PRECISION DRILLING Corp Q1 FY2021 Earnings Call

Ladies and gentlemen, thank you for standing by, and welcome to the Precision Drilling Corporation 2021 First Quarter Results Conference Call and Webcast. At this time, all participants' lines 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 conference over to your speaker today, Dustin Honing, Director of Investor Relations and Corporate Development. Thank you. Please go ahead, sir.

Thank you, Denise, and good afternoon, everyone. Welcome to Precision Drilling’s first quarter 2021 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 first quarter 2021 results. Please note that 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. Our comments will include forward-looking statements regarding Precision’s future results and prospects which are subject to certain risks and uncertainties. Please see our news release and other regulatory filings for more information on financial measures, forward-looking statements, and these risk factors. Carey will begin today’s call by discussing first quarter financial results. Kevin will then follow by providing an operational update and outlook. With that, I’ll turn it to you, Carey.

Thank you, Dustin. Our first quarter adjusted EBITDA of $55 million decreased 47% from the first quarter of 2020. The decrease in adjusted EBITDA primarily results from a decrease in drilling activity in all regions. Also included in adjusted EBITDA during the quarter is $11 million in share-based compensation expense and $9 million in CEWS assistance payments. As a reminder, the CEWS program supports employment in Canada, and Precision has utilized this program to preserve jobs within our organization. We applaud the Canadian Federal Government for this program and its impact on supporting employment during the pandemic. The recent Canadian Federal Government budget that was presented included a proposal to extend the CEWS program beyond its current June expiration. We will provide additional guidance on how the program will affect Precision when details firm up, but for now we expect the Precision impact to be greater than what we communicated in February. In the U.S. drilling activity for Precision averaged 33 rigs in Q1, an increase of 7 rigs from Q4. Daily operating margins in the quarter were US$7,027, a decrease of US$4,131 from Q4. The decrease in margins is primarily due to lower idle but contracted revenue earned during Q1 this year, higher operating costs driven by startup costs relating to 12 rigs activated year-to-date and turnkey activity. Big impacts from idle but contracted rigs and turnkey daily operating margins would have been US$1,217 lower than Q4 with the balance of the difference driven mostly by lower day rates and startup costs. For Q2, we expect startup costs and turnkey activity to continue along with no IBC revenue such that normalized margins, absent turnkey and IBC, will be decreased between $500 and $750 per day.

Thank you, Carey, and good afternoon. We're in the midst of a strong growing services recovery cycle coming off the lows of 2020. Without any doubt, our work has substantially improved even from just a few weeks ago. Global excess inventories of crude are rapidly declining. Demand for crude continues to recover, trending towards pre-pandemic levels as the global economy gradually opens.

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

Hey, good afternoon and thank you. Kevin, I wanted to start by asking a question on pricing. You made the comment that in the U.S. market you think you'll be able to get or command a $2,000 to $3,000 a day premium versus I guess some other rigs out there at least for the rigs that are hot. And I just wonder, I mean that the rest of the market, the rest of your peers are all doing the same thing and they are all reactivating hot rigs as well. So I was hoping you could just explain that a bit more and what you mean by $2,000 to $3,000 a day? What premium are you measuring that against, so any color there would be helpful?

Yes, for sure, Taylor. I think as this market has kind of evolved off the bottom of 2020 and we in the industry activated rigs, so those rigs were being activated from idle into operations. We are bringing crews back out to the rigs. We're getting rigs back up and running again. Competition was fairly intense. We put lots of talk about leading-edge day rates on those rigs, commenting that those are like mid-teens, sometimes a little higher and sometimes a little lower for the activation of those rigs. Once those rigs have been running and drill through their first contract, those contracts are generally short-term. We've been trying to keep that book kind of near-term, so 30-day contracts, some are 60-day contracts, and some are well development contracts. When those rigs reprice on the next contract, that’s when we expect that that rig will get a premium over a cold-stacked rig, and that premium could be in the range of $2,000 to $3,000 maybe more, depending on its location and availability timing.

Okay, yes, that makes sense. And just to be clear when you identify that $2,000 or $3,000 a day, you talked about some labor and input cost inflation, that $2,000 to $3,000 a day you are talking about would be pure margin fall-through or would that be some cost recovery as well?

We really thought here that as pure margin fall-through.

Okay, okay.

You know, certainly the day rates coming off the bottom were unsustainable for the industry and we need to see strong leadership on getting rates back into a sustainable range.

Okay, and my follow-up is, internationally you talked about some early tendering exercises going on in Kuwait and also in the Middle East, and I was hoping you could help us understand what the typical timeline is as it relates to some of these earlier tendering activities eventually turning into contracts and eventually the rig going back to work, and you talked about the potential for all three of the rigs to get back to work in the second half, but any color around the typical timeline there would be helpful?

We did give some guidance we had hoped, so I said that we might have likely in the summer, maybe all of us were exactly available for the end of the year. I'd just say stay tuned and listen to updates. Likely we will have a lot more information come July Q2 conference call. The work right now in Kuwait is all pre-tendering work, it's kind of tender surveys and analytics to ensure the rigs meet the specifications. Certainly, our new build rigs all meet specifications. So, we're quite confident that we will be quite competitive with these rigs.

Awful, that’s helpful. I will turn it back. Thank you.

Thank you.

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

Thanks for taking my question. Kevin, you mentioned that your rig activity in the U.S. could be up into the high forties by late this year. Are all those rigs kind of spoken for already or do you have some contracts or is this just like in discussion mode right now?

Waqar, I think it's a combination of open bids we have out there and customer discussions, we have ongoing and it may be a little bit of reading the market we see out there.

Okay, and is this incremental demand still from the privates or are you seeing some public E&Ps getting involved as well?

Still weighted towards the privates, but you know what we've seen so far this year has been about two-thirds privates and about one-third publics. And I think that weighting looking forward would be similar. But I think there's likely room for the publics to start moving into a few more rig activations in the second half of the year, once they demonstrate a couple of quarters of good free cash flow, which we think they will.

Now Halliburton in their call yesterday mentioned that they now expect U.S. E&P budgets to be up about 10% or so year-over-year. Previously they were commenting that it's going to be actually down by maybe 2% to 3% or so year-over-year. In your discussions with privates and publics, do you get that sense?

Well Waqar, usually we are last to hear because of course they are trying to run game on our day rates. So we're less likely to hear forward guidance on capital spending than some other services might, but listen it makes sense. If we realize these budgets were probably created when the WTI prices were in the forties, not in the fifties or sixties late last year. And certainly, you know we expect that our customers both in the U.S. and Canada will demonstrate very strong free cash flow during Q1 and obviously again during Q2. So, we think some of that money comes back into drilling.

Good, good, yes the expectation is that the public E&Ps may pick up activity late in the year in November-December when that CapEx number may be reported next year's number and not in this year's number. So that's kind of their thinking from discussions. So, hopefully, that's the case. That's all I have.

I was going to say one thing we are certain of is that current drilling rates are inadequate to support current E&P production levels. We do see our customers using their inventory of uncompleted wells to support production right now, that can't go on forever; that's going to work its way down.

Good, good, yes. Thank you, that's all I have. Thank you very much.

Great, thank you.

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

Good morning, everyone.

Hi Cole.

I just wanted to start on margins. So, in the U.S. it sounds like they're going to take a bit of a step down next quarter, which I mean is understandable with all the startup costs. But I mean as we think about the rest of the year, obviously the startup costs will continue, but at the same time I expect there to be some sort of economy of scale. So, I mean do you kind of expect a bit of a recovery in that metric even as you activate more rigs or how should we think about that?

I think you are thinking about it the right way, Cole. You know, Kevin mentioned, we think that spot pricing bottomed in the first quarter. We've got more rigs that have been fired up. We have hot rigs to market which should push pricing up a bit more. And you're also correct about the startup costs, that will be spread over more activity days as we get back into the rig count. So, we would expect after the second quarter, if the fundamentals for the industry altogether different margins will start expanding in the third quarter.

Okay, that's helpful, thanks. Regarding international rig tenders, can you specify how much capital expenditure you anticipate needing to activate these rigs? And I assume that if you do need to spend that, it will be under contract?

That's a great question. There will be capital expenditures involved. Those rigs have been idle for a year, and before that, they were a little over 6 years old, so there will be some time-based re-certifications, particularly for things like BOP stocks. We're estimating that will be in the range of $3 million to $5 million per rig. We expect that this cost will be recovered quickly in the contract, likely from wells in the first year. Therefore, we anticipate the contract duration to be measured in years rather than quarters.

Okay, perfect. That's helpful, thanks. I'm just curious on the GHE monitor pilot; I mean, should we be thinking about it as relatively immaterial in the near term from a cost perspective? And how are you thinking about that from a revenue model standpoint? Would you like it to just be sort of a day rate add on or how do you think about that?

I see our efforts to reduce our environmental impact as a key part of the value we deliver. If these efforts require capital investment, we will look to recoup that capital during the typical upgrade period, which could range from one to four years depending on the contract's scope and duration. It is essential for us to collaborate with our customers to find ways to minimize our footprint while ensuring capital recovery.

Okay, got you.

Does that answer your question?

Yes, yes, that works. So, from a balance sheet perspective, I mean, given where the bonds are trading right now, do you see yourself more paying down the credit facility in the near term and then maybe think about terming out some of that debt even more in the latter half of the year?

Yes, so we're in a position where we have optionality. Obviously, we're generating free cash flow that we can use for debt reduction. We have a healthy cash balance. We have a little bit of balance left on our revolver and we have our 23 notes that are callable at par in December of this year. So, we'll look to potentially make open market purchases throughout the year or pay down the revolver and at the end of the year we will have the ability to call those 23 notes to meet our debt reduction targets. And in terms of longer term at some point in the next, call it 18 months, it is likely that we would execute a high yield transaction to term out some of the longer or actually I should say near term maturities. We think it's probably a little bit too soon right now and we actually have been chipping away at the 23 and 24 notes. So, as we move along in time those balances will be smaller than they are today.

Okay great, that's good color. That's all from me, I'll turn it back. Thanks for the answers.

Thanks Cole.

Your next question comes from John Daniel with Daniel Energy Partners. Your line is open.

Hey guys, thank you for including me.

Hey, John.

Kevin, just on your activity comments, it's a nice progression to the high forties. Can you just elaborate on the duration of those opportunities given where the strip is or are they trying to lock it in for 2022? Just any color on that would be appreciated?

We have some customers looking to secure leading-edge rates for a longer duration, although few extend beyond a 12-month period. We will continue to maintain a mix of medium and short-term contracts. Our exposure is balanced, but in this rising market, we are eager to see contracts renew.

Okay, yes, understandable.

I didn’t really give you liability on that answer, but I would tell you most of the contracts are less than a year.

I understand that why they would be less than a year today, but I don't know because of where the strip is if people are now asking for more term? And now understanding where you want the pricing to be, but just, conceptually if they want to lock these things in for longer?

Very few companies have their 2022 budget identified yet.

Yes.

So, not looking beyond the first few months into 2022.

Okay, got it.

And I think they are still trying to recover from 2020 and really understand where they're going to be sitting financially over the course of this year before they get too committed to 2022. Although I would tell you the long-range planning on '22 is looking quite robust.

It seems there could be a rush, as Waqar mentioned, in the fourth quarter with people trying to secure their positions, which would benefit your company in light of rising rates. I'm not sure if people want to get ahead of this.

So, you know for sure right now every penny they save matters. But if they're back into getting rigs and a rig is $3,000 or $4,000 a day more. And you know they're going to be drilling 20-day wells. That's only $60,000 against what's probably a $2 million or $3 million well, so the rig cost is just a lot less meaningful than it might have been in any previous recovery cycle.

I agree, but they always look at that number first thing they look at, right on an AFE day rate, typically.

They do, they do but in a rising tide I would tell you that, yes, getting a good rig is probably more important than saving your last penny off the price.

Absolutely, no, no, I don't think I hear that. Last one. Kevin, just the sort of big picture thoughts on your well service business as it relates to opportunities in the United States for expansion?

We have a very small footprint pressing into North Dakota, which really leverages our Southern Saskatchewan capabilities. But we don't really see the expansion beyond that natural extension of our activity is nothing, nothing beyond that.

Okay, that's all I got. Thank you, guys.

Thank you, John.

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

Hi, good afternoon everyone.

Hi, Keith.

I have a question that might be a bit sensitive, so I would appreciate any comments you can provide. Considering the $9 million wage subsidies, which are quite significant in relation to Q1's $75 million EBITDA, what is the strategy as that program may diminish in Q2? Are we maintaining our capabilities in anticipation of an upswing in the latter half of the year, or is there a possibility of restructuring? Any insights you could share on this would be valuable.

Well, Keith, through most of us here, we did most of the restructuring that we think is necessary. But I'd add a couple of things here, I think that we did preserve jobs that would have otherwise, maybe not have been in the company without that program. But I would tell you that today, a large portion of the value is actually across the field operations in drilling and well servicing. And you could say that, in fact, the drilling rigs are running a little cheaper right now, and the service rigs were able to be cheaper. And that value is kind of being earned by the operating companies getting the services a little cheaper. So I'd expect that as those relief programs start to wind down, we will look to push rates higher to reflect the increased cost.

Got it and maybe just as a follow up on that, I was sort of also wondering if that, any potential ramp up in the site reclamation program spending that some expect in the second half of the year, kind of plays into your footprint, the way you've got it set up now?

I'd tell you that we're pretty enthusiastic right now about our performance in well servicing, any increase in reclamation awards, and we've been doing very well, got to blanket our business right now as all really good flow through, right so the bottom line for us. I think we'll be pushing hard to win more of those awards and continue to support the increasing demand we see in the field for conventional well service remediation work.

Got it. Okay, that's it from me. Thanks very much.

All right. Thanks, Keith.

Your next question comes from Dan at Morgan Stanley. Your line is open.

There's been a lot of talk about, whether operators in the U.S. are going to kind of stick to managing budgets to production maintenance mode, or if we're going to maybe pick up activity. I kind of wanted to ask a similar line of questioning, but in Canada, just in your conversations with customers, do you get the sense that Canadian operators are kind of in maintenance mode as well, or how would you kind of characterize the strategy in that market?

Dan, I would say that transition probably happened two or three years earlier in Canada, where the E&Ps were forced into a maintenance or fiscal discipline mode, really as early as 2014 or 2015 after the first sort of OPEC collapse. So I think it's running longer in Canada. I think the E&Ps in Canada are trying to find ways now to do both, generate good shoulder capital returns, and find ways to develop modest growth. You've seen a couple of transactions up in Canada that are designed to eke out a couple of our E&P transactions as some of the synergies grow production, but not necessarily increased capital spending. And certainly, we're going to see activity kind of come up off of the 2020 extremely low levels we experienced last year.

Got it and yes, that was kind of my follow up is, you said in the U.S. you think that we're running below maintenance activity levels. Obviously, the answer is a lot more complex in Canada given seasonality in the resource plays, but just wondering if there's any kind of a bogey you could point to for what might represent maintenance activity levels, like, maintenance rig count in Canada?

A little hard to say, because the mix of hydrocarbons is a bit different in Canada than the emphasis last couple of years for our triples has been around what I referred to in my comments was Montney and Duvernay and that's, it's a natural gas basin, but it's actually very wet, and the wells are essentially being paid for, but the natural gas liquids that are being produced, and those are still going to pipelines that get shipped over to the heavy oil producers. And it's used as a diluent with the heavy oil being piped to the U.S. So you've got natural gas liquids, you've got natural gas, and you've got oil. All three are quite constructive right now, and with the Canadian oil and gas complex operating in a disciplined mode, I think there's room to see activity move up and still be disciplined.

Understood, thanks a lot for the color. I'll turn it back.

Thank you.

Your next question comes from Jeff Fetterly with Peters & Company. Your line is open.

Good afternoon, everyone. Just a quick follow-up question on the technology side. So given you've obviously laid out the adoption and successes you're seeing across Alpha and some of the emission stuff, how should we think about the impact on your day rates and margins from both first Alpha, but also the emissions piece?

So on the emission space, I'll start there. If we make a capital addition to the rig, be it a natural gas engine or a battery power back, we'll look at that, like it's an upgrade. And we'll look for typical operating economics, which means payback within the contract period. And that could be one year, it could be two years, unlikely it stretches up to three years. So there's a capital enhancement to the rig, we'd want to see that capital recovered. So we view our customers as partners with us in those GHG emission reduction efforts. Now, and I think even talked about a couple of those on the last call, we had some upgrades we did that were specific to both the natural gas conversions and the footprint of the rig where our customers paid for those upgrades. Now coming back to the Alpha, great question on value assets, I can dive into this a little bit. The price we posted for Alpha Automation in Canada is $1,500 per day Canadian and in the U.S. $1,500 per day U.S. that price has stuck in the market. It's a price we introduced originally three and a half, four years ago. You know, that's essentially a price that allows us to recover any capital investments we need to make within a couple of hundred days. And after that, it is essentially EBITDA for us. On the apps, we're charging in the range of anywhere from $200 to $250, up to about $1,000 per day, depending on the value the app creates. In some cases, if we own the app, although the revenue comes to us if it's owned by a partner, then maybe some revenue sharing agreement, but generally, there's an operating cost for an app, so it is all EBITDA. On our revenue model for our optimization of Alpha Analytics, we're charging a per day rate for the days that we do the optimization for our customers. So these are all per day adders to the base rate cost. So what we see happening, Jeff is that the rig may need to compete on a per rig basis. But all of the adders are a la carte to the price of the rig go on top and there is simply no competition on these technology offerings; we're not being bid down on our technology offerings.

So conceptually, we should think about the $1,500 per day base rate being applied across the 30 plus rigs consistently that you have running today?

I think we gave a U.S. rate of about 60% and in Canada on our super triples, I didn't give a rate on that, but it's less than 50% right now. But we expect over time that both Canadian and U.S. fleets will trend towards full utilization.

Okay. Thank you and on the CapEx side the $54 million budget, is there some room built in for maintenance capital tied to the U.S. fleet ramping up faster than you had previously talked about or is there some potential that your capital program needs to expand obviously ignoring the comment earlier about the reactivations internationally?

Hey Jeff, it’s Carey. I would say that that capital plan of $54 million incorporates a steady increase in activity in our U.S. rig count throughout the year. That's how we've budgeted it. Now there's a sharp ramp, if we get to an activity level that's higher than what Kevin guided to kind of high 40s towards the end of the year, there will be a little bit of an increase, but we're talking probably like low single digits, millions of dollars.

In the $3 million to $5 million per rig for the International that would be incremental to that $54 number that's currently guided?

That would be associated with signing a long-term contract.

Yes, okay, thanks for the color.

Your next question comes from Dan Healing of Canadian Press. Your line is open.

Hi, guys. Thanks for taking my question. I was looking for some comment on Joe Biden and Justin Trudeau announcing bigger emission targets for Canada and the U.S. by 2030. And I heard on the call that Precision Drilling is doing things to help customers reduce emissions while they're drilling. But I wonder from a higher level in terms of what the industry can expect to happen and Precision Drilling specifically over the next eight and a half years? What's the impact going to be?

Dan, these are obviously extremely aggressive targets being laid out by leaders in Canada and the U.S. And I think there's an absence of process or plan behind the targets, but you did start with the target I understand that. And I think the objectives that they're trying to achieve, we agree with that we support. And, in our case, there are solutions for drilling rigs to take them to essentially zero emissions almost immediately. We've done that in the past with grid-powered drilling rigs. And that's not science fiction, it is easy to accomplish; the only issue is having adequate grid power in the field to the rig. But as these fields mature and become more industrialized, I expect to see more industrial-grade electric power applied to the fields, and I'm likely to get better sight. So I think that from a drilling perspective, getting to zero or near-zero, or certainly getting to the target safe talked about which are 40% and 50% reductions are achievable. And in our case, to convert one of our super triple rigs from diesel-powered rig to Highline-powered rig is a very small amount of capital.

Okay, just as a follow-up, are there things that the government should be doing for the oil and gas companies and the drilling companies to get them to these targets?

I think that any of the technology incubators or technology supports that the government is providing for all of the alternative energy sources, the oil and gas industry should be looking at very hard. And that would include everything from solar and wind power to hydrogen fuel cells and highline power. But I think those avenues are open to us now. And I think that I know my team is looking hard at the opportunities we have to seek out Federal R&D assistance for alternative power that we're looking at.

Okay, thanks very much.

Great, thanks Dan.

There are no further questions at this time. I'll turn the call back to Dustin Honing for closing remarks.

Thank you, everyone for joining today's call. We look forward to speaking with you when we report second quarter results in July. Denise, you may disconnect. Thank you.

This concludes today’s conference call. You may now disconnect.