PRECISION DRILLING Corp Q2 FY2021 Earnings Call

Good day and thank you for standing by. Welcome to the Precision Drilling Corporation 2021 Second Quarter Results Conference Call and Webcast. I would now like to hand the conference over to your speaker today, Dustin Honing, Director of Investor Relations and Corporate Development. Please go ahead.

Thank you, Matti, and good afternoon, everyone. Welcome to Precision Drilling’s second 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.

Thank you, Dustin. Before we discuss our second quarter results, I would like to notify the audience on this call that Dustin will be taking on a new role within Precision overseeing the finance operations and other administrative functions within our well service division. As you all know, Dustin has managed Precision Drilling’s Investor Relations efforts very well over the past 2.5 years, and he is ready for a new challenge within our organization. For the time being, you can contact me with Investor Relations matters. Moving on to our second quarter results, our second quarter results were characterized by increasing North American activity, field margin performance exceeding our prior guidance, and a continued strict focus on cost control and cash flow generation. Our second quarter adjusted EBITDA of $29 million included a share-based compensation expense accrual of $26 million. Absent this accrual, adjusted EBITDA would have been $55 million, far exceeding our expectations. The unusually large share-based compensation accrual resulted from our share price approximately doubling between the end of Q1 and the end of Q2 and our cash settled accounting treatment. As noted on our last conference call, the cash treatment and share price volatility may present higher volatility in financial results. Please keep in mind we have the ability to pay a portion of these awards as either cash or equity upon vesting. During the quarter, we received $9 million of 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. The CEWS program has continued into the third quarter, and we expect the impact to Precision to be approximately $25 million for 2021. In the U.S., drilling activity for Precision averaged 39 rigs in Q2, an increase of 6 rigs from Q1. Daily operating margins in the quarter were $6,752, a decrease of $275 from Q1, primarily due to legacy contracts rolling off into the spot market, offset by higher spot market pricing on new rigs and increasing adoption of Alpha technologies. Absent impacts from IBC and turnkey, daily operating margins would have been $227 lower than Q1. During the quarter, we activated 6 rigs, and the reactivation expense remained in the $150,000 to $200,000 range and we expect the same cost per reactivation for the coming quarters.

Thank you, Carey, and good afternoon. I will now take a few minutes to discuss the strong recovery developing in our North American businesses and update you on our progress towards our 2021 strategic priorities. But before I start, I want to reflect that the last year and a half has been extremely challenging for our industry, especially the people who work here at Precision. The pandemic health challenges, the lockdowns, the industry layoffs, the early retirements, and the increased individual workloads have taken a huge personal toll on all of our people. Our field operations remain fully staffed and unavoidably working in close contact, but have managed the pandemic challenges on the job and at home exceptionally well. Over the last 2 months, we have fully re-staffed our corporate offices in Houston and Calgary, and I thank our people for the excellent work they performed in their roles remotely over the past year, and I appreciate the challenges they continue to face every day. We are in the beginning stages of what’s emerging as a strong industry recovery and we rely on the hardworking and loyal Precision team to execute our business, support our customers, and help drive the results our investors and stakeholders expect. While Carey fully covered our recent debt financing activities, I will just add that I am extremely pleased to have substantially resolved our maturity profile, lowered our interest carrying expense, and maintained our strong liquidity, all while continuing to make excellent progress towards both our short-term and long-term debt reduction targets. We believe that reducing our debt levels and bringing our leverage level below 2x EBITDA will create substantial value for our investors. It should be clearer now than ever before that our scale-based business model, utilizing high-value, long-life assets, coupled with highly skilled crews and leading digital technologies, creates a strong full-cycle free cash flow profile and the asset base will require minimal capital reinvestment for the foreseeable future.

And your first question comes from the line of Ian Macpherson from Piper Sandler.

Thanks. Good afternoon. Kevin and Carey, congratulations on the debt refinancing, that’s a great feat for you all financially and operationally, so good to see that. I was informed, Kevin, by your leading edge U.S. day rate data points. Just wanted to clarify, are those base day rates excluding a-la-carte add-ons for the Alpha suite?

Correct. Those are base day rates for the base Super Triple rig, excluding technology add-ons.

Okay. Yes, that’s certainly improving higher than we would have recently expected. And you mentioned the consolidation of your customer base across Canada and the U.S. But there has also been some consolidation in your space in Canada, which I think makes that competitive framework even probably a little bit tighter than it is in the U.S. Are you seeing accelerating pricing power more so in Canada than in the U.S. at this point? And would you lean further out in time to hazard where pricing is going in both markets by the end of the year?

Ian, that’s a very good question, first of all, but the transactions for consolidation in Canada and the one in the U.S. also haven’t closed yet, but we expect them to close soon. I do think that brings an appropriate level of rational thinking to the market space. The way I say that is that in Canada, for example, the Montney play in the Deep Basin and Duvernay are unconventional resource plays with large pad horizontal drilling. These are very much industrialized operations. They require drillers of scale with high-quality technology-driven assets to operate those as economically as possible. So I think that this rationalization we are seeing among the customer base and being echoed in the supply base is constructive. It creates a better pricing environment for our services and a more appropriate pricing environment for the services we provide. The core driver right now for pricing in Canada has been just industry overall demand and some labor tightness tightening up the supply side. Those two combinations are driving the near-term pricing. But we do expect to see rational behavior over the long term on particularly in the Deep Basin in Canada. I think the same thing will develop in the U.S. as that consolidation play takes place.

That’s great. Thanks, Kevin. I will pass it over.

Thanks, Ian.

Your next question comes from the line of Taylor Zurcher with Tudor, Pickering and Holt.

Hey, thanks guys. First question, Kevin, you talked about the Canada market backdrop has clearly improved, and you talked about how we might see a similar dynamic as what’s going on in Canada right now eventually play out in the U.S. In the U.S., we are still well below pre-pandemic levels. So just hoping you could give us a little bit more color on the dynamics at play that you see in the U.S. maybe over the next 12 months? Any suggestion on timing as to when we might get back to pre-pandemic type levels in the U.S.?

Taylor, the number one answer I kind of focused on is that the investor desire for returns and discipline is not going to go away in the U.S., and it hasn’t gone away in Canada either. What happens as our customer’s hedges roll over into the much more constructive strip we see today versus 6 months ago or a year ago, I think that’s going to free up more cash flow. It’s going to allow additional debt repayments, additional investor returns, and the room for modest increases in capital spending like we’ve seen in Canada. Again, the pivot in Canada isn’t a substantial pivot in spending. It’s a modest pivot in spending. When spread among 30, 40, or 50 companies, if you have 50 producers in the U.S. adding one rig, that’s a meaningful step-up in demand for super-spec rigs in the U.S. So I think you’ll see a dynamic emerge in the U.S. with modest increases in spending, one rig additions here and there that across the fleet adds up to 50, 60, or 75 rigs maybe between now and the end of the year. That puts a very strong pull on the super-spec fleet, especially when you factor in regional dislocations—the Permian might have excess super-spec rigs, but most basins don’t.

Yes, makes sense. Good to hear. My follow-up maybe for you, Carey. You talked about robust cash flow for the back half of the year. I suspect with the seasonality in Canada and U.S. activity continuing to trend higher, working capital likely becomes a drag on cash in the back half of the year. Just wondering if you could kind of button up how we should be thinking about that cash flow outlook translating into free cash flow and getting to the midpoint of your debt reduction range would take about $50 million to $60 million of incremental debt pay down? When we think about robust cash flow, should we expect $50 million to $60 million as being kind of the right number to think about for the back half of the year?

Yes, Taylor, I appreciate the question. We don’t typically give guidance for EBITDA; we will provide enough information so you can calculate that. I can walk you through some of the guidance we do provide. I pointed out we have only $22 million of cash interest in the second half of the year. That will be helpful to cash flow. We’ve given our capital guidance where we’ve got another $30 million or so that we’re going to spend on capital expenditures. Those will really be the two main draws of cash. The working capital build since we exited Q2 with such a strong activity in Canada won’t be the typical seasonal working capital build that we would see. We think probably it will be $5 million or $10 million of working capital build and likely that’s offset somewhat by used asset sales that we typically do in the normal course.

Got it. That’s it for me. Thanks for the answers.

Your next question comes from the line of Aaron MacNeil with TD Securities.

Hi, guys. Thanks for taking my questions and Dustin, congrats on the new position. My first question is on the rig move from Colorado to the BC Montney. I assume the customer is paying for the full move but I wanted to confirm. I’m also wondering if the rig already has the Alpha automation technology embedded, and if it will, when the rate kicks off under the contract? And from a pricing perspective, just based on the where you describe the current day rate ranges, how should we think about the pricing on this specific contract, given that you entered into a multiyear contract not a short-term contract?

Yes, I’ll make a couple of comments. I’m pretty sure the customer will identify himself if he’s listening to our call. So I want to be cautious with how much transparency I give out. But the mobilization cost is inside the contract, meaning that the customer is paying the cost of the move. The rig is equipped with Alpha digital technologies and the customer is quite pleased with the performance of Alpha digital technologies. There will be some recertification costs as we bring the rig back into Canada. We will spend under $2 million on recertifications on the rig. I think I hit all the points. Aaron, I think I answered all your questions, but if I missed one, let me know.

Just on the pricing—has the pricing changed materially, given that it’s a multiyear contract versus the rate you described?

I would say that the pricing is structured to give us a return on our investment that we think is well above our cost of capital and in the appropriate long-term range. The bottom line is—it’s not a low market price for the long-term. It’s a price that we’re happy with and that we’ve negotiated carefully with the customer and delivers us a good return.

Yes. And Aaron, I’d also add, we’re not executing this move for strategic reasons. We’re getting an appropriate financial return.

Should I interpret the rig move as just a signal that there is extremely limited capacity in this asset class in Canada?

I think so. I think that the demand could move up further—maybe another two to four rigs into 2022. I don’t think we will be successful in all four of those or three of those or whatever it turns out to be. If we mobilize further rigs, the cost of mobilization is covered by the customer.

And how many 1200s are in the U.S. and idle or otherwise able to move up to Canada?

So I can tell you how many 1200s we have in the U.S. We have—after this one, I think we have about 15, 1200s and several of those are working. I think utilization would be over 50%, but we do have enough idle ones to satisfy the demand that Kevin just outlined.

Got it. And then final question for me, Carey, can you give us a sense of what your expectations are for the wage subsidy for the balance of the year just because those mixed signals on whether the program is wrapping up or not?

Yes. Right now, we’re saying for the whole year, we expect around $25 million. That would mean in Q3, if it wraps up in Q3, that will be $6 million or $7 million.

Understood. That’s all for me. I will turn it over. Thanks.

Thanks, Aaron.

Your next question comes from the line of J.B. Lowe from Citi.

Hi, guys. How are you doing?

Good, J.B. How are you?

I am pretty good. Question, I think, Kevin, you were mentioning something about potential rig reactivations being in the mid-teens. Can you just clarify what geographies you’re talking about?

So actually, J.B., I’d submit to upper teens, so I’ll be clear on that. We see rates moving up for a couple of reasons. Labor is getting tight. Industry reactivation costs are moving up a little bit. You can hang your hat on the guidance Carey gave for our activation cost in that $150,000 to $200,000 range. But I think industry-wide, there may have been some cannibalization of idle assets, but it seems that industry-wide that activation number seems a little bit higher. It's causing better pricing discipline among the industry. We’re seeing that price on cold rig activation costs moving up a little bit to mid to upper teens. That applies pretty much across any oily basin right now and the gas basins are kind of fully utilized.

This would be the U.S. market, J.B., if that was what you’re asking.

Got it. Okay, cool. My other question is could you—I know Ian touched on this with asking about the grades that they include the Alpha suite or not. Could you break out potentially what your total Alpha suite revenue was in Q2 or like a percentage of your total revenue or anything like anything to give us some guidepost on how much that’s really impacting the P&L at this point?

So far, J.B., we’ve given guidance on what we’re getting per item ordered for service utilized. It’s $1,500 a day for AlphaAutomation, and we’re charging on apps anywhere from $250 a day up to $2,000 a day per app. We have additional fees for AlphaAnalytics. We have not yet provided any guidance on what the consolidated revenue number is. That’s something we would likely do in the future. For Q2 and Q3, it’s unlikely that we provide that guidance.

Okay. Alright, thanks guys.

Your next question comes from the line of Cole Pereira with Stifel.

Hi, afternoon everyone.

Hey, Cole.

Hi, Cole.

So I want to start with Carey’s comments on U.S. drilling margin. I want to be clear; you see margins moving kind of flat to up after Q3. I would interpret that the additional activations coming on in Q4 and Q1 in the U.S. are offset by higher economies of scale and higher pricing. Did I get that correct?

Yes. You’ve got that exactly correct. What we’ve said is that we think margins are bottoming this summer and that probably means at some point in July or August, is when we’re going to see margins bottom, where average margins in Q3 are on par with average margins in Q2.

Great. That’s super helpful. Thanks. A lot of concerns about labor tightness around the Canadian oilfield services market. Do you guys worry that the labor issues might put a lid on the rig count heading into Q1? Or how do you think about that?

Cole, I think it’s going to be a struggle, and there are a number of things driving that right now. The drillers have generally, in pretty much every other rebound cycle, always found a way to re-staff rigs. I’m confident that we will re-staff our rigs. I know a few Precision Drilling people are listening to do that work right now, and they are working hard to find crews. But between our brand, our recruiting, and our training, I expect we will be successful. I don’t think it will put a lid on our activity. If a customer wants a rig for one well for 7 days, we might not do that. But for any meaningful program, I think we will be able to step up our crews for that. Industry-wide, it might vary. This could be one of the tougher environments I’ve seen for recruiting. Fortunately, our brand carries a lot of weight out there.

Great. That’s helpful, thanks. With the additional upgrade CapEx, can you provide a little color exactly on what that is? With the increase in small increase in maintenance CapEx, is it fair to assume that’s just because of a more Canadian outlook?

Yes, I think that’s a little bit higher activity expectations in both markets would be the maintenance capital and then the upgrade capital is a combination of additional AlphaAutomation systems and contracted upgrades for customers, things like a third mud pump.

Got it. Okay, perfect. That’s all for me. Appreciate the color. Thanks, guys.

Thank you, Cole.

Thanks, Cole.

Your next question comes from the line of Waqar Syed with ATB Markets.

Thank you very much and again, congrats, Dustin on the move. I’ve enjoyed working with you and thank you for all your help during your stay in Investor Relations. Thanks a lot.

Thanks, Waqar.

Carey, just one quick modeling question. For the rig that’s moving to Canada, the rig mobilization costs, are you going to take a lump sum kind of cost in Q3? Or is this cost going to be spread over the term of the contract?

So it—the revenue we’re going to be getting for that move to cover that move will be spread over the course of the contract, but I actually don’t know right now how we’re going to account for the cost. I can get back to you on that.

Sure. Secondly, you have six rigs working in the Middle East right now. Kevin, do you expect incremental rigs to generate some revenues this year?

Waqar, it’s a little hard to say. Certainly, the tenders are dragging a little longer than we would have thought even just a month or two ago. Nothing is changing that. I think I can comment that vaccination rates in Kuwait and Saudi Arabia are extremely high. Fully re-staffing the office seems to be on the agenda following the current Eid holiday right now, which has wrapped up. I think there is a likelihood we can activate some rigs, quite before the end of the year, but it might be November, December, and then rolling into January.

So is it the COVID issue that’s keeping them from awarding the contract or is it more the current OPEC plus quota, which has eased now?

The simple answer might be yes to your question in that I think it’s both. It’s hard to make a strategic decision at the international oil company when you’re still operating remotely or partly remotely. I think they understand their production depletion curves quite well. They are shutting capacities and drilling activity in both countries is down for oil, and they need to time the restart with when they expect their shut-in wells to come back on again. It’s going to be a careful model about when to bring those rigs back on.

No. Saudi Aramco has a contract to build 50 additional rigs over the next, I believe, 10 years. Do you think they have a need for current idle rigs there, or will they continue to bring in these new builds into the market?

There are tenders in the region right now, including some in Saudi. Some of those are IPM tenders; some are direct drilling tenders. There’s an active tender in Saudi that we’ve been working on for a while. I think we’ve got opportunities to activate some idle rigs. That could be in Saudi or other Arabian Gulf perimeter countries.

Okay. And do you have the Alpha suite of services running on any of the international rigs?

No, we don’t. We’ve been careful to deploy Alpha where we can support it well. We want to ensure we can provide 99.9% uptime. We will be ready to start introducing Alpha internationally in 2022.

Great. Thank you very much, Kevin. Appreciate the answers.

Thank you, Waqar.

Your next question comes from the line of Sean Mitchell with Daniel Energy Partners.

Hi, guys. Thanks for taking my question. I’m going to hit the hot topic here again—labor just one more time. I want to understand, as we move into the back half of ‘21, and it sounds like at least according to your work and some of the work we’ve done, we agree with you that the rig count will continue to rise. How do you think about labor today if you had to crew one rig or two rigs versus having to crew five or ten? What’s the lead time for crew and rig today versus one rig versus five rigs, for example?

Yes, Sean. Typically, when we start working with our customers, we have anywhere from 2 weeks to a month for one rig. I mentioned we have three contracts we signed in the U.S. on those three rigs. I think one rig activates either in late July or early August, and the next two activate a month or two behind that. So we will have plenty of time to build those crews out. The rig managers and drillers already work for Precision. The leadership teams are on staff right now, working on a rig somewhere else. We will pull those guys to the rigs being reactivated and backfill the positions we’ve opened, recruiting for the positions we need to fill. We keep anywhere from 500 to 1,000 people on a callback list. I’d admit we’ve worked our way down that callback list a long way. Now we’re out recruiting beyond that list. I can tell you that for both U.S. and Canada, the next five rigs we need to activate have crews identified. Beyond that, we will rely on our recruiting training methods. I don’t want to underplay how much work it is. We have a dedicated team in Houston and a very strong team in Nisku that do the recruiting and training, and they work really hard, but the results are excellent. They deliver great results for us.

Got it. Thank you.

Great. Thank you.

And Mr. Honing, we have no more questions at this time.

Great. Well, thank you all for joining today’s call. We look forward to speaking with you when we report third quarter results in October. Operator, you may disconnect.

This concludes today’s conference call. Thank you for participating. You may now disconnect.