Ensign Energy Services Inc

TSX:ESI

Q2-2025 Earnings Call

[Operator]

Good morning, ladies and gentlemen, and welcome to Ensign Energy Services, Inc. Second Quarter 2025 Results Conference Call. [Operator Instructions] This call is being recorded on Friday, August 8, 2025. I would now like to turn the conference over to Nicole Romanow, Investor Relations. Please go ahead.

[Nicole Romanow, executive]

Thank you, Ludy. Good morning, and welcome to Ensign Energy Services Second Quarter Conference Call and Webcast. On our call today, Bob Geddes, President and COO; and Mike Gray, Chief Financial Officer, will review Ensign's second 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 services supplied by the company. Additionally, our discussion today may refer to non-GAAP financial measures such as adjusted EBITDA. Please see our second 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.

[Robert Geddes, executive]

Thanks, Nicole. Good morning, everyone. The second quarter was a little bumpy as we witnessed a higher concentration of repairs and maintenance expense, specifically in our Canadian business unit as rigs came off their busy winter programs with work scheduled for right after breakup. In addition, we had a few rigs come down unexpectedly in Latin America due to OFAC sanctions, which negatively impacted the end of the second quarter. Generally, though, we continue to deliver through the second quarter, executing on key points. Those being we further reduced debt in the quarter, and we expect to deliver on the $600 million debt reduction we targeted by the end of 2025. We held a tight rein on maintenance CapEx through the quarter, aligning with the challenging macro environment.

We grew our market share in Canada by 3%, whilst industry was down 9%. We maintained market share in the U.S. in a market where industry activity dropped off 4%. At the very end of the second quarter, we transferred out of Canada, one of our largest rigs in ADR 3000 down into Wyoming for a major on long-term contract there. Our Middle East team successfully closed the deal for 2 additional ADRs in Oman with a major on a 5-year deal where the operator sponsored the upgrade and reactivation costs. We continue to expand our drilling technology solutions app penetration by 25% year-over-year, and we ended the quarter with our best safety performance in the company's history. Over to Mike for a financial summary of the second quarter. Over to you, Mike.

[Michael Gray, executive]

Thanks, Bob. Volatile oil prices and geopolitical events have reinforced producer capital discipline over the near term, impacting certain operating regions. However, despite these short-term headwinds, the outlook for oilfield services is relatively constructive and has supported steady activity in several other regions. Overall, operating days were slightly down in the second quarter of 2025 in comparisons to the second quarter of 2024. The company saw a 1% increase in the United States to 2,943 operating days and a 2% increase in Canada to 2,494 operating days. The offsetting the increase was a 14% decrease internationally to 1,081 operating days. For the first 6 months ended June 30, 2025, overall operating days declined with the United States recording a 5% decrease and international recording a 13% decrease in operating days.

Offsetting the decrease was a 5% increase in our Canadian operating days when compared to the same period in 2024. The company generated revenue of $372.4 million in the second quarter of 2025, a 5% decrease compared to revenue of $391.8 million generated in the second quarter of the prior year. For the 6 months ended June 30, 2025, the company generated revenue of $808.9 million, a 2% decrease compared to revenue of $823.1 million generated in the same period of 2024. Adjusted EBITDA for the second quarter of 2025 was $81.4 million, 19% lower than adjusted EBITDA of $100.2 million in the second quarter of 2024. Adjusted EBITDA for the first 6 months ended June 30, 2025, totaled $183.7 million, 16% lower than adjusted EBITDA of $217.7 million generated in the same period in 2024. The 2025 decrease in adjusted EBITDA was primarily a result of lower revenue rates and onetime expenses related to activating, deactivating and moving drilling rigs. Offsetting the decrease in adjusted EBITDA was a favorable foreign exchange translation on USD-denominated earnings.

Depreciation expense in the first 6 months of 2025 was $164.7 million, a decrease of 4% compared to $170.8 million in the first 6 months of 2024. General and administrative expenses in the second quarter of 2025 were 17% lower than the second quarter of 2024. G&A expenses decreased primarily as a result of nonrecurring expenses incurred in the prior year. Offsetting the decrease was annual wage increases and the negative translation of converting USD-denominated expenses. Interest expense decreased by 27% to $18.6 million from $25.5 million. The decrease is the result of lower debt levels and effective interest rates. During the second quarter of 2025, $19.7 million of debt was repaid and a total of $42.9 million was repaid during the first half of 2025. The company is on track to achieve its stated debt reduction target of $600 million from the period beginning 2023 to the end of 2025.

The remaining amount of debt to be repaid to achieve this target is $119.8 million. If industry conditions change, this target could be increased or decreased. Total debt net of cash has decreased $68.5 million during the first half of 2025 due to debt repayments and foreign exchange translation of converting USD-denominated debt. Net purchases of property and equipment for the second quarter of 2025 totaled $49.2 million, consisting of $13.3 million in upgrade capital and $37.4 million in maintenance capital, offset by dispositions proceeds of $1.5 million. Our 2025 maintenance CapEx budget is set at approximately $154 million and selective upgrade capital of $30.5 million, of which $19.0 million is customer funded. The increase in upgrade capital expenditures in 2025 is due to a recent awarded 5-year contract for 2 rigs in the company's Oman operating region as well as a rig being relocated from Canada to the United States. On that note, I'll pass the call back to Bob.

[Robert Geddes, executive]

Thanks, Mike. So I'll start with an operational update. As mentioned earlier, we have seen a slow climb out of the Canadian breakup as a result of the heavy rains. Globally today, we sit with 95 drill rigs and 34 well servicing rigs active. We will be increasing rig count of rig a week globally through into fourth quarter and expect to hit roughly 105 drill rigs by the end of the year. In our well servicing group, we expect to see an increase in our rig count there from 45 currently to 55 well service rigs by year-end. Let's focus specifically on Canada for a moment. Our Canadian drilling team, which operates a high-spec fleet of 86 rigs continues to gain market share quarter-over-quarter and year-over-year with a 3% increase in market share, again, while industry saw a 9% drop.

We hit a peak of 55 rigs in the first quarter and peaked at 34 rigs over breakup, a 50% increase over breakup from last year. And today, we sit having exited breakup with 48 active today with contract visibility to 50-plus in the third quarter. Over breakup, we had 5 of our ADR high-spec super singles, which are fully booked in the shop for repairs and recertification, which pushed the R&M expense up for the quarter, as I mentioned before. We typically don't see that many ADRs coming into the shop at once, but because they all have immediate work to go to, it was urgent that they'd be cycled through the shop quickly while breakup was upon us. Over breakup, we also upgraded a couple of our high-spec super single ADRs to higher capacity units and tied them up on 2-year contracts to feed the very active Clearwater and Mannville play. We're also seeing operators already contract their preferred rigs out up to 2 years into spring of 2027 with rates in the high 30s. Those would be the high-spec triples, of course.

Our fleet of roughly 20 high-spec triples in Canada are expected to be fully booked through the winter of 2026, and we have roughly 95% of the high-spec single fleet booked through into the second quarter of 2026 with some contracts taking us into 2027. The high-spec single ADR market has really tightened up for us. We have a few more idle ADRs that can be upgraded to fill into this need. Of course, we continue to look for multiyear contracts and rates on those rigs into the mid- to high 20s all in. Notwithstanding, day rates remain well below any new build metrics, rates need to be in the 50s, high 50s before we will see new build super-spec triples. And for the high-spec singles and high-spec doubles, rates need to be in the very high 30s before investment could be made in new builds with a reasonable rate of return.

We're also seeing continual growing interest in our Edge Autopilot in our Canadian business unit with specific apps such as the automated drill system, which we call the ADS, which charges out at $1,000 a day and soon our AutoDriller Max, which provides higher penetration rate increases, will be finished its beta testing in the U.S. and is about to start beta testing in Canada next month. That provides upside of about a $1,500 a day margin at the rig level. Our well servicing business in Canada, which operates a fleet of 41 well service rigs, including slant rigs and an automated well service rig, which we call our ASR, had an active breakup with roughly 11 rigs operating. The OWA work is starting to get going again, which will provide visibility to 19 well servicing rigs running at the end of the third quarter.

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 high torque tubulars to attach to our high-spec ADR drilling rigs. Moving to international. We have a fleet of 26 drill rigs that operate in 6 different countries around the globe, of which 11 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 PBI contracts now, 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. We have 3 rigs currently active on our long-term -- on long-term contracts in Oman. As pointed out earlier, our Middle East team successfully negotiated a 5-year contract with a major to reactivate and upgrade 2 of our ADRs in the country.

The first of these 2 rigs should get on the payroll in December with the second not far behind in January 2026. In Argentina, we had 1 of our 2 rigs come down right at the beginning of the third quarter for some unplanned repairs, and we fully anticipate that rig to be back up and running in mid-September. We see a building market for our high-spec 2,000 horsepower rigs in this area. We had 2 rigs active in Venezuela through most of the second quarter, only to see OFAC shut everything down on May 27. There were some costs that hit the second quarter related to the shutdown along with the loss of a month of revenue on the 2 rigs, which negatively impacted second quarter results. We are awaiting instructions from our client as to the current OFAC directive, which suggests relief and startup potentially in mid-September, we'll wait and see what transpires.

Australia seems to be stuck in neutral as we currently still only have 4 of our 13 rigs in the country active today. We have a line of sight on 1, possibly 2 going back to work early fourth quarter. Moving to the United States. We have a fleet of 72 high-spec ADRs in the U.S., stretching from the California market into the Rockies and main focus back down in the Permian. We have held market share through the second quarter and sit at, give or take, 7% today, while industry fell off -- I'm sorry, 4% in the quarter. We are sitting at 37 rigs today active, and we are expecting to add a few rigs to this count between now and the end of the year. It's interesting to start hearing from operators that the geologic headwinds are stronger than the tailwinds from technology and operational efficiency gains over the last 5 years.

When we look at the generally flat production output of the U.S. over the last few years and the flattish rig count and low DUC 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 PBI contract base and now has over half the fleet on a PBI contract to 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 Edge Autopilot technology, we capture the upside value generated to the operator through performance metrics. Everybody wins. The operator delivers wellbores for lower cost, and we help derisk that with our PBI contract form at higher margins.

Our U.S. business unit -- our well servicing business unit specifically, is focused primarily on the Rockies in California well servicing market, and they continue to enjoy high utilization north of 70% and they delivered a quarter slightly below expectations due to temporarily reduced activity in those areas, although we are seeing some signs of positive activity growth in California, if one can imagine that. 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 and the longest runs in the Rockies. We're expecting another solid year in that business unit. Going to our technology suite, our Edge AutoPilot drilling rig control system. In our last call, we reported that we successfully beta tested our Ensign Edge ATC auto tool phase control in conjunction with a 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 DTS systems.

I'm happy to report that we're now commercial with our Edge ATC and are charging that on 4 rigs today with the possibility of placing that on a fifth rig for the same operator. We also continued the beta testing of our enhanced auto driller called the AutoDriller MAX, which will further increase P rates and will be charged with a base daily rate of $1,000 a day plus a variable per meter or per foot cost so that we can start capturing the upside on 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. This high-tech component of our business continues to grow at a rapid pace and with 100% efficacy with reduced well times and increased P rates, it helps differentiate Ensign from our competitors. With that, I'll turn it back to the operator for questions.

[Operator]

[Operator Instructions] And your first question comes from the line of Aaron MacNeil with TD Cowen.

[Aaron MacNeil, analyst]

I noticed that many of the contracts currently in portfolio are shorter duration in nature, which I'm sure is also typical of your peers. And I just wanted to focus on the U.S. market. Can you speak to contract churn pricing dynamics and ultimately, what your strategy is here in terms of whether you're prioritizing price or utilization?

[Robert Geddes, executive]

Right. So it's -- yes, we've got kind of a couple of dynamics happening globally. We increased our forward contract book by approximately $250 million over our last call. So we now have close to $1 billion of forward revenue booked under contract. Now we break that down into segments to your question specifically on the U.S., I would suggest that the U.S. is probably engaged more in 6-month contracts, which is fine. We start to see when operators in trough start to ask for longer-term contracts, that's when we start to sense that they feel that the market has troughed out.

We're starting to get to the edge of that. We're probably maybe a few months away from that firming up a little bit more. But generally, most of our contracts we've been able to hang on and gain market share again, while industry has dropped by going and doing 1 or 2 wells for different people. So our client base has expanded. We've also expanded our rig count with a couple of majors as well on top of that. But I would say the macro in the U.S. is still a very competitive market, but it feels like we're not having to drop the price like we had in the first half of the year, Aaron.

[Aaron MacNeil, analyst]

Okay. Makes sense. And then maybe one for Mike. Do you see any issues as it relates to your sort of regular cadence of step-downs on the credit facility? Or are you sort of happy with the progression there? And is debt reduction still the target once you hit your $600 million goal?

[Michael Gray, executive]

Yes. The cadence we're quite happy with. I mean we've made the adjustment back in Q1 to push the -- step-downs into Q3 and Q4 as well. So we're happy with how that's progressing. As to what happens after our $600 million target, I think we'll continue to deleverage. I mean, our debt-to-EBITDA ratio is getting better and better and should be sub-2 in 2026. So we'll continue to continue to deleverage. We look at opportunities to deploy capital in the industry right now. The best deployment is probably towards the balance sheet as we see it right now. So we'll continue focusing on that.

[Operator]

Your next question comes from the line of Keith MacKey with RBC.

[Keith MacKey, analyst]

Bob, can you just take us around some of the international regions a little bit more? I know that you added a couple of contracts in Oman, but there certainly are some areas where your rigs, I would say, are underutilized. Can you just talk through what you're seeing over the next 6 months in terms of tendering and potential activity that might get the regions to be a little bit more normalized? Or do you think that there certainly are some areas that will just do better than others over the next 6 to 12 months?

[Robert Geddes, executive]

Yes. Yes. Well, let's start with Argentina. As I mentioned, we had some unplanned repairs on a rig there that shut us down for a few months back up and running here mid-September. So you'll see that with some talk of a third rig perhaps coming into that area in 2026. Venezuela is -- I can only talk to what we know today because that may change tomorrow. So that's plus or minus 2 rigs. When the rigs are running, we make good money. When the rigs are not running, we have a few costs. We go down to a minimal skeleton crew there to keep things going. But shifting into the Middle East, Bahrain, we have 1 of the 2 rigs down. It's being bid out to a couple of places right now in the Middle East with probably high success rate that, that rig goes back to work in the fourth quarter.

Oman, we touched on -- all of our rigs in Oman are currently busy, and we're adding 2 more, and that was operator-funded upgrades and a 5-year contract generating over $120 million of revenue over its term. Australia is a challenge. Australia is -- seems to have some overcapacity. And although the bid activity was a little rapid in the last quarter, it seems to have settled off again, a lot of tire kicking. But Australia is our focus area for improvement for sure.

[Keith MacKey, analyst]

Got it.

[Robert Geddes, executive]

And Kuwait -- yes, just to finish the lap, Kuwait is -- we've got our 2 rigs recontracted into well into '26 and talk of that going even further. So Kuwait is -- those 2 big rigs are just cranking along.

[Keith MacKey, analyst]

Yes. Got it. Got it. And you touched on it a little bit in the last question, I think, but your U.S. outlook is relatively, I would say, constructive for the back half of the year with rig count increasing. We certainly are seeing a bit of divergence amongst operators in terms of rig counts in the next couple of quarters. Can you just talk about what's driving your expectations to increase your U.S. rig count over the next -- over the back half of the year?

[Robert Geddes, executive]

Yes. We've got a couple of increases with a couple of our major accounts. We're finding that operators are continuing to take the opportunity to high-grade their fleet. You probably saw the Enverus report that of the 25 top rigs in all of the United States, Ensign has 12 of the top 25. So we get swept into that benefit. We're also seeing California. Newsom has suggested that if you cap a couple of wells, you can go drill a well. That will help us on both well servicing and the drilling side as well. And so we're already starting to see some chatter of increased activity there.

So we think we'll be adding a couple of rigs between now and the end of the year in our California business unit as well. Plus, as we mentioned, we're seeing Wyoming get busy for the big rigs. These are 3,000 horsepower rigs. We transferred one from Canada which have been down over 5 years down to the U.S. I don't think there's going to be a rapid migration. First of all, that was the biggest rig in Canada. There's not very many of those types of rigs. And those are $60-plus million rigs to go build. So that's the -- that kind of manifests itself into the comment where we see us building up 1 or 2 rigs through -- from now to the end of the year.

[Operator]

And your next question comes from the line of Waqar Syed with ATB Capital Markets.

[Waqar Syed, analyst]

Bob or Mike, you mentioned that the margins were impacted in Q2 because of some repairs and maintenance costs. Is there a way to quantify the impact, the cost impact on margins?

[Michael Gray, executive]

It's probably, I mean, 200 bps maybe. If you look at Q1, our margins were about 23.45%. We're sitting at 21.84%. So yes, I'd probably say around 200 bps.

[Waqar Syed, analyst]

Okay. So you expect them to go back to that 23% to 24% kind of level in Q3?

[Michael Gray, executive]

Yes, as activity starts to pick up, we believe that's where they should be probably headed towards.

[Waqar Syed, analyst]

Okay. That's right. Sounds good. And then Bob, on the drilling rig pricing side, day rate side, are you seeing stability? And then for your own fleet, do you see that this big 3,000-horsepower rig once it starts working, does it move the needle on average day rates for the U.S.? Or is it just on the margin, some positive impact?

[Robert Geddes, executive]

Yes. I think that 3,000 horsepower rig is maybe perhaps a little unique because of its rig type. And the answer lies in the rig types. The super-spec triples that can rack 30,000 feet of pipe are generally hanging on to prices -- and we're in -- all in, we're in the low 30s. In Canada, same situation. The high-spec triples were quickly running out of them into the winter of 2026. And we're -- we've got a couple of clients going after like 1 rig. So pricing opportunity there. We're in the mid-30s all-in easily with those. And now we're starting to look for term. This is what we just started introducing in the last couple of weeks is an operator group that are willing to accept that conversation as well. So the high-spec triples, yes, I would say stable pricing in the U.S.

In Canada, I would say, stable to slightly upward pricing. On the high-spec singles, same situation in Canada. Of course, the high-spec singles in the U.S. aren't as a dynamic rig type demand as it is in Canada. In Canada, we're basically sold out of our high-spec singles. They're in the low to mid-20s and we've got a couple of more rigs that what we basically call our idle rigs that have been cold stacked that are part of our active fleet that can be upgraded for not a lot of capital, and we'd be looking for the operator to either fund that or to give us a longer-term contract where we see payout of our capital within a year, again, being conscious of our debt reduction targets continuing into the future.

And that's continuing to be our goal. Hold maintenance CapEx and growth CapEx, of course, we look to be funded by the operator or paid for within 1 year of EBITDA. That's kind of the margin order. On doubles, of course, we don't have that many in the U.S. We've got a few singles, conventional singles in California that still work, and they still generate positive EBITDA quite nicely in Canada. The conventional doubles and conventional singles are a very, very competitive market. There are some smaller players that are trying to hang on to business, but that's a very small part of our EBITDA proportion in Canada. And then the rest of the world, I can touch on that if you want, but I think you know the metrics there.

[Waqar Syed, analyst]

That makes sense. Just on the Canadian market with this Canada LNG now up and running, that creates some incremental demand for natural gas. But on the other hand, storage is pretty full in Canada for natural gas. When do you see the project -- the start-up of the project having an impact on activity of natural gas drilling activity?

[Robert Geddes, executive]

Yes. Good question. I think that -- I mean, gas is a very scalable product in the area that we drill. I mean they know what they can get out of every well that they want to add it, they add it to your point, there's some backup there. But I think the bigger question is when does the second pipeline come? And that would be at least 3 years out. I see the demand starting maybe in '27 for that type of construct for LNG. I'm seeing our demand on high-spec triples in 2026 and through the rest of 2026 as not being directly related to that comment you made about LNG growth, yes. I see that's further down the road.

[Operator]

[Operator Instructions] Your next question comes from the line of John Gibson with BMO Capital Markets.

[John Gibson, analyst]

Just had one on the debt repayment here. Obviously, you've done a really good job of meeting your targets over the past few years, but the cadence of repayment appears to have slowed here in the first half of the year. I'm just wondering, maybe can you walk through some of the puts and takes to get you to that $600 million number by year-end, just as we're thinking about the back half of the year?

[Michael Gray, executive]

Yes. So it's about $120 million left of that goal to be achieved. We have about $105 million of mandatory repayments with the term loan as well as the step down. So when we look at activity, working capital and sort of the additional factors on the balance sheet, we're confident with that step down and with that target. So yes, like I said, things could change drastically. I mean, if the industry $50 oil hits us and something like that in Q3, Q4, I mean, that target could definitely be down a little bit. But from what we see right now, we're confident. Interest expense, I mean it continues to decline. So we're running about $18 million a quarter, which was down from $20 million in Q1, down from $25 million in Q2 of 2024. So if the operations do decline a bit, we do have a bit of a pickup just with the interest rate reductions that we've seen as well as the debt reductions over the last couple of years have helped generate some free cash flow.

[Operator]

And I'm showing no further questions at this time. I would like to turn it back to Bob Geddes, President and COO, for closing remarks.

[Robert Geddes, executive]

Thanks for joining the call this morning. Let me just close off by saying the last few months have been a roller coaster with the global markets unsettled with tariff negotiations. Looking forward, we continue to execute the plan of reducing debt whilst delivering the highest performing operations safely around the world. We increased our forward contract book by roughly $250 million and now have close to $1 billion of forward revenue booked under contract. With that, we expect to continue the steady run rate of 100 to 105 Ensign drill rigs and roughly 50 to 55 well service rigs operating daily both sides of the border. 1/3 of our drill rigs under contract are on long-term contracts with contract tenure of about 1 year and roughly 30% of those contracts are on a performance-based contract base.

With that, we have excellent visibility for sustained free cash flow with consistent margins, a very predictable maintenance CapEx plan and expected redundant real estate disposals in 2025, all of which will provide the ability to continue executing on our debt reduction plan of clipping off $600 million over the 3-year period ending 2025. Again, the focus continues to be maintain our debt reduction goals 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 in the field, along with our customers for helping Ensign achieve the performance and industry-leading milestones that industry recognize us for. Look forward to our next call in 3 months' time. Stay safe.

[Operator]

Thank you, presenters. And ladies and gentlemen, this concludes today's conference call. Thank you all for attending. You may now disconnect.