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

Good morning and afternoon, ladies and gentlemen, and welcome to the Ensign Energy Services Fourth Quarter 2021 Results Conference Call. [Operator Instructions] This call is being recorded on Friday, March 4, 2022. I would now like to turn the conference over to Nicole Romanow, please go ahead.

Thank you. Good morning, and welcome to Ensign Energy Services Fourth Quarter and Year-End 2021 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 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 that could impact the demand for 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 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, and good morning, everyone. Thank God, 2021 and COVID for the most part is behind us. And here we are faced with another global crisis of a different kind. I'm referring obviously to the terrible Ukraine crisis, and it's escalating day by day. Back to COVID, we are truly learning to live with this virus and with most of the developed world having a high level of vaccination, we are in much less vulnerable position than a few years ago. 2022 out of the gate, as I mentioned before, is already bringing its share of geopolitical tension, which is causing rapid upward pricing in the commodities markets. This enhances the effect of half a decade of underinvestment in the oil and gas business worldwide. The perfect storm of increased demand, restricted global supply and the resulting market price response for oil and gas commodities leads us into arguably the best fundamentals for a drilling and well servicing contractor that I've seen personally in the 30 years I've been in the business. I'll provide you with an update on what we see currently in all of our markets around the world and also touch on what we see developing in the short term and longer term, with respect to pricing torque and activity levels in the various areas. But first, let's come back to the primary focus of this call, to reflect on the fourth quarter and the full year 2021. I'll touch on some highlights. 2021 was yet another challenging COVID year, which Ensign executed extremely well on. Despite having headwinds related to COVID-related costs, the team generated strong EBITDA, kept our maintenance CapEx in line with budget, and we activated roughly 25 rigs in the back half of the year. These reactivations led to onetime fourth quarter expenses, which directly affected the fourth quarter results. Also by continuing to implement innovative system solutions internally, the team also lowered its overhead costs another 23% year-over-year. Taking in an arguably the most efficient oilfield service company from an overhead property day basis. In 2021, we didn't sit back as we executed on the opportunistic acquisition of the Nabors' Canadian assets. I'll say that with over 65 acquisitions under our belt over the last 30 years, this was one of the most seamless acquisitions we've been involved with, great assets, great people help to make this a seamless transition. In 2021, we doubled our EDGE AutoPilot platform and now have our EDGE drilling automation controls package on 40 rigs worldwide. The EDGE AutoPilot is the base platform from which our full suite of EDGE drilling solution products reside. These products range a la carte from $240 to $2,500 a day with various apps. We think of EDGE like Microsoft Office, where you can turn on Excel or Word or PowerPoint or whatever best suits your needs. The focus is on rig process automation these days. This will be critically important as we train up newer drillers into quickly growing active rig market. So I'll turn the call over to Mike Gray to dive into the details.

Thanks Bob. Growth for oilfield services continue to be constructive as the oil and natural gas industry continues its recovery from the adverse impacts of the COVID-19 pandemic. The easing of health restrictions and increasing global economic activity and mobility has supported the recovery of global crude oil demand, supporting strong commodity prices and [ input ] for drilling and completion services. Constructive industry fundamentals have resulted in meaningful activity improvements year-over-year. Total operating days were up in the fourth quarter of 2021, with Canadian operations reporting an increase of 1,795 operating days; the United States operations, a 75% increase; and international operations, a 4% increase in operating days compared to the fourth quarter of 2020. For the year ended December 31, 2021, total operating days were -- with the Canadian operations reporting a 60% increase; United States operations a 12% increase, offsetting a 7% decrease in the international operations days compared to the year ended December 31, 2020. The company generated revenue of $296.2 million in the fourth quarter of 2021, a 47% increase compared to revenue of $201.3 million generated in the fourth quarter of the prior year. For the year ended December 31, 2021, the company generated revenue of $995.6 million, a 6% increase compared to revenue of $936.8 million generated in the prior year. Adjusted EBITDA for the fourth quarter of 2021 was $57.9 million, 10% higher than adjusted EBITDA of $52.7 million in the fourth quarter of 2020. Adjusted EBITDA for the year ended December 31, 2021, was $213.2 million, a 12% decrease compared to adjusted EBITDA of $241.5 million generated in the year ended December 31, 2020. The 2021 decrease in adjusted EBITDA was primarily due to the decline in standby and early termination fees revenues earned in 2020. Depreciation expense for 2021 was $288.2 million, 23% lower than $374.7 million from the prior year. G&A expense in the fourth quarter of 2021 was 14% lower than the fourth quarter of 2020. G&A for the year ending December 31, 2021, was 12% lower than the prior year as a result of cost saving initiatives. Net capital expenditures for the fourth quarter of 2021 totaled $20.3 million compared to net capital expenditures of $3.3 million in the corresponding period of 2020. Net capital expenditures during the fiscal year ending 2021 totaled $176 million compared to $18.4 million in this corresponding period of 2020, and included the opportunistic acquisition of 35 drilling rigs in Canada for $117.5 million completed in the third quarter of 2021. In the fourth quarter of 2021, the company amended and extended the existing $900 million revolving credit facility agreement with its syndicate of lenders. The amendments include an extension to the maturity dates of the credit facility to the earlier of 6 months prior to the maturity date of the senior notes due in April 2024 or November 25, 2024. The amendments and extensions provide the company continued access to the revolver capacity and near-term flexibility in a volatile oil price environment. Subsequent to December 31, 2021, the company completed the sale of 2 drilling rigs that were cold stacked in Mexico for cash proceeds of USD 34 million. The transaction resulted in a USD 23.9 million gain before taxes and has improved our liquidity position from the year-end. On that note, I will turn the call back to Bob.

Thanks, Mike. So we'll go around the world for an operational update and provide some outlook into what we're seeing. Starting with our U.S. drilling operations. In the U.S., we operate a fleet of 88 drilling rigs, close to 75% being high spec and super spec, 1,500 to 2,000 horsepower class rigs. Today, we have about 50 rigs active with 33 of those in Southern, primarily Permian, 10 in the Rockies and 7 in our California business unit. Market momentum is obviously carrying forward, and just in the last few weeks, we have signed up another 10 rigs on contracts ranging from 6 months to 1 year. Some of these involve cold stacked rigs, where the incremental capital required to upgrade or reactivate the rigs is being covered well within the contract period. Rates have moved quickly in the last month as operators call to ensure they have preferred rigs contracted. We've seen our high-spec 1,500 and our newly branded ADR 1500I, I for Intermediate, capturing the 3-mile category. So we have the ADR 1500 on the 2-mile; the 1500I, 3-mile; and the 1500S for the 4-mile categories. This, along with our S -- our super-spec ADR 1500S rigs are quoted out with leading spot prices in the 25-plus range. These are up about $5,000 a day from fourth quarter '21 prices. U.S. well servicing operations, we operate 53 relatively new well service rigs in the U.S. servicing the Rockies, California and West Texas markets. Today, we have 40 or 75% of the fleet actively engaged with rates inching up as we recontract projects. Well servicing is generally on a call out or project base, so opportunities to move pricing can occur with a quicker cadence than the drilling fleet. Directional drilling. Our directional drilling business in the U.S. has a 10-kit capacity. We generally focus on internal business by augmenting our drilling turnkey projects in the Rockies. These projects involve some execution risk. So having our high-performance directional drilling team on these projects helps to maximize our project margin. We have 3 projects on the go today. In Canada, our Canadian business unit, we operate with the recent Nabors acquisition of 35 rigs, a fleet of 123 high-spec drill rigs along with a fleet of roughly 50 well servicing rigs. Also within our Canadian business unit, we have a midsized directional drilling group with 30 kit capacity and also a quarrying and rentals group. Today, we have 52 drilling rigs operating heading into breakup, with about 25 expected to run over breakup on pad work. Once we get through breakup, we expect to rapidly get back up to 50 rigs over the summer and forecast close to 65 to 70 rigs active by year-end. We've identified about 10 cold-stacked and currently active rigs that operators have requested upgrades on and which have attractive contracts with roughly 20% to 25% rate increases. Pricing on the high-spec ADR 1500 style rigs will be turning over in the spring on most of our high-spec 1500 class rig contracts with roughly 5,000 per day increases anticipated. A lot of these rigs were tied up on annual contracts struck over a year ago and which will come up for renegotiation in May or June of this year. Internationally, our international business unit operates in 3 key areas: Australia, the Middle East and Latin America, with a combined fleet of 34 drilling rigs. Australia is one of the largest fleets in the country with 14 rigs and has 7 rigs operating today, with 2 to 3 more rigs coming on contract in the next 3 to 6 months. The Middle East business unit is anchored with our 2 high-spec ADR 3,000-horsepower rigs in Kuwait and our 2 high-spec ADR 2,000 horsepower rigs in Bahrain, all under long-term contracts. Also, we have a fleet of 4 rigs in Oman, none are currently operating. We are very close to tying up work for at least 2 of those rigs on 4-plus year contracts. Argentina has a 4-rig fleet, with one under long-term contract today with a major and another rig contract to start up in the next quarter. Our EDGE Drilling Solutions, which encompasses the technology for reduction of emissions that we apply on a worldwide fleet as I mentioned previously, Ensign has now 40 of our high-spec ADR drill rigs with EDGE AutoPilot installed. The EDGE AutoPilot platform is critical to not only ensuring consistent wellbore construction, but also to efficiently integrate many of the emission reduction systems that are evolving today, from natural gas applications with best systems to high line power installations. Additionally, our Drilling Solutions team has formed a joint venture with another major OFS company to drill a zero emissions test well using green hydrogen as the energy source and deploying current hydrogen fuel cell technology to drive our electric rig. With that, I'll turn it back to the operator for questions.

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

Just wanted to clarify a couple of things on the growth CapEx, the $20 million. Bob, you're speaking pretty quickly, I heard 10 cold-stacked rigs. Is that the majority of the $20 million? Or can you maybe give us a sense of how far you can stretch the budget in terms of the number of rigs that you tend to put back to work? And maybe you could also highlight how many idle 1,500 AC triple rigs you have that could be upgraded?

Right. So the high-spec -- I'll address the last question first, the high-spec 1,500s, they fall into 3 categories, which we're finding clients that some want to drill to 2- or 3- or 4-mile laterals. Some of them have rigs that they want to make some specific upgrades to. We're addressing that with -- usually, we don't want to get out more than a 6-month term on these contracts because the price is moving so quickly, but we're raising our price and applying that. When we think of our CapEx budget of $90 million, maintenance CapEx and some growth CapEx in that, incrementally, this $20 million that's mentioned here identifies probably about 10 to 15 rigs in that range, anywhere from $1 million to $3 million of modifications required on those rigs. And again, all attached to price increases ranging anywhere from $3,000 to $5,000 a day.

Understood. Several of your peers that reported a few weeks ago talked about pricing in the mid-20s range. You talked about [ 25 ] and above, which I guess is the same. But I guess I'm wondering -- they say reported a few weeks ago, the pricing is pretty good -- dynamic. Like has the pricing structure changed over the last couple of weeks? Or it's just a different way of...

Yes. Yes. It's been that dynamic. In fact, I was just talking with the U.S. operation this morning, and we had some pricing out a month ago with a client and we're coming back, and we are raising the price. I mean it's been happening that quick. Certainly, the Ukraine crisis has influenced everything and the thinking. Our phone is basically kind of lit up the last 2 weeks on the sales side. Everyone's wanting to grab the rigs that they're familiar with and/or expand their rig fleet. One particular client we've almost doubled the number of rigs we have with them that they want coming up. So it's happening pretty fast. So we have a lot of shovel-ready projects. We call them where we can incrementally reactivate. And when we say upgrade, the rig usually involves a top drive upgrade, which we tie in with the recertification, while we're doing it at the same time, we take the opportunity. So there's a lot of moving parts, but the key point here is we're basically in the last half of this year, 2021 I'm talking about, we react -- we saw this kind of coming a little bit. We reactivated 25 rigs into the market. And then we, just recently, in the first quarter here, have identified another 10 to 14, I'll call it shovel-ready rigs that can be reactivated for very little capital.

Understood. One more question for me on the maintenance capital side. It does seem like a pretty big number year-over-year and maybe even in the context of some of your peers side. I was wondering if you could maybe just break it down to kind of some of the major components, including kind of the day-to-day piece, drill pipe, if that's relevant and whatever else you think is relevant?

Yes. So I'm not -- I would say a large component would be related to drill pipe, just given the rate reactivations and the, I would say, under investments of the industry on drill pipe the last couple of years. So I think similar to our peers, drill pipe is quite large on it, probably close to 20%. Then there's the other stuff like recertifications, so as rigs get reactivated or rigs that have been operating with recertifications, and then just sort of your run-of-the-mill stuff like pumps and engines and things like that. But definitely, drill pipe is a larger component of this year's budget in comparison to the prior years.

Your next question comes Waqar Syed with ATB Capital Markets.

Well, Mike, when I look at your gross profit margins, even excluding some of the revenues from -- short for revenues or contract termination revenues, your margins actually fell quarter-over-quarter in Q4. Now could you tell why that is? Because some of your peers probably have their margins bottom in Q3, is there anything particular for you guys that you're seeing? And number two, do you think Q4 is the bottom in margins? And then what kind of trajectory should we see going forward?

So in the fourth quarter, certainly in the back half and mostly in the fourth quarter, we reactivated about 25 rigs. So there was a lot of expense -- onetime expense, Waqar, going through the fourth quarter. I see it as a -- it's a lumpy quarter in that respect. But the margins -- there's no margin compression happening at all. You're seeing price increases. There's nothing to be alarmed about. It's just the rig reactivations in the quarter were quite high for obvious reasons.

And what would you say about the cost for those reactivations? Should we assume maybe like $0.5 million per rig or something in that range?

It would make up quite a bit of the margin compression that you saw quarter-over-certain-quarters. So I mean, they'd be probably around that 750-ish.

$750,000 per rig?

Thereabouts. Yes.

Okay. Fair enough. And then how many rig reactivations would there be in Q1?

In Q1? I would suggest right -- most of the rig activations, of course, happened leading into the busy Q1 we saw. So they were, I think, maybe 5 in Q1, Waqar. We've got -- as we've suggested here, another 10 happening in the U.S. that we'll see hitting the books with positive results in the third quarter for sure. It takes a few months to reactivate and upgrade these rigs. We're just getting after that now to meet the demand. As I mentioned in the last month, we signed up another 10 rigs, so they'll hit the third quarter results. Yes.

Okay. So 5 rig reactivations in Q1 and then another 10 in Q3 that could hit the OpEx line. Is that right?

And the EBITDA line, yes.

Yes, yes. And then anything on the international side?

Yes, yes. In the first quarter is your question?

Yes, first quarter or for like one, what would be the cost like OpEx impact of rig reactivations in international markets? And what time period do you think could those hit?

Yes. We didn't have any rig reactivations in the international market, and the 4 or 5 that we have coming up between now and the next 6 months, all the reactivation costs are covered within the mobilization fees. We don't eat any of the reactivation costs on incremental rigs. So you won't see any of that pushing through.

So just to understand that the revenue and the cost for the reactivation would all hit the same quarter? Or the revenue would be spread out over the term of the contract?

Well that depends on the contract. So there will be a bit of a mismatch, but for the most part, they will all wash out as a positive EBITDA event, but you'll have a bit of a lump with some operating costs and some revenue. So I'd say a bit of a mismatch, but on an annualized basis, it will work out.

But to be clear, the [ mode ] cost always cover at least 100% to 125% of the cost, the reactivation costs.

Okay. And then the maintenance CapEx per rig, how is that running between U.S., Canada and international?

I think given the rig specs in the U.S., you'll see sort of a higher maintenance cost in comparison to the Canada, which sort of the triple doubles and singles. So on a per rig basis, you'd be higher in the U.S. in comparison to Canada. Internationally, in particular, in the sort of in Kuwait and Bahrain, those are larger rigs as well. So your maintenance would be higher, just given the size and spec of that equipment.

Okay. And how are these costs -- CapEx costs kind of comparing year-over-year? What kind of inflation are you seeing there?

Yes. It's -- I think we've got about 7% or 8% inflation built into product escalation across the board.

Your next question comes from Cole Pereira with Stifel.

Just wanted to start with the U.S. high-spec rig market. As you comment you had 88 rigs, of which 75% are high-spec, so call it about 66 versus 50 active currently. Sounds like you've got line of sight for maybe another 10 additions at least. I'm just curious if you'd be willing to comment based on what you see today, when you think you could exhaust your high-spec rig capacity in the U.S.?

Yes. So we've got -- I mean, today, we're currently running about 33 of our high-spec rigs in the U.S. southern market, and we've got -- what do we got, we got another 20 that we can put to work. 10 of them, you're going to see going to work here in the next few quarters, which leaves another 10 after that to identify as far as capacity goes.

Okay. Got you. And I assume you're relatively in line with your peers under the assumption that once that idle capacity in the market gets used up, that you expect to see rates push up to the, call it, USD 30,000 a day range?

Yes. I would say that -- I mean, we've been there before, and we'll be there again. Once you get over 70% utilization in any rig category, you certainly get traction and with the commodity price, as long as it stays there, will continue to have the traction. So yes, I would say that $30,000 by the end of the year is not out of whack. I mean, we've seen it just in the last month, move quicker than I've seen it move ever before. I mean it's moving quite fast.

Got it. So in Canada, it sounds like you see a peak in Q3, Q4 similar to peers. I mean, just curious what do you think is driving again that stronger Q3 versus Q1? Is it just a lack of availability of drilling and completions equipment here in Q1?

Correct. Q1 was, of course, still somewhat COVID hampered. And I mean we've -- I've seen years where we have had stronger Q3s than Q1 and it has everything to do with what's going on in the world. But yes, to your point, Q1 was somewhat crew constrained, operators not wanting to get too crazy with trying to attract labor any differently than they had in the past, but mostly COVID-related stuff. Now that we're coming out of that, we shouldn't have those issues going into Q3, and there's lots of assets, the -- what, 240 rigs, just a little less than 50% of the [ CAEDC ] fleet running. So you've got capacity there to take up.

Okay. Got it. That's helpful. And just wanted to go back to your comment on the phone lighting up. So I mean kind of safe to say that you -- it sounds like you've noticed a bit of a change in E&P behavior just in the last month alone. And I'd assume that's driven by a combination of continued improvements in economics and maybe a concern on rig availability?

Yes. Yes. It's exactly the rig type availability and hot rigs with crews, it's all of the above. So yes, all of a sudden, it's like the toilet paper shortage. There wasn't a shortage until everyone said they're going to run out a toilet paper, right? So there you go.

Okay. Got it. That's helpful. And just quickly on the Mexican rig sale, I just want to confirm, based on your comments that this cash is coming through in Q1. And if you have any other idle assets in the portfolio that you think probably have a reasonable chance they could maybe actually be sold as well?

Yes. So the cash -- the deal closed in February. So the cash has been received. As for other assets, we have redundant real estate up in [ this view ] and sort of throughout that. We'll look to monetize. That is available on the market. That's close to almost $40 million. So I wouldn't say it's going to move quickly, but I'd say it's probably monetized in the next 12 to 18 months.

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

Just wanted to start off on the longer-term contracts. Just curious where your thinking is on that now? It looks like you've increased your long-term contract proportion or total long-term contracts from kind of 6 to 12 from last report to now. Can you maybe just talk about where those prices have gone? And was this the operators, particularly driving the signing of the long-term contracts? Would you have preferred a shorter duration of these contracts? Or is this sort of where things are going based on rig availability?

So certainly, in the last 6 months, we have been -- knowing that we're going into an uptick market, we have moved our cadence closer to 6-month turnovers for obvious reasons, where there's been some large capital upgrades requested by the operator. We've not only raised the price, but we insisted on 1-year contracts just to cover -- make sure that we've got some insurance coverage on the cash flow stream. But yes, it's always the situation where when operators start to tie you up for 2-year contracts or wanting to tie you up for 2-year contracts is when you say no. And again, we've been turning over on 1-year contracts, 6-month contracts and where we've -- where the operator has historically put us under 1-year contracts, we've come back and said, we'll sign a 1-year contract, but after 6 months, the rate is going up and here it is. So we have 2 intervals. So we're going to vote pricing on a 6-month basis.

Got it. Okay. And just curious what type of uplift relative to that 25,000 number you're getting on these longer-term contracts?

They -- probably $2,000 to $3,000 a day on those.

Got it. Okay. Perfect. And just a housekeeping item for me, the $89 million and the $20 million of growth CapEx, that is all -- or that is gross CapEx and then the proceeds you received from the Mexico rig sales would be -- would come out of that number, correct?

So the $89 million would be maintenance and then there's $20 million in growth and then the Mexico rig sales would -- I mean it goes towards the balance sheet, of which then would fund debt reduction as well as some of these growth CapEx.

Got it. Okay. Yes. So your net CapEx will be lower than $109 million, given the Mexico rig sales. It's not $109 million net of that?

Yes. Yes.

Okay. Perfect. And as far as debt repayment goes, the credit facility is your priority for direction of funds these days. Is that correct to say?

Yes, that is.

There are no further questions at this time. You may proceed.

Okay. Thanks, everyone, for chiming in on the call. I'll just wrap up. 2022 will be defined uniquely much as the last 2 years have been defined but in a much different way. Ensign has a fleet of 245 drill rigs, 100 well service rigs worldwide and with only 50% utilization of the fleet today, we have lots of capacity to feed into an upmarket. Also having the benefit of a relatively young, high-spec asset base, we should have a long economic life ahead of us, all, of course, dependent on commodity and other influences. Thank you and look forward to updating you once again in 3 months' time.

Ladies and gentlemen, this concludes your conference call for today. We thank you for participating and ask that you please disconnect your lines. Have a great day.