Operator: Good afternoon, ladies and gentlemen, and welcome to the Ensign Energy Services Incorporated. Fourth Quarter 2024 Results Conference Call. At this time, all lines are in listen-only mode. Following the presentation, we will conduct a question-and-answer session. [Operator Instructions] This call is being recorded on Friday, March 7, 2025.

I would now like to turn the conference over to Nicole Romanow, Investor Relations. Please go ahead.

Nicole Romanow: Thank you, Constantine. Good morning and welcome to Ensign Energy Services fourth quarter and year-end 2024 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 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, 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 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.

Bob Geddes: Thanks, Nicole. I'm happy to report to shareholders that the Ensign team ended the 2024 year executing on what we set out to accomplish in 2024. We reduced debt by $220 million. We generated $450 million of EBITDA.

We held a tight rein on maintenance CapEx at $160 million, running about 100 rigs every single day. We grew our market share in Canada. We maintained market share in the U.S. We were 100% utilized in the Middle East and Latin American business units. We identified incremental growth opportunities of approximately $19 million that provided attractive payouts.

We successfully upgraded roughly 20 rigs in the year provided with operator funding. And we expanded our drilling solution penetration by 25% year-over-year. And we ended the year with our second best safety performance in the company's history. In fact, we had three divisions that operated throughout the entire year without any incidents. With that, I'll turn it over to Mike for a financial summary of the fourth quarter, and then I'll come back to provide an operational update in each of the operating areas and also provide some color on how we see the markets moving forward.

Mike?

Mike Gray: Thanks, Bob. Ensign’s results for the fourth quarter and 2024 year-end reflected the benefits of operational geographic footprint with strength in our Canadian and international divisions, offsetting decreased activity in the United States division as a result of customer consolidation and depressed natural gas prices. Despite the recent volatility in commodity prices, 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 down in the fourth quarter of 2024 by 2%. Canadian operations reported an increase of 10%, while the United States International Operations saw a decrease of 8% and 13% respectively, when compared with the fourth quarter of 2023.

For the year ended December 31, 2024 total operating days were down by 7%. Canadian international operations seeing increases of 10% and 1% respectively, while the United States operations saw a decrease of 23%, compared to the year ended December 31, 2023. The company generated revenue of $426.5 million in the fourth quarter of 2024, a 1% decrease, compared with revenue of $430.5 million generated in the fourth quarter of the prior year. For the year ended December 31, 2024, the company generated revenue of $1.68 billion, a 6% decrease, compared with revenue of $1.79 billion generated in the prior year. Adjusted EBITDA for the fourth quarter of 2024 was $113.4 million, lower by 12% than adjusted EBITDA of $129 million in the fourth quarter of 2023.

Adjusted EBITDA for the year ended December 31, 2024, was $450.1 million, an 8% decrease compared to adjusted EBITDA of $490.2 million, generated in 2023. The 2024 decrease is primarily due to reduced activity in the U.S., because of customer consolidation and depressed natural gas prices. Interest expense decreased by 23% for the year ended December 31, 2024, compared with the same period in 2023. The decrease in expense compared to 2023 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. The company expects its blended interest rates, if federal rates hold, to be less than 7%, which will allow us to continue to reduce our interest expense going forward. G&A expense for the fourth quarter of 2024 was $13.1 million, compared with $14.9 million in the fourth quarter of 2023. G&A expense totaled $57.4 million for the year ending December 31, 2024, compared with $58 million for the same period in 2023. The G&A expense remained relatively flat year-over-year, despite annual salary increases and the negative exchange translation on USD denominated expenses.

Net capital expenditures for the fourth quarter of 2024 totaled $22.3 million, compared to net capital expenditures of $28.8 million in Q4 2023. Net capital expenditures for the calendar year 2024 totaled $147.6 million, consisting of $18.7 million in upgrade capital, $160 million in maintenance capital, offset by proceeds of $31 million from property and equipment disposal. The company has budgeted maintenance CapEx for 2025 of approximately $164 million and selective growth and customer funded capital of $8 million. Net repayments against debt during the year totaled $219.7 million. This exceeded the company's 2024 debt reduction target of $200 million.

Since the first quarter of 2019 after the Trinidad Acquisition, when the company's total debt net of cash peaked at $1.69 billion, the company has reduced net debt by $664.6 million over the past six years. During this period, the company also completed two countercyclical accretive acquisitions, which totaled $162.7 million. Our net debt adjusted EBITDA for the year ended 2024 was $2.27. This is the lowest ratio since 2015 and will continue to reduce as the company hits debt targets. The company's debt reduction target for 2025 is approximately $200 million.

The company remains on track with our long-term debt target for the period beginning 2023 to the end of 2025 of approximately $600 million. From January 1, 2023 to December 31, 2024, a total of $437.3 million of debt has been repaid, leaving $162.7 million of the $600 million debt target reduction. If the industry conditions change, this target may be increased or decreased. On that note, I'll pass it back to Bob.

Bob Geddes: Thanks, Mike.

So let's do an operational update around our world, starting with Canada. Our Canadian drilling team, which operates a high-spec fleet of 90 rigs, continues to gain market share quarter-over-quarter and year-over-year with an 18% increase year-over-year. Through 2024, we continued to feed the very active Clearwater Mannville play by transferring three of our California ADR 300 high spec single rigs to Canada where we upgraded them and recertified these rigs, placing them on the long-term contracts. We also expanded our client base to three new clients and expanded our rig counts with our current client base. We currently have 52 drilling rigs active today in the Western Canadian Basin, peaking at 55 this winter, and depending on whether we expect to hold on to that in the mid-March and then with breakups start to see that fall off.

Currently we forecast we'll have roughly 24 rigs running over breakup, which is up from 17 last year. We're also seeing operators contract their preferred rigs for after breakup and in some cases contract out the spring of 2026. In every case, we're adding in escalations in the range of $500 to $1,000 a day, minimally. It's safe to say that the demand for our high spec singles and high spec triples continues to be at the highs that has been in quite some time. This has also helped to drive the high spec double market to enjoy utilization of about 50%.

Almost a quarter of Ensign’s Canadian fleet is high spec doubles. So we have lots of product to feed into this construct. Our fleet of high spec singles and high spec triples are essentially booked well into or well through 2025. And we have roughly 75% of the high spec single fleet booked through into second quarter 2026 already. Notwithstanding, day rates remain well below any new-build metrics.

Rates need to be in the 50s before we will see new-build super-spec triples, and for the high-spec doubles and high-spec singles, rates will need to be in the very high-30s before investment could be made in new builds with a reasonable rate of return that covers at least the cost of capital. We're also seeing growing interest in our EDGE autopilot with specific apps such as the ADS, the automated drill system, which charges over $1,000 a day. The demand growth has been focused on our high spec triples, but in the last six months we are seeing growing demand for EDGE app on our high spec doubles in Canada. While our well servicing business in Canada, which operates a fleet of 41 well servicing rigs, including [SLAM] (ph) rigs and an automated well-service rig, the ASR, did not have as many or did not have as active a year as forecast due to the last 24-hour activity. We continue to see strong scheduling post-breakup.

We continue to capture more of the OWA work in 2025 with our Canadian Well Servicing Group, and we expect our ASR to start back up after break up. Our rental fleet of tubulars, tanks, and other high margin ancillary equipment continues to grow as more and more specialty equipment is called for. Usually things like high torque tubulars, et cetera, attaching to our high spec ADR drill rigs. With accelerated wear and issue on tubulars as a result of the high penetration rates, it is becoming the norm for tubulars to be charged separate from the rig rate and to recognize the consequence of accelerated wear on full cycle tubular costs and charge that out to the operator. Moving to international, we have a fleet of 27 drill rigs that operate in six different countries around the globe, of which 14 earn their contract today.

In the Middle East, we have 100 percent of our high spec ADR fleet actively engaged in long-term contracts, and with half of them on PBI contracts, we're able to get paid for the performance our high performance drilling team provides when coupled with our EDGE autopilot drill rig control systems. In Oman, we drilled the 2024 campaign, while ahead of schedule, and as a result, we had two of the three ADRs in standby for the last few months of the year. All three rigs have started back up right after Christmas in Oman and are fully active today and will be active through the rest of 2025. In Argentina, we are running at 100% utilization with both our 2,000 horsepower high spec ADRs operating in under long-term contracts. We started up the second rig in the back half of 2024 in Venezuela and currently have two rigs in the payroll.

We're awaiting instructions from our client as to the current OFAC directive which suggests shutdowns by April 3, 2025. Australia saw reduction in activity as competitors dropped pricing on the shallow and mid-sized rigs. We currently have three of the 11 drill rigs in the country active today and fully expect to redeploy another three rigs by mid-year. Our deeper ADR 1,500 look to stay busy through 2025. Moving to United States, we have a fleet of 70 high spec ADRs in the U.

S. Stretching from the California market up into the Rockies with the main focus backed out into the Permian. We operate roughly 35 rigs on day-to-day basis, which what we ran on average for most of ‘24, we expect will change through the rest of ‘25 with possibly upside of one or two rigs into the third quarter. We’re certainly not holding our breath for the manifestation of Drill Baby Drill. The challenge we saw in the U.

S. In 2024, that being the after effects of $0.5 trillion of M&A activity over the last two years has manifested itself into less work, not more. That construct continues into the beginning of 2025. Also with gas oil ratios rising as production depletes, the natural gas story may take a bit longer to correct itself. The good news is that we have mainly been an oil focused Permian Driller in the U.

S. And not as affected by the tougher gas market. Our U.S. Business unit continues to expand its PBI contract base and now has over half the fleet on a PBI contract of some degree that builds off our high performance and highly trained field teams coupled with our EDGE Autopilot drilling rig control system technology. Not only do we get a superior rate for our EDGE AutoPilot technology, we capture the upside value generated to the operator through performance metrics.

Everybody wins, the operator delivers wellbores for lower costs, and we help derisk that with our PBI contract performing higher margins. Our U.S. well servicing business unit, which is focused primarily on the Rockies on California oil servicing market continues to enjoy high utilization in the upper 80s and delivered yet another solid year. Our directional drilling business, which is essentially a motor rental business, utilize proprietary technology continues to provide some of the best motors with high-quality rebuilds in the longest runs in the Rockies. We're expecting another solid year in ‘25, similar to ‘24.

Moving to our EDGE AutoPilot drilling rig control system. Happy to report we have successfully beta tested our Ensign EDGE ATC auto tool face control in conjunction with a DGS, a directional guidance system. This paves the way for seamless control of automated directional drilling from those operators, who utilize remote control -- remote operating centers and utilize in-house DGS systems. We also started the beta testing of our enhanced AutoDriller, the AutoDriller Max, which will further increase penetration rates. We continue to grow and deploy EDGE AutoPilot onto our active rigs across the globe.

As I mentioned before, we have a 25% year-over-year growth rate. Most recently, we installed and commissioned our Ensign RigOS on our Bahrain rigs, which are starting to execute on performance-based contracts established late in '24. We continue to expand the EDGE apps platform on each of the rigs that already have our EDGE AutoPilot drilling rig control technology. This part of our business continues to grow at a rapid pace and delivers results with reduced well times, increased penetration rates and high margins. With that, I'll turn it back to the operator for questions.

Operator: Ladies and gentlemen, we will now begin the question-and-answer session. [Operator Instructions] Your first question comes from the line of Aaron MacNeil from TD Cowen. Please go ahead.

Aaron MacNeil: Hey, good morning, all. Thanks for taking my questions.

Can you speak to what you're seeing in terms of spring break up in Canada. I mean it just helped the government in Alberta, the freeze-thaw map, and it seems like we're already sort of edging up to Grand Prairie. Again, just wondering to get your sense of if you're going to be able to get up to all the work you had planned or if there's anything else we should be thinking about there?

Bob Geddes: Well, anytime we get past March 15, it's always a bonus. And you're right, we're starting to see -- starting from the South moving up North. You're asking me to be a weather man now, but we're seeing some instances where we're back down to 100%.

We can move all the way down to 75% with permits and wheels. Most of the rigs that will run through breakup are already on those pads, so they're not going to be affected. But yes, if it's -- like I said, we're down to 52 today from 55. It starts rolling down. We always get a tease a little bit and then we get a little bit of cold snap, but it happens every year.

But after March 15, those are all kind of bonus days in our mind. So that's about all I can tell you right now is what we know.

Aaron MacNeil: Yes. Fair enough. And maybe one for Mike.

Can you speak to how you're tracking against your quarterly term loan payments and credit facility capacity reduction in Q2. I just -- I noticed the working capital deficit at the end of the year. So just wondering if you could speak to that sort of quarter-by-quarter cash flow?

Mike Gray: Yes, for sure. So if you look at the first-half of 2023, we did about $100 million in debt repayments. We got about $130 million that we have to make in the first half 2024.

And the majority of that is being paid at the end of Q2 with the $75 million step down and the $27 million term loan. So when we look at our CapEx spend and timing and then a reduction in the interest expense year-over-year due to the reducing rates as well as reduction in the actual amount of debt we have plus the current activity that we're seeing right now, we're quite confident with the balance sheet and liquidity going forward.

Aaron MacNeil: Fair enough. Thanks. I'll turn it back.

Mike Gray: Thanks, Aaron.

Operator: Your next question comes from the line of Waqar Syed from ATB Capital Markets. Please go ahead.

Waqar Syed: Thanks. Bob, if I remember correctly, there was a rig that you had moved from Canada to the U.S.

Northwest for geothermal drilling, could you maybe provide an update on that rig?

Bob Geddes: Yes. It's fully operational, and we're visiting with the client to extend the program. So I suppose one would call that a success so far.

Waqar Syed: Great. And then could you maybe talk about the impact of tariffs on cost of goods sold in the U.S.

and in Canada, how could that be? And what could be some of the differences there?

Bob Geddes: Yes, yes. Well, a good question where that ends up. We've looked at some sensitivities on things like pipe dope. We have a company that manufactures pipe dope in Canada, and we distribute it around the world. Obviously, if there's a tariff on that pipe dope going into the U.S., the company has already talked about being able to move their production line, half of it down into the U.S.

without having much impact, but there'd be some impact. But it's such a moving target right now that it's not going to reduce costs, so let's put it that way. But all of our contracts have a -- if there's a tax or a tariff general throughout industry, we've got the ability to have the conversation with our clients about covering those costs. But it's -- right now, it's too early to put a finger on what that is, because no one knows what it is, right?

Waqar Syed: Yes. Now certainly, the Canadian market is fairly tight, and so your ability of the drillers to pass the extra cost to the customers may be pretty strong.

But do you see that ability in the U.S. market as well to pass costs on to the customers?

Bob Geddes: Yes. Yes. For sure. We obviously are able to have that conversation with the client.

They get it. It usually gets wrapped up into the next rotation on the contract. So it's -- we put it on the table as a cost increase, and therefore, a small rate increase and then we go from there.

Waqar Syed: Yes. And we've recently seen oil prices slipped below $70 a barrel.

Futures price indicating the low-60s by the end of the year. Although all of this is kind of recent, but are you seeing any change in behavior of the customers or any different conversations coming up? Anything that you could highlight there?

Bob Geddes: Yes. No, good question. No, certainly, like in Canada, of course, the Canadian dollar has kind of helped the arbitrage that dropped in the U.S. operators are telling us it's still within their budget parameters.

So they're not excited. I suppose you get closer to 60, things start to change for sure.

Waqar Syed: Yes. And then finally, so what's going on in Australia, there seems to be a lot big variability in rig count quarter-over-quarter. Could you maybe provide some more color there?

Bob Geddes: Yes, yes.

There was a large major that came out with a bid program, and we had three rigs that didn't win that bid. So we saw some drops in pricing in that area with that particular client. We've got other clients that are able to pick up the rigs. So we've got a gap in that, but a couple of our competitors decided to grab some market share by dropping their price, which is always a crazy way to do it. But we've got other smaller clients that want to pick up the rigs.

They're great rigs. So away we go with that.

Waqar Syed: Great. That's all from me. Thanks so much.

Bob Geddes: Thanks, Waqar.

Operator: Your next question comes from the line of Keith MacKey from RBC. Please go ahead.

Keith MacKey: Hey, good morning. Can you first talk about what you're seeing in terms of pricing in the U.S.? Where are rig rates today versus where they might have been three to six months ago? And then you mentioned about half of your rigs are on performance-based contracts.

Generally, what is the uplift on the regular rate that you're getting from those? And would you look to have more of your fleet on performance-based contracts.

Bob Geddes: Yes. Thanks, Keith. Let me start with the last question coming back. Yes.

We continue to push as we deploy our EDGE AutoPilot technology on the rigs to coordinate that with performance-based contracts. The upside is anywhere from $3,000 to $7,000 a day at its peak. And those costs, we share the upside with our crews on that as well. So there's a small component of that, that goes back to the crews. That's why they're fully engaged in the process.

As far as rates go, we're seeing not much difference over the last three months. If we go back six months, we probably saw a declination of $2,000 to $3,000 a day, which you saw in the third quarter results, that's probably where you would have seen those. But they've kind of stabled off. We're finding that -- we're working harder to maintain market share, but we're able to not have to drop -- like I feel like the drop rate -- the rate drops have kind of settled down and we're having more conversations about reducing costs for the operator by getting on the performance space by being able to showcase comparative cases that we have with other rigs in the same area with the client. And we've got a performance drilling team and performance drillers in the U.S.

that specifically focus on these projects. So we're starting to get some momentum with that and that's helping us differentiate the margin for sure.

Keith MacKey: Got it. Makes sense. Just a follow-up in the U.S.

Can you talk about the pace of contracting and what you're seeing in the country? It looks like the U.S. industry rig counts may have or have improved a little bit in the last little while, yet you've got half of your rigs on some type of contract, but a very small amount on any type of longer-term contract, like 8% with six months. So can you talk about your strategy there? Do you expect that to improve over the next little bit? Just anything you can give us on your contracting status approach.

Bob Geddes: Yes. Well, with the lower day rates, we always try and have a contracting strategy of six months.

We don't want to get caught along on lower rate strategies. So we like the six month type of application, rotate that over and play the market that way. We do have some clients that were woven in with Directional Guidance System and other technology and they love the rig, they love their crew. Those rigs tend to get re-contracted on an annual basis. And of course, they're covered by escalation should there be any crew wage increases through that contract.

And those are generally 10% above -- 10% to 15% above the spot price. So we're comfortable with those prices as well.

Keith MacKey: Got it. And maybe one final one for Mike. In addition to organic free cash generation for 2025, any additional levers on the debt reduction that you can highlight or that you have available?

Michael Gray: Yes, for sure.

I mean, we still have two properties up in Nisku that are on the market. So that's some additional cash that can definitely come into the door. If something happen during 2025, we also have -- because we clear up some of the yards, getting ready for disposals or scrap metals and stuff like that. So there's a few levers here and there. I mean, the property being the bigger one.

Keith MacKey: Got it. Okay. That's it for me. Thanks a lot.

Michael Gray: Thank you.

Operator: Your next question comes from the line of Josef Schachter from Schachter Energy Research. Please go ahead.

Josef Schachter: Good morning everybody and thanks for taking my questions. First one, are we seeing any movement from the Secretary of Energy, Secretary of the Interior to open up more of the lands, federal lands in New Mexico and opening up a bigger area for Permian drilling. Is that something that you're hearing from your clients? And would that potentially give a little boost to your activity level in the Permian in the months ahead?

Bob Geddes: In the months ahead, no.

The Permian is -- there's not a lot of federal lands in the Permian. But the approval process and the rotation on that is a good one year to two years. So once they open it up because remember, under the prior administration, all federal lands were restricted and there was no auctions. So they're just starting to get some auctions going. But by the time they do that, figure out their strategy on facilities on these new areas, because they probably don't have much infrastructure, you're a good year plus out.

So you're in the mid- to late '26 at best on that notion. So no immediate impact, no.

Josef Schachter: Okay. Second one, this one for Mike. You generated cash $472 million versus last year, $492 million.

So let's say, a $450 million even a low number, $450 million, your dip's going to be down to $800 million, is the next target to get one-to-one debt to cash flow. So maybe '26 or '27, you start looking at options of NCIB dividends and stuff like that. Am I looking at correctly that once you get down to that one-to-one, then the flexibility opens up for shareholder returns and stock buybacks?

Michael Gray: I mean, it definitely does. The term loan is fully amortized by the end of '26. So realistically, until the term loan is 100% repaid, we just be focusing on debt reduction.

So there's always a debate on what is the correct leverage ratio for service companies or even companies in general. So I mean 1 to 1.5 is probably an appropriate level. It allows you kind of to navigate the ups and downs of the cyclical industry. So I think definitely by the end of '26 depending on how things are looking, I think there'll be some additional conversations taking place.

Josef Schachter: And last one for me.

Given, of course, the tariffs in China, U.S., Mexico, Canada and the EU in early April, are there any things you can do to preposition equipment, pipe, motors, any things that you need in terms of lubricants, whatever, mud pumps, anything that you need to -- that you could do that would save you the tariff battles that probably are still to come?

Bob Geddes: Yes. On the easily mobile stuff, we've been getting ahead of that. But the rest of it, it's again, wait and see and approach it that way. But we've taken some preemptive strategies and put those in place on the smaller items and the arrangements we have with some of our vendors. They've got the ability to provide it from different platforms as well.

Josef Schachter: Thank you very much. Thanks for taking my questions.

Bob Geddes: Thanks, Josef.

Operator: [Operator Instructions] Your next question comes from the line of John Gibson from BMO Capital Markets. Please go ahead.

John Gibson: Good morning, all. Thanks for taking my question. I just had one kind of following on Keith's topic of pricing in the U.S. Can you just ask the same question in Canada, any pockets of strength or weakness here to start '25?

Bob Geddes: Yes. Yes.

The high-spec triples have not reduced pricing at all. The high-spec doubles came under some pressure last summer. But this fall has started to expand some of them moving into the Clearwater area where with increased racking capacity, as we predicted a few years back, they would start to put some pressure on the high-spec singles. Having said that, the high-spec singles are still the choice. And those prices are in the mid-20s consistently on the high-spec singles and the high-spec triples are in the 30s, a few as high as the low-40s.

John Gibson: Okay, got it. Appreciate your response. We'll turn it back.

Bob Geddes: Thanks, John.

Operator: There are no further questions at this time.

I'd like to turn the call back over to Bob Geddes, President and COO, for closing remarks. Sir, please go ahead.

Bob Geddes: Thanks, operator. Looking forward, it continues to be an exciting time for Ensign as we build on last year's robust Canadian international market fundamentals. We're seeing an improving long-term outlook in all our U.S.

markets, but don't expect any meaningful growth until back half of '25 or into '26 with roughly $0.75 billion of forward revenue booked under contract, we expect to continue a steady run rate of 100 to 110 Ensign drilling rigs daily and roughly 50 to 60 well service rigs operating daily, both sides of the border. One-third of our drill rigs are under contract and long-term contracts with contract tenure of about one year and roughly 25% of those contracts are on a performance space. With that, we have excellent visibility for sustained free cash flow with consistent margins, which will provide the ability to continue executing our debt reduction plan of $200 million a year, '25 should be a repeat of '24. With the application of EDGE AutoPilot combined with an expanding PBI contract base backed up with our superior performance drilling teams in the field, Ensign is delivering value to operators, which supports rate increases moving forward. Again, the focus continues to be accelerating debt reduction into a steadily improving construct for the drilling and well servicing business globally.

I'd like to thank our highly professional crews and all our employees, along with our customers for helping Ensign achieve the performance and industry-leading milestones that industry recognizes us for. Look forward to our next call in three months’ time. Stay safe.

Operator: Ladies and gentlemen, this concludes today's conference call. Thank you very much for your participation.

You may now disconnect.