Ladies and gentlemen, thank you for standing by, and welcome to the Precision Drilling Corporation 2020 Fourth Quarter End of Year Results Conference Call and Webcast. At this time, all participants are in a listen-only mode. After the speakers’ presentation, there will be a question-and-answer session. Please be advised that today’s conference is being recorded. I would now like to hand the call over to Dustin Honing, Manager, Investor Relations and Corporate Development. Please go ahead.

Thank you, Michelle, and good afternoon, everyone. Welcome to Precision Drilling’s fourth quarter and year end 2020 earnings conference call and webcast.

Thank you, Dustin. Precision exceeded the financial targets set out at the beginning of 2020, leveraging our scale to generate $263 million in adjusted EBITDA, growing our cash balance by $34 million and reducing debt by $171 million, despite experiencing year-over-year North American activity declines of over 44%. Precision’s ability to achieve these results was a function of strict cost control and cash management as well as excellent field performance. Our cost reduction initiatives activated in the second quarter were necessary, given the anticipated steep activity drop in 2020. We successfully reduced fixed costs by over 35% in SG&A by over $30 million, which positioned the Company to generate strong financial results through the fourth quarter of this year and establish a cost structure we believe is sustainable in an increasing activity environment. Cost control, cash management and debt reduction will continue to be focus areas for the Company in 2021. Moving on to our fourth quarter results. Our fourth quarter adjusted EBITDA was $55 million, a decrease of 47% from the fourth quarter in 2019. The decrease in adjusted EBITDA primarily results from a sharp decrease in drilling activity in North America and a slight activity decrease in our international operations. Also included in adjusted EBITDA during the quarter is $10 million of CEWS assistance payments and $11 million of share-based compensation expense. Absent these items, EBITDA would have been $56 million for the quarter.

Good afternoon. And thank you, Carey. All right. 2020 was a deeply challenging year, but it was one where Precision demonstrated the resilience and agility of our business model and the resourcefulness of our highly skilled people. Now, you may recall that on our conference call last February, we foreshadowed the potential risks from the emerging pandemic. And within a few weeks, the Precision team pivoted to a full risk mitigation mode, immediately executing our pandemic safety response plan and then addressing spending.

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

Hey. Good afternoon and thank you. Kevin, you talked about 15% to 20% improvement in the U.S. rig count by hopefully sometime around midyear. So, off the top of my head, it looks like 5 to 7 additional rigs. Can you talk about what sort of operator groups, whether it be private or public, if there’s any trend behind the operators for those potential incremental rigs? And industry-wide, as we look at the next leg of growth from here, do you expect it to be driven mostly from the private side of the equation or fairly balanced between private and public?

Taylor, great question. Certainly, what we’ve seen so far has been weighted towards private -- the private equity E&P companies adding rigs with a blend of some publics. But, I think looking forward into how things sort of play over 2021, I’m really encouraged by the strong discipline our public customers are showing around capital discipline. I’m encouraged that the markets seem to be recognizing that. I do think that the commodity price raise we’re in right now, both for gas and oil is higher than anyone anticipated, either in their budgeting process or even in their bank redeterminations. So, I think the outlook is improving. And I do think, looking forward, the mix of new rigs will be more of a blend of publics and privates, less weighted to the privates.

Understood. Okay. And then, my follow-up is also in the U.S. As of the last quarterly earnings release, you had about 7 term contracts for 2021, now you’ve got 16, so a nice improvement there. I suspect on a leading-edge basis, the spot market pricing is much lower than certainly what it was a year ago. And so, just curious if you could help us understand how you’re thinking about your contract book and pricing in this sort of environment, and the willingness to add some longer term contracts at whatever lower pricing you’re able to get today?

So, first of all, a component of our contracts that we’ve announced are renewals of rigs that are already running and in play. So, those are customers that have the rigs are on location. There’s no mob or demob cost. So, in fact, those rates tend to be closer to prior year’s rates. New activations will certainly be a little bit more affected by spot market rates, a bit lower. I’d say that we think rates have bottomed. We think that there is sort of a concerted effort to start to move rates upwards, and we expect that will play itself out nicely in Q1 and Q2.

Okay. I’ll squeeze one more in. I found the comments about the 4 upgraded rigs pretty interesting, particularly the 2 in the U.S., reducing the environmental footprint a bit. Can you talk to whether or not you’re able to get paid for those upgrades? I mean, are you getting term in some sort of decent pricing for those rigs above and beyond what you can get in the -- on a leading-edge basis in the market, to go ahead and do those upgrades?

Absolutely. We are being paid for the upgrades. The return on the investment is very, very good and fits our long-term return expectations.

Great. That’s it for me. Thanks, guys.

Yes. In fact, Taylor, I’d just elaborate. We didn’t expect those upgrades. It was a -- I wouldn’t say a surprise, but we were surprised that our customers are willing to pay for upgrades. But, I think, it helps you understand the market’s evolving.

Our next question comes from Connor Lynagh with Morgan Stanley. Your line is open.

Yes. Thanks. I just wanted to build on the conversations around contracting and pricing dynamics. I appreciate you don’t want to go too into detail on rates for competitive reasons. But, I guess, what I’m wondering is, are you guys seeking to push rate more so or term more so in your negotiations? To what extent are customers willing to sign long-term contracts or willing to give incremental rate versus “spot” that was sort of obviously pretty hampered by weak demand? So, just your thoughts around that would be great.

Yes. Connor, again, I think these are really key questions and ones everybody would like to get some really good clarity on. There’s always a balance. Certainly, when the market is beginning to recover, early in the recovery, customers that have long-term plans will look to try to lock in the best rigs at the lowest rates they can, for the longest periods they can. So, we’ve had customers asking for contracts in the range of anywhere from 6 months to 18 months, trying to walk in the lowest rate. Certainly, we don’t want to have a large volume of super-spec rigs locked up for the next 18 months at leading edge rates. So, we’ll balance that out. We might take a couple, but we’d look to leave optionality, so as rates start to improve, we can continue to capture those rates as they rise. I can tell you, our team has a very specific spreadsheet. They used to manage this, which you can’t have a copy of.

We’ll see, we’ll see. Maybe if I ask nicely. But, the -- I guess, the other dynamic is cost. So, cost is something that, obviously, as you’re reactivating rigs and getting things back into the field, I imagine that weighs on margins somewhat. I guess, the offset is what contracted rigs. So, can you help us think through the next couple of quarters here, how we should think about the -- and I’m particularly thinking in the U.S., obviously, Canada is a bit more complex with breakup. But, how should we think about your cost per day or your -- that impact on margin?

Connor, broadly, I think, the rigs that we’ve stacked so far have been stacked in pretty good shape, and we have de minimis reactivation costs, certainly nothing we’re guiding towards. But, I’ll just let Carey kind of reiterate his views on our cost guidance.

So, I’ll point out my comments in the introduction that our efforts to reduce operating costs have largely offset the increased overhead burden by lower activity levels. So, that’s been a really good development from a cost standpoint. As we add the next handful of rigs, we don’t expect to have a whole lot of reactivation cost. We had -- it wasn’t too long ago, we had 80 rigs running in the U.S., I’d say not too long ago, about a year and half ago. So, a lot of those rigs are in really good condition to go back to work. So, it’s not going to be overly burdensome reactivation cost. But as we get deeper into the pool, you may see a bit more cost to reactivate the rigs.

Okay. So, just to square it here, the trend in cost per day probably would be flattish from here, or do you think some fixed cost absorption helps? How should we think about that for the duration of the year?

I think, for the next couple of quarters with the activity forecast that Kevin provided, we should have relatively flat cost per day, absent variations in turnkey, if we’re talking about the U.S. market.

Our next question comes from Keith Mackey with RBC. Your line is open.

Hi. Thanks for taking my question. Just a question on the CapEx number, the $54 million, should we assume that that is a gross number, or is that going to be net of some kind of dispositions as well?

That is a gross number, Keith.

Got it. Okay. And just on the recontracting, and in particular, any rigs you’ve had to add back to the field? Just maybe if you can comment on staffing those rigs, have you been able to recontract the same crews, or is there new people that you’re going to be dealing with in the mix?

Keith, good question. Typically, we’re always trying to bring in some new people. We’ve been quite successful restaffing in Canada and the U.S., pulling back prior Precision during the downturn. But, we still like to seed in some new green hands. We continue to keep -- to build our base of staff. So, we’ve been doing some of that. But, we had no trouble staffing up rigs in Canada or the U.S. in this early stage of the rebound. Now, let me just turn to well servicing for a moment, which is a little different story. In well servicing, we find -- we’re competing with some of the unemployment subsidy programs that are underway in Canada right now as part of the pandemic relief. And the challenge in well servicing is that the workers call out work might be 3 or 4 or 5 days work and then they’re home for two days and then back on work for three or four days. Whereas in drilling we can guarantee months and months of work, typically six months or a year’s worth of work. So, we don’t have that frictional problem. But, well servicing, labor has gotten very tight. And I think, the well servicing sector, I know, ourselves included, are kind of reaching limits of what we can do for recruiting. So, we’re really having to become very creative on recruiting and looking at referral programs and things like that to start getting the base of employees up in well servicing. It is primarily a Canadian problem for us.

Our next question comes from Cole Pereira of Stifel. Your line is open.

As we think about the U.S. opportunity set, should we be thinking of it as continuing to be split between oil and gas basins, or how do you expect that evolves?

It depends on what we get next. I’m not sure what the next award will be. We have a pretty good line of sight to several. But, Cole, my expectation is to see a little more weighting towards oil going forward.

Okay. That’s helpful. Thanks. And so, over the past few quarters, you guys have kind of been able to divest to noncore assets for, call it, proceeds of a couple of million, et cetera. Is there any line of sight that should continue into 2021 to help offset some of that CapEx program?

So, we typically will sell drill pipe when it -- we use it beyond the standards that -- be on the time standards that we’ve established, and we’re able to sell that into a secondary market. That’s typically anywhere between $5 million and $15 million a year. And then, we’ll look to sell other kind of older assets that don’t have much of a use within the Precision organization anymore. So, I think absent larger idle rig sales or noncore divisions, think about divestitures in the kind of $10 million to $20 million range.

Okay, got it. That’s helpful. So, talking about some of the ESG strategy, your ESG report had some pretty good disclosures on your bi-fuel and gas-powered rig fleets. Can you just comment on the level of utilization you’re seeing for this equipment specifically, and if you’ve seen a notable change in the volume of E&Ps requesting this equipment?

Cole, I think, right now, the rigs we have that are not being utilized that either have bi-fuel or natural gas engines are probably just in the wrong physical location. So, we may have demand for bi-fuel in the money, but the rig might be sitting in North Dakota, say. But, I would tell you, almost every E&P conversation now includes a short discussion on the potential to lower GHG emissions.

Okay, got it. And so, as we think about those conversations, has it gone to the point, I guess, very commonly where E&Ps are willing to actually pay for, call it, bi-fuel or other opportunities, or is it kind of just here and there at this point?

No. I would say that our E&Ps have been paying for bi-fuel, and paying for upgrades to bi-fuel, will continue that discipline. I don’t see a capital upgrade to a rig being nonrevenue opportunity for us.

Our next question comes from Aaron MacNeil with TD Securities. Your line is open.

In the context of the three strategic priorities on technology, debt reduction and ESG, are there any specific targets that you’re looking to hit this year, and how should we benchmark you against those priorities as the year progresses?

I think, the one clear target that Carey outlined in his comments was the debt reduction target of a range of $125 million for 2021. You can benchmark us against that all year. As the year evolves, we’ll disclose the steps we’re taking in each of the other priorities and continue to update on those. So, obviously, on technology, market penetration, that’s clearly what we’re looking for. They’ll be disclosing our market penetration. And ESG initiatives that we believe either are important to our investors or important to our customers, we’ll disclose successes on those.

Got it. And could you maybe give us a sense, aside from bi-fuel and some of the other examples you’ve given on what kind of initiatives, some of the ESG part you might be looking at to help your customers?

I didn’t mention in my narrative highline power on the rigs, and we’ve got right now several projects that are highline powered. And our customers are looking at also then securing their power contracts on renewable power contracts. So, that would be a -- for a customer a possibility to have almost a zero emissions rig.

Okay, makes sense. And then, switching gears, you obviously mentioned the U.S. activity should increase 15% to 20% by midyear in the U.S. Do you think that in order to facilitate that, we’re going to have to start to see and now adjustments from E&PS increasing their capital budgets in the first half of the year?

Well, I don’t think so. Because I think if you think about it, in our case, that would be a handful of rigs, five or six rigs. I don’t think that necessarily warrants a capital announcement for the increase. And Aaron, I don’t expect any E&P to lead with their chin on increasing capital spending.

That’s kind of what I was getting at.

Yes. I think, what will happen, though, is I think that receipts at $58 or a lot better than, receipts were going to be at $48. And as they demonstrate strong free cash flows, they demonstrate sustained or improved dividends or share buybacks or debt reduction, I think, they’ll start to earmark additional capital to replace their inventory of wells as they start to work through their DUCs, which is happening right now. I expect it to be -- no question, I expect it to be an all of the above answer for our customers. They’re not going to sacrifice investor returns to add rigs. But, if they can continue to show strong investment returns and add rigs at the margin, they’ll do both.

Our next question comes from Blake Gendron with Wolfe Research. Your line is open.

So, your peer this morning talked through some of the math in the U.S. in terms of super-spec utilization and maybe some of the mechanisms start getting pricing. And part of that was the stacking of older rigs and potentially the retirement of those older rigs, theoretically Tier 2, maybe SCR rigs. I’m just wondering what the mechanism for that would be. I mean, would contractors basically just sell them for scrap? And the reason why I ask is, I’m just wondering the extent to which you think pricing can maybe materialized middle of this year to back half of this year. Considering the rigs never really have gone away in the past and the spread between Tier 1 and Tier 2 hasn’t really expanded all too much outside of maybe rapidly increasing activity levels, just wondering how you think about scrapping versus super-spec utilization and maybe the outlook for pricing? Thanks.

Yes. So I didn’t hear the comments. I don’t know exactly what might have been said. But, we really haven’t seen DC SCR rigs dragging on the price that we’ve been able to achieve in the marketplace with our super-spec, horizontal drilling pad walking rigs. So, I’m not too worried about watching rigs being retired. I’m really looking closely though at contractor by contractor utilization of their super-spec pad walking rigs. I think, the market is really tight. I mean, we’ve added back 100 rigs off bottom. I think, utilization of the super-spec rigs is getting into the territory of pricing power. There are some regional dislocations right now. So, for example, we’re doing quite well with our rigs in the DJ Basin because we’ve got the right-sized rigs in the right place. And it wouldn’t make sense to move a rig from the Permian to the DJ Basin. So, that mobility correction is helping us out there. I think, you’ll see that once -- I’m not sure if it’s a handful of more rigs or maybe 20 more rigs in the Permian that get used up. I think, that we’re going to be in a much tighter market in the Permian.

That’s helpful. In addition, performance-based contracts, you’ve been, if I remember correctly, pretty centrally opposed to some of that commerciality. And the peer this morning, I don’t know if you’ve caught the comments, noted some traction on the performance-based contract side. Just wondering if you’ve come up against it in any tendering activity? And quite frankly, how do you think it plays out, either receptivity of the customer base or otherwise? How do you see this commerciality evolving?

So, we do have performance contracts in Precision right now. We have them in more than one basin and more than one customer in the U.S. We’re watching this closely. We’re continuing to bid other performance-based contracts. I don’t think -- I’m still remaining a little skeptical on this. I just don’t know where it ends up. What I have seen in the past is that once you achieve a new performance shelf or barrier for a sustained period of time, it ends up being a bit of a reset. And you’d also say the same thing about day rates, get reset when supply gets extreme. So, it’s still hard to say how it’s going to play out. We’re keeping our avenues open here. And we’re still not going to miss out on a performance-based contract trend if that continues. I remain a little skeptical on this. I can tell you that we are sustaining our pricing and our technology initiatives with really no competition and certainly no competitive pressures downwards on our technology initiatives. So, we’re quite happy with the à la carte model, day rate for the base rig, à la carte for the add-ons working quite well for us.

That’s...

Yes. I think, Blake, it could go either way here. And I think we’ll be ready to go either direction. Certainly, we have the tools in our analytics and our Alpha technology to deliver strong performance. And as I said in my prepared comments, ultimately, those rigs have delivered the best efficiency drilling, the best wellbore placement, the best safety. We’ll get the best rates, whatever the pricing model is.

Understood. That’s encouraging. When you do bid for a performance-based contract, do the other contractors see the KPIs that you’re submitting? And is there any back and forth in that regard?

There is a lot of game theory by the operators with KPIs and rates in all aspects. Every negotiable term, you can rest assured the procurement team has applied game theory on.

There are no further questions. I’d like to turn the call back over to Dustin Honing for any closing remarks.

Great. Thank you everyone for joining today’s call, and look forward to speaking to you when we report 2021 first quarter results in April. Operator, you may disconnect.

Ladies and gentlemen, this does conclude the conference. You may now disconnect. Everyone, have a great day.