Ensign Energy Services Inc. (ESI) Earnings Call Transcript & Summary

Good morning and afternoon, ladies and gentlemen, and welcome to Ensign Energy Services Inc. Third Quarter 2021 Results Conference Call. [Operator Instructions] Also note that this call is being recorded on Friday, November 5, 2021. I now would like to turn the conference over to Nicole Romanow. Please go ahead.

Thank you, Sylvie. Good morning, and welcome to Ensign Energy Services Third Quarter 2021 Earnings Conference Call and Webcast. On our call today, Bob Geddes, President and COO; and Mike Gray, Chief Financial Officer, will review Ensign's third quarter 2021 highlights and financial results followed by our operational update and outlook. We'll then open the call for questions. Our discussion today may include forward-looking statements based upon current expectations that involve several business risks and uncertainties. The factors that could cause results to differ materially include, but are not limited to, political, economic and market conditions, crude oil and natural gas prices, foreign currency fluctuations, weather conditions, the company's defensive lawsuits, the ability of oil and gas companies to pay accounts receivable balances or other unforeseen conditions, which could impact the demand for the services supplied by the company. Additionally, our discussion today may refer to non-GAAP financial measures such as adjusted EBITDA. Please see our third quarter earnings release and SEDAR filings for more information on forward-looking statements and the company's use of non-GAAP financial measures. With that, I'll pass it on to Bob.

Thanks, Nicole. Good morning, everyone. Ensign, as you know, is an energy services company that operates in 8 countries around the world. We employ about 3,000 people. We have about $3 billion of assets, 260 high-spec drill rigs and 100 well service rigs. So the third quarter produced strong results with $60 million EBITDA in the quarter. This includes the benefits of the 2 months of the Nabors Canada acquisition, August and September, which went very seamlessly. The effect of the rate traction mid-summer should -- or showed positive gross margin growth in the quarter. Ensign's firm stance on COVID protocol, that being proof of vaccination or on-site rapid test, has provided worker protection at the rig site and has resulted in essentially no shutdowns. We continue to keep a tight rein on CapEx in the quarter and have been pushing most upgrades over to the operator at cost. In the quarter, we had 7 cold stacked rigs in our U.S. Southern division that were reactivated at about $500,000 per rig on average. In the quarter, we had $3 million of standby revenue, which is affirmation that our clients don't want to let their best rigs go and are prepared to keep their best rigs under contract while they prepare for the next project. We also had $5 million of ETF on 1 particular rig, which we expect to be recontracted here in the next month. The team also delivered on another great safety result for the quarter in spite of all the COVID-related challenges and distractions. The numbers really speak for themselves. And with that, I'll turn the call over to Mike Gray, our CFO, for some detail. Mike?

Thanks, Bob. The outlook and demand for oilfield services continues to improve. Tight supply and demand fundamentals for crude oil and natural gas continue to support strong commodity prices, supporting the recovery of oilfield services and driving activity and pricing improvements year-over-year. Overall, operating days increased in the third quarter of 2021. Canadian operations recorded 2,846 operating days, an increase of 2,160 days. U.S. operations recorded 3,074 operating days, an increase of 1,637 operating days and international operations recorded 929 days, an 18% increase compared to the third quarter of 2020. For the 9 months of 2021, operating days were higher with the Canadian operations experiencing a 38% increase, offsetting a 3% decrease in the United States operations and a 10% decrease in the international operations when compared to the same period in 2020. The company generated revenue of $268.6 million in the third quarter of 2021, a 71% increase compared to revenue of $156.9 million generated in the third quarter of the prior year. For the first 9 months ended September 30, 2021, the company generated revenue of $699.4 million, a 5% decrease compared to revenue of $735.6 million generated in the same period of 2020. Adjusted EBITDA for the third quarter of 2021 was $59.8 million, 51% higher than adjusted EBITDA of $39.5 million in the third quarter of 2020. Adjusted EBITDA for the 9 months ended September 30, 2021, totaled $155.3 million, which was 18% lower than adjusted EBITDA of $188.8 million generated in the first 9 months of 2020. The third quarter increase in adjusted EBITDA was predominantly due to increased activity in Canada and the United States, partially offset by lower termination fees during the third quarter of 2021 when compared to the same period in 2020. The 9-month decrease in adjusted EBITDA was due to lower early termination fees during the 9 months ended September 30, 2021, when compared to the same period in 2020. Depreciation expense in the first 9 months of 2021 was $214 million, a decrease of 23% compared to $278.4 million for the first 9 months of 2020. G&A expense in the third quarter of 2021 was 9% higher than the third quarter of 2020. G&A expense increased as a result of increased activity, which was partially offset by cost-saving initiatives, wage subsidies, overall reductions in personnel and organizational restructuring. The company continues to focus on and will manage costs going forward. Net capital purchases for the third quarter of 2021 were $134.3 million. During the third quarter of 2021, the company acquired a fleet of 35 land-based drilling rigs located in Canada as well as related equipment and certain real property for $117.9 million. The remaining purchases consisting of $8.5 million in maintenance capital and $9.5 million in upgrade capital, offset by proceeds of $1.7 million from disposals. Planned capital expenditures for 2021 year is expected to be between $60 million to $65 million, of which approximately $20 million will be targeted to capital upgrade projects tied to contracts. On that note, I'll turn the call back to Bob.

Thanks, Mike. Let's run around the world with a bit of an operational update, starting with Canada. In Canada, we run 125 drill rigs, which include 35 Nabors rigs, as Mike had mentioned. We also run about 50 well service rigs. Canadian drilling has 43 rigs currently contracted and running today with visibility of 50 rigs by year-end. Canadian drilling has set a 10% quarter-over-quarter rate increases for each of our rig categories going into the third quarter and also into the fourth quarter, an additional 10% quarter-over-quarter increase. Basically, the rate increases reflect roughly a $2,000 a day increase to cover off, one, the loss of wage subsidies and with a net bump of $1,000 to $1,500 a day to the bottom line. While industry utilization is still sub-50%, generally, there are pockets such as the high spec triple for utilization is above 70%. Accessibility to crews is the anchor point now for pushing rates. Crew utilization is more important today than fleet utilization and driving rates up. Rates still have a long way to come back in this inelastic demand market. Recall, we used to get $30,000 a day for our high-spec triples, high-spec 1,500 horsepower rigs not that long ago. Well servicing. Our Canadian well service business unit is currently running at 30% utilization and should peak close to 45% to 50% in the first quarter 2022. Like drilling, we are pushing rates up 10% to 15% quarter-over-quarter and getting it. In directional drilling, we have 5 directional drilling jobs running today with visibility to double that year end and into first quarter '22. In the U.S., we run 93 drilling rigs and 50-plus well service rigs. Our U.S. business unit has 46 of our high-spec rigs currently on the payroll today with visibility to 50 by year-end and are continuing up from there into 2022. We currently have 9 running in California, 9 in the Rockies, 28 in the Southern Permian, Haynesville, et cetera. With a wider distribution of competitors in the Permian specifically, we saw our competitors jockey to recapture market share first. Now everyone seems settled in with their market share and with tight crew availability and bids coming in strong. Everyone is raising rates about $500 to $1,000 every month now. Well servicing, another strong quarter out of our U.S. well servicing team. Our P&A rigs still start -- will start to pick up again in the fourth quarter after crop season ends. Horizontal completion work also picking up. Rockies with 18 to 20 rigs out every single day and California about the same, around 18 rigs as well, running about 36 or 57 well service rigs in the U.S. Our U.S. directional drilling business works closely with drilling team in the Rockies on all of our turnkey projects. Having the directional drillers under the same roof helps deliver excellent project margins. Moving to international, starting with Australia. We run 42 rigs international. International does about 20% of our business. Australia has some COVID-related issues, and that's an understatement. Those COVID-related issues have hampered the buildup of rigs that had projects planned through 2021 that will get pushed into 2022. We operate a fleet of 16 rigs. We currently have 7 running today. We expect we'll be up to 8 by the end of the year, pushing towards 10 into 2022. In the Middle East, we have our two Kuwait 3,400-horsepower rigs that remain under contract until the end of 2024. They continue to be top decile in performance. Our 2 rigs in Bahrain remain under contract and are fully expected to be renewed here later in 2022. In Oman, we are shortlisted on a couple of projects, but we have no rigs active today in Oman. In Latin America, we operate 16 rigs. We have 6 in Argentina, 2 in Mexico, 8 in Venezuela. In Argentina, we have 1 rig working for a major under long-term contract well into 2022, and we're shortlisted on the second rig, which we expect to start up in the first quarter -- second quarter 2022. Mexico, we've got 2 to 3, 3,400-horsepower rigs, So the rigs have mimic the rigs in Kuwait. They're perfect for the PEMEX deep tender, but we may start bidding those on to extended reach deep wells in the U.S. In Venezuela, we're waiting on the November election behavior and the IMF's willingness to support Venezuela moving forward. It is looking somewhat encouraging. Generally, we're currently running 102 rigs worldwide. We expect to grow that about 10% quarter-over-quarter and rate increases 10% quarter-over-quarter. Debt reduction remains priority one. CapEx for 2021 should come in around $60 million to $65 million, right as planned. And as we reactivate rigs moving forward, we anticipate that cost to reactivate will, of course, increase, but not significantly. Rate increases will continue to stay ahead of any cost increases. We also are now commercial on our EDGE AutoPilot rig controls platform with 30 installs under our belt and 1 to 2 installs per month moving forward. We also developed new product called the Auto Downlinking app, which allows operators with real-time operating centers to send instructions to our driller to steer the rotary steerable assembly, which inputs right into our EDGE AutoPilot controls platform, that goes à la carte at $300 a day. We're expecting by the end of 2022 we'll have all of our high-spec AC fleet with our EDGE AutoPilot rig controls platform installed and drillers highly trained with the performance drillers that grow and actually train the -- almost like pilots onto our AutoPilot system. Our revenue per operating day for EDGE suite of drilling optimization products is compounding at about 10% to 15% every quarter. With that, I'll turn it back to the operator for some Q&A.

[Operator Instructions] And your first question will be from Aaron MacNeil at TD Securities.

Bob, can you speak to the specifics of the contract cancellation in Canada? Candidly, I'm surprised to see anyone canceling contract in light of where the rig count is going with labor shortages.

Yes. It ties into -- the rig was basically on standby without crews for the longest period of time as they're developing a second program, and the second program never came together. They didn't want to let the rig go but they finally got to a position where they said, we'll buy out the contract and let the rig go out back to the market. So we benefited both ways. We got a lump sum for an ETF. And we also have the rig back, and it's out on 2 bids right now. So it will be going back to work before Christmas here.

Got it. Can you give us an update on your performance-based contracts? And I guess, in light of the increased automation adoption on your rigs, what kind of appetite would you have to pursue this model more broadly?

Well, in the U.S., as we're adding rigs for a certain couple of clients, they're all on performance-based contracts. We probably have 20% of the fleet in the U.S. on a performance-based contract of some mechanism. In Canada, we've got probably 10% of the fleet on contracts with performance metrics. And our performance-based contracts are constructed differently with different clients, depending on what their specific needs are. Basically, we're focused on also nondrilling time events, nickeling up the OPs, things like that, the total rig spectrum. And because, in most cases, we're also getting our EDGE AutoPilot platform in addition to all of that. In some cases, it's included in the day rate and we make the benefit on the performance-based contract side up to $3,000 a day. So it's continuing to develop and evolve. But I would look at it as roughly 20% or 8 to 10 rigs in the U.S., 3 to 4 in Canada right now.

Okay. Great. Maybe a question for Mike. Can you speak to the go-forward expectations for stuff like reactivation costs, labor cost inflation or any other supply chain or transitory cost pressures that you're seeing?

On the rig activation, I mean it's coming in line with what we're expecting. We did activate 7 rigs in the U.S. during the quarter and looking to activate another 5 plus. So it's coming in line between that sort of $200,000 to, I'd say, $500,000. On the labor side, I mean we are seeing some increases, but those do flow through predominantly to the customer. So we're, I would say, slightly protected on that side. Supply chain -- I mean, it's definitely -- you can see it getting tighter. So we are making sure that we have the inventory and the spare capital as required. So it doesn't have an impact on operations. But our supply chain is doing a very good job at maintaining and making sure that we're seeing minimal to no increases where possible.

Next question will be from Cole Pereira at Stifel.

One of your peers recently talked about that they see drilling demand in Canada next year reaching 2018 levels. I mean is that consistent with what you're seeing at this point? And obviously, labor is going to become a huge issue. I mean how confident are you that you can sort of mitigate any labor constraints over the next few quarters in Canada?

Yes. Well, 2 questions there. When you say 2018 levels, you're talking about number of rigs operating, is that what you mean? Or percent utilization?

Yes. I think number of rigs operating.

Yes. So I think the industry will have a challenge getting to those levels. But I think that we're going to be working at higher rates than we were back at those levels as we run through 2022. The constraint is -- I think there's a couple of things. One is, I mean, the capital is just not getting thrown at the business, thank God, like it used to be, and it's more of a controlled ramp-up. The other big issue is people. Mike touched on the fact that any inflation on the people side with crews is passed on to the operator. I mean we are drilling wells faster every year. So we are creating true value. So the crews that have to be attracted and trained. It's going to be the biggest challenge the industry has over the next year, for sure. So we're -- and we're seeing a lot of our competitors as well bid their rigs based on their crew availability. We're running about 40% utilization as an industry. Yet people are starting to go, hey, I'm tapped out on crews. This -- we've got $2,000 a day premiums for hot rigs. If we have a rig that's got a crew and is hot and so has a window an operator wants to pick it up, we're raising the rate quarter-over-quarter. Plus if it's hot, another $2,000 a day because it pays for itself very quickly.

Okay. Perfect. That's helpful. And just maybe on the debt side. Obviously, there was kind of minimal availability on the credit facility. As you generate some free cash flow into Q4, but also balance out with the need for working capital investments, I mean are you fairly confident that you'll get a bit more breathing room in that realm by the end of the year?

Yes, for sure. I mean we've seen this picture show before, and we manage our balance sheet quite effectively. So as the accounts receivable picks up and collections start coming in, we will have some outflows to AP. But definitely, we'll start to go into the deleveraging mode. The Nabors acquisition did take a bite into our liquidity. But with the rigs that we picked up and the EBITDA potential from those rigs, I think we're definitely going to see some cash flow generation from them.

Okay. Perfect. That's helpful. I guess maybe thinking about the Canadian rig fleet, obviously, kind of increase your Montney position meaningfully with that acquisition. And then so if we think about 2022, I guess, obviously, there isn't a ton of visibility at this point. But with both oil and gas very strong, I mean how do you see the rig composition in Canada evolving between the different plays? Do you think it stays relatively similar to current levels?

Well, I think, I mean, gas is such a different market than oil. Even the gas well and it will stay strong for 15 years, 2% declines, quite different than the oil spectrum. But higher gas prices will increase higher demand for the product. So we're starting to see some demand for 2,000 horsepower rigs come back mostly down in the U.S., down in the Haynesville area. We've got 1 of our 2,000 horsepower rigs that's about to go back to work here. So that's an indication. Obviously, the Henry Hub is driving that. And in Canada, the coastal pipeline, yes. It's got to get fed by something. That's, I think, 1.2 Tcf takeaway capacity, if I'm not mistaken. But anyway, yes, it's more and more conversations about putting deeper rigs to work in Northeast B.C. and some of the challenges are getting resolved. It's coming along, yes.

Your next question will be from Keith MacKey at RBC Capital Markets.

First one, I just wanted to start on. In Canada for Q1, how are you thinking about the peak rig count for your fleet as far as both what the demand is and then what you can actually supply?

Yes. Well, it's -- we're already having -- we expect to be up to around 50 rigs by the end of the year and probably peak at 60 in the first quarter. We're already having conversations with the clients about picking up, getting going and not slowing down through Christmas, New Year's. In the past, people would move a rig on and then shut down the 15th of December, come back on January 5. We're pushing clients hard to say, you know what, you're going to need to get your program drilled. We want to hang on to crews. They'll probably get some special bonuses over the Christmas period, but we're finding that the crews we have want to work. And so I think we're going to see that happen, but we'll probably get to 50 by the end of the year, peak 60 first quarter, I'm thinking.

Got it. And just as you think about your rig count footprint in Canada and the U.S., obviously, it's changed a little bit in the last quarter. Are you still relatively happy with where you've got your high and super-spec rigs? Or could you see some of those moving around a little bit as demand and supply in various areas kind of shifts?

Yes. No, I think we're kind of happy where they've all landed. And they've landed there for a reason. We're seeing some uptick in the Jonah gas fields in our Rockies division. We've got lots of assets. I mean we're running 102 out of 260 rigs worldwide. Those are all rigs that can go to work and turn to the right. So we've got the capacity. And we've got -- over the years, we've put the right rigs into the right place. We've got -- we're a little different than our competitors. We've got a more diverse rig fleet size. So different projects sometimes require different types of rigs. And so we're quite comfortable with where our rig type and depth capacity is positioned here currently.

Got it. Okay. And one final one. Just on the balance sheet. With the credit facility highly utilized, is there any thought for inclination to maybe term some of that debt out into a longer time in the future? Or are you comfortable having the flexibility to pay it all off as cash comes in?

Yes. We're comfortable with where we are right now. I mean we'll definitely look into it as we kind of go into this market in the future years. But I think for right now, the credit facility is a good way of being able to deleverage because you can just put cash towards it, where if you do term out debt, you do have some limitations of being able to deleverage into the future. So from our perspective right now, sort of we'll hold the course with what we're doing, increased activity, increased cash flow and put that towards the balance sheet.

Next question will be from Richard (sic) [ Waqar ] Syed at ATB.

Okay. So it's Waqar Syed. So a couple of questions here. Bob, in the wealth servicing business, do you expect any seasonality in Q4 this year with like stoppages around Thanksgiving and Christmas? Are you seeing the same kind of trends that are playing out in the drilling rig business?

Well, in the U.S., for example, around the Rockies, we always have a crop season, which is starting to get over that. So that's -- that happens every year. That's kind of cyclical, but we're back at it into the fourth quarter here. In Canada, I'm not seeing any abnormal cyclicality for Thanksgiving or anything like that, certainly in Canada. Well servicing is probably less likely to work over Christmas on a drilling rig because of the nature of its work. But I'm not expecting anything abnormal.

Okay. Then, Mike, if I look at your receivables Q3 versus Q2, they went up by about $44 million, but payables went up by about $60 million. As we get into Q4, do you see working capital to be a source of cash? Or do you think there'll be more bleeding from working capital as you catch up on your payables?

It can be, I think, a bit of a blend. So I mean, we're definitely seeing activity pick up into Q4. So with the rig activations we saw in the U.S., that will come to fruition in Q4. We'll have the cash flow from there, where we have the AP kind of buildup in Q3 related to that. So we'll -- it will probably be somewhat neutralized, but I think definitely, we'll see, I think, some excess working capital come back to the balance sheet as we continue to work through this and continue to go from there. So I would say it's probably going to be slightly muted. But definitely into Q1, into Q2, we'll see the fruits of the labor from that.

Okay. And Bob, just a big picture question. When we hear from drilling contractors and even pumpers and others, the feeling is that service pricing could be up meaningfully next year. And certainly, on the drilling side, it looks to be year-over-year well in excess of 10%. Now when you hear -- talk to the E&P companies, most of them are budgeting somewhere around 10% kind of year-over-year price increases. So could you help us reconcile these 2 different views between the service industry and the E&P industry?

Yes. Well, it's the classic case, isn't it? I think what they're doing is they're increasing their well cost -- total well costs in their projects by 10%. Keep in mind that we -- year-over-year, we clip another 5% of efficiency. So think of a 5%, 10%, or 15%. So if they're talking specifically, they expect day rates on rigs to only move up 10%, they're underestimating it. Absolutely.

Yes. But do you expect efficiencies to improve next year or actually come down? Because typically, we see in the industry, industry is most efficient when activity is low. And as activity continues to increase then you have more green labor into the workforce, efficiencies actually come down.

Yes. That's generally true. Keep in mind that we've been running 40 rigs most of the summer here going up to 50, and then by the end of the year and then moving up to maybe 60. You're absolutely correct. There's more of a notion to keep projects going then to come up and down, but there will always be the winter push. We've never seen a winter where it hasn't push. You are correct that the first quarter is where the most inefficient wells get drilled. There's no question about that, green crews, colder weather, other logistics issues, things like that. So I think the operators may be underestimating that number.

[Operator Instructions] And your next question will be from John Gibson at BMO.

First one for me, just given the tightness of the Canadian high spec market, would you maybe look to move some regular crews from the U.S. to Canada as we move into '22? Or are you kind of happy where the balance sits right now?

Yes. We're -- well, it's -- I don't think there's availability of crews in the U.S. We have the same issue in the U.S. attracting crews to come work on rigs since they are resting. The entry-level roughneck wage used to be 4x minimum wage. Today, it's about 2x minimum wage. And so I don't think the notion of bringing U.S. crews up to Canada has ever crossed our mind at this point.

Okay. Got it. Second one, just given the first full quarter of the Nabor rig integration, are you seeing some additional synergies or maybe some other positive aspects of the deal? Or I guess, maybe just provide some color on how the first quarter went and particularly just the increased market...

Yes. Well, it was our 65th acquisition, and it went so seamlessly well that I was starting to get worried of what I was missing. But the team did a great job. Mike and his team and the operations, Eldon Culshaw and our group in Canada. We also added to the 15 rigs that they contracted when we acquired them. We've since added 4 more rigs on top of those 15 rigs as contracted rig. Great culture, very similar to ours, safety oriented, performance oriented. And yes, just has worked extremely well for us.

Got it. And then last one for me. It's kind of a 2-parter, I guess. When you look at the CapEx increases, the incremental growth capital mostly going to go to your North American platform. And then as we look into 2022, can we maybe assume a similar level of growth CapEx? Or could this push even higher just given your outlook for next year?

Yes. It's not going to be too much different, for sure. It's not going to be too much different. We continue to have conversations where operators want specialist crews to drill pipe. We're pushing that on to the operator, where they want us to buy it. We're arranging for it, so it gets paid in 1 year's EBITDA type of thing. So we'll always continue to do good deals that make sense. But the CapEx will be up at this notionally, I expect.

And at this time, Mr. Geddes, we have no further questions. Please proceed.

Thank you. So closing remarks. Market buoyed by strong commodity prices is not overacting with the capital infusion we saw in the last cycle. This is a good thing. We can continue to drive cost efficiencies and safe delivery of our services and drive much higher returns in the near future through higher utilization of our high-spec ADR fleet and with our advanced rig controls and drilling automation features. We look forward to our next call in 3 months from now. Thank you, everyone, for attending.

Thank you, sir. Ladies and gentlemen, this does indeed conclude your conference call for today. Once again, thank you for attending. And at this time, we do ask that you please disconnect your lines.