take advantage of low borrowing costs. We expect to meet our debt reduction target range of $100 million to $150 million in 2020 and remain on track to meet our longer-term debt reduction goal of $700 million between 2018 and 2022. We have reduced debt by over $400 million since the beginning of 2018.

We remain in compliance with all of our credit facility covenants and earlier in the second quarter, reached an agreement with our secured lending syndicate to relax certain debt covenants in our revolving credit facility through Q1 2022, namely the EBITDA-to-interest covenant, which is currently 2.5x. Although we are well clear of this covenant today, the extent of the recent downturn is unknown, and we want to ensure full access to all sources of liquidity, including our revolver.

For 2020, we expect depreciation to be approximately $320 million. We now expect SG&A to be under $60 million before share-based compensation expense. This guidance compares to the 2020 guidance provided in February of $90 million and the guidance of $65 million to $70 million we provided in April. We expect cash interest expense to be approximately $100 million, and we expect cash taxes to remain low with our effective tax rate in the 20% to 25% range.

I will now turn the call over to Kevin.

Thank you, Carey. Good afternoon. Well, the last few months have been deeply challenging for the oil service sector and its companies. But the human impact on the industry's large labor force has been profound. And let me start there.

As Carey described, with the steep decline in customer demand and drilling activity, Precision has aggressively cut costs. Regrettably, this means that hundreds of long-term hardworking and loyal Precision employees have experienced salary reductions, benefit reductions, work week reductions, temporary layoffs and for some, permanent layoffs. In Canada, the Emergency Wage Subsidy program has helped with some jobs, but the outlook for many working in this industry remains highly uncertain.

I want to thank those employees no longer with Precision for their efforts and service to the company. I share their hope that the global economy recovers soon and they can once again return to jobs in this industry. I also want to thank the employees still with Precision, many working remotely for their continued hard work and the strong operational and financial results that are helping Precision deliver for our stakeholders.

Now as I said when I opened, this has been a very challenging time. For most of March, April and May, all of our customer discussions centered on terminating contracts, idling rigs and working with our customers to find ways to minimize their spending. And nowhere does this happen faster than in Canada, which is already biased for the spring breakup seasonal slowdown. Industry activity and levels in Canada plunged below all-time lows during the second quarter. And so far, the summer seasonal rebound has been muted, with the industry activity tracking almost 75% behind last year's levels.

Now the Montney and Duvernay plays remain a bright spot. During the second quarter, Precision's Super Triple rigs operating in those plays made up a high percentage of the entire industry's active fleet. Our market share hitting a record peak at 1 point, we are close to 50%, albeit with a relatively small denominator. We expect our strong market positioning to continue as those plays will remain busy for the second half of the year.

While we do expect some day rate pressure, it should be noted that the competition of this segment is narrow, with a small competitive field in the Super Triple category. During the second quarter, we demonstrated excellent success with our Alpha technology suite on these rigs. I'll have more on that later. But we expect that strong customer uptake on Alpha technologies will continue in Canada and help pull rig market share forward.

Outside the Montney and Duvernay, we expect that the shallow basins will have light activity compared to last year, and price competition will continue to be intense. Scale matters. And with Precision's scale, we have the best ability to drive down our costs and sustain positive cash flow even in this deeply-depressed market. Free cash flow will be our focus for the balance of the year in the Canadian shallow regions.

Currently, we're running 13 rigs in Canada and have another 6 rigs contracted to activate in the coming days. While forward visibility remains opaque, we see rig activity moving towards the upper 20s late in the third quarter and believe this will trend into the 30s during the fourth quarter.

Turning to the U.S. Our service -- our second quarter activity was a little lower than we expected. However, the difference was due to more rigs than anticipated shifting to idle but contracted status, with up to 11 rigs during the quarter being IBC, as we call it. It seems those customers prefer to hold those rigs and retain the option to reactivate those rigs. Alternatively, they have a financial incentive for early termination lump sum payments, should they choose.

In the U.S. as in Canada, we delivered very strong performance results with Alpha technologies, and I'll have more on that later. But I would say that we expect to continue to grow both our technology revenue and rig market share as the industry looks to high-grade or add back rigs. Now as commodity prices recovered substantially from the negative oil prices quoted earlier this year, customer sentiments also markedly improved. Our customer conversations have shifted away from laying down rigs and terminating contracts to more normal conversations about safety, efficiency, operations and technology.

We have noticed a heightened interest in technology, both from a cost and savings perspective, but also from a management perspective. It seems that as our customers transition to using technology to work remotely, their acceptance of digital technology as a drilling performance opportunity is normalizing. Today, we have 23 rigs running, up slightly from our low of 20 in Q2. We continue to have visibility for a handful of potential activation opportunities. But since the opportunity set is limited, and we expect tight competition. I'll not provide much guidance on rates other than to say that opportunities are in both gas and oil plays.

Now we believe that in the absence of an industry rebound, we will gain market share. And our active rig count will move modestly upwards, trending towards 30 by the end of the year, potentially with 6 rigs remaining on IBC, earning IBC rates. We have added one term contractor in the second quarter for a rig in the Haynesville. I think this is a positive indication.

Turning to our international business. Despite the sharp decline in international drilling activity, we expect stable revenue in our Kuwait and Saudi Arabian business, with 6 rigs operating under long-term contracts. Our biggest challenge is managing the international crews we have working on those rigs, with strict pandemic border controls remaining in place.

In Kuwait and the Kingdom of Saudi Arabia, the national oil company offices remain closed or partially staffed, so we expect no decisions to renew or contract additional rigs until the lockdown eases. We currently have 7 idle rigs in the region and continue to believe that opportunities to activate some or all of those rigs will emerge when the global economy recovers.

Now as I mentioned earlier, we continue to have very good success with our Alpha technologies. Currently, we have AlphaAutomation running and earning revenue on half our active rigs, and we expect this to trend upwards through the end of the year. We have also fully commercialized 6 AlphaApps and have utilized the AlphaApps on over 100 wells this year. We have more than a dozen other AlphaApps on field trials and expect to commercialize most of those before the end of the year. Our progress with customer acceptance on the AlphaAutomation and AlphaApps is excellent. And as we mentioned in our press release, we believe this digital drilling capability will drive the next technology transformation that our customers will demand to lower well construction costs.

But the real excitement for our technology group this quarter has been with our AlphaAnalytics trials. We activated our AlphaAnalytics team with 2 multi-rig clients. The first in IOC in the Permian Basin and also a private client in the Haynesville. In both trials, our teams analyzed both offset wells and our own drilling KPIs to uncover process and drilling operational recommendations for those customers. The recommendations were implemented on a real-time basis in a repeatable and measurable manner on our AlphaAutomation platform. The results have been excellent.

For the IOC in the Permian on a 28-day well plan, we've reduced the drilling time to under 24 days, providing a 4.1 day average improvement per well. In the Haynesville, we performed detailed analytics on a group of rigs operating during the first quarter to also uncover process improvement opportunities. We applied those recommendations across the same group of rigs fleet-wide using our AlphaAutomation platform during the second quarter. And we averaged -- we delivered an average 8% or 2.25 days per well savings. These performance gains are repeatable and scalable as the process recommendations are locked in and executed repeatedly as planned on every rig with our AlphaAutomation platform. A key element of the analytics exercise is recommending the appropriate AlphaApps to optimize the various sections of the drilling process and then implementing these apps in the drilling plan.

With AlphaAnalytics, we save our customers' time and money, we drive automation and app revenue, and most importantly, we've demonstrated our ability to scale this technology and the performance gains across all Precision rigs for the same customer almost immediately. I'm confident this technology enablement and the revenue for our Alpha services will grow. But equally importantly, this will also drive market share and revenue growth for Precision Super Triple rig fleet. We will continue to report on our progress throughout the year on the Alpha technology growth initiative.

Now turning to our Completion and Production Service business. Our Canadian well service group experienced its slowest activity level on record during the second quarter. This was a function of our customers essentially curtailing all discretionary spending and shutting in wells. Most well service work is largely discretionary. And when an operator is already shutting in production, any wells needing service will go be deferred.

As the third quarter unfolds, we're experiencing a muted seasonal rebound with Precision service rig activity trending into the mid- to upper teens. This has been partially due to weather delays, but also continued spending constraints by many of our customers. The Canadian government announced a $1.7 billion well reclamation program, and this was handed over to the provinces of Alberta, British Columbia and Saskatchewan to administer. All 3 provinces kicked off the application process during the second quarter with Alberta, the largest, with $1 billion first out of the gate.

Precision is qualified and has been submitting applications directly or with our customers in all 3 provinces, and we received approvals or indication of approvals in all 3 regions. Unfortunately, the programs have been slow to disburse funds and as of yet, little of the subsidy program funding has made it to our rigs or jobs for our people. While this is frustrating for us and especially for our crews, we have been in constant contact with the program managers. It's clear to us that the province of Alberta is fully committed to disburse the full $1 billion as efficiently as possible, as are British Columbia and Saskatchewan with their respective allotments.

We know that in the first funding round, Alberta received over 35,000 contractor applications. I know they expected a strong uptake, but it seems they are quickly overwhelmed with the tens of thousands of applications. All indications are that the funding will begin to flow in the coming weeks, and they appear to be better prepared for the subsequent rounds. It's clear they're working hard to get the money flowing to our rigs and our crews. We still expect to win our share of the work and expect this will provide a strong tailwind for this business segment later this quarter and through 2022 when the program is expected to wrap up.

So to conclude my prepared comments, our focus will remain on leveraging all aspects of our business to generate free cash flow, maintaining adequate cash liquidity while focusing on reducing our debt, and we'll continue to grow our revenue and market share, leveraging our digital Alpha technologies.

So with that, I'll turn the call over to the operator for questions.

(Operator Instructions) Our first question comes from Kurt Hallead with RBC.

Kevin, I see that one of your primary U.S. competitors is looking to sell its Canadian land drilling rigs. Just wondering what you think the prospect of those rigs being acquired would be as we kind of move forward from there? What do you think the value proposition is for those assets from an industry standpoint?

Kurt, I think it's hard for me to comment on another company's process right now. I would just say that free available capital in Canada for rig acquisitions is pretty tight right now. But I really don't want to comment on another process that's running.

No. All right. That's fair enough. So on the Precision Drilling front, Kevin, it's good to see that you continue to get traction with your AlphaApps. There's been a lot of discussion here over the last week or so from other oil service companies talking about an increased use of remote operations and advances in technology seems to be coming a lot more, like getting a lot more tracking here during the downturn than some may have expected.

So can you give us some general sense as to are you pleased with kind of the traction that's been happening? And have you seen E&Ps be more willing to kind of take on this technology through this downturn?

Kurt, I think that's a good observation. Certainly, all of our customers are using a lot more technology themselves, just to do their jobs than they were even just a few months ago in working remote mode. So I think they very quickly become comfortable with the notion of both remote operations and technology-enabling performance. So I think that's helping us. But what's really helping is hardcore results on the rig. We can go out and show that we can drill about 4.2 days faster and do that to an IOC, that catches everybody's attention.

So we've had a number of meetings with clients who lay down rigs are kind of in a quiet period right now, with not a lot of activity. We've run I think 4 or 5 other customers through our demonstration facility in Houston, demonstrating the technology, showing them the case studies. And these are clients that don't have rigs running today, but expect to fire up rigs later this year or into next year.

So there's no question that both for the customers we have, and prospective customers down the road, I see a high degree of interest in digital technologies, all tied to drilling wells a little more efficient, but also repeatedly and predictably and managing that cost exactly as expected.

That's great. That's great color. And maybe on a follow-up basis, you talked about having some idle rigs in the U.S. that are generating revenue. What do you think the prospects for those rigs are once their contract terminations kind of run through the process? And do you think you'd be able to kind of resign those rigs with the existing customer base? And do you think be able to maintain pricing on those assets?

Well, Kurt, I think you know kind of you've been around this business a long time. Customers have a strong preference to keep the crew and the rig that they have that worked for them for a long time. So on those rigs, they are currently IBC. I think part of the reason the customers didn't choose the early termination option, but kept the IBC option was to keep control of the rig and the crew. I wouldn't expect they renew the rig if they don't have a drilling budget. But if they come into 2021 with the drilling budget, even a partial budget, I'm highly confident they'll want the same rig back.

So while it might have fallen off IBC, maybe October, November, December, come January, I'm quite confident those same customers will want the same rigs back if they have a program starting in 2021. Does that answer your question?

Yes. That's also good color, Kevin.

Our next question comes from Taylor Zurcher with Tudor, Pickering, Holt.

My first question, and Kurt kind of took part of it there, but it sounds like in the U.S., you talked about potentially getting to somewhere close to 30 rigs by year-end. I think you said up to 11 IBC rigs in Q2. And at year end, you'd have close to 6. And so 2-part question.

Going from the low 20s today to 30, I assume that's not just IBC rigs going back to work and staying employed. It's probably kind of net rig additions or rigs that aren't working today that are going back to work in the back half.

And two, I'm just curious if those are operators that formally had those rigs, at least the operators are talking to for those rigs? Or are these potentially new customers?

Taylor, so my comment was trending towards 30. And I could have said trending towards 25. We're at 23 rigs today. I think we have a pretty good shot of punching past 25 and moving towards 30. I don't know if we'll hit 30. That's a bit of a stretch, just knowing what we know about the world at this moment. But it only takes 3 or 4 rigs. And that's -- across the U.S. right now, that's a pretty small number. So if we add 3 or 4 rigs between now and end of October, I'd be pretty happy with that. That gets us to the high 20s.

It could be -- and by the way, I think to the rigs we have an IBC unless something changes with those clients. We're just keeping -- assuming they're to stay IBC and that we'd be adding additional rigs beyond that. So it could be customers that use rigs in the past have a reactivated rig that's off contract or it could be a new opportunity creeping up, and there's a very limited number, 1 or 2 or 3 of those opportunities. But I do think with the results we're having with technology and efficiency right now, that we're going to stay in a couple of this.

Got it. Understood there. And a follow-up internationally. I realized essentially all your rigs are on contract and long-term contracts. Just in the Middle East, though, there seems to be growing talk that, that activity broadly in the Middle East, but particularly in Saudi, could come down in the back half of the year and beyond. And just curious if that's something you're seeing?

And for the customers you work with, I realize that those rigs are on term contracts today, but are you talking to those customers about any sort of pricing concessions today? Or do those contracts seem pretty firm where they're at today?

So those are firm take-or-pay contracts. I'd be remiss if I said that we did not have pricing pressure. But I think we've dealt with that and don't have any adjustments to our guidance. So I think we've worked with the customers, keep them happy, but keep things moving. I comment that we've had 2 rigs in Kuwait that we've talked about renewals on. And those rigs are idling now, and we expect it to have renewals by now. But with the shutdown in Kuwait, until those offices restaff and they get their drilling plans back, figure it out again and organize, those renewals are delayed. So I don't see any further changes in Kuwait.

Turning to Saudi. I think we're stable in Saudi unless something changes dramatically. I think the 3 rigs we have on contract, those contracts will continue for the year in Saudi. But I will tell you that we're a world of uncertainty right now. Things change quickly and surprise us sometimes.

Yes. Got it. And I'll squeeze one more in, probably for Carey. Working capital inflows were expectedly strong in Q2. I think you said in the prepared remarks that working capital should be a source of cash or continue to be a source of cash in the back half of the year. Is there any way to help us think about what magnitude of cash inflows from working capital you might get in Q3 and Q4 of this year?

Sure. So in April, we gave guidance that we thought we would have $80 million to $100 million of working capital converting to cash by the end of this year. I think we're probably pretty close to the high end of the range so far with what we captured in Q1 and Q2. If we look at now to the end of the year, it might be another $10 million to $20 million. So I think we've gotten the bulk of it, but I think we'll end up converting a little bit more than what we guided.

(Operator Instructions) Our next question comes from Waqar Syed with ATB Capital Markets.

Kevin, you mentioned in your earnings release that as the outlook improves, then you'll be back buying debt. What do you need to see to do that? You generate a lot of free cash flow in the quarter. Cash balances look good. So what do you need to see to be back in the market?

I think, Waqar, we're going to keep our -- kind of our strategy around how we manage our debt repurchases to ourselves at this point. I would tell you that sitting with north of $150 million of cash on the balance sheet, $175 million of cash the balance sheet feels a lot better than $75 million of cash on the balance sheet. But I think managing our total liquidity, managing our debt maturities and trying to capture some discount to market are all the things we think about every day.

So the target that you have, that $100 million to $150 million, is that -- I know you repeated that in your earnings release. Is that still a firm target? Or there is flexibility around that based on the outlook?

So the range is $100 million, $150 million, and I'd say that target is not going to change. It's hard wired into our incentive metrics. And so we're not likely to change targets that are tied to compensation.

Fair enough. Now in the U.S. market, as you are having conversations with customers, as you indicated there was -- there could be a couple of rigs that could go back to work. Are those mostly related to private customers? Or are those with public E&Ps?

That's a really good question. We've been looking hard to try to figure out any trends that might be emerging but here at this point, there aren't. We have a couple of private opportunities, a couple of kind of intermediate opportunities, some gas, some oil. There's so little that there's really not a trend emerging yet, but we're watching closely to see if anything sort of pops up on that front.

And when we talked to you earlier, I think we talked to you back in June. There was a little bit of a gassy sort of trend, but now it's going to equalize, both gas and oil.

Fair enough. And then you mentioned that there was a new term contract signing in the quarter. Would you care to comment how the rates kind of held up on that particular contract versus where the rates were before?

Just because there's so few data points out of the marketplace. I would say that, that -- the rates in that contract were in line with prior guidance we've given around rates. And I've heard of rates kind of all over the map. But our guidance in the past has been upper teens to low 20s, depending on the spec of the rig and location and timing and size and nothing changed on that contract that's outside that guidance.

Fair enough. And you talked about this as well. And it feels that the rig of the future now is the smart rig with all the digitization. Now to convert a super-spec rig into a smart rig, what kind of investment is required?

Carey, why don't you grab the investment piece, and I'll talk about the trading.

Sure. For us, what we're doing is we're putting in a kit from third party, which enables our automation platform. And we haven't given specific numbers to that. We could say it's well less than $0.5 million to put that kit onto our rig.

So Carey, that's essentially a server and a software that gets hardwired into the rig, plugged into the rig. And then the -- probably the more meaningful component is training our 3 drillers or 4 drillers, our rig manager and for that matter, the company man, the drilling engineer for the company on all the apps and utilization of the system. And that usually takes in the range of anywhere from kind of 1 or 2 wells, maybe to as much as 5 or 6 wells. That could be a 1-month to 3-month process to get that -- the full training and the full value realized on a rig.

Yes. And Waqar, I'd also say that we've got 39 of our rigs in North America that already kitted out with automation.

Fair enough. So in a way, like if you look at the industry super-spec fleet, maybe like numbers vary, but it could be between 650 to 750. And bulk of it, 80% of that is in the hands of 5 companies. All of them have, to varying degrees, some component of that automation. We can debate which is better or not. But some degree that everybody feels comfortable with. So in a way, a lot of those 650 to 750 rigs could be converted into these smart rigs with relatively like $1 million-type investment. Is that a fair observation?

I think it depends on the platform. So I think ours is relatively inexpensive because we're using kind of a standard platform, a standard operating system on all of our rigs. That's the NOV AMPHION system. And they were buying a mass-produced server hardware package for (inaudible) for their AMPHION -- for their NOVOS control system. And then as we train our team and get the rig configured, it becomes AlphaAutomation. I don't think any other driller has that plug-and-play capability that we have. So I think that's an advantage we have.

Of course, all of our Super Triple rig fleet have exactly the same version of AMPHION, so it's very simple scalable opportunity for us. I think we've got some advantages there. I think philosophically, you're right, all rigs can be converted, but I think it's with varying degrees of capital and time across that fleet. Now look here, we've been told by a couple of the IOCs we're working with that while all drillers are dabbling in this area, that we are delivering full process automation control, full app performance. And we're charging commercial rates on all of these rigs and receiving commercial returns.

So I'm comforted that we're in a meaningful first mover position on this. And I would tell you that the time and training and as Carey commented, 38 rigs and 38 crews and 115 drillers that are all trained on the system already. We have scale that we can put into play immediately, and we expect that to happen over the coming months.

Great. And just one last question. Are there opportunities for this trend in Saudi or Kuwait as well?

There is, for sure. Our Kuwaiti rigs are all AMPHION rigs. So it'd be very easy for us in Kuwait to upgrade those rigs. We do know that our customer there is very interested in technology. But I would tell you that any forward-thinking right now until they get back to fully staffed offices is just on hold.

Our next question comes from Ian Gillies with Stifel.

With respect to CEWS and the remainder of the year, I mean, the recovery still looks like it's going to be reasonably large. Can you maybe explain how you arrive at getting to what the anticipated recoveries are? And maybe why even if the rig count goes up, that recovery may not even be a bit bigger than what happened in Q2?

Sure, Ian. So obviously, that subsidy is based on the number of employees we have working for our company while it's in place. And as you know, the land drilling business employs a lot of people. So to some extent, it is dependent on activity as people -- if we have more people in the field, it could be higher.

If we're -- the comment we made in our press release that we expect to receive kind of the same participation level in Q3 and Q4 as we did in Q2, that is a function of both our expected activity levels. And I think Kevin covered that in his opening comments. And the way that, that program changes throughout the back half of the year that the government has funded certain percentages and they ratchet down a little bit more in the fourth quarter.

Okay. That's helpful. The other question I wanted to hit on was with the specter of another federal election coming up in the U.S. in November. I'm just curious whether your customers have begun asking about dual fuel rigs or anything along those lines. Or whether you're looking at anything you can maybe do around the carbon emission side in the event that policy perhaps goes a bit more negative if there's a change of administration.

Ian, great question. And we have a surprising amount of customer interest on both sides of the border right now on dual fuel engines and natural gas engines, with customers we're working for currently, and customers are looking kind of down the road. I would say that kind of market-wide right now, I've probably never seen the interest higher in dual fuel engines. In fact, we're involved in a project right now with Tourmaline, where we've developed a completely portable dual fuel, natural gas and electric storage package where we can move this full power pack to any one of our Super Triple rigs and essentially plug it in and provide power.

This is a project that Tourmaline applied for energy funding under the -- per the government incentive program. They are successful. So it's ourselves, Tourmaline and Caterpillar partnered together in this power system. It's a hybrid power system using batteries, dual fuel engines to lower the carbon footprint and use hybrid technology.

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

First question is around the debt repayment. I'm just trying to understand the evolution you're thinking over the last few months. So going back to the end of April, you talked about carrying $80 million to $100 million of cash and then repaying the notes on the 2021 notes by the end of the year.

The comment earlier in the call about now using a modest amount of the credit facility to repay notes and you're carrying well above $100 million of cash. How do you think about those variables? And where do you think the cash balance goes to as the year progresses?

So I will go back to what Kevin said earlier about our specific tactics for reserve debt level we'll keep to ourselves, but I can answer some of your questions. I think we've given pretty clear guidance that the cash balance is expected to increase throughout the year. Both as we expect to generate positive operating cash flow and then get some benefit from working capital release. And I would say that how our thinking has evolved, as Kevin also touched on a little bit earlier, we had just under $100 million of cash at the end of last -- at the end of Q1, and we've been able to get basically 100% collection from all of our receivables and convert that to cash.

Now we sit on a cash balance of $175 million, which gives us a little bit more flexibility with how -- which pieces of debt we go after, gives us a bit more comfort using a revolver, which kind of has an all-in borrowing rate for us of less than 3%. That has -- the facility has maturity at the end of '23, and so I think we're looking at all of those and trying to figure out what gives us the best return, potentially extends our maturity runway and also provides us the most liquidity.

Is your intention to still retire the 2021 notes fully by the end of this year?

There's a good chance we do that.

And is it reasonable to assume that the credit facility will be used at least partially to retire those notes?

I said in my opening comments that we are evaluating that option.

Okay. On the working capital side, Carey, your comment about $10 million to $20 million of incremental working capital in the second half of the year. Should we assume that the majority of that comes from your DSO declining from the 90-ish days you were at, at the end of Q2?

So we expect to get a little bit from accounts receivable and a little bit from inventory. And obviously, if there's a ramp-up in activity in the back half of the year, in Q4, we won't be able to recoup that. But if the activity level is kind of how Kevin projected, where it's kind of a slow ramp, we should be able to do that.

And just to confirm your comment earlier, from a collection standpoint, the small increase in your DSO had nothing to do with any delays in payments? It's just a function of, call it, the nuance of timing.

Correct.

Okay. Last question just around cost reductions. The $150 million annualized that you now referenced and the $30-plus million of SG&A. How much of that would be reflected in your Q2 cost structure? And do you expect that to be fully reflected in your Q3 cost structure?

I would say the majority of it is reflected in our Q2 cost structure with the exception of the $6 million restructuring charge we took in the quarter, which were changes we made at the end of the quarter. So we had mentioned that there's going to be $14 million of additional savings that will be reflected in Q3 and Q4. So when we talk about the $150 million cash savings, that's a combination of reducing CapEx by $48 million, paring back the share buyback program, getting tax deferrals, other rent deferrals and then absolute reductions to SG&A and field overhead.

So it's a combination of a lot of different things. A lot of those are captured in Q2, but we'll see even greater savings in Q3 and Q4. And I think the run rate G&A prior to share-based comp in Q3 and Q4 will be well below $60 million.

Our next question comes from John Daniel with Daniel Energy Partners.

Kevin, you mentioned the interest is really high on the dual fuel. Can you speak to what type of conversion or upgrade opportunities you'd expect to do over the next 1 to 2 years? And are customers willing to share in the cost of your investment?

So during the second quarter of 2020, customers are willing to share nothing. Try to increase rates. But I do think going forward, the fuel savings benefits likely will help us drive economics and pay for those upgrades. I think we have a handful of idle rigs right now to have dual fuels. So we can activate rigs into demand for the time being. It's probably more of 2021 event for us where we have to start investing in more dual fuel systems, probably.

And the cost of that is...

John, I think that's a trend that's going to continue for a long time.

Sure. Well, I mean, it makes sense for them to do it. I just don't know.

Yes, there's a cost benefit. What's interesting is what I find with -- on the entire ESG file on drilling, everything we do on drilling that saves us money also almost always saves us energy and saves us emissions. So there's a really -- this is one business where there's a very good alignment between doing the right thing and actually making more money. And as we further develop our own ESG disclosures, we're going to be really clear on helping explain that to both our investors and our customers.

Okay. Got it. And then just one final one for me, and I should probably know this but I don't, so I apologize, but can you just walk us through the time and process to install the AlphaApps, that technology onto a rig and the time to train someone up on it?

Yes. So the installation time is less than a dozen hours. It's very simple physical and electrical hookup on the rig. So installation time is irrelevant. It happens during a rig move while they're waiting for trucks. There's no delay. We'll generally do both classroom training, training, rig training and then on the job training for our people. But you can presume that a new driller who is going from just strictly a super-spec AC rig to be becoming a fully call it, Alpha expert is about a 3-month cycle.

Now right now today, we have about 60 -- or probably about 30 rigs -- sorry, about 15 rigs of crews that are waiting to come back to work. So we don't need to train anybody for the near term. But if we activate 15 more rigs, we're going to be training more people.

I just want to make sure that you got your question answered. Kevin was describing the installation of AlphaAutomation. You had asked about AlphaApps.

Yes. Yes the apps is what I was asking, that I was referring to, I'm sorry.

The apps installed in seconds and typically, training time is minutes.

Our next question comes from Blake Gendron with Wolfe Research.

Just following on the AlphaApps line of questioning here. Just wondering if clients -- customers are giving you specific feedback on specific apps, maybe to give us a better understanding of what, specifically, what parts of the drilling process are maybe the most impactful from an app perspective?

So short answer is, yes, we're getting specific feedback on ones we have customers willing to pay for the app on a repeated basis. That's when we deplore commercialization. So we've declared commercialization on 6 apps, meaning their commercial earning -- are capable of earning commercial rates. Most of what we're doing right now is tied to rate of penetration, specific energy at the bit and a vibration in the drill strength.

Got you. And if we do see...

And for each of these dynamics, drill string dynamics, there may end up being several different apps that apply different biases to minimize or to optimize [ROP] or optimize vibration. And just like we have several different mapping apps for our telephones, I mean quite certain we'll end up with several different types of apps to control differ parts of that [identical] process. And that's what we find our analytics team is quite good at is helping determine which apps work best for which geology and which customer we're working with.

Got it. Understood. And then in this lower perhaps pricing environment or whatever the outlook is for the medium to longer term, if we don't see a concerted recovery here in the North American rig count. Would you consider licensing this technology in any form to maybe insulate yourself from some of the service delivery cyclicality and just take down the software portion of the value?

Well, most of the apps -- we're actually not retaining ownership. These are owned by other parties so far. We have a few that we own. But many are being owned by other parties. They can sell those apps or license those apps to anybody that's running the NOVOS automation platform. But we still think the larger portion of value isn't in the software. It's in having the crews able to operate and run the software, having the company man up to speed on the software. So we think there's a lot of intellectual property in the training and development of the rig teams.

Where you probably didn't see a whole lot of crew differentiation, obviously, in the second quarter as things were just rolling off as quickly as possible. It seemed more tied to when contracts are actually up as opposed to rig crew or rig quality. Do you think this could be a differentiator as even in a steadier recovery environment, customers that have signaled to you that they'd rather have the Alpha-capable crews and rigs back to look first?

So it's still pretty early in this trough period, but that seems to be what we're hearing from customers. But what we also know -- what we've seen with previous installations we talked about, I think it was in our Q4 conference call. We talked about an operator up in the Northeast and Marcellus that had 2 rigs running Alpha. We brought a third rig in. There was a green rig with a green crew. And by the second well, they are drilling pacesetter wells using AlphaAutomation because they had the parameters from the other 2 rigs they could load in.

So we think that as rigs get added back, if a customer has 2 PD rigs going out of a third rig, we can almost certainly guarantee leaving as performance on the second well, if there are any Alpha on the other 2 rigs and bringing in Alpha on the third rig. So I do think there'll be a strong pull when rigs get added back, especially if a customer is going from 2 PD rigs to a third PD rig or 3 to 4 or whatever the dynamics may be.

Right. Right. That makes sense. And one more, if I could squeeze it in here. The $48 million capital spending program. Can you just help us calibrate relative to maintenance levels for the active rig count what kind of tailwinds you're getting from equipment harvesting, if at all? And then as we look out into 2021 and beyond, if we think about the sustainability of that in a flattish rig count environment, anything we should be aware of? You mentioned the dual fuel upgrades, but anything like research or drill pipe, more lumpy expenditures that we should be aware of across your fleet?

Yes. I think we're doing a pretty good job keeping here most of our maintenance current. Certainly, we need a little less drill pipe today than we did when we were running 80 rigs in the U.S. and 80 rigs in Canada a year ago. So I think if we get back into a sharp ramp up, there may be some drill pipe needs popping up. I don't think it's anything that would distort our long-term maintenance spending profiles.

I'm not showing any further questions at this time. I would now like to turn the call back over to Dustin Honing for any closing remarks.

Thank you all for joining today's call and look forward to speaking with you when we report third quarter results in October. Thank you.

Ladies and gentlemen, this concludes today's conference call. Thank you for participating. You may now disconnect.