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

Good afternoon, ladies and gentlemen, and welcome to the Ensign Energy Services Inc. First Quarter 2023 Results Conference Call. [Operator Instructions] This call is being recorded on Monday, May 8, 2023. I would now like to turn the conference over to Nicole Romanow, Investor Relations. Please go ahead.

Thank you, Joel. Good morning, and welcome to Ensign Energy Services First Quarter 2023 Conference Call and Webcast. On our call today, Bob Geddes, President and COO; and Mike Gray, Chief Financial Officer, will review Ensign's first quarter highlights and financial results, followed by our operational updated 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 first 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. I'll just start with a quick summary before Mike gets into some of the details. So a strong quarter with increasing margins year-over-year and quarter-over-quarter as tightness in certain rig-type classes continues to support the rate increases that the industry realized through the back half of 2022 and into the first quarter '23. Every one of our operational areas, U.S., Canada and international delivered significant operating day increases. The quarter had a few timing drags for projects that were scheduled to start in Q1 have been delayed until the second quarter. EBITDA margin jumped another 5% and gross margins on our high-spec rigs jumped about 15%. Ensign continues to manage its balance sheet spending only $41 million in planned maintenance capital to maintain the high-spec fleet in the first quarter. The target for CapEx, maintenance and upgrade is still around $157 million for the year and the focus is reducing debt by $600 million over the next 3 years. I'll turn it over to Mike for a detailed summary of the quarter.

Thanks, Bob. The outlook for oilfield services continues to be constructive despite fluctuating global energy commodity prices and macroeconomic headwinds. Recessionary pressures, inflationary concerns, financial sector stress and the potential for slowing economies continue to weigh on commodity prices over the short term. However, oilfield services activity and revenue rates continue to be steady year-over-year. Ensign's first quarter 2023 results reflect meaningful operational and financial improvements year-over-year with it being our best first quarter since 2014. Operating days were up in the first quarter of 2023 with Canadian operations experiencing a 2% increase, United States a 25% increase and international operations showing a 26% increase compared to the first quarter of 2022. The company generated revenue of $484.1 million in the first quarter of 2023, a 46% increase compared to revenue of $332.7 million generated in the first quarter of the prior year. Adjusted EBITDA for the first quarter of 2023 was $127.3 million, an 82% increase from adjusted EBITDA of $70 million in the first quarter of 2022. The 2023 increase in adjusted EBITDA can be primarily attributed to improved industry conditions, increasing both drilling and well servicing activity. Depreciation expense in the first 3 months of 2023 was $77.9 million, 11% higher than $70 million in the first 3 months of 2022. The increase was primarily driven by a year-over-year increase in the United States dollar. G&A expense in the first quarter of 2023 was $3.4 million higher than the first quarter of 2022. G&A expense increased due to supports of increased operational activity, annual wage increases and higher foreign exchange rate on the United States dollar translation. On a per operating day, G&A was up about $200 per day year-over-year. Net capital purchases for the quarter were $49.7 million. The purchases consisted of $8.3 million in upgrade capital and $41.6 million in maintenance capital for a total of $49.9 million, offset by sales proceeds of approximately $200,000. Total net -- or total debt net of cash was reduced by $29.1 million since December 31, 2022. Our debt reduction for 2023 is targeted to be approximately $200 million. Our target debt reduction for the period beginning in 2023 to the end of 2025 is expected to be approximately $600 million. If industry conditions change, its target could be increased or decreased. Regarding the refinancing of the balance sheet, we do not have any additional news to share. Our commentary and the views are similar to the last quarter discussion. We continue to look at several options that will best serve the company on a go-forward basis. Overall, our debt metrics continue to improve substantially. At the year-end 2021, our total net debt to EBITDA was 5.98, decreasing to 3.76 in 2022 and has further decreased to 3.18 as of March 31, 2023. We will continue to see this decrease to levels we have not seen in many years. On that note, I will turn the call back to Bob.

Thanks, Mike. So let's walk around the world with an operational update. Most of you on the call are well aware that Ensign operates a high-spec fleet of 232 high-spec drill rigs and over 90 well servicing rigs, which employ over 4,000 highly trained crews in 8 countries around the world: the U.S., Canada, Kuwait, Bahrain, Oman, Australia, Argentina and Venezuela. Let's start with the U.S., which provides over half of our EBITDA. We continue to run 55 to 60 rigs in the U.S. with a strong position in the Permian with 45 rigs active today. With the Haynesville play softening due to gas prices, the sales team has been very active churning rigs over on to new contracts. In most cases, where rigs have come off 2022 contracts, we have been able to raise prices to current market prices, a bump of approximately $2,000 a day on the contract turn. So the margin run rate for the second quarter will be marginally above the first quarter run rate in the U.S. In some cases and on more current negotiations, we are more likely to hold rates for a 6- to 12-month term. Our California business unit continues to get frustrated with ongoing challenges with drilling permits in that state. Our U.S. team has plans to pull a few of these rigs over into the Rockies for surface hole projects. These light, agile, highline-capable electric rigs are great for those type of projects. We maintained a 7% market share on the lower 48 and see this stabilizing over the rest of 2023, albeit the negotiations were tougher today than they were 6 months ago. We also see the Permian rig count stable at around 350 drilling rigs active. We're also starting to see operators to drill more into their Tier 2 acreage, which means that to maintain production -- not grow, just maintain production, they will need to drill more wells. We have close to 25% of our active U.S. fleet on an Ensign emissions reduction strategy, which is a combination of high-line powered rigs and also natural gas engine rigs with best systems, battery energy storage. With the arbitrage between diesel fuel and gas, the argument becomes more compelling. As a result, we'll continue to see expansion in this area, which not only reduces emissions, it provides Ensign a high-margin incremental revenue stream. Our U.S. well servicing business had one of the slow starts out of the gate in 2023, purely due to operator project timing, but we are back up to 85% utilization today and look to stay strong through the rest of the year with no rate degradation. Our directional drilling business, mostly Rockies-centric, continues to deliver with steady work on numerous projects. Turning to Canada. Canada had a strong operational quarter, but fell short of expected days as the team pushed rates hard into the fourth quarter, which impacted the first quarter activity. We'd expect it to get closer to 65 rigs active in the first quarter. The second quarter is already looking much stronger as we will maintain 22 of our high-margin high-spec rigs over breakup and then grow that to 50 into July. Our high-spec triples are running well over 70% utilization, which provides continued strong pricing, and we're starting to see most of the high-spec doubles attract work after breakup with no rig degradation. We also signed up 2 of our high-spec triples, 1 coming off contract in the U.S. Rockies onto 2 take-or-pay contracts in mid-30s. That's a base rate. Our Canadian well servicing business unit is expecting to get back up to 18 rigs active after breakup, and a few of those will be '24 operations. We still have for sale of roughly $30 million to $40 million of redundant real estate in Nisku, which when sold, will go towards debt reduction. International is steady as she goes, generating steady, predictable free cash flow and long-term projects. We just commissioned our third rig in Oman on to a 5-year contract. The other 2 started up later in 2022. All 3 rigs are performing well out of the gate. These rigs are all on performance-based contracts. Kuwait and Bahrain, where we have 4 of our largest rigs, continue to execute in the top decile of our contracting peer group in these countries. Australia's first quarter results were frustrated with a delay of 2 large projects that were delayed until the second quarter. This affected the first quarter results but will benefit the second quarter results. In Argentina, we have 2 super spec triples on long-term contracts with day rates moving 10% to 15% on their next turn mid-year. The situation in Venezuela changes daily, but we're expecting that we may have one of our workover rigs and a drilling rig working by the end of the year, but don't hold your breath. On the technology front, our EDGE drilling solutions product line continues to expand with a lot of the supply chain issues behind us with respect to computer hardware access as a result of the pandemic. We're in the middle of deploying and commissioning another 10 of our EDGE drilling control systems on our high-spec rigs. This attracts roughly $1,000 to $1,500 a day of incremental high-margin technology to the rig. We will have EDGE actively engaged on most of our super-spec and high-spec triples by the third quarter. With the obvious arbitrage between diesel and natural gas, notwithstanding the obvious emission reductions when using high line or natural gas power, we are seeing growing demand for EDGE emissions reduction strategy. The product offering ranges from the high line power substation, which rents for $2,000 a day to the stand-alone BES for about the same rate to the full-blown natural gas power system with BES and EMS, engine management system, for around $5,000 a day. These are all high-margin opportunities, and they help reduce emissions by as much as 50%. We have about 10% of the North American fleet on one of these strategies. And when we include dual fuel applications, we have roughly 1/4 of the fleet on an emissions reduction strategy. Our ADS, or automated drill system, which delivers consistent slips that automates the routine for the driller, has been fully tested and now commissioned on 10 rigs in the U.S. The ADS charges out for about $1,000 a day à la carte. So I'll turn it back to the operator for some questions.

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

Bob, I can appreciate you had no meaningful U.S. gas exposure, but several of your larger competitors do and many, I think, if not all, have all pointed to a declining rig down throughout Q2. So I guess, do you see a rig count declining at all in Q2? And are you at all concerned about the knock-on effect of heightened competition for rigs in the event of a decrease of activity? And, I guess, maybe finally, what might be your approach to pricing if that does play out?

Yes. No, fair question, Aaron. I mean we started seeing some impact 3 or 4 months ago. Some of those rigs in those areas are tied up on term contracts with the kind of a Tier 1 contractors, maybe having some ETFs, things like that. But we've been able to, in the last 2 to 3 months anyway, turn over about 20 of our rigs on to other contracts. So we got ahead of it termed them up a little bit more. As you know, we had very little gas exposure, but it did provide a defensive situation, which means we weren't able to raise rates much. We did have some contract turn where from the prior contracts, we were able to move them up a couple of thousand dollars a day to more at the leading edge. But I would suggest that the leading edge has probably degraded a little bit and people are looking for some term as a defensive strategy. California is a little bit of a unique situation all by itself. I mentioned we've got at least 1 rig -- 1 of our electric ADRs, smaller rigs moving over into the Rockies to do some shallow surface hole projects. And who knows 1 year if California will start to straighten up, but it is steady, I'll say that in California, but we're probably down about 4 or 5 rigs from where we expected to be in the first quarter, which had some effect on our first quarter results.

Understood. Mike, maybe one for you. I realized there was nothing specific in the disclosures, but on the prior conference call, you did suggest that you were going to kick off debt refinancing following Q1 results. And so maybe just a bit of an update there. Is that still the case? Can you walk us through the potential time line and maybe what we can expect from you over the coming weeks or months?

Yes, for sure. No concrete sort of additional information to share. So we will definitely look at reaching out to the different areas and looking at what's going to be the best approach going forward. So like I said, our debt metrics really have improved quarter-over-quarter as well as year-over-year. So we think that's going to be a strength going into this type of market. But, yes, I know we continue to look at a bunch of different options, and we'll select the options that gives the company the best durability going forward.

Not to pin you down to a specific time line, Mike. But like, do you think I'll be asking the same question on the next conference call? Or do you think you'll have...

I can't say for sure. I mean the facility will have to deal with something by at least October. So I would say in the next few months for sure, we'll be moving things along, but I can't commit to a firm time line.

Your next question comes from Keith MacKey with RBC Capital Markets.

Just maybe to start out in the international, Bob or Mike, can you kind of just give us a bit more color on the impact of the delays in Australia and then what you think a good run rate for Q2 will be given those projects starting up as well as the Oman rig?

Yes. The Australian projects probably affected Q1 by a couple of million dollars. So that will push into the Q2. The third Oman rig was -- it came on stream on as scheduled. So the first quarter results weren't necessarily too impacted by that, although we thought we may have got going a month earlier, we were ready to go, but the operator wasn't. So we've got a good steady run rate in the second quarter. I'm not sure, Mike, if you want to expand on what effect that has.

Oman, you're going to see one additional rig for the full quarter, pretty much the full quarter of Q2. And then we should see sort of 2 more rigs start up in Australia over the next month or 2. So from an operating standpoint, I mean, there should be probably 1.5 to 2 kind of net new additional rigs for Q2 of 2023.

Okay. Got it. And maybe just a little bit on Canada. So operating days didn't really grow much from 2021 to 2022 -- sorry, 2022 to 2023 in Q1. Can -- you mentioned pushing rates hard in Q4 as part of the reason for that. Can you just give us a little bit more detail on the discussions that you've had then with client and what that will mean for the second half of the year?

Right. Right. So the -- I mean, the first quarter is always prefaced by what happens in the October, November bidding cycle before that. And as we started pushing rates and holding rates into the first quarter on certain rig categories, we found some of the competition not as aggressive on pricing and we lost 8 to 10 bids basically, which put us down about 7 or 8 rigs into the first quarter. And it's hard to claw that back when you're going into the first quarter. So that was a bet that we made. Of course, the other rigs benefited from -- our fleet benefited from that hold on rates or a push and depending on the rig category. We're down at 22 rigs currently. We've got contracts that will take us to 50 rigs by July. So you'll see us go from about 100 rigs currently to back up to about 125 here quickly into July. So we're not going to be reducing the number of rigs that we have active. When we look at the end of the first quarter as compared to the end of the second quarter, we're back up real quick as compared to some of our peers who may see some degradation. We're seeing some clients who use some other contractors through the winter coming back to us and saying, "Hey, we went with the lower price for the winter, have you got this rig available after breakup?" So they're -- they weren't -- I guess the performance wasn't as expected in the first quarter with some of the other contractors. But anyway, we'll be back up to 50 again by July here.

Got it. And just maybe to follow on that, what are you seeing now in the Canadian market? Is most of the competition -- I know it's always price, but has price clearly impacted how things went in Q1? Has the conversation shifted at all from customers looking for the lowest price to, okay, now it's more about operational execution and availability? Or are you still finding that whatever work there is, you're losing a similar portion due to price?

Yes. Well, we're always price-sensitive. Obviously, we misread the market in certain rig categories going to the first quarter being aggressive into the fourth quarter for first quarter pricing. But we're definitely seeing prices always factor, but operational excellence and performing with less downtime is always the key. We represent less than 1/3 of the operation on a daily basis. So the operator is willing to take a lower price sometimes, but not always. It depends on the performance that he picks up. So it's a combination of both. I would suggest that we've been able to now get our price in the second quarter that we were bidding into the fourth quarter, which created some first quarter frustration. So the market's kind of coming back to us and here's an example. In the last 10 bids, we've won 8 of the last 10 bids here in the last 2 weeks.

Your next question comes from Cole Pereira with Stifel.

Bob, you talked a little bit about U.S. drilling margins improving into Q2. A lot of your U.S. peers have talked about their margins sort of flattening out from there. Is that kind of what we should expect with Ensign just given some of the dynamics in the current market?

Yes, I think that's fair. A lot of it has to do with contract cadence there, Cole. So we're certainly not able to push pricing. In some cases, you're having to throw a few things in to hold the market because you've got a Tier 2 contractor kind of nipping at your heels there. But yes, generally, I would say that we will see some rate progression because of the contract turnover from the first quarter into the second quarter, but it will probably normalize through the third quarter, and we'll see what happens in the fourth quarter.

Got it. And can you just add some commentary around what you're seeing in the pricing environment for super-spec rigs in Canada just in terms of the supply and demand fundamentals and how rates are moving as a result?

Yes. The -- there's a big bifurcation, of course, the high-spec triples are very tight markets still. Those rates are not going down at all on any contract turnover, we're seeing that go up $3,000 to $5,000 a day in some cases. It depends on the number of rigs that are being offered. On the high-spec doubles, as I mentioned before, we're starting to see the price that we put out there in the fourth quarter that felt some resistance now get traction because operators are going, you know what, we want that kind of rig. On the more conventional rigs, it's a very tough and tight business still.

Got it. And Mike, just on the interest expense side, I mean, cash interest costs relatively high this quarter. Anything onetime in there? Or is that kind of a reasonable run rate for the credit facility? And how should we also be thinking about lease payments for 2023?

For the interest, we've dropped about 100 bps starting in Q2 on our facility. So we saw sort of a fully priced facility in Q1. So we should actually see our interest costs start to trend downwards. So I wouldn't probably use that as a full run rate, so I'd probably include probably 100 to 150 bps decrease overall for 2023. For lease costs, we expect that to normalize kind of in Q2 and Q3 to historically what we had. We had some leased equipment that we had in Q4 and Q1, and then that's going to normalize for the remainder of the year.

Okay. Perfect. And just one last quick one. I mean, what are you guys seeing in terms of the impact of wildfires on your operations so far?

Yes, yes. It's having some effect. We've got 3 rigs that have been evacuated, 4 rigs on watch. Of course, all the rigs are on standby without crews, we're monitoring it hour by hour. It is cooling off and there has been some rain. So let's knock on wood, the worst is probably behind us. No incidents with respect to personnel. And at this point, no impact on any of our rig assets.