Ensign Energy Services Inc.

Thank you, Amy. Good morning, and welcome to Ensign Energy Services First Quarter 2021 Earnings Conference Call and Webcast.

On our call today, Bob Geddes, President and COO; and Mike Gray, Chief Financial Officer, will review Ensign's first quarter 2021 highlights and financial results, followed by our operational update and outlook. We'll then open the call for questions.

Our discussion today may include forward-looking statements based upon current expectations that involve several business risks and uncertainties. The factors that could cause results to differ materially include, but are not limited to, political, economic and market conditions; crude oil and natural gas prices; foreign currency fluctuations; weather conditions; the company's defense of lawsuits; stability 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, and welcome to the First Quarter '21 Ensign Energy Services Update and Earnings Call.

Well, the effects of the pandemic are certainly still with us. We are, however, starting to see some light at the end of the tunnel as global demand starts to ratchet back all while the reality of accelerating decline rates set in.

Crude oil is wanting to settle in the mid-60s and natural gas close to $3. WCS sits at about $51.10 this morning or CAD 65.

So the product pricing is there. In spite of the headwinds, the team at Ensign generated in the first quarter about $50 million of EBITDA.

We paid down an additional $12.5 million of debt. That's a combined $273 million in the last year from first quarter '20.

I'll let Mike Gray expand on that a little bit more. And I'll say we did all that with an industry-leading safety record.

The U.S. continued to deliver strong operating days in the quarter, but we did have some onetime redeployment costs on cold-stacked rigs on about 5 of those starting up, which received expenses in the quarter.

International delivers consistent cash flow streams, benefiting from its long-term contract runway. Kuwait and Bahrain, despite enormous crew labor challenges due to COVID, deliveries as forecasted without missing a beat.

Canada had a softer forecast -- or I'm sorry, Canada had a softer first quarter than expected with industry peaking at about 186 versus what we thought we might get to 250 rigs in Canada. Canada's dismal vaccine procurement plan or lack thereof has continued to keep the economy on pause and created some challenges with the field labor.

I'll turn it over to Mike Gray for more specific details. But before that, I want to mention that we are pleased to have Mr.

Gray back in the CFO role for the foreseeable future. I from one, am comforted to have Mike settle back in the seat as we move forward into this interesting market forward.

Over to you, Mike.

Thanks, Bob. Over the first quarter of 2021, oil and natural gas industry fundamentals, including the demand for crude oil and natural gas and crude oil commodity prices, continue to improve and recover from the significant impacts of the COVID-19 pandemic.

Improving financials, coupled with the commencement of COVID-19 vaccine distributions are expected to drive improvements to the oilfield service activity year-over-year. However, over the short term, financial and operating results continue to be negatively impacted by and are recovering from significant fallout of the COVID-19 pandemic on the oil and gas industry.

Operating days were down in the first quarter of 2021 with Canadian operations experiencing a 40% decrease. The United States had 50% decrease, and international operations showing a 40% decrease compared to the first quarter of 2020.

The company generated revenue of $218.5 million in the first quarter of 2021, a 43% decrease compared to revenue of $383.9 million generated in the first quarter of the prior year. Adjusted EBITDA for the first quarter of 2021 was $49.9 million, a 45% decrease from adjusted EBITDA of $91.2 million in the first quarter of 2020.

The 2021 decrease in adjusted EBITDA can be primarily attributed to the macroeconomic and industry conditions, seen since March of 2020, including, but not limited to, the impact of COVID-19 pandemic and declines in demand for crude oil over the course of the 2020 year. Depreciation expense in the first 3 months of 2021 was $71 million, a 21% decrease from $89.8 million for the first 3 months of 2020.

The decrease relates to assets that have now been fully depreciated, not incurring depreciation expense on a go-forward. G&A expense in the first quarter of 2021 was 22% lower than the first quarter of 2020.

G&A expense decreased as a result of cost-saving initiatives implemented in March of 2020. The wage subsidy received from the government of Canada, reductions in personnel and organizational restructuring and management will continue to look to reduce costs on a go-forward basis.

Net purchases of property and equipment for the first quarter of 2021 totaled $9.6 million. The purchase of property equipment in the first 3 months of 2021 consists of $7.2 million in maintenance capital and $3.6 million in upgrade capital.

Over the first quarter of 2021, the company purchased USD 16.6 million face value of senior notes in the open market for cancellation, recognizing a gain of $5.3 million. Total debt decreased by $20.9 million in the first quarter of 2021 from $1.83 billion at December 31, 2020, to $1.33 billion at March 31, 2021.

Year-over-year debt decreased by $279.9 million to $1.36 billion at March 31 from $1.64 billion on March 31, 2020. On that note, I'll pass it back to Bob.

Thanks, Mike. So just a quick overview.

As you know, Ensign runs in 8 different countries around the world with about $3 billion of assets, employing about 3,000 people, specifically 223 drilling rigs around the world and about 100 service rigs. Let's start with the U.S.

Currently, we're running 35 drilling rigs in the U.S., trending towards 40 over the next few months as we move into the third quarter. Rates have definitely bottomed out and rate increases -- notional rate increases of $500 to $1,000 a day are happening.

More importantly, Now that we have our EDGE AutoPilot product commercialized and being rolled out systematically on all of our AC rigs worldwide, we're getting product traction. Our AutoPilot core starts at about $240 a day and the complete AutoPilot package with apps peaks out at $2,600 a day.

In fact, we were just recently after the beta testing on a couple of rigs in the fourth quarter, have successfully signed up a complete AutoPilot package at $2,600 a day with a major in the U.S. U.S.

well servicing has expanded up to an average of about 24 well service rigs working daily, some of those on 24-hour operations. We successfully were awarded a large P&A program in the Rockies, which is steady work over the next year.

Our direction drilling unit has 4 to 6 jobs working mostly on turnkey wells in the Rockies region. In Canada, we operate 92 drilling rigs and 50 well service rigs.

We're currently running 10 rigs peaked at 33 in the first quarter. We thought that the industry would peak close to 250.

It's actually peaked at about 186. We thought we would get to 40 to 45 as a peak, we ended up at 33 as the peak mostly in line with the industry.

The other thing as I mentioned, we're currently running 10 rigs. It looks like we've got good visibility up to 20 rigs here in the next 2 to 3 months, which is where I think we'll see the third quarter settle in and then move north of that into the fourth quarter.

What is important is that we've been raising rates coming out of breakup by $1,000 a day. And notionally, we've had some conversations with some clients into the fall close to $2,000 a day increases.

We have 50 well service rigs in Canada. We're running about 10 of them today.

I think we'll get up to about 15, perhaps 20. We were successful on getting prequalified with OWA.

We will start to see more of that business coming our way. As I mentioned before, though, Canada does have its macro vaccine issues and lockdowns that affect areas.

Everyone is having some challenge getting entry-level people to come to work. When we have a government that is willing to pay them to stay at home that, of course, creates some labor inflation.

Labor inflation, of course, gets pushed through to the operator, as always. Nonetheless, $65 oil and $3 gas floats a lot of boats.

Internationally, outside of COVID flare-ups and rotation travel issues in certain regions. Our international team has been steady with our long-term contract fairways.

Bahrain and Kuwait are both 100% utilized and steady: 2 in Bahrain, 2 in Kuwait. Australia is in the middle of a new bid cycle, which we expect should provide us increased activity up from currently 6 moving to 7 and to 8 or 9 in the back half of the year.

Argentina is in the middle of negotiating a 1-year contract extension on -- with its current operator on our 2,000 horsepower AC high-spec rig there? As I mentioned on the technology front, we've kind of packaged it all up now with beta testing behind us on the auto drilling component.

You'll see that auto pilot is our product platform that we add apps in different technology to it depending on the level of sophistication of the wellbore and the client. As I mentioned before, we recently signed up a major with EDGE AutoPilot and apps with a combined pricing at $2,600 a day.

The other thing that we're finding is there's more clarity between control systems and real-time operating center rollout of directional guidance to the rig. By that, I mean, there's becoming a clear understanding on the -- where the real estate starts and stops with respect to rig controls.

I think over the last few years, that's been a little blurry. Now there seems to be a better understanding of that, which is good.

It provides clarity on what the product does and what it provides. We also tied into our performance-based contracts.

About 10% of our rigs in North America have run on a performance-based contract type, and they provide upticks of anywhere from $2,000 to $3,000 a day of margin, pure margin based on performance metrics with no risk attached. On the CapEx side, we anticipate our planned maintenance CapEx to come in as we forecast of plus or minus $50 million.

Any incremental CapEx for redeploying cold-stacked rigs into a busier market, will have incremental day rates applied or the operator provides a CapEx for the upgrades, if required. As always, we remain opportunistic finding the balance with debt reduction and EBITDA growth.

With that, I'll turn it back to the operator for Q&A.

I just had a question about -- you mentioned some adds come out in Canada through the second half the year. Just curious if you can speak to where you expect those rigs to be added, will it be more Cardium, Viking-focused or are most of those going to be Montney deep basin type rigs?

Yes. Well, it's actually all of the above.

Some in the Cardium, a few in the Viking, but I would say mostly the Cardium and a couple of upticks into the Montney, Duvernay.

Okay. Got it.

And maybe just in the U.S., can you talk a little bit about some of the potential reactivation costs you might expect to see on upcoming rigs there and whether or not we should expect that to have a noticeable impact on your gross margin through the rest of the year relative to the 26% you put up in Q1?

Yes. No, sure.

The -- as you recall, in prior quarters, as we put rigs into a cold-stacked basis, meaning that we didn't see any foreseeable work for those rigs, but they were part of still of our active marketed fleet, we would harvest the consumables of the rig into a sea-can, bring them back to the warehouse and then we would deploy them for the rigs that we're running to keep the operating costs down and consume those cold-stacked rig consumables. As you turn those rigs back around, of course, you have to refurnish them with the consumables.

And those typically, we're talking $200,000, $250,000 involved in that process.

A couple of things. First of all, these price increases in the U.S., Bob, that you mentioned $500,000.

These are kind of net price increases or these are also some reimbursements for your input cost inflation, like labor or others?

No, that would be net incremental increase. We're not seeing any labor inflation in the U.S.

at the moment. And we -- probably safe to say we haven't seen any consumable or product pricing increases.

There are steel increases that everyone is starting to see that will probably affect the operators more on casing and things like that, doesn't affect us much.

Okay. Fair enough.

Now there was a comment made by one of your competitors in the U.S., that they thought that only a handful of super-spec rigs were idle in the U.S., that could be reactivated in that $200,000, $250,000 kind of cost that you mentioned. And that beyond that -- those handful of rigs, then the cost to reactivate super-spec rigs would be materially higher.

And do you agree with that? Or do you -- or you have a different view on that?

No, I would -- I mean, obviously, everyone's fleet has a different perspective. But I would say, generally, that is true.

I think what they were probably referring to is for high-spec rigs where they may want an additional pump or generator that doesn't exist on the rig currently, that would involve another level of new capital.

And all the rigs that you expect to put back to work by the end of the year in the U.S., when -- did they all work over the last 9 to 12 months?

Generally, most of the rigs that we're putting back to work have certainly worked in the last 18 months, let's say, whether or not they worked in the last year. The last year has been quite a pause for everyone but, certainly, in the last 1.5 years.

When we put rigs -- when we stack rigs, we cold-stack and we've got a rigorous protocol where they're put away properly and they're ready to go. Plus we have a team that occasionally goes by and check them out, checks oil, checks for any leaks that may come into certain parts of the rig and that type of thing.

Okay. Do you expect any IBC revenues or any early term revenue contribution in Q2?

Yes. standby revenue.

There's some, but it's diminishing. There is some in Canada on a couple of rigs, and there is a few rigs still in the U.S., but it's diminishing as contracts roll off.

And we -- they're basically looking at putting them to work or recontracting them onto new contracts.

Okay. And then the demand in the U.S.

is -- how would you kind of characterize that between private E&Ps and public E&Ps?

So the -- yes. I would say the calls from the private E&Ps are increasing at a more rapid pace than the majors.

And from a perspective of the basin, is it still primarily in the Permian? Or are you seeing it more spread around the U.S.?

Yes. I would say the Permian has got our biggest beta right now.

The Rockies has been fairly steady, tough but steady, slight increases, but there's more geopolitical headwinds in the Rockies, but steady there. California, quite steady as it always has, so the biggest beta is in the Permian, correct?

Okay. And then just one final question.

Any guidance with respect to what the Working capital changes could look like in Q2 in terms of cash inflow or outflow?

Mike, do you want to handle that?

I'd say, it'll be overall fairly moderate with the pickup in activity in the U.S. We'll see the accounts receivable build up, but with the decrease in activity in Canada, we usually see that AR collections from Q1 roll in.

So I think for the most part, it should be fairly muted. In addition, our CapEx is sort of truck along at that $40 million to $45 million, of which $10 million was spent in the quarter.

So I don't see any big draws or big buildups.

On the international side, the commentary in the release about seeing an improvement in rig count in the second half of the year, is that entirely related to Australia? Or are there other markets?

It would be Australia, Jeff. That's correct.

We're fully utilized in Bahrain and Kuwait. We may have another opportunity to add an additional rig into Bahrain, but we're not quite sure at this point.

Venezuela, of course, is Venezuela. And Argentina, we may be adding another rig here in the back half of the year that has about a 50% opportunity at this point.

And the Australian side, what type of rigs do you expect to add?

The Australia rigs, as you know, we've got a mix of the smaller ADR single-type rigs and then we've got the 1500 type rigs. It will probably be in the 1500 category.

Okay. On the EDGE side, do you have with that operating platform deployed across it today?

We have three rigs with the AutoPilot platform currently installed. We have about 50 rigs with the EDGE, some sort of our EDGE automation on it.

We -- the way to look at the autopilot, it's like a Microsoft Office. You get a computer and you have Microsoft Office loaded onto it and then you decide to turn on Excel, Word, Teams, et cetera, et cetera.

The Microsoft office is our AutoPilot platform. So the AutoPilot platform will start rolling out in every one of our AC rigs.

From there, the sales and the operations can easily turn on. And we can turn this on with -- most of it remotely, out of Houston.

And occasionally, we have to make a field visit with one of our technicians for a couple of days to tune in the rig and help educate and tune up the driller to utilize the new function, much like will get tuned up on Excel and had in the Office. So it's a very, very analogous to that platform.

So now that we have that, we can start to roll out, but we have it on 3 commercial platform or 3 rigs with this platform on currently.

What do you expect the cadence of incremental adds with the AutoPilot could be?

Well, we've tasked the team with -- coming back with a schedule on that. We've got a very agile and small team that works around the world.

And in some cases, we have our technicians in the certain areas like Australia, et cetera. I would suggest that we're probably looking at a cadence of -- by the end of the year, I think, we'll have it on another 10 rigs easily between now and the end of the year, maybe 20.

Okay. And then just a clarification on the U.S.

side. So to go from the 35 rigs today to 40 or so, you expect that the reactivation redeployment costs will be in that range of $250,000 per rig that you mentioned earlier?

Correct.

And with the standby and early termination payments, how meaningful do you expect those will be in Q2? And how quickly do you think they tail off, as you mentioned earlier?

Yes. I think that, Mike, have you got some visibility on that runway, any?

Not on the top of my head, no.

Yes. I'm thinking of some of the rig contracts on the top of mind that I know go to the end of the year.

Probably, half of them will continue through to the end of the year and the other half will probably peter out into the third quarter, fourth quarter type thing.

Yes, I think that would be a good assumption.

So the rigs that you're reactivating a decent portion of them are not ones that are currently contracting?

Correct.

First, just on the note repurchase. Can you maybe walk through some of the moving parts that allow you to go over and above covenant thresholds for debt repurchases?

And secondly, are additional share repurchases -- or sorry, note repurchases priority number one going forward?

Over to you, Mike.

So the new credit agreement that was signed at the end of the year allows for up to $25 million of notes to be repurchased. So that's the not to face value, but the actual cash value.

So when you look at how much cash expense, it would be close to the $25 million. So under the broad basket of $25 million, I'd say we're pretty much tapped out.

There's a little bit left. The credit agreement does allow for additional note purchases to take place with certain liquidity thresholds and asset dispositions taking place.

So potentially down the road, we would be able to go back to the market. Debt repayment in general, is still priority number one.

So if we're not able to purchase back notes, we'll be putting it towards our credit facility, so there'll be one or the other.

Okay. Great.

And just second one for me. So your outlook in Canada is somewhat softer relative to your commentary last quarter.

I'm just wondering if this is more customer conversation driven? Or is it more based around just sort of the softer rig count to start the year and maybe some correlation to the back half?

Yes. I think that we're expecting a little stronger first quarter.

We thought that the industry would pick out at 250, as I mentioned, but peaked at 186. Correspondingly, we thought we'd be in the low 40s, we ended up at 33.

So I do think, though, that we'll pick it up in the back half. We're seeing, as I mentioned, I think we'll be going from 10- to 20-plus rigs here going in the third, fourth quarter.

There's a lot of pausing with COVID and the lockdowns, the ability of crews, the interprovincial challenges. So some of those are headwinds.

But as I mentioned, $65 oil and $3 gas does float a lot of boats. But Canada has still some macro issues.

I think it is pointing in the right direction. It's not reacting as quickly as it is in the U.S.

though. And when I look around the world, because we operate in 8 different countries, we have a perspective on the areas differently.

Just a quick one from me. You mentioned in the press release that you expect a more meaningful increase in U.S.

activity in the back half of the year. We're obviously mostly through Q1 reporting at this point and on balance, E&Ps are still talking about capital discipline, at least the public ones.

So I guess what gives you confidence to guide to that increased activity? Is it just as simple as a call on the commodity?

Or are there specific customer conversations that you're having that are giving you that confidence?

Yes. No, we're seeing a real book increase.

And we are booking rigs and contract rigs and having real conversations. There is a paradox, of course, here between companies like EOG.

They announced that they're not going to increase their drilling program and their stock bumps up 8%. So there's a lot of things going on.

There's the reality of the cash flow, people -- investors wanted to get their money paid back to them, rightfully. So -- and then depletion.

Depletion, every company has slightly different depletion rates. So we're also finding that a lot of the private cos aren't having to necessarily deal with that noise at that level, are wanting to increase production to fill that gap.

The Permian depletion rate is probably in the 30s, maybe closer to 40. So there's nothing like stopping drilling over the last few years to fix drilling business and here we go.

But there is kind of a buffering upside that compared to how we used to see this 4 or 5 years ago. It'd be -- we'd be bang on the way we go again.

But -- so it's slowly coming back, and our reference is with the reality of bookings and contracts.

Okay. Thank you, operator.

Thanks again, everyone chiming in on the call. And as we climb out of this COVID macro issue and see demand come back as the world needs to drive low-cost and efficient carbon-neutral energy, we'll be there to do that.

Look forward to our next call in the second quarter. Thanks, everybody.