Ensign Energy Services Inc. ($ESI)

Good afternoon, ladies and gentlemen, and welcome to the Ensign Energy Services Inc. First Quarter 2026 Results Conference Call. [Operator Instructions] This call is being recorded on Thursday, May 7, 2026. I would now like to turn the conference over to Michael Gray, Chief Financial Officer. Please go ahead.

Thank you. Yes, just to clarify, former Chief Financial Officer. But, thank you, and good morning, and welcome to Ensign Energy Services First Quarter Conference Call and Webcast. On our call today, Bob Geddes, President and COO; Trevor Russell, new Chief Financial Officer; and myself, Mike Gray. Today, we will review Ensign's first quarter highlights, financial results, followed by operational update and outlook. We will then open the call for questions after that. Our discussion today may include forward-looking statements based upon current expectations and involve several business risks and uncertainties. The factors that could cause results to differ materially include, but are not limited to, political and 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 first quarter earnings release and SEDAR+ filings for more information on forward-looking statements and the company's use of non-GAAP financial measures. Before I pass the call back over to Bob, I'd like to take a moment to sincerely thank all of Ensign's employees for their hard work and dedication. I truly appreciated my time here and the opportunity to work along such a strong team. I'm confident that the company is in very good hands going forward under Trevor's leadership. On that, I'll pass the call back to Bob.

Thanks, Mike. Let me start by acknowledging that Mike Gray is retiring, as you understand here, and we have appointed Trevor Russell into the CFO role. I just want to, first of all, thank Mike for his guidance and service with Ensign over the last years on behalf of the Board of Directors, myself and all employees. Mike has helped the company manage through some intense Trinidad acquisition, the Nabors acquisition, the COVID years, et cetera. Thank you, Mike, for all of that. I also want to congratulate Trevor on his promotion to the CFO role. Trevor has been with the company for 20 years and was the last in the role of VP Finance. Mr. Russell will provide a seamless transition for us moving forward. Also, Mike Gray has agreed to stay on as an executive adviser until July to help through the transition period. So we've had 2 significant events in the first quarter that have provided a very positive construct for Ensign. Right out of the gate in 2026, we saw Venezuela become derisked to a large extent with a strong proxy for increased activity. With Ensign having the only rigs operating in Venezuela, we are well positioned to expand our business unit. And then we have the Middle East conflict, which has pushed oil prices up significantly. Today, we are bumping in the low 90s. If anyone had told me WTI would be in the low 90s a few months ago, we would have been critical as such a prediction. Let's just hope the demand stays somewhat inelastic anyway, here we are. So for a deeper dive into the first quarter financial results, I'll turn the call over to Trevor Russell. Trevor?

Thanks, Bob. The oilfield services sector maintains a generally constructive outlook despite a year-over-year activity decline in Canada. With the political and security situation in the Middle East, the disruption of shipping within the Strait of Hormuz, and the continuing conflict between the Russian Federation and Ukraine and the recent actions of the United States in Venezuela, the expectation is these factors and their continued development will have a direct impact on the industry. To date, oil and natural gas producers continue to moderate their capital spend, remain committed to cash flow generation and maintaining current production levels. Furthermore, the impact of uncertainty around the global economy and tariff policies adopted by the United States administration and the implications from such policies continue to impact operating activity. Total operating days were slightly lower in the first quarter of 2026 with the United States and International operations, recording of 15% and a 1% increase, respectively. While our Canadian operations saw a 15% decrease compared to the first quarter of 2025. The company generated revenue of $418 million in the first quarter of 2026, a 4% decrease compared to the revenue of $436.5 million generated in the first quarter of the prior year. Adjusted EBITDA for the first quarter of 2026 was $94.8 million, a 7% decrease from the adjusted EBITDA of $102.4 million in the first quarter of 2025. The decrease in adjusted EBITDA was primarily due to a decrease in the operating activity as well as a negative 4% translation difference of converting our U.S. dollar-denominated earnings. Depreciation in the first 3 months of 2026 was $85.1 million, 4% higher than the $81.9 million for the first 3 months of 2025. The increase in depreciation is due to more assets entering services following additional capital spending. Offsetting the decrease is a 4% decrease in the translation effect of converting our depreciation on U.S. denominated assets. General and administration expenses was $14.7 million, 3.5% of revenue for the first quarter of 2026, compared to 15% (sic) [ $15 million ], up for the first quarter of 2025. General and administration expenses decreased due to nonrecurring fees incurred in the prior year and a positive 4% translation effects of converting our U.S.-denominated expenses. Net capital purchases for the quarter were $64.8 million. The purchases consist of $14.4 million in upgrade capital and $50.9 million in maintenance capital for a total of $65.3 million, offset by sales proceeds of $600,000. Our 2026 maintenance capital budget is set at $162 million and $79.2 million in selective upgrade capital, of which $58.2 million is customer funded and will be monitored very closely and will be adjusted if required. Interest expense in the first quarter of 2026 was $12.9 million, a decrease of 37% from the first quarter of 2025 as a result of lower debt levels and effective interest rates, a onetime recovery and a positive 4% translation on converting U.S.-denominated interest expense. The company expects its blended interest rate to be less than 7% and will allow us to reduce our interest expense going forward. Net repayments against debt totaled $7 million during the quarter. Our trailing 12 months net debt adjusted EBITDA was 2.47 and will continue to reduce as the company continues to reduce debt. Our debt reduction for 2026 is targeted to be approximately $125 million. If industry changes -- if the industry conditions change, this target will be increased or decreased. On that note, I'll turn it back to Bob.

Thanks, Trevor. So let's circle the globe now with a summary of our first quarter and some insight operations and what we're seeing develop under the strong commodity price environment. Starting with U.S. drilling which is our biggest revenue and margin generator. Today, we have 45 rigs in the contract in the U.S. We are seeing a more active bid book over the last months developed, obviously, the result of generous commodity prices. We are seeing more private equity, [indiscernible] new rights that are at these prices, a lot more shoulder players become more compelling. Starting on the West Coast, we were seeing our California drilling asset base, now up to 8 high-spec ADR drilling rigs under contract and the business looks very steady moving forward. We have 8 rigs active in the Rockies division and 29 in our U.S. Southern division, mostly in the Permian. The Permian continues to be extremely active for our high-spec ADR rigs with an expectation that we should see 2 to 3 more rigs going go to work over the next 6 months. Almost half our U.S. rigs are on a performance-based contracts, which elevates margin opportunities. Going to Canada, we operate a wide range fleet of 76 high-spec ADR drill rigs in Canada. In the first quarter, we saw 5 of our rigs come down early in the quarter for the 5-year recertifications, which were planned for breakup but because the operator wanted to get back to the drilling during breakup, we had to take these rigs off the production line in the first quarter and get them in for the recertification. This, of course, affected the first quarter results. So we had a lumpy first quarter, which we'll see push into a beneficial uptick in our second quarter activity. Last year, we had 30 rigs active breakup opening up to 43 of July. This year, we expect to have those 5 rigs incrementally added year-over-year, and will see us build up from 30 rigs today to 50 by late summer. This is a 7-rig year-over-year uptick in the second quarter and entering into the third quarter, which we expect will stay sticky at 50 plus through the rest of the year. We have 2 cold stacked rigs coming back to work after breakup, and we have 3 rigs receiving operator requests and upgrades, which are tied into 2-year contracts. We are already seeing operators want to tie up in the spring 2027. That's a leading indicator for business getting busier. We are now wanting to get our book not too long as we see upward demand construct, and we will start raising rates about 5% to 10% as we move into the back half of the year. On the international front, we ended with 25 rigs in our international fleet. We have 9 rigs, of which 8 are under contract in the Middle East. All our rigs in the Middle East. We're kept on contract with the revenue rate. Some on standby rig crews, but in any case, we're making revenue during the conflict. Cost to run crews and parts, while the conflict is on has pushed some additional expenses our way, which are clipping margins, obviously. We added in a rig in Oman in the quarter, and we'll have another one on the payroll on the long-term contract in the second quarter. We had hoped to have that with the Oman commissioned in the first quarter, but the Middle East conflict created some challenges. Nonetheless, it is up and running today. In Australia, we have 5 rigs operating and expect to add a sixth and seventh in the back half of the year. Argentina is steady with both our high-spec ADR 2000s under contract and contract expansions underway. Venezuela, let's talk about Venezuela. Everything changed in January 6. Ensign has the only 2 drilling rigs running in the country, and we expect to add a third rig before year-end. Infrastructure buildup will determine how fast Venezuela is able to add rigs efficiently. We feel it will be into 2027 before it catches traction. In any case, our strategic positioning in the country over the last 25 years will provide great opportunities for the company moving forward. Well servicing. We operate a fleet of roughly 92 well servicing rigs in North America, split mostly in the U.S., 2/3 U.S., 1/3 Canada. To drive better focus on the well servicing assets, we incorporated all our assets under the responsibility of one focused Vice President -- well servicing VP, Mr. Pat Kearley. Pat is solely now responsible for all the well servicing assets. This focus will help drive growth in this business segment for Ensign. The EDGE drilling rig automation, our EDGE drilling rig control system platform is now on 65% of our rigs globally, generating revenue anywhere from $650 a day to $2,600 a day. We continue to see the opportunity to grow this business top line and bottom line by 15% year-over-year well into the future. We're also beta testing our Directional Guidance System, DGS, which with the help of AI, the team were able to deliver a beta test ready product in months versus years at 1/10 the cost. Our other business segments, directional drilling and MPD are delivering consistent steady revenue and margin. So I'll turn it back to the operator for questions.

[Operator Instructions] Your first question comes from Aaron MacNeil with TD Cowen.

Before I get into that, Mike, just wishing you all the best. It's been an absolute pleasure working with you over the years. And Trevor, I wouldn't take the share price performance today as your first day as CFO personally. So looking forward to working with you going forward.

Thanks very much.

Bob, on the Venezuela rig add, can you give us any additional insights on the upgrade? Is it in country? What type of rig is it? What kind of work does it require. And then you mentioned 2027 before we likely get more. But bigger picture, what do you think is sort of the potential quantum of rig adds beyond the current 3?

Yes. So to unpack that, it's a lighter version of a high-spec ADR 1500 currently in the U.S. that's getting specific upgrades and recertifications for the Venezuela market because we've been operating there for so long, we've got a pretty good idea of what's required. But the rig will be down there forever. We expect -- well, that we have a long-term contract with the rig and operator on the CapEx upgrades that they specifically requested, which will help to drive a little bit of efficiency in their well planning into the future. As far as infrastructure, this is a challenge, I think, that the whole Venezuela is, everyone wants to turn on the tap tomorrow, but there's a lot of these infrastructure issues, building locations, getting service and products. We've got a great field -- professional field crew presence, and they're all Venezuelans and they're highly trained. We're able to add kind of a rig at a time. So I think it develops slower than everyone thinks, but it will develop positively upward for sure. And we've got the capacity to add more rigs into that market as it needs to be.

Okay. And then I just wanted to make sure I heard this right, but I think you mentioned the potential for 2 to 3 rig adds in the U.S. Is that based on contracts in hand today? And then one of your largest U.S. customers has said, I think last week earlier this week that they may return to a higher spending and growth rate going forward. So is there the potential for something incremental to that if the strong commodity price persists?

Yes. That's the story. We're adding 2 to 3 -- these are contracted into the near-term future, that's what those are talking to. We can tie those 2 comments together.

Your next question comes from Parvin Mamedov with Equinox.

Congrats on the results. I had 2 questions. First one was more high level your expectations of the rig market? And when do you think it changes the dynamics for you. So far, it seems like -- and you noticed this in your release, too, in North America, the rig count hasn't moved significantly in response to prices. Do you think it takes another quarter or 2 quarters of high oil prices to push it higher? Or what is your internal expectation?

So what -- that's a very good question and a question we've been putting to our client base. Of course, the consistent response we're getting back is we'll take a quarter of these nice prices. And once we get past the second quarter, we'll start to expand drilling to pick up on that. That's why you're also seeing private equity slide in where they're putting together some management teams and going after areas where the cost base entry level may have been around $60 a barrel. And so when the oil is in the 60s, it attract capital. Now it's attracting capital, and we're seeing a lot of private equity names we haven't seen before, put together teams and call us and ask us for rigs and rig activity. Rig activity, of course, the desirable rigs will see several rig drillings fully booked. The operators who have them now are hanging on to them. A couple of our operators have told us they want to add 1 to 2 rigs in the back half of the year. But everyone is waiting for your question for a second quarter under the belt of these prices before they start to move with any prediction.

Got it. And my next question is, I guess, your CapEx behavior in response to this. Q1 was almost more than 30% of, I think, total annual CapEx already spent. Is this partially because you expect higher activities in the second half of the year and you're already spending now? Or this just happened to be so .

Yes. A combination of both. We've had a lot of customer-funded CapEx where they wanted to make upgrades to the rigs. Oman is a perfect example where we had a couple of rigs in the first quarter. One that pushed into the second quarter because of the delay in commissioning because of the situation in the Middle East. But generally, you're seeing a little bit of an acceleration of capital. Most -- at least half of that is operated fund capital, which will push into work starting in the second half of '26. So it's not to suggest that there's any difference in our run rate. Our maintenance CapEx, is right on schedule with the number of rigs we have running. But as you add rigs, you have to recertify, reactivate and put them to work. And in most cases, we're able to get the operator to fund that and/or changes the request and also tie in our term contracts. And we're careful to tie in term contracts not to get too long because we see a situation developing where 5% to 10% increases through the back half of '26 will happen into '27 because available rig equipment is starting to tie up. I think you just can't get it. And if you need new pumps, you can't go buy an option anymore, you have to order them. And you're almost a year out now. So everything is starting to tighten up, which is a great construct for starting to get the value that we've created over the last decade back to the drilling contract.

One quick last one for me on Canadian activity. It seems like your peers have gained market share in Canada? What do you attribute that to?

So capital investment, basically company invested more capital into Canada specifically, where we've been deploying capital focus into other areas of the world, the U.S. and the Middle East where we get a higher margin.

Your next question comes from Josef Schachter with Schachter Energy Research.

Mike, congratulations, and good luck with your career and go-forward life intentions. Two questions for me. Bob, with all the problems going on in the Middle East, did you guys pull back on and get your crews away when the fighting was on? And if there is no peace deal in the next week or 2, they go back to fighting, what do you do in the field? Do you stop drilling? Do you bring your crews out? How do you handle the safety of your employees when the craziness goes on there?

Yes, fair question. I get a report every day and the team is on top of this every day. Safety of the crews is most important, of course. It's interesting if you watch the news, you will see occasional fireworks in the skies every night. But the Bahrain operation is the most affected. Oman, not really. Kuwait, not as much either. So we run a lot of crews in camps. And of course, we're on top of it, moving crews in and out. We've had to bring them in other ways through land rather than fly them in. Obviously -- we described Middle East as the most stable part of the world and then everything changed. But we've operated in difficult places of the world. We were in Libya when it went through its conflict. So we're pretty street smart. We've got great teams. But to your point, the safety of the crews is always first, always first.

Okay. Second one, Venezuela. The last Baker Hughes International rig count showed there were 4 rigs in the country. So 2 of the 4 were yours. And production has gone up. I think Energy Secretary there said they were 1.2 million barrels a day, up from the 800. How much upside is there? He's throwing a number of 1.5 million by the end of the year. Is that possible? And do they have enough rigs and equipment and the whole infrastructure to raise production that quickly? And where do you see potential production in the next 2 to 3 years? And then how much more activity does that do for Ensign?

Well, Venezuela. We've been there [indiscernible]. They used to produce 3 million barrels a day. They're around 800, and numbers you mentioned are reasonably accurate. That is coming through a lot of working with the wells that were shut in, getting current infrastructure going. That's where the efforts are. I think that behind that starts to come the drilling, and that will start in the back half of '26 and into '27. So everyone's efforts are spent just getting wells completed or not completed reserviced, well service, back on production, getting infrastructure going, changing valves, fixing leaks, all of that, getting things up and running. That will take them from the 800 to 1.2. To get up to 1.5 by the end of the year, they're going to have to start to do some drilling. To get to the 3, they're absolutely going to have to do some drilling. And it's anyone's guess, you can extrapolate how many rigs you think are going to be required to get there. But it's going to be a bunch. And Venezuela is a challenging area to work in. Again, we've been working there for a long time. 95% of our people there are Venezuelans. So we've got a great infrastructure to lever off of. As I mentioned, we'll be adding a third rig into the back half of 2026. And we've got capacity to add rigs as they are required into the country. So it will move up. It's been derisked. So far, everything is looking very nice.

Super. Is the pricing of the rigs because of the political risk, et cetera, et cetera, that are you getting higher margins on those Venezuelan rigs than other parts of your international business?

It's all relative. And it's all relative -- generally because of crew-based costs. So the margins in Venezuela are very close to what we've been getting in the [ Middle East ].

Next question comes from Keith MacKey with RBC.

Bob, I just want to pick up on the comment you made about your capital deployment strategy. Maybe some of your peers are a little bit more focused on Canada and you've got a bit more focus in other parts of the world. Can you just comment on the returns you're seeing in some of these other regions. And what underpins your long-term strategy of whether it's U.S., Middle East, Latin America, et cetera, beyond just Canada? Is it the level of resource available? Is it geopolitical factors? Just a little bit more color there would be appreciated.

Well, first and foremost, we want to stay focused on debt reduction. As Trevor pointed out, $125 million is our target for 2026. When we're having conversations about rig upgrades and movement of rigs for our clients, we have that in our background. Because we operate in different countries, we've got pools for capital in different ways. The U.S. has been absorbing a lot of our capital input over the last 3 to 4 years. The Middle East, specifically Oman, the last 2 years and Canada, we're just starting to focus back into Canada. We've got 5 rigs, 2 of those 5 are cold stacked are being reactivated. The go to work here right after breakup. So we're starting to focus back on to the high-spec singles, which were sold out of in Canada and high-spec triple upgrades and with [indiscernible] packages, things like that. But we've got a good runway of projects for capital in Canada, for example, that are paying for themselves in a year or less, with the incremental margin that we're making. So again, we put capital where it provides us the best return. And now you're starting to see us focus back into Canada. So our goal is to get to 25% market share. That's what we used to own in Canada. We grew our market share in the U.S., and we're holding on to that significantly. Our market share in Oman has grown et cetera. So that's the strategy we're deploying.

Got it. Appreciate the color. Just on the debt reduction target, so $125 million targeted for this year. I'm not mistaken, it is quite possible that I am, but that would take you beyond the initial $600 million that you had planned to do from 2023 to 2025. Can you just comment on what you think the right amount of debt is or even if it's an amount of debt versus an amount of liquidity is for the company? And then ultimately, what portion of free cash flow do you think that $125 million will represent? I'm guessing substantially all, but is there also some, say, dispositions or potential small dispositions built into that target?

Yes. Trevor, do you want to take that one on?

Sure. Yes. So starts with our $600 million debt reduction target that we announced a while back from 2023 to 2026 first half, we should hit that target. We're on target for that now to complete that. The target for this year is $125 million debt reduction. We feel with the cash flow that we're generating that, that will be an achievable target. There is some excess room in our free cash flow to cover some more on that. But with our CapEx commitments and plans, we are leaving a little bit left over to make sure we hit that. So we're comfortable with the $125 million, and it remains our focus to hit that target. Overall debt ratio, I mean we're probably at that like 2, 2.25, 2.5, somewhere in that zone, target would be to get down to that 1, maybe 1.5 in the near future couple of years. We feel that, that's kind of the appropriate level of debt for our company. Looking forward to continue moving on towards that target.

Your next question comes from Josh Young with Bison.

First question, can you talk a little bit about California and your activity trajectory there and when we might see more rigs after that.

Yes, yes. Well, California is such an enigma. It don't like oil and gas, but take it away and give us more of that. It seems interesting. But yes, we've been in California for a long time. We're the biggest driller in California. We were down the 3 or 4 rigs at the beginning of the year. We're up to 8 rigs now. We're seeing that as a steady business moving forward. We've probably only got one available rig left to put back to work. California is almost like a different country. They have their own transportation regulations, tax, everything else a little bit more high barrier to entry into California. So we see a little bit of upside to maybe add another rig before the end of the year, but we're certainly steady at 8, which we're very happy about.

Got it. That's great. And then on the Canadian market share, you guys have been slipping a little bit over the last year or so. Do you guys have thoughts on where you want to be there? And any plan or strategy to either make back market share gains or sort of continue as you're going?

Yes, fair question. Yes, we -- market share is always important to us. We want to gain that market share back. Over the last few years, we've sent 2 of our biggest rigs, 2,000 horsepower rig down to the U.S. We got tired of waiting for the Northeast B.C. gas to develop. So we ship those rigs down to the U.S. and started. Now we're focusing back on market share expansion into Canada. 25% market share is where we need to be and where we will get to. As I mentioned, we've got 5 rigs come on stream at the back end of the breakup here in next month or 2. And year-over-year, we're going to have 7 to 8 rigs more running year-over-year. We should be getting 50 rigs by mid-summer. And the plan is to extend and grow up. So we're going to be growing market share as an uptick market, which is a nice place to be, but trying to grow market share in a downtick market. And we've been focusing on debt reduction at the same time deploying capital to the market to provide us the best return. Keep in mind, in Canada, you made Canadian dollars whereas the equipment we buy put on rigs like [ CATS ] are all denominated in U.S. dollars. So that's why other areas in Canada has a lot of capital deployment because it's just been a better business for us. But now we've got 5 projects underway that will pay for the incremental upgrade capital in about 8 to 10 months.

[Operator Instructions] Your next question comes from Tim Monachello with ATB Cormark.

I joined the call late, so I don't know if I missed this, but could you just outline how many rig upgrades your capital program contemplates and in which regions?

So we've got -- let me get that for you, Tim. We've got 5 in Canada. Generally, we've got about 10 projects underway, 5 of them are in Canada, [indiscernible] in Venezuela and the rest of the U.S. I'm sorry, 1 in Australia. 1 in Australia, 1 in Venezuela and the rest in the U.S.

Okay. And are all those rigs idle currently? Are those like net new additions to the rig activities through the back half of the year?

Three of those 10 -- 4 of those 10 would be [ reactivation ] .

And then when you talk about customer-funded capital, how much of that is upfront payments? And how much of it is like, I guess, implied in higher day rates over the term of the contract?

So there's -- I would say, probably at least 1/3 of them are upfront capital and with term contracts probably the remainder of them are where we've been able to raise our rates to retrieve the capital within the first year. And then, of course, we have a new base for contract extension after that first year at a higher rate. So we tended not to go along in those contracts.

Got it. In the U.S. market, can you talk a little bit about the state of your idle fleet and the amount of rigs available that you think could be upgraded for a reasonable cost or, I guess, an economic cost and current market conditions, you go back to work in an up cycle?

Right, right. Well, we've -- we think we're going to get close to 50 rigs running in the back half of 2026, as I mentioned before. We have a fleet of 70 rigs for the moment. So we have about 20 rigs that we can put the work that the sales team can market. And that varies from some of the Rockies, a couple of doubles, but the rest probably -- probably at least 10 of them are kind of the high-spec triples that can be deployed and put the work competitively for probably about $5 million -- $5 million to $8 million per rig of recertification and upgrade capital.

Okay. And is that Venezuela rig that's being added in Q4, is that coming out of the U.S. fleet?

Correct.

Do you expect to see more rigs going down there?

Yes. I think that if it plays out like everyone thinks it will.we've got the capacity to feed into and we've got the infrastructure to support it, yes.

There are no further questions at this time. I will now turn the call over to Bob for closing remarks.

Thank you, all. This industry keeps on finding ways to deliver value by reducing well times and you have equipment performing at higher duty and delivering more work on a daily basis. That value has for the last decade been captured by the operators and help keep industry competitive globally. Notwithstanding as a result, contracted drilling costs have increased with replacement equipment costs moving up. It's time for contractors to capture the value creation generated over the last decade. With that and the tightening supply of high-spec rigs, we will be increasing rates roughly 5% to 10% of contract rollovers. This will help contractors cover those costs and monetizing in the future the value we've created over the last decade. We'll see where oil pricing lands, but it certainly is lining up from where it was. And with very little excess rig equipment capacity and lead times on rig equipment getting out there up to a year or more and with utilization moving up, the market construct looks very promising for Ensign. We will chat in 3 months. Thank you for joining the call.

Ladies and gentlemen, this concludes your conference call for today. We thank you for participating and ask that you please disconnect your lines.