PRECISION DRILLING Corp Q2 FY2020 Earnings Call

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 unprofitable 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 $4 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 Emergency 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 expenses with subsidies. We expect to participate in this program at similar levels for the remainder of the year. I will now review some of the second quarter financial details. Our second quarter adjusted EBITDA of $58 million decreased 28% from 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 are $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 chosen payments. Absent these items, EBITDA would have been $47 million for the quarter. In the U.S., drilling activity per precision averaged 30 rigs, a decrease of 25 rigs from Q1 2020. Daily operating margins in the quarter were US$15,198, an increase of US$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 US$9,250 or approximately US$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, up $4,844 from Q2 2019. Margins were supported by a strict focus on operating costs and chosen payments. Absent the chosen 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 US$54,779, up approximately US$500 from Q1 and over US$3,000 per day from the prior year benefiting from an active rig mix. In our Completion and Production 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 billion 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 comprises $34 million for sustaining infrastructure and $14 million for upgrading and expansion. As of July 22, we had an average of 35 contracts in hand for the third quarter and 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 is largely 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 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 is approximately 3.5 times 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 will 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 at 2.5 times. Although we are well clear in this covenant today, the extent of the recent downturn is unknown and we want to ensure full access to all sorts 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 expenses. 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 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, workweek reductions, temporary layoffs and for some, permanent layoffs. In Canada, the emergency wage subsidy program has sheltered 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 thank the employees still at Precision; many are working remotely for their continued hard work, and for the strong operational and financial results 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 due to the 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 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 of 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 in this segment is narrow with a smaller competitive field than in the Super Triple category. During the second quarter, we demonstrated excellent success with our Alpha Technologies suite on these rigs, and I'll have more on that later. We expect strong customer uptake on Alpha Technologies to 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 second-quarter activity was a little lower than we expected. However, the difference was due to more rigs than anticipated shifting to idle contract status, with up to 11 rigs during the quarter being idle, as we call it. It seems those customers prefer to hold those rigs and retain the option to reactivate those rigs. Alternatively, they have the financial incentive for early termination of lump-sum payment should they choose. In the U.S. also in Canada, we delivered very strong performance results with Alpha Technologies, and we'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 remarkably improved. Our customer conversations have shifted away from laying down rigs and intermediate contracts to more normal conversations about safety, efficiency, operations, and technology. We have noticed a heightened interest in technology, both from a cost-saving perspective but also from a national perspective, as it seems 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 has limited, we expect tight competition and I’ll not provide much guidance on rates other than to say the opportunities are in both gas and oil price. 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 six rigs remaining idle. We have added one term contract during the second quarter for a rig in the Haynesville. We 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 six rigs operating under long-term contracts. Our biggest challenge is managing international crews we are working on those rigs with strict pandemic border controls remaining in place. In Kuwait, the Kingdom of Saudi Arabia, the national oil company offices remain closed or only partially staffed. So we expect no decisions to renew or contract additional rigs until the lockdown eases. We currently have seven idle rigs in the region and continue to believe that opportunities to activate some or all of these rigs will emerge as the global economy recovers. Now, as I mentioned earlier, we continue to have very good success with our Alpha Technologies. Currently, we have Alpha Automation running and earning revenue on half our active rigs and expect us to trend upwards through the end of the year. We have also fully commercialized six Alpha Apps and have utilized Alpha Apps out of our 100 wells this year. We have more than a dozen other Alpha Apps under field trials and expect to commercialize most of those before the end of the year. Our progress with customer acceptance on Alpha Automation and Alpha Apps is excellent. 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 Alpha Analytics trials. We activated our Alpha Analytics team with two multi-rig clients: the first, an IOC in the Permian Basin, and also a private client in the Haynesville. In both trials, our teams analyzed both asset 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 Alpha Automation 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 uncover process improvement opportunities. We applied those recommendations across the same group of rigs fleet-wide using our Alpha Automation platform during the second quarter and 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 executing repeatedly as planned on every rig with our Alpha Automation platform. A key element of the analytics exercise is recommending the appropriate Alpha Apps to optimize the various sectors of the drilling process and then implementing these apps in the drilling plan. With Alpha Analytics, we save our customers time and money. We drive automation in 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 of this technology enablement and the revenue for Alpha Services will grow, but equally importantly this will also drive market share and revenue growth for Precision’s Super Triple rig fleet. We will continue to report our progress throughout the year on the Alpha Technology growth initiatives. Now, turning to our Completion and Production Service business. Our Canadian Well Service Group experienced the slowest activity level on record during the second quarter. This was a function of our customers essentially curtailing all discretionary spending and shutting the wells. Most well service work is largely discretionary and when an operator is already shutting in production, any well needing service will be deferred. As the third quarter unfolds, we're experiencing a muted seasonal rebound with Precision’s service rig activity trending into the mid-upper teens. This has been partially due to weather delays, but also due to continuous spending constraints by many of our customers. The Canadian government announced a $1.7 billion well restoration program, and this was handed over to the provinces of Alberta, British Columbia, and Saskatchewan to administer. All three provinces kicked off the application process during the second quarter with Alberta being 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 three provinces and we received approvals or indications of approvals in all three 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 disperse the full $1 billion as efficiently as possible, as our British Columbia and Saskatchewan counterparts 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 sector later this quarter and through 2022 when the programs are expected to wrap up. In conclusion, 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 continuing to grow our revenue and market share leveraging our digital Alpha Technologies.

Our first question comes from Kurt Hallead with RBC. Your line is now open.

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

Kurt, I think it's hard 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.

On the Precision Drilling front, Kevin, it's good to see that you continue to get traction with your Alpha apps. There has 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 gaining a lot more traction here during the downturn than some may have expected? So can you give us some general sense as to, are you pleased with the traction that’s been happening, and have you seen E&Ps being more willing to 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've quickly become comfortable with the notion of both remote operations and technology enabling performance. So I think that's helping us, but what was really helping is hard-core results on the rig. When we can go out and show that we can drill a well 4.2 days faster, that catches everybody's attention. So, we've had a number of meetings with clients, but breakdown rigs are in a quiet period right now; there’s not a lot of activity. We’ve run I think four or five other customers through our demonstration facility in Houston demonstrating technology showing them the case studies. And these 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 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 run through the process and do you think you'd be able to kind of re-sign those rigs with the existing customer base, and do you think you’d be able to maintain pricing on those assets?

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

Our next question comes from Taylor Zurcher with Tudor, Pickering, Holt. Your line is now open.

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 idle rigs in Q2 and by year-end, you’ll have close to six. This is a two-part question: going from the low 20s today to 30, I assume that's not just idle rigs going back to work but 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, just curious if those are operators that formerly had those rigs at least the operators you're talking to for those rigs, or are those potentially new customers?

Well Taylor, my comment was trending towards 30; I could have said trending towards 25. We had 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 right now, that's a pretty slow number across the U.S. So if we had 3 or 4 rigs between now and the end of October, I’d be pretty happy with that — that gets us in the high 20s. That could be — by the way, I think that the rigs we have idle unless something changes with those clients, we’re just keeping assuming they’ll stay idle and that we could be adding additional rigs beyond that. So it could be customers that used rigs in the past wanting to reactivate those rigs that are off-contract, or it could be new opportunities creeping up. There are a very limited number, one or two or three of those opportunities, but I do think that the results we're having with technology and efficiency right now are going to take a couple of years.

In the international space, I realize essentially all your rigs are on contract and long-term contracts. Just in the Middle East, there seems to be growing talk that activity is probably going to come down in the back half of the year and beyond. Just curious if that’s something you’re seeing, and for the customers you work with? I realize 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 are today?

Those are firm take-or-pay contracts. I'd be remiss if I said we did not have pricing pressure. But I think we've dealt with that and don't have any adjustments to our guidance. I think we've worked with our customers, kept them happy, and things are moving. I commented that we had two rigs in Kuwait that we've talked about renewals on and those rigs are idling now. We expect to have renewals by now, but with the shutdown in Kuwait, until those offices restart and they get their drilling plans back figured out again and organized, those renewals are delayed. I don’t see any further changes in Kuwait. Turning to Saudi, I think we're stable unless something changes dramatically. I think the three weeks we have a contract will continue for the year in Saudi, but I will tell you that we’re in a world of uncertainty right now. So, things change quickly and surprises sometimes.

Now I’ll squeeze one more in, probably for Carey. The 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. Certainly would help us think about what magnitude of cash inflows and working capital you might get in Q3 and Q4 of this year?

In April we gave guidance, and we thought we would have $80 million to $100 million of working capital comparing 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. Looking 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.

Our next question comes from Waqar Syed with ATB Capital Markets. Your line is now open.

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 generated 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 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 and $175 million of cash on 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 in the market are all things we think about every day.

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

So the range is $100 million to $150 million, and I’d say that target is not going to change. It’s hardwired into our incentive metrics, and we’re not likely to change targets that are tied to competition.

Fair enough. Now in the U.S. markets as you are having conversations with customers, and you indicated there were 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. You know what, at this point there aren't. We have a couple of private opportunities, a couple of intermediate opportunities, some gas and some oil. So, 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 are you...

When we talked 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 kind of equalized for both gas and oil.

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

Just because there are so few data points out in the marketplace, I would say that the rates in that contract were in line with prior guidance we’ve given around rates.

Okay. And what...?

I’ve heard rates all over the map, but our guidance in the past has been upper teens to low 20s depending on the stack of the rig and its location, 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 like 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 drilling.

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

So, Carey, that's essentially a server and the software that gets hardwired into the rig. The probably more meaningful component is training our three drillers, four drillers, or rig balancer, and for that matter, the company man and the drilling engineer for the company on all the apps and utilization of the system. That usually takes in the range of anywhere from one or two wells maybe to as much as five or six wells; that could be a one month to three month process to get 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 are already outfitted with automation.

In a way, if you look at the industry's super-spec fleet, maybe the numbers vary, but it could be between 650 to 750, and bulk of 80% of that is in the hands of five companies. All of them have, to varying degrees, some component of that automation. We can debate which is better or not. But in a way, many of those 650 to 750 rigs could be converted into smart rigs with a relatively like a $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 a standard platform, a standard operating system on all of our rigs. That's the AMPHION system. We were buying a mass-produced server hardware package for their AMPHION — for their NOVOS control system. Then as we train our team and get the rig configured, it becomes Alpha Automation. 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 has the same version of Amphion, so it’s a 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. We've been told by a couple of the IOCs we're working with that while all drillers are dabbling in this area, 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 are in a meaningful first-mover position on this. The time in training, as Kevin commented, that 38 rigs and 38 crews and 115 drillers that are all trained on his system already. We have scale, but we cannot put into play that are all trained on the system already. We have scale that we can put into play immediately that 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 would 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. Your line is now open.

With respect to Qs and the remainder of the year, I mean a 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 be a bit bigger than what happened in Q2?

Sure Ian. 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 and as people in the group, 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 program changes throughout the back half of the year that the government has funded certain percentages, and they ratchet it down a little bit more in the fourth quarter.

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 may do around the carbon emission side in the event that policy perhaps goes a bit more negative if there is a change in the administration.

Ian, great question. 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 work for currently as well as those looking down the road. I would say that 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 government incentive program and they were successful. So it's ourselves, Tourmaline, and Caterpillar partnered together with this system. It's a hybrid power system using batteries and dual fuel engines to lower the carbon footprint and use hybrid technology.

Our next question comes from Jeff Fetterly with Peters & Co. Your line is now open.

First question is around the debt repayment. I’m 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?

I'll go back to what Kevin said earlier about our specific tactics for reserve debt level we will 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. How our thinking has evolved is Kevin also touched on a little bit earlier. We had just under $100 million of cash at the end of Q1. We've been able to get basically 100% collection from all of our receivables and convert that to cash. Now we sit on the cash balance of under $175 million, which gives us a little bit more flexibility with how, which pieces of debt we go after. It gives us a bit more comfort using a revolver, which has a borrowing rate of less than 3%. That facility has maturity at the end of 2023. I think we're looking at all of those factors 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 note 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 mentioned in my opening comments that we're evaluating that option.

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 in Q2?

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

Correct.

Last question just on 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. We mentioned that there is going to be $14 million of additional savings that will be reflected in Q3 and Q4. When we talk about the $150 million cash savings, that's a combination of reducing CapEx by $48 million, paring back to share buyback program, getting tax deferrals, other rent deferrals, and then absolute reductions to SG&A and field overhead. It’s a combination of a lot of different factors. 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. Your line is now open.

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 one or two years? And are customers willing to share in the cost of your investment?

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

Yes, and the cost from that is all part?

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

Thank you. 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.