Ensign Energy Services Inc.

Thank you. Good morning, and welcome to Ensign Energy Services Fourth Quarter Conference Call and Webcast.

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

Our discussions 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 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.

On that, I will pass the call back to Bob.

Thanks, Mike. Good morning or afternoon, everyone, wherever you're at.

Some introductory comments. The fourth quarter 2025 provides a great deal to discuss, both in terms of reflecting on the full year's performance and looking ahead to the opportunities and challenges that lie in front of us.

The Ensign team completed the 2025 year with results that exceeded analyst estimates, both for the quarter and the full year. And most importantly, we're able to clip off an additional $80 million of debt in 2025.

The Canadian business unit led the way with year-over-year EBITDA gains, while the U.S. battled great headwinds.

In 2025, the team was successful in getting operators to fund roughly half of the $48 million in upgrades executed in 2025. These rigs are all tied up now on long-term contracts.

The team ended the year expanding our forward long-time contract book to $1.2 billion of forward contract coverage with 60% of the fleet contracted forward. Our international business unit, which operates in Venezuela, Argentina, Australia, Oman, Bahrain and Kuwait had a share of ups and downs, which I will expand on later.

For a deeper dive into the fourth quarter and full year '25, I'll turn it over back to Mike. Mike?

Thanks, Bob. Ensign's results for the fourth quarter and 2025 year-end reflects the benefits of our diversified operational geographic footprint.

With the recent volatility in commodity prices, and -- the outlook is constructive and the operating environment for the oil and natural gas industry continues to support relatively steady demand for oilfield services. Total operating days were up in the fourth quarter of 2025 by 1%.

The United States operations saw an increase of 14%, while the Canadian and international operations reported a decrease of 8%, each when compared to the fourth quarter of 2024. For the year ended December 31, 2025, total operating days were down by 3%.

The United States operations saw an increase of 2%, while the Canadian and international operations saw a decrease of 3% and 15%, respectively, compared with the year ended December 31, 2024. The company generated revenue of $418.8 million in the fourth quarter of 2025, a 2% decrease compared with revenue of $426.5 million generated in the fourth quarter of the prior year.

For the year ended December 31, 2025, the company generated revenue of $1.64 billion, a 3% decrease compared with revenue of $1.68 billion generated in the prior year. Adjusted EBITDA for the fourth quarter of 2025 was $107.5 million, lower by 5% than adjusted EBITDA of $113.4 million in the fourth quarter of 2024.

Adjusted EBITDA for the year ended December 31, 2025, was $389.8 million, a 13% decrease compared to adjusted EBITDA of $450.1 million generated in the year ended December 31, 2024. The 2025 decrease in adjusted EBITDA is due to the decreased year-over-year activity caused by customer consolidation, economic uncertainty and volatile commodity prices.

Depreciation expense for the year decreased by 3% to $345.4 million compared to $355.8 million for the year ended 2024. Interest expense decreased by 23% for the year ended December 31, 2025, compared with the same period in 2024.

The decrease in expense compared to the prior period is the result of lower debt levels and reduced effective interest rates. Offsetting the decrease is the negative exchange translation on U.S.-denominated debt.

G&A expense for the fourth quarter of 2025 was $14.5 million compared with $13.1 million in the fourth quarter of 2024. G&A expense totaled $55.5 million for the year ending December 31, 2025, compared with $57.4 million for the same period in 2024.

The G&A expense decreased for the year due to nonrecurring expenses incurred in the prior year. Offsetting the decrease is the annual wage increases and the negative 2% translation effect on converting U.S.-denominated expenses.

Net capital expenditures for the fourth quarter of 2025 totaled $35.3 million compared to net capital expenditures of $22.3 million in the corresponding period of 2024. Net capital expenditures for the calendar year 2025 totaled $183.7 million, consisting of $48.1 million in upgrade capital, $146.3 million in maintenance capital, offset by proceeds of $10.6 million for equipment disposals.

The company has budgeted maintenance capital expenditures for 2026 of approximately $161.4 million and $32.8 million of selective upgrade capital, of which $24 million is customer funded. Debt repayments against debt totaled $80.3 million for the year, but we saw a total net decrease by $105 million due to foreign exchange as well as debt repayments.

With the reductions in adjusted EBITDA, the stated debt reduction target of $600 million will now likely be achieved in the first half of 2026. The revision is the result of the current industry conditions and the reinvestment of capital expenditures.

If the industry conditions change, this target could be increased or decreased. On that note, I will pass the call back to Bob.

Thanks, Mike. Let's start with a quick reflection by region for 2025.

The fourth quarter was quite active for us right across all our world as we methodically grew rig count in the high-spec triples and high-spec single rig type categories in North America. Each area had different market dynamics -- excuse me, each area had differing market dynamics at play.

In Canada, we were up 3% on activity year-over-year whilst being up year-over-year on EBITDA. This is a result of our Canadian business unit continuing to focus on delivering high-spec rigs with high-performance crews.

In fact, one of our new ADR HSS set a record drilling 2,500 meters in a 24-hour period. In the U.S., the market forces were much tougher and keeping rigs active meant spot pricing was falling.

Rigs that have consistent work remained active and with little rate degradation. Once again, the U.S.

operations team outperformed their peer group and placed 10 Ensign rigs in the top 20 across the entire U.S. for outstanding performance metrics.

Our international business unit was relatively calm through 2025, and then that changed quickly at the beginning of the year, more on that in a moment. Current operational update starting with Canada.

Whilst industry was down 10% year-over-year in the first quarter '26, we peaked at peaked at 51 and enjoy 43 drilling rigs active today in Canada. As we head into breakup, we expect to run 20 or so rigs over breakup similar to the prior year.

We are currently upgrading one of the high-spec singles we recently brought up from California and expect to have it contracted long term for rates in the mid-20s all in. That rig should be spudding its first well by the summer.

The value proposition is still valid for the client as we continue to perform by improving drilling efficiency offsetting any rate increases. Also because the rig equipment is being run closer to its technical limits more and more, rate increases are quite justified to offset the higher operating costs.

We see strong support for the high-spec triples in Canada, and they operate in the low 30s all in. We continue to see the Canadian market adapt our EDGE drilling rig automation more and more every quarter.

This provides a high-margin bolt-on incremental revenue stream of anywhere from $1,000 to $2,600 a day across the high-spec triples generally, and now we are deploying on to our high-spec singles. We continue to address any upgrades that operators request by assisting the capital upgrade be paid for by the operator with a notional rate increase or we adjust the day rate incrementally in order to achieve a 1-year payout or less on the incremental capital with the incremental rate increase.

In the U.S., we mentioned in our last quarterly call, our rigs continue to drill more footage per day, albeit we are finding that the double-digit rig efficiency gains in years past has slowed into the single digits as we get closer to the technical limits of the rig equipment. This is good news and an indication that we are at or near a trough.

Operators now focus on continued duplication of their best wells. Again, we mentioned on our last call, our position hasn't changed.

Most operators are starting to look at Tier 2 acreage as we move along into the future. We also saw the U.S.

hit record oil production close to 14 million barrels per day. So with the technical limits of rigs establishing somewhat of a ceiling and with Tier 1 acreage diminishing, we will need to see rig count move up if we were to hang on 14 million barrels of oil production.

Current oil prices certainly helped us construct. So in the U.S.

today, we have 38 high-spec Ensign rigs, mostly high-spec triples out of our fleet of 70 high-spec ADRs operating across the U.S. from California to the Rockies and down into the Permian.

Our busiest operating area is, of course, in the Permian, where we run roughly 26 rigs daily and which we own 9% of that market share. We continue to increase our market share in the U.S., the result of our high-performance rigs and crews in concert with our EDGE drilling solutions technology.

We saw our California business unit almost double its rig count in 2025 from 5 to 8, and we expect that we will stay at that level through 2026. Our directional drilling business unit, which is essentially a mud motor rental business that utilizes proprietary technology continues to provide some of the best motors with high-quality rebuilds and the longest runs in the Rockies.

We're expecting that '26 to be very similar to '25 there. On the international front, we have a fleet of 25 high-spec rigs that operate in 6 different countries around -- sorry, outside of North America, of which 13 of those 25 are active today.

At this point in time, our 7 Middle East rigs are still operating under either standby with freeze or on full operational rate. This is, of course, a day-to-day situation, which may change at any point in time.

The area is what we call on yellow alert with safety of the personnel and security of the assets most important. In Kuwait, we have been successful in contract extensions on both 3,000-horsepower ADRs, taking us out into mid-2026.

We started back in Venezuela and now have both rigs operating. The only 2 drilling rigs operating in Venezuela, I will point out.

As you know, there is no lack of excitement in Venezuela these days, and we'll see how this area develops. In any case, Ensign has a product to fill operators' demands, and we have the on-the-ground experience that very few have in the area, thanks to our strong Venezuelan team.

In Argentina, we have both our ADR 2,000 horsepower super-spec triples under contract with demand possible for additional rigs in the area. In Oman, the 2 rigs we have undergoing extensive upgrades are on budget on time with the first rig now operational and the second rig planned for April commissioning.

This will add to the 3 ADRs currently under contract in Oman and bring us to 5 rigs active in the country once the last rig is commissioned. The current Middle East situation will, of course, create possible delays in the commissioning of the fifth rig in Oman, notwithstanding the general concerns in the Middle East region today.

In Australia, we have 4 rigs active going to 5 by the summer and with strong bid activity, which we feel will take us to 6 rigs by year-end. Moving to well servicing.

Back in North America, we have a fleet of 85 well service rigs in North America, 38 in Canada, of which we operate 15 to 20 on any given day, plus we have 47 well service rigs, primarily in the Rockies and California where we operate with high utilization rates consistently. Our U.S.

well servicing business unit, which is, again, focused primarily in the Rockies in California, has come out of the gate stronger than last year and is expecting a stronger year than 2025. Our Canadian business unit focuses primarily on the heavy oil market and has been very steady with rates increasing basically in line with cost inflation protecting margins.

Moving to the technology side, our EDGE AutoPilot drilling rig control system. In 2025, we increased our EDGE autopilot installs by 15% and now have our EDGE AutoPilot systems on 60% of our rigs globally.

Our EDGE drilling rig controls product line continues to expand with increasing adoption of products like our ADS, automated drill system, which we doubled the number of rigs we have deployed this technology in the 2025 year. In the last call, we reported that we successfully beta tested our Ensign EDGE ATC auto toolface control in conjunction with the DGS.

This paves the way for seamless control of automated directional drilling for those operators who utilize remote operating centers and utilize in-house DGS systems, direction and guidance systems. I'm happy to report that we are now fully commercial with our EDGE ATC and are charging that out on 5 rigs today.

We have also initiated the development of an Ensign EDGE state-of-the-art DGS, directional guidance system. With the help of AI, our development team was able to develop a DGS ready for beta testing in less than a year and for a fraction of the cost of other DGS developments.

Happy to report that we're now beta testing this on our super-spec -- one of our super-spec ADR 1500s in the U.S. With this, we'll be able to provide a complete and comprehensive drilling control system offering all the bells and whistles.

With that, I'll point the call back to the operator for questions.

Maybe just to start off, Bob, if you ask me where will oil be in 1 year from now? If you asked me that about a year ago, I would have said not -- I wouldn't have said $90.

But at the same time, we're hearing from most E&P operators in the U.S. and Canada that it's not necessarily going to affect the activity levels with prices even being where they are.

So question for you is, what's your view on that? How long do you think it takes of high prices before we start to see an activity improvement in the U.S.

based on the oil price spike that we've been seeing of late?

Yes. Well, I agree with your summary there, basically that oil companies will be takers of this blip in oil pricing.

I don't think it will affect activity too much if it -- but I would suggest though that if it continues for 6 months, I think it will start to attract capital, and people will go after more drilling. That's been the plan.

But the question is, as you point out, I mean, last week, would I have thought oil would be $90 today? No.

But -- so that's our sense on it. Short term, I see very little impact.

But if it stays for 6 months, I think there's enough capital going after it that will make a good return that people will start to drill more for sure.

Yes. Got it.

And what about pricing? Like maybe activity doesn't change in the next couple of months, but does it give you and your competitors a bit more of a leg to stand on when you go to renew contracts now that customers have healthier cash flows?

Like do you think this is at least positive for pricing? Or is it neutral for pricing, would you say?

Well, I'd say it's -- our pricing is always dictated by the supply of drilling rigs. And -- but there's no question, as we're getting more calls and getting more bids, we tend to bid up.

So we'll see. We'll see, yes.

Got it. Okay.

And just one more for me on Venezuela. Certainly, you're the only ones kind of working there now with the 2 rigs running.

Can you just give us a bit of a summary on the state of the environment there with respect to the rigs that you have there, how many rigs you have, how many could work, what types of bidding or at least inquiries that you're getting now? And what's your sense of how many rigs competitors might have on the ground as well?

Yes. Well, that's a big question.

Just to unpack that a little bit. We've got 2 drilling rigs that have been active.

I mean they're great rigs. I've been down there recently.

There are, of course, over the last 5 years, a lot of the U.S. competitors have disappeared and chased away or whatever, and there hasn't been much activity.

So the rigs that are on the ground are not in very good shape in any shape at all outside of the rigs that we have running. We've got kind of 3 rigs, 2 drilling rigs and kind of a deeper workover rig in the country.

But we've got -- or not properly, we've got assets that we can deploy from the U.S. that can meet the needs, and we're under current conversation with some clients on that.

Got it. Do you have an estimate of how many rigs you think could be deployable from the U.S.

to Argentina in your fleet? Or is it too early...

Venezuela? Venezuela or Argentina.

Venezuela?

Yes.

Yes. It's -- we -- well, let's put it this way.

We've got capacity. We could send 10 if we needed to.

But it's -- I think Venezuela develops slowly. There's a lot going on, but it's very active.

A lot of OFAC licenses have been granted to various operators, and they've been in touch. But I think it develops slowly.

It's a tough place to do business as one can imagine. But right now, it seems to be a little bit of a party compared to what's going on in the Middle East.

Just more of a clarification one on the Kuwait rigs that are rolling off contract mid this year. Is this something that you reasonably expect to get renewed again once the contracts expire?

Or at this point, are you trying to find sort of new homes for them?

Yes. The operator has provided some indication that they might have another well behind each one of these rigs.

And it's typically how they move along. They'll get close to 60 days from when the rig is going to be complete and they find another well.

That's how we've been operating in the last year or 2. So they provided some indication, but we don't know with everything happening in the Middle East, everything is happening here.

Got you. And then we saw Tourmaline cut capital earlier this week, not materially, but ARC also recently removed Attachie Phase 2 from their long-term plans.

How are you thinking about sort of that deep basin and liquids-rich Montney outlook in Canada, maybe starting to see some cracks in the armor given gas prices? Like any updated views there?

Yes, good question. Yes, gas prices are not helping.

I got to think that liquids pricing has got to be helping. But yes, I'm not too surprised.

This is the -- the dilemma Canada has, of course, is takeaway capacity, and that's another conversation. But yes, we are victims of gas prices for sure.

Fair enough. And then maybe I'll sneak one more in to build on Keith's question.

In the event that you would mobilize rigs to Venezuela, what's the rig spec that makes sense for the market? And how would you think about sort of staffing and sort of other sort of soft issues in...

Yes. Well, yes, we've been in Venezuela over 25 years.

Almost all of our people in Venezuela are Venezuelans. There are some people coming back.

We've got a strong franchise there. The type of rigs depends on the area where we operate.

They're typically 1,000, 1,500 horsepower type rigs, mostly 1,500. That's kind of the rig for the Orinoco Belt.

First one on the debt side. You knocked down $100 million to that $918.6 million.

How should we be looking at debt going forward? You mentioned that in the commentary that the $600 million target should be reached during 2026 first half.

If you go back -- if we go back to periods when you had $80, $90 oil, let's say, post war, [ 28 ], [ 29 ], and we get there, in 2012, you had EBITDA of $561 million. In 2014, you had $537 million.

If you look at and say something like you do have EBITDA [ 28 ], [ 29 ] of $500 million, would your target be to get to 1:1 debt to EBITDA?

Mike?

Yes. I mean, ideally, that [ 1 ], [ 1.5 ] is really the target.

So yes, I think once we kind of get to that, then conversations would start to change. But yes, that would be the target that we'd be looking at.

So about $100 million a year then for debt reduction is still something to keep in mind for models?

Yes, for sure. We're still laser-focused on the debt reduction.

Super. At what point would you be starting to look at increasing the amount of NCIB versus debt reduction?

Is there a number that you need to reach $700 million? Is there some number out there that you need before you could start looking at the mix of allocation of capital funds flow?

There's a minimum liquidity on the credit facility that we have that we'd have to meet first, then we probably -- like I said the conversations at the Board level would need to take place on what would happen. But like I said the next year or 2 years are really focused on continued debt reduction.

Okay. Last one for me.

Given we're seeing insurance companies pulling insurance coverage for shipping, is there any concern about your rigs in the Middle East, given they're in the zone of drone attacks that insurance is -- could be an issue or the cost could get up to the point where putting the rigs in the field doesn't make sense?

Yes. We've got -- we're not going to -- we don't talk in detail about our insurance programs, but we do have insurance.

We're -- we've been operating in the Middle East for long periods of time, and have good protocol on keeping most importantly, personnel safe and then equipment. Where we're at in Oman and Kuwait, there's been a little bit of action, but not much.

We're basically both green in that area. Bahrain or what we call yellow alert.

But the rigs are -- in Oman and Kuwait are still drilling and in Bahrain, we're on basically standby with crews. So -- and it's changing every day.

So tomorrow may be a different story.

I just wanted to start, I guess, with margins. They came in a little bit above my model.

And I was thinking perhaps this might be an impact of either rig mix and business mix, but maybe also just the impact of adding some of these EDGE automation systems to the fleet over time. Do you have an expectation for what the margin lift could be in sort of an otherwise flat environment for pricing just based on those EDGE automation systems and other technology additions?

Yes. We've got -- I mean, we're building our EDGE rollout at about 15% per year.

We have about 60% of our fleet today that is active. We have [ 100 to 160 ] rigs.

So we're adding about 10 per year with anywhere between $1,000 to $1,500 a day on average. And it's all margin.

It's all margin. So you can build that into the model pretty quickly there.

Okay. That's helpful.

And then -- most of my questions have been answered. But I guess I want to dive in a little bit into what's going on in California.

It sounds like there's at least some rumblings of more oil and gas friendly policies being pushed in California. Are you seeing any changes to, I guess, your customers' expectations or activity levels or expectations for what their activity levels will be going forward in California?

A little bit, yes. I mean we -- we basically are running 8 rigs now.

We're down to about 4 or 5 there at the beginning of '25. So it is changing.

It's opening up a little bit, and I'll say that tongue in cheek for California, but they're starting to realize that they do need a little bit more oil and gas. So operators that are in the area are able to get some permits that are allowing them to get after some drilling along with some P&A activities, which we benefit from in our service rigs.

We also run a bunch of service rigs in California. We're the biggest -- one of the biggest in California as well on the service rig side, the biggest on the drilling side.

So yes, it's California, but it is a little more happy face than sad face, I'd say.

Okay. Do you think you'll see stronger activity levels in California on average in '26 than '25 or at least...

I think we stay steady -- yes, I think we stay steady at 8 through '26 is my thinking.

Okay. And then Ensign has historically been a little bit underrepresented in gas basins in the U.S.

Are you making any progress in moving into gas basins or getting more activity levels in the Haynesville or talking to customers in that basin?

Yes. Yes.

We're seeing some bids coming out into the Haynesville, the Eagle Ford. We've got a few idle rigs that can take those bids.

But yes, it's slowly moving for sure. I mean gas prices down there a little different up here, right?

Okay. And then just in terms of Venezuela and the prospect of perhaps moving some idle equipment into the region for the next few years.

I guess, what type of contract structures would you require for that? And what type of assurances would you be looking for to be able to deploy incremental capital or equipment into that region?

Yes. Well, it's -- Venezuela is still a risky market.

Let's -- it's been derisked to some extent, but it's still a risky market. We would look for long-term contracts of at least 3 years to 5 years and with some coverage on getting us in and getting us out.

We work in U.S. dollars in Venezuela, obviously.

And that's about all I want to disclose, but we've been working there for 25 years. So we know how to run the business there and the commercial side of it well.

Congrats on the release. I had 2 [ assigned ] questions.

So if I look at the international rigs that you have, I think it's around like low teens and then half of it is in the Middle East. Should I think about in terms of revenue also roughly similar breakdown, 50% of international revenues are in the Middle East and the rest is split between other markets?

Mike, do you want to handle that one?

Yes, that would be appropriate. I said that would be appropriate.

Okay. So sorry, I didn't hear that.

And in terms of the CapEx, I expected lower growth CapEx considering that it is -- a big chunk of it was customer paid, but I don't really understand where that number shows up. How should I think about the customer paid portion of the CapEx?

Do you -- is it already netted out of the growth CapEx number? Or are you going to get it this year?

Like where does it show up in financials?

It show up through the revenue line over the course of the contract. So that CapEx is the growth CapEx number.

And then the customer funded one, depending on structure of the contract will flow through revenue.

I just have 2 quick ones on Venezuela. Can you speak to just the AR collections over the last couple of years?

And then has anything changed post Maduro leaving? That's the first question.

And then the second would be, would you be more likely in terms of faster incremental deployments of equipment down there? Would it be workover rigs or drilling rigs?

Just your thoughts.

Yes. Well, let's answer the last one first, drilling rigs.

In our perspective, there's some local workover rigs that I suspect the local companies will jump on to because lower capital required, less complex equipment. As far as the commercial side, since Maduro left, nothing has changed as far as our relationship with our client and how we're getting paid.

And we'll see how it evolves. We've got a pretty good contract structure that we've been using for a period of time that is within the OFAC restrictions.

So yes, Maduro leaving hasn't changed anything other than it appears to have more blue sky ahead of Venezuela. But on a day-to-day basis, there's not much change.

Thank you. Well, the outlook for the drilling industry remains constructive, supported by obvious stronger commodity prices and the ongoing need for reliable global energy.

At the same time, the sector continues to operate within a volatile macroeconomic and geopolitical backdrop. That's obviously an understatement today.

In this environment, operators will remain focused on efficiency, capital discipline, high-performance drilling contractors like Ensign, whom also have a global footprint and are capable of delivering fast, safer and more cost-effective wells on a consistent basis. We will stay active well into the future.

And with that, I'll close off, and we'll look forward to our next call in 3 months. Thank you.