Ensign Energy Services Inc.

Thank you, Constantine. Good morning, and welcome to Ensign Energy Services first quarter 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 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 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. So happy to report the shareholders of the Ensign team started the 2025 year executing on key points.

We further reduced debt by $23 million in the quarter and stayed focused on $200 million debt target reduction for 2025. We increased our year-over-year revenue.

We held a tight rein on CapEx of $37 million down 30% year-over-year. We grew our market share in Canada.

We maintained market share in the U.S. We were fully utilizing our Middle East and Latin American business units, and we expanded our drilling technology solutions app penetration by another 25% year-over-year, and we ended the quarter with our best safety performance in the Company's history.

So over to Mike Gray for a financial summary of the first quarter and then I'll come back to provide an operational update in each of the areas and provide some color on how we see the markets moving forward. Mike?

Thanks, Bob. Volatile commodity prices and customer capital discipline have been headwinds impacting certain operating regions for Ensign.

However, despite these headwinds, the Canadian operating region continues to show strength and activity and support steady demand for our services. Total operating days were lower overall in the first quarter of 2025 with United States and International operations recording a 12% and a 13% decrease respectively, while our Canadian operations saw a 7% increase compared to the first quarter of 2024.

The company generated revenue of $436.5 million in the first quarter of 2025, a 1% increase compared to revenue of $431.3 million generated in the first quarter of the prior year. Adjusted EBITDA for the first quarter of 2025 was $102.4 million, a 13% decrease from adjusted EBITDA of $117.5 million in the first quarter of 2024.

The decrease in adjusted EBITDA was primarily due to overall decrease in operating activity as well as some one-time expenses in the United States operations related to activations and deactivations of drilling rigs. Depreciation expense for the first three months of 2025 was $81.9 million, 7% lower than $88.3 million for the first three months of 2024.

The decrease in depreciation is due to certain operating assets having become fully depreciated offset by the negative 6% translation effect of converting USD denominated expenses. General and administrative expenses remain generally flat at $15 million or 3.4% of revenue for the first quarter of 2025 compared to $15.1 million or 3.5% of revenue for the first quarter of 2024.

G&A expense decreased due to non-recurring fees incurred in the prior year of last year. Offsetting the decrease is the annual wage increases and the negative 6% translation effect of converting U.S.

dollar dominated expenses. Net capital purchases for the quarter was $36.9 million.

The purchases consisted of $3 million in upgrade capital and $35.7 million in maintenance capital for a total of $38.6 million offset by sales proceeds of $1.8 million. Our 2025 CapEx budget is set at $164 million and selective growth and customer funded capital of $8 million, and we will be monitoring this very closely and we will adjust as required.

Interest expense for the first quarter of 2025 was $20.5 million, a decrease of 23% for the first quarter of 2024 as a result of lower debt levels and effective interest rates. The company expects its blended interest rate if the Fed's rates hold to be less than 7%, which allow us to continue to reduce our interest expense going forward.

Net repayments against debt totaled $23.2 million during the quarter, which is an increase from net debt repayments of $11.4 million in the first quarter of 2024. For trailing 12 months, net debt to adjusted EBITDA was 2.32 and will continue to reduce as the company continues to reduce its debt.

We have paid $460.6 million of debt from the start of 2023 to March 31, 2025, leaving $139.5 million to achieve our three-year goal of reducing debt by $600 million by the end of 2025. Our debt reduction for 2025 is targeted to be approximately $200 million.

If industry conditions change, this target will be adjusted. On that note, I'll give it back to Bob.

Thanks, Mike. So let's provide an operational update on our global fleet of 186 drilling rigs and 88 well servicing rigs, spanning eight different countries.

Today, we have 85 drill rigs and 50 well servicing rigs active. Keep in mind that we are still in breakup in Canada and after road bans come off, we expect to see our Canadian fleet pop back up another 20 rigs which will bring us back to roughly 55 in Canada and over 100 drill rigs active globally.

Let’s start with Canada. In Canada, our Canadian drilling team, which operates a fleet of high spec ADR rigs at 89 of them continued to gain market share quarter-over-quarter and year-over-year with a 3% increase in market share year-over-year and a 7% increase in days year-over-year.

We had a peak of 55 rigs this winter and still have 33 operating today, a 50% increase over breakup from last year. The first quarter saw our Canadian business unit continue to feed the very active Clearwater Mannville play with the upgrade completion of one of our recently transferred California ADR 300 high spec single rigs.

That rig is out in the field and already drilling record wells. We have also started the upgrade of another ADR 200 to an ADR 275, which is also signed up on a long-term contract in the Western Canadian Basin.

In Canada, when we look at the macro chart, we see total oil production flat over the last five years, excluding oil sands of course. While we see average annual active rig count trending up about 50% post-COVID, the combination of building line fill for TNX and LNG Canada coupled with decline rates in the Western Canadian basin drives one [mythic conclusion] that we will continue to see a growing construct in Canada for our Canadian drill rig and well servicing business.

As mentioned, we have project commitments that should see our Canadian business going to get back to 55 rigs late summer from 33 currently. Again, this activity depends on commodity prices and whether Ottawa does what it says and gets pipeline projects moving and repeals certain unconstitutional energy regulations and laws.

We are also seeing operators contract their preferred rigs for after breakup and in some cases contract out the spring 2026. In every case, we are adding in escalations in the range of $500 to $1,000 a day and if the tightness continues, we should be able to see rates move back up about 10% into winter.

It’s safe to say that the demand for our high spec singles and high spec triples continues to be at the highest it’s been in quite some time. This has also helped to drive the high spec double market to enjoy utilization above 50%.

Almost a quarter of Ensign’s Canadian fleet are 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 through 2025 and we have roughly 75% of the high spec single fleet booked now through into second quarter 2026.

Notwithstanding, day rates remain well below any newbuild metrics. Rates need to be in the 50s before we will start to see any new high spec triples built and for the high spec singles and high spec doubles rates will need to be in the very high 30s before investment could be made in newbuilds with a reasonable rate of return that covers at least the cost of capital.

We are also seeing continual growing interest in our EDGE Autopilot with specific apps such as the ADS, the automated drill system, which charges over to $1,000 a day and soon our AutoDriller Max, which provides for 10% penetration rate increases, which will be finished with beta testing in the U.S. and will start to be commercially marketed in Canada later in 2025.

While our well servicing business in Canada, which operates a fleet of 41 well service rigs including slant rigs and an automated well service rig or ASR, does not have its active first quarter as forecast due to less 24-hour activity and about 10 days of minus 40 degree weather which shut down operations, we continue to see strong scheduling post breakup. We continue to capture more of the OWA work into 2025 with our Canadian Well Servicing Group and we expect our ASRs to start back up after breakups.

Rental fleet of tubulars, tanks, and other high margin ancillary equipment continues to grow as more and more specialty equipment is called for. Let’s move to International.

We have a fleet of 27 drill rigs that operate in six different countries around the globe, of which 15 are under contract and active today. In the Middle East, we have 90% of our high spec ADR fleet actively engaged on long-term contracts and with half of them on performance based contracts we are able to get paid for the performance or high performance drilling team provides when coupled with our EDGE Autopilot drill rig control systems.

We have three rigs start back up right after Christmas in Oman and are fully active today on PBI contracts. They’ll be active through to the end of 2026.

In Argentina, we are running at 100% utilization with both our high spec 2,000 horsepower ADRs operating under long-term contracts. We started up a second rig in the back half of 2024 in Venezuela and now currently have two rigs on the payroll through the first quarter.

We are awaiting instructions from our client as to the current OFAC directive which suggests shutdowns currently by May 27 unless extensions are granted yet again. Australia seems to be picking up again as we are seeing much more bid activity.

We currently have four of the 13 rigs in the country active today and fully expected to redeploy another two to three into the back half of 2025. Moving to the United States.

We have a fleet of 70 high spec ADRs in the U.S. stretching from the California market up into the Rockies and with the main focus back down into the Permian.

We are up a few rigs to 37 today and we expect some near-term – but we do expect some near-term softening into the third and fourth quarter due to softer commodity prices. It’s interesting to start hearing from operators that the geologic headwinds are stronger than the tailwinds from technology and operational efficiency gains in the last years.

We look at the generally flat production output of the U.S. over the last few years and the flattish rig count over that same period and putting that last statement into context more rigs will need to start coming back on if the goal is to hold production.

Our U.S. business unit continues to expand its performance-based contract base and now has over half a fleet on a PBI contract of some degree that builds off our high performance highly trained field teams coupled with our EDGE Autopilot drill and rig control system technology.

Not only do we get a superior rate for 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 and California well servicing market, continues to enjoy high utilization close to 80% and delivered yet another solid quarter. Our directional drilling business, which is essentially a mud motor rental business that utilizes proprietary technology, continues to provide some of the best motors with high quality rebuilds in the longest runs in The Rockies.

We are expecting another solid year in 2025 for that division. Moving to our technology, our EDGE AutoPilot drilling rig control system.

In our last call we reported that we successfully beta tested our Ensign Edge ATC, that’s auto tool phase control, in conjunction with DGS directional guidance system. This paves the way for seamless control of automated directional drilling from those operators who utilize remote operating centers and utilize in-house DGS systems.

I’m happy to report that we are now commercial with our EDGE ATC and are charging that out on four rigs today in the U.S. We also started the beta testing of our enhanced AutoDriller, the AutoDriller Max, which will further increase penetration rates and be charged out with a base daily rate of $1,000 a day plus a variable per foot or per meter rate so that we can start capturing the upside of the cost and operational efficiencies that our technology enhancements provide.

We continue to grow and deploy EDGE AutoPilot onto our active rigs across the globe with a 25% year-over-year growth rate. We continue to expand the Edge apps platform in each of the rigs that already have our EDGE AutoPilot DRC technology.

We have EDGE on about 50% of our rigs globally with lots of opportunity growth ahead. This high-tech component of our business continues to grow at a rapid pace year-over-year and with 100% efficacy with reduced well times and increased penetration rates with reduced tortuosity that helps differentiate Ensign from our competitors.

With that, I’ll move it over to the operator for questions.

Hey, good morning. Just curious if you can, Bob, maybe walk us through how you see the trajectory of your U.S.

rig count playing out through the year. Sounds like maybe there’s some optimism in some regions, but one of your large customers of course did announce some rig reductions in its own rig count recently as well.

So can you kind of just help us put those pieces together and help us get a sense of where you expect your U.S. rig count to play out through the year?

Sure. On the last note you made there, we are not expecting Ensign to have any rig reductions from that particular client at this point in time.

We do expect generally through the U.S. to probably come off two or three rigs as we go into the third quarter.

So you may think of it, Keith, as 37 going down to maybe 35-ish and then start building back up again into the fourth quarter. That’s some of the expectation right now.

Okay, very good. And then Mike, can you just give us some of the puts and takes or the moving pieces on the liquidity going through second quarter?

It sounds like you’ve got some healthy expectations for free cash flow generation in Q2, maybe to offset some of the term loan repayments. Just can you help us – help walk us through where some of those pieces sit today?

Yes, for sure. So in Q1, we saw a big reduction in accounts payable.

So that was a large use of the free cash flow in Q1, similar to what will happen in Q1 of 2024. So when you look at Q1, we had about $11 million of debt reduction in 2024.

We did about $23.2 million in Q1 of 2025. When we look into Q2, you’ll have the collections from the winter drilling season here in Canada starting to come through.

So we’ll follow a similar, I’d say, pathway as we did in 2024, with that build up happening in Q2, Q3 and Q4. We also have some redundant real estate that we continue to market.

So there’s a few different options on that. Our interest expense also is down probably $30 million plus from 2024.

Our full-year expense was around about $100 million, we’ll probably be around that $60 million to $65 million in interest expense for 2025. So there’s a few pickups that are going to be happening year-over-year that will help fill in some of the gaps if there is an operational decrease.

Okay. Appreciate the comments.

Thank you very much.

Thanks, Keith.

Thank you for taking my question. Mike, could you quantify the impact on costs from these rig reactivations and deactivations in the U.S.?

We don’t get into particular detail. I mean, it probably hit our margins by 200, 300 bps.

So I mean the reactivated rigs probably mobilization, everything probably $0.5 million to potentially $1 million. So it was probably maybe $3 million to $5 million that would have hit in the quarter.

But we don’t expect to well, depending on rig activity to come again in the future quarters.

And then, Bob, if see pickup of a couple of rigs in Argentina through the course of the year, do you expect any CapEx impact or any OpEx impact from reactivations?

So in Argentina, we have two rigs and they’re both

I apologize. Australia, I meant to say.

Australia. Okay.

Yes, the rigs that we’ve got in Australia, of course, when we rack our rigs, we rack them with the intent that we’re probably not going to be back on for some period of time. That’s always the safe way to rack them.

But there’ll be some cost to reactivate. We typically put that into the contract as a part of the mob fee to reactivate the rig and get it ready for running.

So typically the operator will cover that cost. That would be the case we would expect in two that we expect to come here in the next quarter.

We’ve got some pretty good visibility on current contract bids.

Okay. And then in Venezuela, based on your current information by the end of May, the rig would be released, both rigs would be released?

Correct. That’s the current deadline that exists with OFAC today.

But as you know, that’s been extended many, many times in the past. We’ll see what happens, but that’s how we know today, Waqar.

Yes. And then we’re hearing from some of your – some of the E&Ps and also generally from some drilling contractors about pricing pressure in the U.S.

Could you maybe talk about that and if possible quantify that?

Yes, well, over the last few weeks, of course, there was a lot of noise about where the price of oil was and where it was headed, where it would stay down in the low-50s. And then today we see where it’s at again.

So we haven’t generally had to react with operators. Certainly we’re not raising our prices, Waqar, but I would say generally, we are holding on to rates and when they start asking us for more term, which they haven’t yet, they’re more.

Two weeks ago, the discussion is a lot different than it would be today, for example.

Sure. Okay.

Great. Thank you very much.

Thanks, Waqar.

Thanks for taking my call. Good morning, Bob and Mike.

First question, given the softness of the U.S. and the strengthening Canadian market, especially with LNG coming and of course the activity with oil because of TMX, do you see moving any of your best rigs that are not being active in the States to Canada?

Is there starting to be discussions where companies will talk about paying the mob cost to move rigs to Canada?

So good question. Yes, that type of discussion started about a year and a half ago where we moved some of our high spec singles up into Canada.

Interestingly, we did move one of our deeper high spec triple or 2,000 horsepower rig out of Canada down into the U.S. on long-term projects there.

So it goes back and forth. But I would say generally we have a product to fill the high spec triple market in Canada.

We’ve probably got four or five rigs that we could contract into that market or recontract at higher rates than current operators. The high spec single market for which we’re 100% utilized in, as I mentioned, we moved three from California over the last year into Canada and we’re just in the process of upgrading a current high spec single rig in Canada into a deeper capacity to almost 300,000 pounds.

So to summarize, yes, I’m not seeing any future movement. We don’t have any planned future movement in the cards between the U.S.

and Canada at this point in time.

Super. My next question is just maybe just a little bit of a learning exercise.

With what’s going on, of course, LNG Canada will be up and hopefully the first cargo goes in July. Are you seeing more activity in Northeast BC or more in Northwest Alberta in terms of activity and booking of rigs and all of that?

Is there a difference in terms of ramp up and percentage of business to you from either those two markets?

Yes, it’s stayed busy. We’re starting to see some discussion with a couple of operators into 2026, depending on the area they’re in.

I would say it’s not a fire sale or anything like that, it’s of demand, it’s basically slowly feeding into it. There’s lots of capacity up in the area from a well production point of view to fill the line.

But people are starting to get a little more active into it. But I think that that will start to be more heavily activated into 2026 and beyond.

Super. Thanks for answering my questions.

Thank you, operator. The last few months have certainly been a roller coaster with the global markets unsettled with the tariff negotiations.

Looking forward, it continues to be an exciting time for Ensign as we build on a strong first quarter with robust Canadian market share gains, but with near-term headwinds in the U.S. But as I pointed out before, we feel the macro for the U.S.

expects to get better into 2026. With roughly three quarters of a billion of forward revenue booked under contract, we expect to continue the steady rate of 100 to 110 Ensign drilling rigs and roughly 50 to 60 well servicing rigs operating daily both sides of the border.

One-third of our drilling rigs under contract are long-term contracts with contract tenure of almost a year and roughly 25% of those contracts are on a performance basis. With that, we have excellent visibility for sustained free cash flow with consistent margins, a very predictable CapEx plan, and expected redundant real estate disposal in 2025, all of which will provide the ability to continue executing on our debt reduction target of clipping off $200 million in 2025.

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, maintain our debt reduction targets into some short-term headwinds for the drilling and well servicing business globally.

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

Stay safe. Thank you.