PRECISION DRILLING Corp Q4 FY2020 Earnings Call

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 are $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.

Hey. Good afternoon and thank you. Kevin, you talked about a 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?

Great question, Taylor. So far, we've observed that private equity exploration and production companies have been adding rigs, along with some public companies. As we look ahead to 2021, I am encouraged by the strong capital discipline our public customers are demonstrating, and it seems the markets are recognizing this as well. I believe that the current rise in commodity prices for both gas and oil is beyond what most anticipated during their budgeting or bank redeterminations. So, the outlook is getting better. Moving forward, I expect the mix of new rigs to be more balanced between public and private companies, rather than heavily skewed towards private ones.

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 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, I’d like to add that we didn’t anticipate those upgrades. While it wasn’t a complete surprise, we were taken aback by our customers' willingness to pay for them. This helps illustrate how the market is changing.

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. Maybe if I ask nicely. The other dynamic is cost. Cost is something that, as you’re reactivating rigs and getting things back into the field, I imagine that weighs on margins somewhat. The offset is what contracted rigs. Can you help us think through the next couple of quarters, particularly in the U.S.? Canada is a bit more complex with breakup. How should we consider your cost per day or the 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 minimal reactivation costs, certainly nothing we’re guiding towards. But, I’ll just let Carey kind of reiterate his views on our cost guidance.

I want to highlight my earlier comments that our efforts to reduce operating costs have mostly balanced out the increased overhead from lower activity levels. This has been a positive development in terms of costs. As we bring on the next few rigs, we do not anticipate significant reactivation costs. Not too long ago, we had 80 rigs operating in the U.S., roughly a year and a half back. Many of those rigs are in excellent condition to resume work, so reactivation costs won't be overly burdensome. However, as we delve deeper into the inventory, you might see slightly higher costs 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.

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, that's a good question. We are always looking to bring in new staff, and we've had success restaffing in Canada and the U.S. by bringing back former Precision workers during the downturn. However, we also want to incorporate some new individuals into the team. We continue to grow our workforce and have managed to staff our rigs in Canada and the U.S. without any issues during this initial phase of recovery. Now, regarding well servicing, the situation is a bit different. In well servicing, we're facing competition from the unemployment subsidy programs currently in place in Canada as part of pandemic relief efforts. The difficulty in well servicing lies in the nature of the work, where employees might work for several days and then have a break, whereas in drilling, we can offer continuous work for long periods, typically six months to a year. Thus, we don't encounter the same staffing challenges. However, the labor market for well servicing has become quite tight. I believe that the well servicing sector, including ourselves, is nearing its limits in terms of recruitment efforts. We are having to get creative with our recruiting strategies, such as implementing referral programs, to increase our employee base in well servicing, which is primarily an issue for us in Canada.

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 to evolve?

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?

We usually sell drill pipe when it is used beyond our established time standards, and we can sell that in a secondary market. This typically generates between $5 million and $15 million a year. Additionally, we look to sell older assets that no longer have significant utility within Precision. Therefore, excluding larger idle rig sales or noncore divisions, consider divestitures in the range of $10 million to $20 million.

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 a non-revenue opportunity for us.

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 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.

I believe that with receipts at $58, the performance will be significantly better than if they were at $48. As they show strong free cash flows and maintain or enhance dividends, share buybacks, or reduce debt, they will start allocating more capital to replenish their inventory of wells while they work through their DUCs, which is currently underway. I foresee that they will adopt a comprehensive approach for our customers. They will not compromise on investor returns to add rigs. However, if they can keep demonstrating solid investment returns and gradually add rigs, they will pursue both strategies.

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 materialize 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.

I didn’t hear the comments, so I'm not sure what was said. However, we haven't seen DC SCR rigs negatively impacting the prices we've achieved in the market with our super-spec horizontal drilling pad walking rigs. I'm not overly concerned about retiring rigs. I am keeping a close eye on the contractor-specific utilization of their super-spec pad walking rigs. The market is quite tight. We've added back 100 rigs from the bottom and the utilization of the super-spec rigs is approaching a level where we may have more pricing power. There are some regional dislocations currently. For instance, we’re performing well with our rigs in the DJ Basin because we have the right-sized rigs in the right locations. It wouldn’t be sensible to move a rig from the Permian to the DJ Basin, so this correction in mobility is benefiting us. I believe that once a few more rigs, possibly around 20, are utilized in the Permian, we'll see a much tighter market there.

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?

We currently have performance contracts in Precision across multiple basins and with several customers in the U.S. We are closely monitoring the situation and continue to pursue additional performance-based contracts. However, I remain somewhat skeptical about the outcome. My previous observations suggest that when a new performance standard is achieved consistently, it often leads to a reset. The same applies to day rates, which tend to reset when supply becomes extreme. It's difficult to predict how this will unfold, but we are keeping our options open and will not miss out on the trend of performance-based contracts if it persists. I still have some skepticism regarding this. However, I can assure you that we are maintaining our pricing and technology initiatives without facing any downward competitive pressures. We are satisfied with our a la carte model, offering a day rate for the base rig with additional costs for add-ons.

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.