Trican Well Service Ltd.

Hello and welcome to the Trican Well Services first quarter 2026 results conference call. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question and answer session, and if you would like to ask a question during this time, please press star 1 on your telephone keypad. I would now like to turn the conference over to Mr. Brad Fedora, President and Chief Executive Officer. Please go ahead.

Thank you very much for joining us and good morning everyone. First to start the call, Scott Mattson, our CFO, will give an overview of the corridor results for Q1 2026 and I'll provide some comments with respect to the corridor, the current operating conditions and our outlook for the future, both near and far. And then we'll open up the call for questions. We've got several members of our executive team in the room here today, so we should be able to answer any questions that people may have. I'll now turn it over to Scott to start us off.

Thanks, Brad, and good morning, everyone. Just before we begin, I'd like to remind everyone that this conference call may contain forward-looking statements and other information based on current expectations or results for the company. Certain material factors or assumptions that were applied in drawing conclusions or making projections were reflected in the forward-looking information section of our MD&A for Q1, 2026. A number of business risks and uncertainties could cause actual results to differ materially from these forward-looking statements and our financial outlook. Please refer to our 2025 Annual Information Form for the year ended December 31st, 2025 for a more complete description of business risks and uncertainties facing Trican. This document is available both on our website and on CDAR. During this call, we will refer to several common industry terms and use certain non-GAAP measures, which are more fully described in our Q4 2025 MD&A. Our quarterly results were released after close of market last night and are available both on CDAR and our website. So with that, I'll provide a brief summary of our results. My comments will draw comparisons mostly to the first quarter of last year and I will also provide some commentary about our current activity levels and our expectations going forward. Trican's results for the quarter compared to last year's Q1 were generally stronger due to an increase in operating activity and also with the inclusion of a full quarter of contribution from the Iron Horse acquisition. Overall revenues for the quarter were 330.3 million compared to the 259.1 million we generated in Q1 of 2025. Adjusted EBITDA for the quarter, 70.1 million or 21% of revenues compared to adjusted EBITDA of 61.3 million or 24% of revenues generated in Q1 of last year. Adjusted EBITDA for the quarter came in at 77.7 million or 24% of revenues up from the 62.3 million or 24% of revenues in Q1 of last year. To arrive at EBITDA, we add back the effects of cash-settled stock-based comp, recognizing the quarter to more clearly show the results of our operations and remove some of the market-to-market impact from our share price between reporting dates. On a consolidated basis, we generated positive earnings of 30.3 million in the quarter. That translates to 14 cents per share, both on a basic and fully diluted basis. compared to the 31.9 million and 17 cents per share on a basic and fully diluted basis in Q1 of last year. Profit and profit per share were impacted primarily by higher depreciation expense related to Iron Horse, our technology initiative expenses, and the higher stock-based comp during the quarter. Trican generated free cash flow, 49.6 million during the quarter. Our definition of free cash flow is essentially EBITDAs, less non-discretionary cash expenditures, which includes maintenance capital, interest, current taxes, and cash settled stock-based comp. You can see more details on this in the non-GAAP measures section of our MD&A. CapEx for the quarter totaled $18.5 million, split between maintenance capital of about $9.6 million and upgrade capital of $8.9 million. Our upgrade capital was dedicated mainly to the electrification of our fourth set of ancillary support equipment and ongoing investments to maintain the productive capability of our active equipment. We continue to maintain a very strong balance sheet exiting the quarter with positive non-cash working capital of $142.7 million and net debt of $29.8 million. Both measures meaningfully down from the December 31st 2025 levels. Reduction in net debt during the quarter was mostly a result of some working capital harvest and the free cash flow generated in the period. With respect to our return of capital strategy, we repurchased and canceled 756,900,000 shares under our NCME program in the first quarter at a weighted average cost of $6.46 per share. Subsequent to Q1 of 2026, we repurchased and canceled an additional 289,000 shares and continue to be active in our buyback program when market prices are at levels that provide for a favorable investment opportunity. As noted in our press release, the Board of Directors approved a dividend of 0.55 cents per share, reflecting approximately 11.6 million in aggregate payments to shareholders. Distribution is scheduled to be made on June 30th, 2026 to shareholders of record as of the close of business on June 15th, 2026. And I would note that the dividends are designated as eligible dividends for Canadian income tax purposes. So with that, I'll turn things back to Brad.

Scott, maybe just before I start, remind everybody how much we've spent buying back our shares just even since COVID.

Well, we bought back 53% of the outstanding shares that were sitting there kind of at the beginning of 2017, 2018.

Yeah, so we've been very active. It's been a big investment avenue for us. It's definitely something to consider. You know, we've... We view the NCIB as M&A, sort of risk-free M&A with a very good target company. So we've been really happy with the progress we've made on the NCIB in the past few years. Okay, I'll make some comments about Q1 and some forward-looking observations for 26 and beyond. So please, as Scott was mentioning, please see our disclaimer that can be found on our website. Q1, overall, the quarter went pretty much as expected. We were quite active. We did have quite a bit of pricing pressure, and so the quarter, it probably doesn't reflect the activity that we had, and we're sort of hoping that Q1 will represent the bottom for pricing going forward, but we were still generally pretty happy with the quarter. A lot of tough weather in February, which we always budget for. very warm conditions for a good chunk of February, which made for a bit of a choppy quarter, but overall it seemed to play out nicely. We got some cold weather towards the end of March, which really helped us make up what we had lost in the month of February. So we always kind of expect to deal with those issues in Q1 and Q4. Customers, again, are still, you know, very focused on our technology and our efficiencies particularly now with the ability to burn natural gas in our natural gas-fueled frack pumps and our electric ancillary equipment, given the price of where diesel went to since the beginning of the year, those assets are looking even better. You can be well over $100,000 a day in fuel savings by burning natural gas instead of diesel. In fact, it's probably pushing towards $150,000 a day. You know, we're the leader in tier four technology. I think we have 86, 78 tier four frac pumps. So we're the leader in that. And then we have four sets of electric and silvery equipment, which is like the blenders, the chem van, data van, sand assets, et cetera. And so when you combine our tier four frac pumps with our electric equipment, you know, we get very high substitution rates, without a doubt, industry leading. not just in Canada, but in North America. We're very fortunate that our customers have level-loaded. I think I've spoken about this in the past, but as you see, if you look back at our quarters, Q3, Q4, and Q1 all looked very similar, and there's lots of variations between the quarters, but It makes for a much more efficient business when you can level load the activity levels and the staffing levels and you're not seeing those things go up and down and having to react from a staffing perspective. So very happy with the way that's unfolding. We are seeing inflation given that what's happened with oil prices. I'm not going to comment on the Middle Eastern situation. I think everybody's fully aware of what's going on there and what that's done to oil prices. But that, of course, has flowed through our entire value chain. And it is pressuring on our margins. But that's okay. We'll adjust and react accordingly. But it's impacting almost everything, whether it's fuels, chemicals, steel, sand, transportation. All of that is affected by oil prices, as everybody can see in their day-to-day lives. When oil price goes from 57 to over 100, there's a big impact on on many aspects of the economy, and we're certainly not immune from that. We're still very natural gas focused. About 75% of the work that we do in Western Canada is what we would consider to be a natural gas well. But of course, these oil prices translate into higher condensate pricing. So even the gassy players are benefiting from what's been happening lately. You know, condensate pricing is well over 100 Canadian dollars, as high as 145 at one time, I think. All four of our divisions, the two frac divisions, the coil and the cement division, are all performing well, and we're really happy with the strategic direction of all four of those. I'll just make some comments about each one. On the Trican frac division, which is the deep work, which is pretty much Montney and Duvernay focused, I think everything is going well. That's where we've really differentiated our service offering with the investments we've made in technology. Without a doubt, we are the technical leader in natural gas fuel pumps and electric operations in Canada, and I think our customers can see the benefits of those operations. You know, in the plays, Montney and Duvernay, the wells are getting longer. There's more stages, more sand per stage in some cases. All of that means more sand per well. And so you've got to be careful when you look at the well count now. That's not really the primary driver of our services. You really have to look at meters drilled. But without a doubt, the more sand that gets pumped, the more time on location for us. We typically charge by the hour. That will use up the effective capacity in the industry. So we fully expect that pressure pumping services will get tighter and tighter as the months go by here. Unfortunately, given the amount of sand that's being pumped into the well, we're seeing more and more customers trying to self-source sand, which is a big contributor of EBITDA and cash flow for us. We are losing some of that and we're just trying to figure out every way possible to offset that loss. Particularly, we view the logistics offering that we have or our logistics division as the main way that we're going to offset that. of sand trucks in Western Canada and we're continuing to invest in that division and there's lots of technology that we can deploy in that as well. I think our first natural gas-fueled trucks will arrive in August. We ordered three of them. We're expecting that to go really well. There'd be a big fuel savings there. They have as far as an 1,100-kilometer range. think that'll be a problem for us. We'll fuel those trucks up in Grand Prairie and they should be able to deliver sand to all of our customers' locations. So really looking forward to getting those in the field. We also received our first 100% CAT 3520 natural gas frack pumper and that is the next evolution in the natural gas fuel technology. Testing was completed in Q1, and then we just recently have moved that into the field, so we'll see how it does in real operating conditions. But so far, very happy with the performance of that. And these are high horsepower, high rate, very heavy duty equipment that will replace almost on a two-for-one basis our old equipment. And so we're expecting less people on location, a smaller footprint, the ability to pump at high pressures for very long periods of time without any impact on R&M. So really looking forward to that. When you combine 100% frac pumpers with our electric ancillary equipment, we're getting almost 100% substitution on location. So I think our customers are very much looking forward to us having those assets in the field. On the iron horse side, that division obviously suffered as a result of oil prices below 60, but it's bounced back nicely. We're really excited about the future for that division given where oil prices are. We're seeing capital being deployed into their part of the world. You know, clients are planning to return to the field earlier. They're adding wells to their budgets. And this is probably the first time in almost a year where we're seeing a real renewed focus on their sort of their shallow, oilier parts of the basin. You know, they continue to add new clients and their customers are coming to them asking, you know, their ability to execute given increased programs. You know, we fully expect this to to really play out in Q4 when normally we would have otherwise seen budget exhaustion, we expect that that division will stay busy until the end of the year, right up to Christmas. And just like in the Motney and the DuVernay, they're seeing stage counts grow, sand volumes per stage increasing. So overall, more sand being pumped into the wells. So that's good for both the customer and us. We expect this division to perform much better in the second half of the year as these oil prices filter through into the programs of their customers. Times like this really highlight why we made that acquisition. We now have instant exposure to the oilier parts of the basin that we previously had basically a 0% market share. In cementing, again, very happy with how that division is going. They ran sort of a trial program in the SAGD market in Q1, which was a new area for us. It went very well. Assuming we can secure some customer commitments, we'll invest in infrastructure to make this a permanent area for us. If not, we might just sort of play it by ear. But we certainly expect that division where we have very high market share in the Montney and the Duvernay, that we can also continue to grow it into other parts of the basin and As with all of our divisions, they're looking at technology as a way to differentiate their product offering. We're investing in things like ball plants, which mix the cement up pre-transportation to the well to ensure that we reduce blending errors and just increase cement quality for our customers. We're also looking at hybrid cementers that would basically plug into the rig and we would remove a lot of the hydraulics that you would see with a conventional engine, which is just points of potential failure, especially when it gets cold. So, we'll continue to invest in technology where we think we can have an immediate benefit. Coil division, again, that division has been sort of trying to pick itself up off the floor, and it's been going very well. I think 2025 was our best year ever in coil, and we expect 2026 to be even better. You know, really what's happening in coil is as these wells get longer, the extended reach of the coil gets tougher and tougher. And so we've been putting lots of effort into sort of joint venture agreements and operating agreements with tool companies to allow us to better service the customer as well, even as they continue to grow. We've had issues with wear and tear on the coil strings, but I think there's solutions being developed all around North America that we will utilize to make sure that we're able to service our customers regardless of how long these horizontal sections get. So the outlook, you know, going forward, I would say, or maybe I'll just touch on Q2. Q2 is going okay, as always. It's very weather dependent, so it could be a bit unpredictable. You know, I'm not expecting anything out of the ordinary for Q2. I'd say revenue appears to be slightly ahead of last year, but just given what's happening on the cost side of things due to high oil prices, we are expecting some lower margins. But really, Q2 acts as a bit of a shock absorber for Q3, and so anything you gain or lose in Q2, you typically would give back or you would gain in Q3. So, you know, we kind of watch the weather fairly closely. We are seeing oily customers getting back to work earlier than we would have thought even as recently as 30 days ago. But a lot of Q2 depends on what happens with weather, in June in particular. And again, we are experiencing cost inflations across all of our product lines and as a result, we've implemented fuel surcharges and we're trying to get our prices up just to even offset the cost and I would say generally the customers are being very cooperative with this. Going forward, we believe our premium service offering and our operating efficiencies will continue to attract our valued customers. You know, I think generally as these volumes grow, the customers want to see, you know, what are you doing from an efficiency perspective, just given the scale of all of these operations. And certainly we believe that we are a leader in this space in Canada. You know, we do expect that budgets will expand in the second half of this year. But likely what will happen is they'll play out their original budget and then as those budgets are exhausted, you know, they'll add on to their programs in the fall and early winter. I think we've said this many times, but we continue to view Western Canada as a great place to be. It's a very attractive basin in which to develop and grow our business over the long term, and it just seems to be getting even better. When you think about all the major basins in the US, they're basically flat to declining. People see Canada as a real source of growth and having some of the best inventory that any major basin in North America has. So when we look at Canada, we see growth coming from five key areas. There's just general industry activity increasing as oil prices have gone up and we expect gas prices to strengthen going forward. We expect to grow our market share given our technology advantage. We see well intensity growing as well. So just more sand in the well means more time on location, which just means a larger invoice on a per well basis. We expect both cement and coil to expand and we expect to expand our logistics offering. Just trying to keep up with the growth in sand and, you know, just to remind everybody how much that has changed. Like in 2021, there was about four and a half million tons of sand pumped in Canada. And then 2025, it was eight and a half million tons. So there's no, everybody, all analysts are basically expecting that trend to continue. and we currently haul about 75-80% of the sand that we pump, so we can expand that division every year and probably never really catch up to the growth in the amount of sand that's pumped in Canada. And we expect that the Motley and the Duvernay will continue to be a focal point of our operations going forward. I think I'll just wrap up with a few comments on for shareholders and return of capital. TRICAN continues to generate significant free cash flow and we've maintained a very conservative balance sheet. I think we've paid back the majority of the debt that we added on for the Iron Horse transaction and by the end of the year I expect that we would be debt free. It depends on how much we invest in our NCIB but we're currently modeling sort of debt free to slightly cash positive at the end of the year so we maintain a lot of flexibility. We still subscribe to a diversified return of capital strategy. We love the NCIB, we view it as M&A, but I think the shareholders like it as well. They view it as return of capital. We combine that with the dividend that we're paying and between those two, we expect that approximately 50% of our free cash flow will get returned to shareholders in one form or another going forward. Of course, that will vary given what's available to us from an investment and an organic growth perspective. It's probably a reasonable rule of thumb to use over the long term. Certainly not afraid to use our bank lines that are available to us if we find the right accretive transaction. We think this business certainly feels a lot more stable than it did in the years prior to 2020. And so we feel a lot more comfortable holding debt if the right transaction comes along. But, you know, our corporate priorities remain unchanged. Build a resilient, sustainable, and differentiated company that the customers value. You know, invest in high-quality growth and upgrading opportunities to ensure that the technology offering that we have is best in class and provide a consistent return of capital to our shareholders through the dividend and the NCIB. And again, you know, it's why would you own this? Why would you want to buy these? buy our shares. To us, it looks better and better every day. We have the largest market share in a growing basin with the best technology offering out of all of our competitors. We just think this probably just gets better going forward and certainly over the next five years. We're really excited about the future. Maybe I'll stop there, Cathy, and we can

Thank you. If you would like to ask a question, please press star 1 on your telephone keypad. If you would like to withdraw your question, simply press star 1 again. Your first question comes from Keith Mackey of RBC Capital. Your line is open.

Hey, good morning and thanks for taking my questions. Maybe just to start out on pricing. You mentioned that there was some headwinds in Headwinds in Q1, just if you could maybe run us through the factors that might lead you to believe that pricing will improve in the second half of the year. Are there any Trican-specific factors, or is it mostly the industry, that capacity that you think will tighten up? So, you know, Brad, what are your expectations for how much slack is actually in the system and ultimately what you think it would take to move pricing up? a noticeable amount?

That's not one question, that was about five questions. So I would say the supply and demand equation is fairly balanced here and it has been for a while. The industry continues to evolve and get more efficient. And so even though you're seeing growing sand volumes, we as an industry just get better and better at what we do and we seem to be able to pump more and more every day. That trend is certainly positive though, we believe. And so that's part of why I think Q1 represents the bottom for pricing is that as these volumes continue to grow, we're just going to be on location longer and if you get tipped into the next day, You know, you've now taken a frack crew out of the float. And if that's happening all over the basin, whether it's shallow or deep work, you know, that capacity is just going to tighten up. I think pricing was particularly low in Q1 because I think there was some tough – some of our competitors were having a tough Q4 and maybe, you know, a kind of murky outlook for Q1 last fall. And so that always puts a lot of pressure on Q1 pricing as people position to fill their boards. And we're just not immune to that forever. For the most part, we don't play in that, but certainly when our customers are getting low bids, then that falls back on us eventually. But I think also you combine maybe slightly softer pricing with some unexpected cost inflation just given oil prices. you know, it maybe felt like pricing was even worse than it was, but I think between just general increase in commodity prices, whether it's oil or gas, you know, I think optimism surrounding a much more business-friendly government, you know, I think the importance of Canadian oil and gas supply is really highlighted by what's happening here in the Middle East. Certainly, you know, we've always known it as an industry, and I think now, sort of, I think the Our federal government is having to recognize that that, of course, is the case and that the people want more Canadian oil and gas. And so we expect industry activity to grow. And as activity grows, things will tighten up. It's a very long lead time on getting new equipment and getting people trained. So that'll just tighten up the supply and demand equation and pricing will react accordingly. Like when exactly is it going to happen and how much is it going to be? That's impossible to know. But I do feel there's a lot more optimism for the first time. You're seeing E&P companies talk about growth and unapologetically talking about growth. That's relatively new. Before, it was very much just maintain production, get as much money back to shareholders as possible, get your debt in line. And I think for the first time, it's okay to say we're going to grow. And you know all of those customers had. We're just chomping at the bit to start growing again. And they all have their projects identified and figured out. And once they get the green light to do that, they will. So we're feeling really positive about as a whole. When is the exact timing? That's not important. I think most people are investing in this for the next five years. We certainly don't have any reason to believe that the next five years are anything but bullish.

Okay, makes sense. And I'll follow up with just one question. So you've got 135.20 Can you just run us through when you expect to have that replacement fleet in the field, assuming it is a replacement fleet?

Yeah, it's always tough to know the exact timing just because there's lots of testing that occurs and it depends on how quickly the cat and the fabricators can react to the changes that we made. But we're expecting the 10 pumps to be available in the field in the fall. We would hope it's incremental equipment, but we're hoping for the best. But I think sort of September, October feels about right from a timing perspective.

Got it. Okay. Thanks very much.

Your next question comes from Tim Monticello with ATB Cormark Capital Markets. Your line is open.

Hey, good morning, everyone. Just a quick follow-up to Keith. Are you starting to price equipment into the back half of the year, and are you seeing stronger net pricing on that equipment, or are the pricing increases that you're putting through just offsetting cost inflation at this point?

I would say it's more offsetting at this stage, but they're very early days on pricing discussions.

When do you think you get better visibility into the back half pricing?

Oh, end of the quarter.

Okay. And then it's good to hear that the Iron Horse Division is seeing some stronger activity levels. When you think about the run rate for Iron Horse this year and into, I guess, early next year. How does that compare to the EBITDA metrics that you had contemplated at acquisition?

Say that all again, Tim. You kind of cut out there a bit.

Apologies. I'm just curious, based on higher activity levels for Iron Horse in the back half of the year, where do you think that's going to land relative to, I guess, the $80 million that was contemplated as a normalized run rate for the business at acquisition?

Are you asking what sort of the new implied multiple?

Sorry about this, guys. Sorry, guys. I was thinking about some issues with my headset or something. So, can you hear me?

Yeah, we got you, Tim. Okay. I was just curious. I think I understand your question, Tim. I would say that as we've come out of Q4 last year and into Q1 this year, we're a little probably lower than we were expecting. As we climb through the back half of this year and into the next year with stronger oil prices, that outlook is improving. Do we get back to and exceed that number? Hard to say at this point, but we're pretty optimistic with what we're seeing in the back half of the year.

Okay, appreciate it. I'll turn it back.

The next question comes from Colby Sasso of Daniel Energy Partners. Your line is open.

Hi. Thanks for taking my question. I just got a quick one. With sand volumes increasing per well, have you seen more customers moving to wet sand? And if so, how would that affect Trican's logistics line?

Yeah. It's still very early days from a wet sand perspective, in fact. We're on our first wet sand completion as we speak, just started about 48 hours ago. And so yeah, with sand volumes increasing and obviously the cost of sand being a very significant portion of their overall fracturing bill, customers are, you know, they're trying to find the lowest price alternative. And so they're looking at wet sand all around the basin. Where this ends up, it's very hard to tell. It's just too early at this stage. We're relatively indifferent in many respects. From a transportation perspective, that sand has still got to move from A to B. There's no shortage of sand to move. Whether it's moving 150 kilometers or 450 kilometers, in a wet sand situation, that just doesn't impact the overall scenario. So we're still very optimistic about growing our logistics division.

Thank you for the call. I'll turn it back.

Thanks. Your next question comes from Joseph Shatter with Shatter Energy Research. Your line is open.

Thank you very much. Good morning, everyone, and congratulations on the great quarter. One question for me is really you have those four FRAC fleets that are not working at this point. Are you having customer contact with you to look at maybe mobilizing them in 27? And, you know, given the different types, where would potentially those FRAC crews or FRAC units be positioned in terms of the basins? And how much cost would there be to upgrade the next fleet?

Yeah, okay. Thanks for prompting me on this, Joseph. I'm going to give you a bit of a big picture answer. So when you think about the spare capacity in Canada, none of it is new technology capacity. Like it's all, like the equipment that we have parked are older diesel engines, or diesel frac pumps with diesel engines. They work fine. You know, they're in great shape. But they're not an asset class that really you would look to deploy into the Montney or the DuVernay. And so when we talk about spare capacity, we probably need to tighten up our wording on that. And from an industry perspective, there's almost, I mean, there'd be a few extra frack fleets around, but not nearly as much spare capacity as probably compared to what's in analyst models, just because of the age of that equipment now. And so we've been selling our really, really old equipment. And certainly when we look at an Iron Horse situation, the type of work they do, the diesel-fueled frac pumps are what's appropriate for their operations. And so we would expect that as that division grows, they would use that spare capacity. And it's, you know, it always needs a bit of tweaking here and there. So I don't, but I don't really have that cost, you know, in front of me right now. But it's not significant in the grand scheme of things. But I think we need to change the way we think about spare capacity and its ability to come back into the basin and plays like the Montagnin and the Duvernay. Because the world has moved on from those assets. So, you know, it's not really... A customer's not going to come to you and say, geez, I'd like you to bring your 10-year-old diesel-fueled frack pumps off the fence and put them to work on my well. They're coming to us saying, when do I get to use your 100% natural gas assets, given that you only have one fleet? And so we're more, the juggling act is more deploying and allocating our tier four frack pumps and our electric ancillary equipment opposed to figuring out where sort of track pumps built in 2013 are gonna end up. The world has advanced considerably since those assets were built.

So if it was a demand increase for modern fleets, would that potentially have to come from somebody bringing a fleet in from the US?

No, we would either build, do, or retrofit that equipment. Now you are talking about sort of a $30 to $40 million per fleet investment and probably a one-year lead time. But, you know, as things get busier here, we're expecting things to get busier in the U.S. as well. So, no, we're not expecting a bunch of equipment to come from the U.S. You know, we've been asking, or people have been asking that question for 30 years. And it's never really happened in any kind of significant scale. With moving assets from the U.S. to Canada, it's a different equipment spec. It's different staffing issues, different DOT issues. It's not quite that simple. It is, of course, possible. But why would you move it if it's already at work in the lower 48?

Okay. That's it for me. Thanks very much, and again, congratulations on a great quarter. Thank you.

This concludes the question and answer session. I will turn the call to Mr. Brad Fedora for closing remarks.

Okay. Thank you, everyone. Thank you for your time. We're available for the rest of the day if anybody has any follow-up questions. Thanks very much.

This concludes today's conference call. Thank you for joining. You may now disconnect.