Ensign Energy Services Inc.

Bob Geddes - President, Chief Operating Officer Mike Gray - Chief Financial Officer Nicole Romanow - Investor Relations

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 defense of 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 is escalating day-by-day. Back to COVID, we are truly learning to live with this virus and with most of the developed world have a high level of vaccination we're in a much less vulnerable position than a few years ago.

2022 out of the gate as I mentioned before is already bringing a share of geopolitical tension, which is causing rapid upward pricing in the commodities markets. This enhances the effect of half a decade of under investment in the oil and gas business worldwide.

The perfect storm of increased demand, restricted global supply and result in market price response for oil and gas commodities leads us into arguably the best fundamentals for 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 and 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 and reflect on the fourth quarter and 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 reactivated roughly 25 rigs in the back half of the year.

These reactivations led to one time 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, making it then arguably the most efficient oil field services company from an overhead per operating 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 and great people helped to make this a seamless transition.

In 2021 we doubled our EDGE AutoPilot platform. We 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 à la carte from $240 to $2,500 a day with various apps.

We think of EDGE like Microsoft Office. We can turn on excel or word or PowerPoint 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 a quickly growing active rig market.

So I’ll turn the call over Mike Gray to dive into the details.

Thanks Bob. The outlook 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.

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 [in-field] (ph) 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. United States operations at 75% increase and international operations of 4% increase in operating days compared to the fourth quarter of 2020.

For the year ended December 31, 2021 total operating days were up in – 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 is stand by 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 a $176 million compared to $18.4 million in the 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 date of the credit facility to the earlier of six months prior to the maturity date of the senior notes due in April 20, 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 two drilling rigs that were cold-stacked in Mexico for cash proceeds of $34 million U.S.

The transaction resulted in a $23.9 million U.S. 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 seven 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 in our contracts ranging from six months to one year.

Some of these involve cold-stacked rigs, where the incremental capital required to upgrade or reactivate the rig that is being covered well within the contract period. Rates have moved quickly in the last month as operators called to ensure they have preferred rigs contracted.

We’ve seen our high spec 1,500 and our newly branded ADR 1500-I, I for intermediate, capturing the three mile category. So we have the ADR 1500 on the two mile, the 1500-I three mile and 1500S for the four mile categories.

This along with our Super Spec ADR 1500S rigs are quoted at with leading spot prices in the 25 plus range. These are up about $5000 a day from fourth quarter ‘21 prices.

Our 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 turn key projects in the Rockies. These projects involve some execution risk.

So having our high performance direction drilling team on these projects helps to maximize our project margins. We have three projects on the go today.

In Canada: Our Canadian business unit we operate with the recent neighbors’ 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 mid-sized directional drilling group with 30 kit capacity and also a coring and rentals group. Today we have 52 drilling rigs operating heading into break up with about 25 expected to run over break up on pad work.

Once we get through break up, 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 quote stacks and currently active rigs that operators have requested upgrades on, and which have attracted contracts with roughly 20% to 25% rate increases.

Pricing on the high spec ADR 1500 style rigs will be turning over in the spring, and most of our high spec 1500 class rig contracts with roughly $5,000 per day increase as 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 three 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 seven rigs operating today with two to three more rigs coming on contract in the next three to six months.

The Middle East business unit is anchored with are two high spec ADR 3000 horse power in Kuwait, and our two high spec ADR 2000 horsepower rigs in Bahrain, all under long term contracts. Also, we have a fleet of four rigs in Oman, none are currently operating.

We are very close to tying up work for at least two of those rigs in a 4-plus year contracts. Argentina has a four 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. So 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 oil and gas 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.

Good morning, all. Thanks for taking my questions.

I 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 1500 AC triple rigs you have that could be upgraded.

Right, so the high spec – I’ll address the last question first. The high spec 1500s, they fall into three categories, which we're finding clients that someone who drilled two or three or four 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 six month term on these contracts, because the price is moving so quickly, but we are raising our price and implying that. When we think of our CapEx budget of $90 million, maintenance CapEx and some growth CapEx that incrementally this $20 million that's mentioned here, is – 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 $3000 to $5000 a day.

Understood. Several of your peers that have reported a few weeks ago and talked about pricing in the mid-20’s range.

You talk about 25 and above, which I guess is the same, but I guess I'm wondering you know, they reported a few weeks ago that pricing is a pretty dynamic like. Has the pricing structure changed over the last couple of weeks or it's just a different way.

Yeah, it’s been that dynamic. In fact I was just talking, 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're raising the price. I mean it's been happening that quick.

Certainly the Ukraine crisis has influenced everything and the thinking. Our phone has basically kind of lit up the last two weeks on the sales side.

Everyone's wanting to grab the rigs that they are familiar with and or expand the rig fleet. One particular client, with 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 we can incrementally reactivate and when we say upgrade the rig, it usually involves a top drive upgrade, which we tie in with the recertification, while we're doing it at the same time we take every opportunity. So there's a lot of moving parts, but the key point here is, we are basically in the last half of this year, 2021 I'm talking about, 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 they 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, you know year-over-year and maybe even in the context of some of your peers, but 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 you know whatever else you think is relevant?

Yes, so on that I would say you know a large component would be related to drill pipe, just giving out the reactivations and I would say, under investment in the industry on drill pipe the last couple of years. So I think similar to our peers drill pipe is quite large on it.

I thought it would be close to 20%. Then there's the other stuff like re-certification, so is the rig reactivated or rigs that have been operating was recertifications and then just sort of your run in 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.

That’s it. Thanks guys.

I’ll turn it over.

Thanks Aaron.

Thank you. Bob, Mike, when I look at the your gross profit margins, even excluding some of the revenues from – you know short fall 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 bottomed 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 you know trajectory should we see going forward?

So in the fourth quarter Aaron, and certainly in the back half and mostly in the fourth quarter we reactivated about 25 rigs. So there is a lot of expense, one-time 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 was 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-quarter. So I mean it would be probably around at $750,000-ish.

$750,000 per rig.

There abouts, yeah.

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

Q1? Gosh!

I would suggest – most of the rig activations of course happened leading into the busy Q1 we saw. So there were, I think maybe five 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 that will hit the third quarter results, yeah.

Okay, so five rig reactivations in Q1 and then another 10 in Q3, that’s what hit the OpEx line. Is that right?

And the EBITDA line, yeah.

Yeah, yeah. And then anything on the international side?

Yeah, yeah. In the first quarter is your question?

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

Yeah, we didn't have any rig reactivations in the international market, and the four or five that we have coming up between now and the next six 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 with 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?

It depends on the contract. So we have a bit of a mismatch, but for the most part the [inaudible] positive EBITDA event, but you'll have a bit of a lump with some operating costs and some revenue.

So that's a bit of a mismatch, but on an annualized basis it will work out.

But to be clear, the month costs always cover at least 100%, 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?

Waqar, given the rigs back in the U.S., you'll see sort of a higher maintenance costs 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 comparisons to Canada, Internationally and 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.

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

Yeah, it's. I think we've got about 7% or 8% inflation built into product escalation across the board.

Great! Okay that's all I have.

Thank you sir.

Thank you, Waqar.

Good morning, everyone! Just wanted to start with the U.S.

high spec rig market. As you commented you had 88 rigs, of which 75% and I expect to call about 56 versus 50 active currently.

It sounds like you 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.?

Yeah. 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 we’ve 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, gotcha. And I’d 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, U.S.

$30,000 day range.

Yeah, 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, it – as long as it stays there, we’ll continue to have the traction.

So yeah, 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 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. You know Q1 was of course still somewhat COVID hampered.

I mean we've – I’ve seen years where we have had stronger Q3’s than Q1 and it has everything to do with what's going on in the world. But yeah, to your point, Q1 was somewhat crude constrained.

Operators not wanting to get too crazy with trying to attract labor any differently than they have 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.

There is a what – 240 rigs, just a little less than 50% of the CA EDC fleet running. So you've got capacity there to take up.

Okay, got it, that's helpful thanks. And just wanted to go back to your comment on the phone lighting up.

So I mean kind of safe to say that 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 the rig availability.

Yeah, yeah it's exactly the rig type availability and hot rigs with cruise; you know it’s all of the above. So yeah, all of a sudden it's like the toilet paper shortage.

There wasn’t a shortage until everyone said they are going to run out of toilet paper right, so there you go.

Okay, got it, that's helpful. And just quickly on the Mexican rig sale.

Just wanted to confirm based on your comments that this cash is coming through in Q1 and you know if you have any other idle assets in the fourth quarter that you think probably have a reasonable chance they could maybe actually be sold as well.

Yeah. So the cash, the deal closed in February, so the cash has been received.

As for other assets, we have redundant real estate up open that you – and sort of throughout that. We 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.

Okay, got it. That’s helpful, thanks.

That's all for me, I'll turn it back.

Thanks Cole.

Hey, good morning, and thanks for taking my questions. Just wanted to start off on the longer term contracts.

Just curious where you're thinking is on that now. It looks like you’ve increased your long term contract proportion or total long term contracts from kind of six to 12, from last reported to now.

Can you maybe just talk about where those prices have gone and was this the operators, particularly driving the driving the signing of the long term contracts you know. Would you have preferred a shorter duration of these contracts or is this sort of where things are going based on rig availability?

So, and certainly in the last six months we have been – knowing that we are going into an uptick market, we have moved our cadence closer to a six month turnover for obvious reasons. Where there's been some large capital upgrade requested by the operator, we've not only raised the price, but we insisted on one year contracts just to cover, make sure that we've got some insurance coverage on the on the cash flow stream.

But yeah, it's always the situation where – when operators start to tie you up for two year contracts or wanting to tie up for two year contracts is when you say no. And again, we've been turning over on one year contracts, six month contracts and where the operator has historically put us on one year contracts, we have come back and said we’ll sign a one year contract, but after six months the rate is going up and here it is.

So we have two intervals, so we interval pricing on a six month basis.

Got it, okay. And just curious what type of up lifts relative to that 25K number you're getting on these longer term contracts?

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

Got it, okay perfect. Thanks for that.

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

Got it, okay yeah. So your net CapEx will be lower than 109, given the Mexico rig sales.

It’s not109 net of that.

Yes.

Okay. 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.

Okay, perfect! That's it for me.

Thanks very much.

Thanks.

Okay, thanks everyone for joining on the call. I’ll just wrap up.

2022 will be defined uniquely much of the last two 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 three months’ time.