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

Good day, ladies and gentlemen, and welcome to the Ensign Energy Services Inc. Fourth Quarter 2022 Results Conference Call. [Operator Instructions] This call is being recorded on Friday, March 3, 2023. I would now like to turn the conference over to Nicole Romanow, Investor Relations. Please go ahead.

Thank you, Michelle. Good morning, and welcome to Ensign Energy Services Fourth Quarter and Year-End 2022 Conference Call and Webcast. On our call today, Bob Geddes, President and COO; and Mike Gray, Chief Financial Officer, will review Ensign's fourth quarter and year-end 2022 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 defense of lawsuits; the ability of oil and gas companies to pay accounts receivable balances; and 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 fourth quarter and year-end 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. So Ensign, as you know, operates a fleet of 230 high-spec drilling rigs in 8 different countries around the world, along with roughly 100 well service rigs in North America. So we operate about 3 billion assets worldwide, employing about 7,000 people. 2022 was a year coming out of COVID, where we upgraded and reactivated 31 drill rigs, which were all covered with long-term contracts with a payout of incremental capital in less than 12 months. Also in the fourth quarter, we divested our Canadian directional drilling business in exchange for shares in a publicly-traded directional drilling consolidator, which has already doubled in value. We continue to see the drilling contractor space focus on margin over market share, which helps provide this industry better returns necessary to support new technology development and returns to our shareholders. Of particular interest, you'll see in our press release a note regarding our policy. The payments to employees and management is capped at 5% of EBITDA. And close to 30% of the stock is owned by management directors, reinforcing the fact that we are very aligned with our shareholders. I'll turn it over to Mike for a summary.

Thanks, Bob. The outlook for oilfield services continues to be positive with year-over-year increases in oilfield services demand and activity. Inflation concerns have continued to prompt central banks to tighten monetary policies leading to uncertainty for global economies. These factors continue to impact global energy commodity prices and add uncertainty in the macroeconomic outlook over the short term. Despite these macro headwinds, Ensign's fourth quarter and 2022 year-end results reflect meaningful improvements year-over-year, both operational as well as financially. Total operating days were up in the fourth quarter of 2022, with Canadian operations reporting an increase of 21%. United States operations, a 36% increase in international operations, a 14% increase in operating days compared to the fourth quarter of 2021. For the year ended December 31, 2022, total operating days were up, with the Canadian operations reporting a 51% increase. United States operations, a 46% increase and 11% increase in international operating days compared with the prior year. The company generated revenue of $468 million in the fourth quarter of 2022, a 58% increase compared with revenue of $296.2 million generated in the fourth quarter of the prior year. For the year ended December 31, 2022, the company generated revenue of $1.6 billion, a 58% increase compared with revenue of $996 million generated in the prior year. Adjusted EBITDA for the fourth quarter of 2022 was $130 million, higher by $72.1 million than adjusted EBITDA of $57.9 million in the fourth quarter of 2021. Adjusted EBITDA for the year ended December 31, 2022, was $373.6 million, a 75% increase compared to adjusted EBITDA of $213.2 million generated in the prior year. The 2022 increase in adjusted EBITDA is primarily due to improving industry conditions caused by support of commodity prices. Adjusted EBITDA margins for the fourth quarter of 2022 was 27.8%, which is a large improvement from the 19.5% margins that we had in the fourth quarter of 2021. We continue to expect margins to increase into 2023. G&A expense for the fourth quarter of 2022 was $12.8 million compared with $10.2 million in the fourth quarter of 2021. G&A expense totaled $48.6 million for the year ended December 31, 2022, compared with $38.2 million for the same period in 2021. G&A expense increased due to increased operational activity, the reinstatement of salary rollbacks taken during the downturn and annual wage increases. Further increasing the G&A expense was the negative foreign exchange translation on converting U.S.-denominated expenses. Net capital expenditures for the fourth quarter of 2022 totaled $40.6 million compared to net capital expenditures of $20.3 million in the corresponding period of 2021. The net capital expenditures during the year ended 2022 totaled $126.8 million compared to $58 million in the corresponding period of 2021. Our 2023 CapEx budget is set at $157 million, which primarily relates to maintenance capital. Long-term debt, net of cash, was reduced by $51 million since December 31, 2021. Our debt reduction target for 2023 is approximately $200 million, and our expectation is to reduce debt by $600 million by the end of 2025, with industry conditions permitting. Also to note, during the fourth quarter, the company sold its Canadian directional business to Cathedral Energy Services for $5 million in common shares, which translates to approximately 7 million shares. On that note, I'll pass the call back to Bob.

Mike, thanks. So today, we have roughly 125 drilling rigs, roughly 55% of our worldwide drilling fleet active and under contract today. We also have 55 of our well servicing rigs active in North America, which is about 60% of our marketed fleet of 100 well service rigs. Starting with our largest business unit, the U.S., we operate in various regions, California, the Rockies and a primary focus in the Permian. We have 43 of our super and high-spec fleet active in the oil-rich Permian today, 10 in the Rockies and 5 in California. I'll point out that we are not active in the Haynesville gas play. And with very few of our U.S. rigs working on gas prospects, we're generally not seeing the effects of a challenging gas market on our rig activity today. The Rockies continue to pivot over to more high-line power applications with our high-spec AC rigs. With this growing market, we see the opportunity to differentiate Ensign further by applying high line power kits a la carte, coupled with our EDGE power management system. This helps to reduce emissions and fuel costs. California continues to be an enigma. Give us more energy, but don't drill in my back backyard is how it goes. The completion continues as drilling permits are restricted. Nonetheless, we see a path forward, where we will have a base of 5 rigs active through the rest of the year, possibly moving to add 3 or 4 more depending on permit flow. Leading-edge rates for our super spec triples in the U.S. are close to $40,000 a day when we include all the a la carte items like pipe loaders, EDGE-automated drill rig control systems, et cetera. In Canada, we have been steady with 50 high-spec drill rigs operating and approaching breakup now. We have seen strong demand for high-spec rigs or high-spec pad rigs over breakup. We expect to keep 20 to 25 of these high-spec pad rigs running over breakup and then building up over breakup -- or I'm sorry, building up after breakup back to 50 rigs into the third quarter and 60 by year-end. Happy to point out we just closed the deal with a large Canadian operator to tie up 2 of our high-spec triples on 2-year contracts at rates all in close to $40,000 a day. One of the rigs will be transferred up from our U.S. operation once it completes its contract there. That's in the Rockies. As you know, we have the most diverse fleet in Canada with a fleet of 112 high-spec rigs ranging from 800 horsepower all the way to 3,000 horsepower, sorry, in variations of high spec singles, high spec doubles and high spec triples. The Canadian all-service fleet has 16 active today with growing business through the summer and rest of the year. We have a few of those rigs working on 24-day operations. Moving to international. Australia has 7 out of 14 operating today. Australia has been somewhat of a disappointment through 2022 as costs continue to climb faster than the day rate increases on contract turnovers there. Still a very tough place to make a return. In the fourth quarter, and turning to Oman, we activated 2 of our high-spec ADRs in Oman with a third one starting up here in about a month. These 3 rigs are tied up on 5-year long-term contracts. And they're also on performance-based contracts, which enhance our margins. We just recontracted our second high-spec 1,500-horsepower rig in Argentina, which provides full contract coverage out another 12 months. We're careful not to sign long-term contracts over 1 year in Argentina so as to be able to pass on rate increases and stay ahead of inflation. You'll recall we have 8 cold stacked rigs in Venezuela it looks like one of our major clients there may be starting up operations in the fourth quarter, which may see one of our drill rigs go back to work. Very preliminary stages at this point. Kuwait and Bahrain, where we have 4 rigs, high-spec 2,000 horsepower and 3,000 horsepower rigs on long-term contracts, they continue to run like tops with operational excellence in the top decile. We also continue to expand our EDGE Drilling Solution Technology on our rigs around the world and have a backlog today of about 15 systems to be deployed and installed. Our average product revenue for EDGE is around $1,000 to $1,500 per day, which with high margins typical of technology products is rapidly becoming a growing EBITDA generator for Ensign year-over-year. So with that, I'll turn the call back to the operator for Q&A.

[Operator Instructions] Your first question comes from Aaron MacNeil from TD Cowen.

Bob, one of your competitors often speaks to being sold out on AC triples in Canada. I assume you're probably in the same boat. But to the extent that we see incremental demand growth for this rig class over the coming years, can you speak to how you might participate in any supply growth in the Montney or other gas plays just given the Blueberry River and I guess -- and LNG Canada. I guess what I'm getting at is, is this something that you're expecting to invest in over the coming years? Or do you have to sort of sit on your hands given your debt reduction targets?

Yes. No, I think that to be clear, nothing has been released as far as the consequences of the Blueberry decision. There's a lot of conversation on how that will affect drilling prospects. It will be positive in any event. As you saw, as I just mentioned, we have a Rockies gas rig that 1,500-horsepower high-spec rig that we're able to move forward. After it finishes its contract, put onto a 2-year contract up here, close to $40,000 a day. We also have 2 other high-spec rigs in Canada that are ready to go to work and could fill that demand. So I would suggest that what is sold out of rigs, meaning Canada, we've got capacity for 2 more to put to work. Would we invest in a new one? No, I think we're -- we need to see rates well over 50, closer to 55, before 1 could get their head around putting any investment in it. So we got a long way to go. And you also -- I'm not worried about the fail into the Coastal Link pipeline. We have enough forward view with our clients that they seem to be pretty rational in what they need for a rig fleet moving forward, so I don't think Canada needs more rigs is where I'm going.

Understood. Mike, sticking with sort of the debt theme, can you walk us through what a debt refinancing might look like in terms of both timing, composition? And if you want to be so bold, any indications of what blended cost of debt might look like?

Sure. So right now, I mean we're looking at all options and really looking at what's going to be the most beneficial to the company and shareholders going forward, what's going to have the lowest sort of cost of debt. So I'd say we have nothing specific we can share. But when we look at it, there are several options out there. Definitely, a high-yield market has improved from where it was in the prior year. Our debt metrics have also really improved as well. So our belief was always to get a couple of good quarters under our belt as it's easier to have discussions with potential investors and debt holders on having actual results and then set of what things could be, so with Q4 being operationally and financially quite strong, and with Q1 in 2023 and the whole being quite operationally strong as well as financially. We'll really look to probably -- potentially kick something off probably in that May after the Q1 results, just giving us another quarter of operational performance. And like I said, our debt to EBITDA metrics have gone down substantially from where they were in early 2022 of over 5x debt-to-EBITDA, [ sub-4 ] now into 2022, and then we'll see it getting into the [ 2s ] in 2023. So like I said, it's a lot easier to get stuff behind you and then to go out and market off of the story than instead of having to say, well, this is what the future looks like. So nothing specific we can get into. But definitely, there's options out there that we're looking at.

Understood. Maybe I'll sneak one more in. Bob, could you give us a sense of what the potential lift could be in Australia in terms of the number of rigs you could put to work? And what the timing might look like?

Yes. I think Australia is mostly gas. Now it's mostly gas used for utility consumption and export, so they've got a nice arbitrage. And the government put a $12 cap on -- which is -- it sounds like a nice number to put a cap on gas for internal consumption. So it's -- the interesting thing is it's -- as you know, gas is a very geographic-specific situation. But yes, we just see it very normal there. There's very few clients in Australia. It's a tough place to do business. Inflation has been pretty rapid. It was the last one to come out of COVID. So there was a lot of cost there, a lot of business frustration over the last 3 years there. And Australia is -- sometimes to me feels bureaucratically a little bit like California, not to the same extent. They do like resources because they exploit them and they consume them. So not to read too much into that, but Australia because of its gas is not seeing the same uptick like you see in other areas of oily.

The next question comes from Cole Pereira of Stifel.

So it's been about a month since a lot of your U.S. driller peers reported. I'm just curious, I mean you mentioned you don't have a ton of gas exposure. But have you seen a weakening at all of leading-edge day rates in the U.S.?

No, not any weakening. As you know, we are pushing up rates quarter-over-quarter, and we've kind of landed on the low 30s, mid-30s as a base rate before any a la carte items. Our contracts have been turning over into those numbers consistently. Even as of yesterday, we signed another one up. We're tending to -- through the buildup in rates, we tend to term out on 6-month intervals as we move into where we see some stability in rates. We tend to term out in 1- to 2-year contracts to move term. We've probably added $100 million of contract. That's $100 million EBITDA of contract term forward over the last 6 months with that strategy. So no, we're certainly not seeing any tension on bidding down. No.

Got it. And on the 2 Canadian rigs contracted, any additional details you can give on that? Was that related to LNG work? And you said one was from the U.S. Was the other just idle in Canada? And then what would any upgrade cost for those rigs be, if any?

Yes. Good question, Cole. The other rig was currently contracted with this particular operator, and so they wanted to extend its contract out 2 years and add an additional sister rig. The sister rig to that rig, which was shipped down the U.S. 3 or 4 years ago, was a Canadian rig. So it's kind of coming back to Canada, tying it up with the same client on a 2-year term with rates, as I mentioned to you there, all in, closer to $40,000 a day as far as what it's drilling. It's a Duvernay stuff. So liquids, and it's not dry gas by any means, no.

Okay. Got it. And then so I guess my takeaway from that would be that the high day rate is more to support the customer wanting to make sure these rigs are available as opposed to supporting some kind of upgrade CapEx. Is that fair?

Correct. There's no CapEx involved in any of these 2 rigs, 0. The operator thing is in full mode.

Okay. Perfect. And obviously, a lot of talk about the high-spec market in Canada, which means pretty healthy. I mean what are you seeing in the double market right now? I mean, obviously, it's not quite as tight, but I assume still somewhat positive.

Yes, absolutely. There's just a lot more conventional doubles and then the bridge into a high-spec double is defined by 7,500-psi operating system, a high-torque top drive, the ability to move as a pad rig, that type of thing. We're seeing good demand in our high-spec doubles. We're signing those close to $25,000 a day now. So they're kind of filling in the gap behind the high-spec triples. High-spec doubles start to lap over into the bottom end of the high spec triples. So you can see the arbitrage on the rates. So it's pulling our high-spec double rates up. And also, as you see the Clearwater move more into pad-type drilling, pad-type drilling, of course, suggests that you want a high-spec double because you can rack back more capacity than, let's say, a high-spec single. We only have 4 high-spec singles, but we've got a lot of high-spec doubles. So we're in a pretty good position to run that market a little bit.

Okay. Perfect. And Mike, can you give any details on the split of the CapEx and how many rigs you might plan to upgrade this year?

Yes. So our CapEx budget is primarily maintenance capital. We'll kind of look at growth capital opportunities as they come up. But definitely, conversations with customers is that has to be funded by them. So yes, the $157 million is predominantly maintenance capital. And then we'll, like I said, assess as we go throughout 2023.

[Operator Instructions] The next question comes from Waqar Syed of ATB Capital Markets.

Bob, since the beginning of the year, how has your rig count in the U.S. changed?

It's been very stable. The buildup was 2022. Right now, we're stable, running about 60 rigs, give or take, on any given day in the U.S.

And what's your outlook for the next, let's say, 3 to 6 months?

So as I mentioned, we're -- we've been looking for term and recontracting and understanding that there may be some gas rigs moving out of Haynesville knocking on our clients' doors. We've been ahead of that. We saw that coming. So we've been tying up our clients on longer-term contracts at current rates in the 30s, as we mentioned there. I see the -- if we go from California East, California, of course, is all dependent on licensing, and that seems to be a little bit of a teaser there. We think there will be a clear path to see another 3 or 4 rigs there. We have one of our rigs out of California. It's an electric super single that will be deployed into the Rockies, tied into high line power to do surface holes. Very efficient doing that. And the Rockies looks to be quite stable for us. It will be down one rig that we're deploying back to Canada, a 1,500-horsepower super-spec rig. And then the Permian, we're very steady with our client base in the Permian. And we're seeing some of the clients actively putting out 1- to 2-year contracts at these rates because they've seen quite an aggressive 2022 quarter-over-quarter rate increase. And I think they're a little fearful that, that might continue through 2023, plus they also want to secure their best rigs. That's the other thing they're doing.

Okay. And in the Canadian market, Bob, how many super triple rigs do you have?

Well, in the Canadian market, a little different like in Permian. A super-spec triple, of course, is 4 gens, 3 pumps in a high-torque top drive. Because you're drilling with 5.5-inch pipe going out 4 miles, you need the 3 pumps, the high-torque top drive. In Canada, we're not drilling out with those horizons, with those whole diameters. So the concept of super spec triple in Canada just isn't there. The high-spec triples are getting the same rates without having to add the third pump and the fourth generator. All of our high-spec rigs or triples in Canada have the capacity to run both pumps full power and the high-torque top drive. And we're seeing more demand now in Canada for the automated drilling rig controls. So the ADS, which is our auto back, is kind of an auto connection, a little bit of automation on the rig, which drives consistent connection times and back to bottom, which operators are saying, "We don't need to go faster. We need to be consistent." Much like -- so it's becoming -- it's taking a page out of manufacturing, where more operators are more concerned about consistent slips to slips than they are going faster slips to slips. It's already going fast enough.

So how many of these high-spec triple rigs do you have?

In Canada, we've got -- in the triple side, we've got about 25.

And what's the utilization right now for those?

Well, it'd be -- one of them, of course, is a 3,000 horsepower rig. So it would be 22 divided by 25. Mike, what's that?

And then you have -- so you have now one incremental picking gap, so you'll get to 23 with that, and then you have one coming from the U.S. Okay.

Correct.

So you'll be going to -- just I want to make sure I get the math right. So you'll be going to 24 out of 26.

No, we'd be going to 23. I think one of your math is that one additional, one coming out of the U.S. The other one that's I mentioned in that 2-rig deal with a manager is already working. So we'll probably end up at 23 or 26.

Okay. That's good. And as you look forward, let's say, over the next 12 months, and I'll go a little bit longer than you described before, between your international markets, where do you see the most growth?

The most growth, I would say we're back up and running in Oman, and we had Oman shutdown for about 2 or 3 years. And we're starting to see some more activity for our ADR-type or shallow ADR rigs there. So that may improve through the year. Of course, early discussions are any capital would have to be funded by the operator. We're not interested in the deal. Other than that, I kind of at '23 as a year of running steadily 130 rigs and harvesting.

And Mike, some of your peers report daily drilling margins. And is that something that you can let us know either maybe directionally? Like how much incremental change there has been or maybe even absolute numbers of what the daily drilling margin is in dollars per rig day in the U.S. and Canada?

We can look at potentially adding some additional disclosure in the future. But for this call, no, we wouldn't be able to get in that detail. But definitely, I mean in my statements, I mean EBITDA margins have increased from 19.5% in 2022 of Q4 to 27.8% of Q4 of this year. So definitely, we're seeing an increase. And we'll see that probably get into, I'd say, the low 30s into 2023.

With a target -- I mean this business full cycle has to see peaks closer to 50%.

At the rig margin.

Yes.

Yes.

The next question comes from Keith MacKey of RBC.

The first one here is -- so if we assume that some of the Haynesville rigs or gas rigs make their way to the Permian, Bob, Mike, what do you think the breakeven point is for rates, where it's worth it for you or another operator to let a rig go down versus accepting a lower rate to remain utilized? Historically, rates would go down to a certain level, and it's worth it to keep the rigs working, then you end up repricing the fleet at that lower level. But how are you and your competitors, you think, thinking about that now? Is that -- has that breakeven rate changed? Will you lay down a rig if you can't get 35,000 versus 36,000 per day? Or how does that math work today?

Yes. No. It's -- we're just not getting into those conversations. We find that -- because we've been -- my experience has taught me years over year that it costs a lot of money for an operator to change horses. You're on a pad, you got to complete the pad. You've got a team of the rig, the directional crew, the operator's drilling staff, and it becomes a finely-tuned team. So I've always -- we've had clients talk to us and say, "You know what, they'd have to see a $5,000 a day drop before they would even consider making a change." So it's really a nonissue in our mind. As far as a breakeven point, if we're making close to 30% margins, if there's some suggestion that someone would drop their rate by 30% to breakeven to get work, I don't see that happening at all. I mean the high-spec and super-spec triples, usually anything over 60% utilization, you can continue to hold price and get it. So it would be very awkward for a contractor to drop his rates. He'd probably be more likely to drop the rig and be just down one rig and with the sales staff than to go and find work for it.

Got it. Understood. Now just on the debt paydown, I think it was $200 million for year. Are you contemplating that repaying yet with 100% of your free cash flow? I guess the question is, is that $200 million your free cash flow forecast for 2023? Or is there some cushion in there for holding cash on the balance sheet side?

There definitely would be some cushion. So like I said, there's some selective upgrade capital that makes economic sense. We'd have the ability to look at that as well. So that's a target based on what we're seeing with our forecast to be able to start to delever, but also give us some flexibility to look at opportunities as they arise.

Just to add to Mike's comment, we don't look at upgrade capital, but it doesn't pay out in less than 1 year, and we target 6 months.

Thank you. There are no further questions. I will turn the call back to Bob Geddes closing remarks.

Thank you, operator. Once again, we saw 2022 as being the year where Ensign deployed capital to upgrade and reactivate 31 rigs, which, along with the rest of our active fleet, will provide us a fleet of 130 rigs, active every day, generating strong cash flow, which we'll provide, as Mike pointed out, the necessary free cash flow to pay down roughly $600 million of debt over the next 3 years, depending on the market, of course. I'd like to thank all of our employees around the world, whom without this focus and hard work, none of these strong results would have materialized. I'd also like to thank you, the shareholders, for your support and look forward to sharing our first quarter '23 results on our next call. Thank you.

Ladies and gentlemen, this does conclude the conference call for today. We thank you for your participation and ask that you please disconnect your lines.