Trican Wellrvice Aktie

Thank you for standing by. My name is Jordan, and I'll be your conference operator today. At this time, I'd like to welcome everyone to the Trican Well Services Third Quarter 2026 Results. [Operator Instructions] I would now like to turn the conference over to Brad Fedora. You may begin.

Thank you, everyone. Good morning. First, Scott Matson, our CFO, will give an overview of the quarterly results, and then I will provide some comments with respect to the quarter overall and talk a little bit about what we're seeing for the next sort of 6 to 9 months, and then we'll take questions. As usual, we have all the senior members of our executive team in the room today, so we should be able to handle any questions that may come up. If you do have a question about your model or anything like that, please leave that for a later day. .

Now I'll turn the call over to Scott.

Thanks, Brad. 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 are reflected in the forward-looking information section of our MD&A for Q3 2026. A number of misrisks 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 31, 2025, for a more complete description of the business risks and uncertainties facing Trican. This document is available both on our website and on SEDAR. 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, again, are available both on SEDAR and our website. .

So with that, I'll give a brief summary of our quarterly results. My comments will draw comparisons mostly to the third quarter of last year, and I'll also provide some comments about our current activity levels and expectations going forward. Overall, third quarter reflected strong activity levels after a bit of a slow start with improved utilization and a solid contribution from the Iron Horse division for the full quarter. Commodity prices remain supportive of activity, particularly for oil and liquids-focused producers and completion programs continue to increase in scale and complexity across many of the resource plays where Trican operates. Overall, revenues for the quarter were $338.3 million compared to the $300.6 million we generated in Q3 of 2025. The increase was driven again by stronger operating activity and utilization levels during the quarter, together with the contribution from Iron Horse for the full quarter of this year versus effectively 1 month of Q3 of 2025 just due to the timing of the acquisition.

Adjusted EBITDA for the quarter, $87.7 million or 26% of revenue compared to adjusted EBITDA of $59.5 million or 20% of revenue in Q3 2025. Adjusted EBITDAS for the quarter came in at $87.1 million or 26% of revenue compared to the $66.9 million or 22% of revenue we printed in Q3 of last year. To arrive at EBITDAS, we add back the effects of our cash settled stock-based comp recognized in the quarter to more clearly show the results of our operations and remove some of the mark-to-market impact of the movements in our share price between reporting dates. So on a consolidated basis, this resulted in earnings of $48 million during the quarter, which translates to $0.23 per share on both a basic and fully diluted basis compared to earnings of $28.9 million or $0.15 a share on a basic and fully diluted basis in Q3 of last year.

We generated free cash flow of $66 million during the quarter, and our definition of free cash flow is effectively EBITDA less of nondiscretionary cash expenditures, such as maintenance capital, interest and current taxes. You can see more details on this in the non-GAAP measures section of our MD&A. CapEx for the quarter totaled $26.5 million, split between maintenance capital of $7.7 million and upgrade capital of $18.8 million, and our upgrade capital was primarily directed towards the construction of our first 100% natural gas-fueled continuous duty -- continuous heavy-duty hydraulic frac fleet and the purchase of electric ancillary frac equipment. These investments form part of our broader fleet modernization strategy and support our [indiscernible] on technological leadership, to operating efficiency and the ability to execute larger and more complex customer completion programs.

We continue to maintain a strong balance sheet exiting the quarter with positive noncash working capital of $1,013.7 million, net debt of $50.3 million, in line with what we were expecting and approximately $127 million of accessible liquidity. During the quarter, strong cash flow generation from operations, partially offset by a seasonal build in working capital following a spring breakup session, but again, in line with where we were expecting. And I would expect some of this to unwind as we move through the back half or the back part of the year.

With respect to our return of capital strategy, we repurchased and canceled 6.9 million shares under our NCIB program in the third quarter, the weighted average price of $6.09 per share, representing approximately 3.3% of the shares that were outstanding at the beginning of the year. Subsequent to the quarter, we repurchased and canceled about 600,000 shares, and we'll continue to be active in our buyback program on market prices are at levels that provide a favorable investment opportunity. And as noted in our press release, the Board of Directors approved a dividend of $0.055 per share, reflecting approximately $11.1 million in aggregate distributions to shareholders. That distribution schedule to be made December 31, 2026, to shareholders of record as of the close of business on December 15, 2026, and I would note that the dividends are eligible dividends for Canadian income tax purposes.

So with that, I'll turn things back to Brad.

Okay, thanks. Overall, Q3 came in as expected. It was a good quarter, but believe it or not, our results were, again, significantly impacted by wet weather, much more than normal for a third quarter. So even though it was very busy, we actually still had a lot of down days, particularly in the 2 frac divisions. All divisions performed really well. Margins were quite consistent across all 4 service lines. We pumped record amounts of sand in September. Unfortunately, nowadays, much of it is self-supplied by our customers, which is a significant loss of margin for us, meaning that we have to work a lot harder to make the same amount of cash flows that we used to in prior years. We are still experiencing significant pricing pressure in the bidding processes that have been unfolding over the last couple of months, and we're still seeing cost inflation across our entire supply chain due mainly to higher diesel prices that started earlier this year. It doesn't look like any of that is going to abate anytime soon.

It's still too early to determine the impact of the counter tariffs against U.S. parts and steel, but we expect that those will be material. As it happened with sand, we got all those tariffs back. But in the meantime, they can be a little bit painful and feel a little bit costly, but I think overall, in the long run, that will probably work out much like sand did last year.

Q4 has started off great. We're having a record month in October. We do expect though that all the divisions [indiscernible] will slow down as we approach the end of Q4. And we do expect our results to be lower than Q3. I know we've seen some analyst comments out there that they actually show growth in Q4 over Q3. I think that's at the stretch. As with -- as I think with normal seasonality and exhaustion going into year-end, you should see Q4 a little bit lower than Q2, and that would be, I think, the normal cadence going forward.

Nothing has changed. Our customers are still very [indiscernible] and efficiency. Efficiency is king on location now given the size of these fracs and -- of these frac programs, any little time savings or cost savings that you can provide are significant over the course of the year, particularly the opportunity to burn natural gas instead of diesel. The cost savings that are well over $100,000 a day, obviously, way lower emissions. Again, natural gas is available right on location in many cases, and so it's a very important part of our frac strategy going forward. Our natural gas assets, combined with our electric backside equipment, are leading the industry in Canada. We get substitution -- diesel substitution rates well over 90% when you combine our 100% natural gas pumps with our electric blenders and sand handling equipment.

We still remain very focused, Montney, Duvernay, and probably 70% of our work is still directed toward natural gas plays. I mean they all have, I think, fairly heavy liquids components for the most part, but it's still very much a natural gas basin. And we actually see the oily parts of the basin as a great opportunity to expand our services, particularly in cement and coil. So in the deep frac division, it's going very well, continue to build out our differentiated service offering with our 100% natural gas GMS bump. We're definitely the leader in this space when you combine our natural gas equipment with our electric backed equipment, combined with our engineering and lab facilities, we view ourselves as a technical leader. And I think our clients do, too. While getting longer, there's more stages. The sand per well continues to grow. I'm always referencing sand numbers, but I think this basin could approach 10 million tonnes any day now. You compare that to sort of 4 or 5 years ago, it's double the amount of sand that's getting pumped. So to us, that just means more time on location, the need for more robust, efficient equipment. Certainly, we are leading that war on innovation and technical ability in the field.

Almost 30% of our work now is in the Duvernay. That's a big increase from even 2 years ago. Very positive for future frac demand. It's a very pressure pumping intensive play, and it pumps at very high pressures. And so the importance of new, robust equipment designed for long pumping rates at very high pressures is just amplified in that place. So we're really happy with our position there. Unfortunately, there is an undisputed trend of customer-supplied sand. It's been a big loss for us from a cash flow perspective. And the only way to deal that is to increase your last mile logistics and try to find returns in sort of the logistics value chain. That is not a trend that we see going away. It probably continues to increase, but we've really focused a lot of our work and driving efficiencies from our last-mile logistics. We have the largest fleet of sand trucks in Western Canada, and we continue to focus on that division.

We have received our 100% natural gas pumps, as I discussed earlier. Those are coming in. They're a little behind, but we do expect to have all of our pumps in the field by year-end. They're performing very well in the field so far, better than expected, better earning field gas than the old Tier 4 engines that we were using -- that we continue to use. And then just the more gas you can burn, especially at these diesel prices, the more fuel savings are provided for the customers. So something that the customers are very focused on.

It looks like the pumps will be more spread across our deep fleets instead of being combined into an 8 fleet in the near term. And what that does, it just makes each of our fleets sort of more technically and operationally advanced and as a result, a little bit more profitable. So you may want to adjust your models accordingly. And then as we add more of these pumps, then we will evaluate at that time, well, whether or not we want to add incremental fleets or want to just continue to increase the profile of each of our deep fleets. We need more fleets. We simply can't get them fast enough. They're a huge win for our customer, and they're a win for us. So this is certainly a technology that we expect to be deploying over the next few years.

We're the only company that is now running in the pressure pumping space anyway, that is now running natural gas fuel [indiscernible]. We've received 2 of 3 so far. They're performing well. They have a great fuel range. There's a significant savings on fuel versus diesel. So even though these trucks are expensive, we expect that we're going to be getting reasonable returns just on fuel savings alone. So we'll be deploying those into our trucking fleet as they arrive. And what I would say is demand for the natural gas pumps far exceeds our ability to supply them and as well as our electric backsides as well, which is composed of the blenders and the sand handling and the chemical handling equipment. So it's frustrating for us that we can't get more of this equipment, but there's basically a global demand for these engines. And so we're just trying to make sure that we position ourselves in the queue, and we'll get them as fast as we can, but we fully expect that we'll be ordering more of those pumps going forward.

On the Iron Horse side, as anticipated where oil prices went, Q3 was a great quarter for them. Clients were busy in the field. They especially had a lot of weather delays, but they still had a great quarter. It really highlights the oil price conditions like we're experiencing today really, really highlight why we thought that was a good acquisition. And it's broadened our exposure to the [indiscernible] base, that we were not present in before, and we're looking forward to a really busy 2027 in that division.

On the cement side, we continue to be really happy with how that division continues to operate. We maintained really high market share in both Montney and the Duvernay. We secured a Q1 SAGD project, twice the size of our 2026 program, in-depth discussions with additional simmers to provide equipment and efficiencies in their programs. We currently have almost no market share in heavy oil in SAGD. So as we expand into that market share, it's pure organic growth and incremental to what we're doing today from a revenue and cash flow perspective. And those jobs are smaller, but there's lots of them, and the margins on those are almost as good as our deep gas margin. So that will be an area of expansion for this company in the future.

We successfully cemented the longest well in Canada in the summer. It was just over 9,600 meters. So great job to the cement division and the crew that executed there. As wells get longer, more expensive for the customer. They, of course, are more and more reliant on companies like us that have advanced blends, a deep engineering program, a deep lab expertise and years and years of operating experience. So our competitive positioning should just do [indiscernible] improve as wells get bigger and more complicated going forward.

We are working on electrification in that division as well. We expect delivery of a hybrid mixing unit in Q1 of 2027. That is delayed from Q4 of this year. But with that equipment, we'll see the elimination of hydraulics, which will mean less breakdown, less R&M and just better reliability for the customer and especially cold -- a much more pleasant operating experience for the auditors as well. On the coil side, we had a good summer in coil. Again, lots of delays due to weather. But August, September were 2 of the busiest months ever in that division, this has continued into October as well, which will probably be the busiest month for this division. As with everything, wells get longer, creating challenges for coil. Trican manages all of these challenges with an extensive string inventory, lots of high rate injectors and our relationships with tool companies that continue to allow us to take on technical challenges and provide a really good service for our customers.

This coil division as well, we look at heavy oil and SAGD as a great opportunity for us to expand. And again, we've done very little in that part of the world just due to equipment and staffing shortages over the past few years, but we see that as a great opportunity to show significant organic growth in that division.

I'll just make a few comments about our outlook for Q4 and 2027. I'd say Q4 is going very well. October is basically a continuation of Q3, probably will be a record month for this company overall. But we do -- you should expect things to slow down significantly in December. And so financial results will be good, but I do expect them to be a little bit lower than Q3. We're seeing research notes that are implying Q4 is going to be higher than Q3. I think that's very, very unlikely unless there's significant roll forward budgets in 2027 into 2026. So I think the normal cadence will be Q3 is probably the busiest quarter of the year and then Q4 and Q1 are just slightly below it. And again, the loss of sand is a real impact to our operations. And so we have to end up doing a lot more work to show the same sort of EBITDA and cash flows.

At this time, we're not seeing any significant budget being pulled forward from Q1 2027 into Q4. I won't be surprised if we see a little bit of that. Q1 2027 is very busy. All of our customers are telling us that they're going to be busier next year. Q1 2027 is almost fully booked, and the conditions for Q1 are improving as the weeks go by. So we are expecting a very busy winter and a very busy spring. Overall, when we look at the basin, we think in terms of -- we expect activity probably goes up 5% or so a year, and we probably see a similar increase in pricing to go along with it. this might be conservative. But I think until we get a much more constructive natural gas market, we're taking, I think, a conservative stance on growth and focusing on getting the people, getting the right equipment, making sure that even though things are getting busier, we continue to operate at an extremely high level of not just quality of operation but efficiency of operations as well. Still a very competitive space to operate in and lots of pricing lots of pressure from our suppliers across our entire supply chain.

So even though it's growing, we want to continue to operate on efficiencies, provide very good service for our customers, making sure that we have the right people in place as this market grows. I would echo our comments in the last few years, we view Western Canada as a great place to be. We expect that this basin is going to continue to expand over the next 4 years -- 4 or 5 years, just given everything that we've seen from an egress perspective on both oil and natural gas. And we hope to be a big part of that. we see growth coming from 5 key areas. Just overall industry activity and pricing is one. Our market share within that market is two, just given our technology and equipment advantage. The third is just well intensity growth. More sand means more time on location for us, which just means higher frac builds, reducing the effective capacity of the fleet in Canada as a whole. So that will just -- more hours on location, I think, is a win.

Cement and coil, we'll have lots of organic expansion just in the heavy oil and SAGD areas. And as our last mile logistics expand, we'll start seeing that as a separate operating division that is also providing profits to the overall company. And I'll just finish off with sort of our view of value for shareholders and return on capital. It's a grind, but we continue to generate free cash flow and maintain a conservative balance sheet. We're not totally debt-free, but we're effectively debt-free. We [indiscernible] diversified return of capital strategy, a combination of sustainable dividends in the NCIB. Since 2020, Trican has turned over $540 million to shareholders in the form of tax and dividends. So it's a very, very significant number that I think it's almost going to be taken for granted for now. We look at buying our own share is probably the best M&A we ever could have done. So we're really happy with how that's worked out. I think we're, I don't know, Scott, what are we, almost 55% of the share since 2017.

So we'll continue to flex our NCIB up and down based on share prices and other market opportunities. We are very active in sort of our M&A -- in our M&A department. We're coming through deals, trying to find the right places to best, making sure that they're exposed to the markets that we want to be in. It's, as always, very tough to find the right deal, and we'll just keep digging. And in the meantime, we'll keep buying our shares as a form of M&A. So I don't expect that to change anytime soon.

On a go-forward basis, like we've said in the past, give or take, you should expect about 50% of our free cash flow to go to shareholders in the form of buybacks or dividends. I think over the long term, that's probably a good metric, and it will vary from year-to-year depending on the stock price environment and what's available from an M&A perspective, but over a 10-year period, I think that 50% number is probably about right. We're not afraid to use our bank lines. We feel a lot better about debt today than we did even a couple of years ago. I think it's no surprise to people that this management team is very conservative from a debt perspective. But just given the stability that we're seeing in the market and how we -- our view of the future for the Canadian market over the next 5 to 10 years, we wouldn't hesitate to use our bank lines to make the right investment.

I'll just finish off by saying our priorities haven't changed: build a resilient, sustainable and differentiated company, invest in high-quality growth and upgrading opportunities to ensure that we're adding value for our customers. It's not enough to just show up and execute. You have to show them that why using our services creates incremental value for them. And then provide a consistent return of capital to our shareholders through the dividend and NCIB when appropriate.

Okay. Operator, I think I'll stop there, and we'll go to questions.

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

Brad, you highlighted that pricing pressure persisted in Q3, and then you had later mentioned the potential 5% inflection in both activity pricing next year. Hoping you can just expand a bit more on how you see the competitive intensity evolving into 2027. And maybe just couch it as both on the sort of supply side as well as the demand side. I know demand, you said maybe 5%. And would you characterize the market today as sort of adequately supplied, oversupplied? And what would it take to change your view?

Yes. It's a bit of a corky market in the sense that, I don't think activity is necessarily in any particular month that consistent across all the service providers. I think we sort of take turns having very busy months, but there's certainly some white space present if you looked at the industry as a whole. And so you haven't -- even though I think everybody is expecting a much busier next year, I think our customers have played this really well. They're securing longer-term relationships using today's may be angst about white space. And so even though I think the market's going to be undersupplied very soon, you're not seeing it in pricing today. But it will happen quickly. Is it going to be a huge 20% jump in pricing? No, I don't think so. And that's I think taking a sort of a conservative view of getting -- starting with cost recoveries, just given how much our margins have been squeezed, starting with cost recoveries and a little bit more activity will allow you maybe to inch pricing up a little bit.

But remember, this is a very corky business. We have about $1.2 billion top line. You don't need a big price increase to really move earnings around and free cash flow. So a little bit of activity, combined with a little bit of pricing and a little bit of cost recovery, it's very, very significant. The timing -- the exact timing of which nobody knows.

Got you. Just to maybe clarify, anything you're seeing on the supply side?

Well, I think as everybody knows, supply side has actually improved here. We're just chatter about maybe up to 4 spreads, leaving Canada going to the U.S. And my sense is, once they get down there, it's going to be really hard to bring them back. That's busy down -- it's busy in the States, too. Maybe I would even say, like the slope of their recovery curve has been higher than Canada's in some of those basins. So my guess is, some of the equipment is going to go south and not be back anytime soon. So the number of frac fleets in Canada doesn't take as we all know, like a marginal fleet, either additions or subtractions, can have a big influence on the overall market. So thanks for asking that question. That's good point.

Yes. Okay. And then you mentioned, again, back to the supply side, that you couldn't get for the natural gas fast enough. Maybe in broad strokes, like how many pumps do you think you can get your hands on next year? And do you think you'll sort of maximize your ability to do that? And I know you said no modeling questions, but to the extent you'd like to comment on what the '27 CapEx could look like, I'd be interested in getting your views.

I would say the Cap -- you should assume the same CapEx for next year. I'm looking at Scott, and he's nodding. But if we could double it, we would. You can't buy what they won't sell you.

Yes. The other comment I'd make, Aaron, is that there's a time line around these things like we ordered our first set of these natural gas pumps about a year ago. And so we've taken delivery of kind of 3 of 10, but there's quite a lead time and then it's quite a build slot time. So even if we could order, double them, we wouldn't get them for a full season.

Yes. I think [indiscernible] is 2028 basically. So it's frustrating, but there is demand for those engines in all parts of the economy, especially in power.

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

Maybe we could just start on the sand pumping trends that you mentioned a few times there, Brad. What portion of sand did you pump -- that you pumped in the quarter? Did use supply versus third-party supply? And how might do you expect that to change going forward? Are we in the eighth or ninth being of that? Or is there a significant amount of sand that might be supplied by third parties going forward?

Yes. In the quarter, that number was, call it, roughly 50% supplied by Trican or customers supplied. That's a slow, steady trend upwards as we've moved through the last year or 2.

It would have been 70-30 a year.

70-30 a year . That trend will probably continue, but it's not -- there will still be an element of Trican supplied sand specifically for certain customers who want us to be able to handle that process for them. And the larger and bigger demand on sand from a program perspective that you have when a larger -- the larger the operator, the more play there to procure their own sand. So we're probably in the sixth, seventh inning of that as we go forward but not dramatically.

Okay. Very helpful. And maybe just talk a little bit about business development. You mentioned M&A active. Can you just kind of speak to some of the things that you've, in general and broad strokes, have looked at? What types of things might meet your return thresholds versus what types of things might not? And how do you want to bolt those into Trican as an existing business? Is it about creating more integration or more bread? Or what is the approach in the latest thinking today?

Look, we're looking at everything. We're very bullish on not just Canada, but we're bullish on the U.S. as well. Again, we would never -- we'd never buy fracturing operations or sole fracturing operations in the U.S. like -- that's not -- we don't think we have anything to offer there. But we're looking at everything. We're a logistics-based business today. And we do have seasonal issues that we have to deal with. So we're always looking to smooth those out. But quite frankly, it's hard to do in Canada. We are, I would say, are underexposed to the oily parts of the basin. Like I said, we're 70-plus percent focused on natural gas. Our first foray into the oil world was the [indiscernible] acquisition. And frankly, just given everything is happening from an egress perspective, we're not really participating in the oily side of the market. Like, look at the Clearwater, it's not going to slow down anytime soon, and there's really nothing for us to do there other than coat.

And we're actively looking to expand our coil services in that play, but if there's acquisitions that could speed up our exposure to heavy oil and SAGD and things like that, we would look at it. So I'm giving you a nonanswer answer, but -- so we're not fussed with it having to be a vertical integration. We're happy to add business lines on that we're not currently in and where we may be in sort of indirectly in our own operations. And so -- but I think when people talk about M&A and other service lines, I think you have to remember, we're all calling on the same people right? Like our coil and fracking divisions call on the [indiscernible] departments. Our cement division calls on the drilling department. And so it's very easy for us to make step-out acquisitions into other service lines because you have the same customers. We all know who those customers are. So -- and the people that we're calling on, they have a long, long positive experience with Trican. They're very familiar with our company and the quality of our service offering.

And so we're not afraid to add on what appear to be unrelated service lines, but we all go to the same well and we all call them the same customer. So they're not actually all that unrelated. And at the end of the day, much of oilfield services is can you move lots of people and lots of equipment around officially. So we obviously know what our core competencies are, and we're not afraid to use them in other places.

Your next question comes from the Tim Monachello from with ATB Cormark.

Most of my questions have been answered. But just curious on the addition of new 100% natural gas pumps that probably comes in the 2027 budget. Are you seeing inflation in the cost of that equipment given, I guess, the demand that you're seeing -- that those OEMs are seeing across different end markets?

Not a ton. Tim, yes, the thing that probably keeps me the most up at night would be what potential tariff impact of those things moving back and forth. Any engine is predominantly steel, so there's a lot of impact there. But to date, we haven't seen a rapid increase in what we've been getting and what we've seen delivered so far, but TBD for 2027.

[indiscernible].

Yes, they never get less expenditures.

Yes. It will [indiscernible] and the price will go up.

Okay. And have you guys made a decision on that formally? Or when do you think that you'll pull the trigger on that decision?

No, we make a formal board approval on our 2027 budget in early December. But we'll certainly be asking for more.

Got it. And so it sounds like the new equipment that you have coming in, in late '26 will be largely complementary to the current fracs that you have in the market, adding capacity and some margin there. Like, how do you think about the idle equipment that you have in the fleet, I assume it's largely Tier 2 stock? Does that ever go back to work? Or is that something that you think about divesting to other markets or something?

Yes, like, I'll back up a little bit. Yes. When we -- as we think about the fleet and the quality of the fleets going forward, our goal is to high-grade those fleets and make them, I guess, technically advanced as possible to increase their sort of profile for customers. And what that means is, we will continue to sort of bring in the new state-of-the-art technology and move out the diesel pumps or the old Tier 2 pumps. And those -- that equipment is old, like really old. It's not just here. It's everywhere.

And so the good thing about the pressure pumping business is, even though we all continue to invest in our fleet, the fleet isn't growing, which sets up a good supply and demand dynamics going forward. And we've had sort of 3 to 4 spreads parked on the fence now just make sure we don't sort of run the industry by bringing that equipment back to work. But the reality is we may never put on equipment back to work. And we continue to dispose of sort of parked equipment that we talk very little of. And it doesn't get sold into the Canadian market, it only gets sold outside of Canada. So you'll just see a continuous improvement in the quality of our fleet. It's a totally different frac fleet than it was 3, 4 years ago.

Yes. Okay. And then last one for me. I'm just curious if you can give an update on, I guess, the profitability and activity levels that you're seeing within the Iron Horse fleet? Any outlook for that fleet in '27?

We don't talk divisional margins or anything like that, but certainly that Q3 would be a good indication of how we expected that business to perform, and they have more seasonal issues than the deep fleet just due to road bans and things like that. But it's fair to say when that equipment is highly utilized, we're really happy with the purchase.

You next question comes from the line of [ Nathan Ritchie ] from Schachter.

First of all, I just want to thank you for everything you're doing for shoulders. I've been following your story since prior to the Canyon merger and that has continued to deliver. So first off, thanks for that on behalf of shareholders. What I wanted to speak about is, if you can speak more on your application of AI in the business. And some context of why I ask is, I was at a presentation this summer that Liberty Energy did. And they spent so much time talking about technology and AI and data. By the end of the presentation, I had to remind myself as an oilfield services firm, I know they're not that big in Canada, you're not probably competing with them as much as far as customers go, but you may be competing with them for investors.

So I just want to see if there's a focus, I know the focus right now is, use technology to deliver results for your customers, which is obviously like a priority and is obviously working for you, but is there also whether you can talk about your technology a little bit more and promote what you're doing in the market. So that you're viewed more as a technology company that's in oil and gas services rather than an oil and gas service company that uses technology and then from that, potentially be able to trade at a little bit higher multiple.

Well, I hope none of the Board is listening. Yes, we hear you. But first and foremost, my job is to provide returns, not [indiscernible] brochures. And we are an oilfield services company that uses technology, and that's never going to change in the next few years. So I'm never going to say I'm a technology company that is in the oilfield services business. I should -- I'm never going to say that. But in the next 36 months, that's very unlikely.

We very much understand what you're saying. We're all fighting for the marginal dollars from investors. And we probably could do a better job talking about the technology investments that we're making, particularly using data that is in the trillions of data points in this organization. We are going through a great baked systems upgrade, and I do not want to be a first mover on AI .so I'm happy to be a number two on AI and let the non-return money gets spent by somebody else. And where we're seeing probably the best opportunities in the near future on using AI and data management is on frac automation and preventative maintenance. And so as that gets more developed and it gets field tested, we'll start to talk more about it.

But rest assured, we understand sort of the comments you're making. I don't agree with all of them, but I certainly understand what you're getting at.

[Operator Instructions] Your next question comes from the line of Colby Sasso from Daniel Energy Partners.

Just a quick question for me. You've discussed the trend towards longer laterals, more stages and higher sand intensity across the Montney and Duvernay. Are you seeing any indication that operators are beginning to reach diminishing returns on completion intensity? Or do you expect these trends to continue driving higher service requirements over the next several years?

Yes. Remember, we make sort of blanket statements for the basin as a whole. There's always exceptions from on this area versus that area, or this operator's view of how they should do it versus that operator's view. But in general, yes, we expect this trend is going to continue.

And then one last one. You delivered a strong EBITDA margin of 26% in Q3, which is one of the highest levels we've seen over the past several years. As you look ahead towards '27, how sustainable are these margins? And should we expect this level going forward? Or does Q3 represent a high watermark of sorts?

Yes, good question. I mean if you look through the year, this has been our highest margin quarter, probably the last 4, 5 or 6 quarters. I mean, I think this will kind of moderate as we go through 2027. There was a bit of G&A stuff in this quarter that gave us a bit of a benefit as well. So if you're in the mid-20s as we go forward, that's probably a pretty good indicator. Some of that changes the relative proportion of sand-in versus stand-out work moves that margin percentage number up a little bit. but not the aggregate dollars, if that makes sense. So this is probably a decent run rate to go forward. If you blend this thing out for the whole year, we're probably mid-20s, and I would expect that's pretty safe.

That concludes our question-and-answer session. I would now like to turn the call back over to Brad Fedora for closing remarks.

Okay. Thank you, everyone. Thanks for your time and your interest. I know it's a busy time of year. We are available for any follow-up calls that you may have, particularly with respect to the financial models, et cetera. So we won't be hard to find for the next couple of days. We can help you. Please, reach out. And thanks again.

This concludes today's meeting. You may now disconnect.

Thank you for standing by. My name is Tina, and I will be your conference operator today. At this time, I would like to welcome everyone to the Trican Well Services Second Quarter 2026 Results Call. [Operator Instructions] It is now my pleasure to turn the call over to Brad Fedora. Please go ahead.

Good morning, everyone. Thanks for joining us. We'll start off with Scott Matson, our Chief Financial Officer. He will give an overview of the quarter, and then I will provide some comments with respect to the quarter, the current operating conditions and our outlook for the near future, and then we'll open up the call for questions. As usual, we have several members from our executive team in the room today and are available to answer any questions anyone may have. I'll now turn over the call to Scott.

Thanks, Brad. So 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 are reflected in the forward-looking information section of our MD&A for Q2 of 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 31, 2025, for a more complete description of business risks and uncertainties facing Trican. The document is available both on our website and on SEDAR.

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 SEDAR and on our website.

So with that, a brief summary of the quarter. My comments will draw comparisons to the second quarter of last year, and I'll provide some comments about our current activity levels and expectations going forward as well. And before getting into the details of the quarter, it's important to recognize that Q2 of 2025 was an exceptionally strong period for Trican. During that time, there was significant concern across the industry regarding operators' abilities to secure sufficient water resources to support planned frac programs heading into the fall. And in addition, Alberta and British Columbia experienced an active wildfire season with operators anticipating access challenges at completion locations as we moved into Q3. Both of these items have resulted in demand for available service capacity being pulled forward into Q2. As a result, Trican benefited from an unusually strong activity level throughout Q2 '25, culminating in a very, very busy June.

In contrast, Q2 of 2026 reflected a more typical spring breakup period with reduced operating activity and lower equipment utilization across much of our business lines. While the acquisition of Iron Horse in August of 2025 expanded our service offering and increased our operation scale, the contribution reflected its seasonally weaker second quarter operating profile with seasonal softness further weighing on profitability. So with that, overall revenues for the quarter came in at $214.6 million compared to the $213.8 million we generated in Q2 of 2025.

Again, lower activity and utilization levels throughout breakup, together with the wet weather conditions in certain operating areas during June were largely offset by the contribution from Iron Horse, resulting in revenues that were broadly consistent with last year. Adjusted EBITDA for the quarter was $22.6 million or 11% of revenue compared to the adjusted EBITDA of $44.9 million or 21% of revenue in Q2 of 2025. This was driven by lower activity, again, and utilization levels and compounded by continued pricing pressure across our service lines as recovering the full impact of freight, fuel and other operating cost increases remains challenging in a very competitive environment.

Adjusted EBITDAS for the quarter came in at $25.2 million or 12% of revenue compared to the $47.3 million or 22% of revenue in Q2 of last year. To arrive at EBITDAS, we add back the effects of our cash settled share-based comp recognized in the quarter to more clearly show the results of operations and remove some of the mark-to-market impact of movements in our share price between the operating dates.

On a consolidated basis, this resulted in a loss of $2.3 million during the quarter, translates to $0.01 per share on both a basic and fully diluted basis compared to earnings of $19.5 million or $0.11 per share on a basic and fully diluted basis in Q2 of last year. Net earnings and earnings per share were also impacted by higher depreciation and amortization costs with Iron Horse, technology initiative expenses and some higher share-based comp costs.

While profitability was below prior year, we continue to be encouraged by the underlying customer activity levels, our market position and the ability to generate free cash flow and further strengthen the balance sheet. We generated free cash flow of $13 million during the quarter. Again, our definition of free cash flow is essentially EBITDA less nondiscretionary cash expenditures. You can see more details on this in the non-GAAP measures section of our MD&A.

CapEx for the quarter totaled $20.8 million, split between maintenance capital of $9.5 million and upgrade capital of $11.3 million. Our upgrade capital was dedicated primarily to the electrification of our fourth set of ancillary frac support equipment, construction of Canada's first 100% natural gas fueled continuous heavy-duty hydraulic fracturing fleet 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 noncash working capital of $81 million and a cash balance of $15.4 million with no outstanding debt.

During the quarter, we harvested significant working capital as receivables were collected following an active winter season and inventory levels reduced accordingly. Those proceeds were used to repay our outstanding borrowings and further strengthen our balance sheet.

With respect to our return of capital strategy, we repurchased and canceled 885 million shares under our 85 -- 185,000 shares under our NCIB program during the quarter at a weighted average cost of $7.28 per share. Subsequent to quarter end, we repurchased and canceled 305,000 shares, and we'll continue to be active with 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 $0.055 per share, reflecting approximately $11.5 million in aggregate return to shareholders. This distribution is scheduled to be made on September 30, 2026, to shareholders of record as of the close of business on September 15, 2026. And I would note that the dividends are designated as eligible dividends for Canadian tax purposes. So with that, I'll turn things back to Brad.

Okay. Thanks. I'll make a few comments about the quarter and just how we're viewing the world, which really hasn't changed much since our last call. Obviously, Q2 came in a little lower than expected. I really caution you -- we don't get too fussed by Q2 results, and I would caution you not to extrapolate Q2 into the rest of the year as it just isn't relevant. If you go back to our call from Q1 at that time, we talked about Q2 is really dependent on June and how wet it is.

As it turned out, June was the wettest June on record in history and is the second wettest month ever in the history of Central Alberta. So that has a huge impact on our operations. And so don't worry about Q2. It's not a quarter that is indicative of how the rest of the year is going to go. It stands out in particular to last year, which was unusually good. A bunch of work had been pulled forward due to fears for forest fires and water access. So again, I wouldn't get too fussed by how Q2 shook out. And we also -- we don't go to work at any price. This equipment has a certain number of hours of life. And we're not afraid to say, no, that's not good enough, and we'll save those hours for a different customer at a different time at a more attractive return.

So I would say the market overall feels good. Customers are still very focused on technology and efficiency, particularly the opportunity to burn natural gas versus diesel. at these fuel prices, this is becoming more and more important every day. The arbitrage between natural gas prices and diesel has never been higher. It's -- you're buying gas at $3 a GJ, it's like buying diesel at $0.12 a liter, not the $2 a liter that we're currently paying throughout the basin. So all of the investments that we've made over the past few years have all been generally focused towards getting our equipment to run on natural gas versus diesel, and that stuff is really starting to pay off.

And wells like Duvernay, as an example, in Duvernay play, burning natural gas versus diesel can save $200,000 a day of fuel costs. So all of those investments that we made, turning our equipment -- our backside equipment to electric, replacing our diesel burning natural gas pumps with our diesel burning frac pumps replacing them with natural gas engines. Those are -- that stuff is all really paying off and is becoming basically the standard for the industry. The oil work is obviously going well. I think you'll see Iron Horse really perform well in the second half of this year. We've got good oil pricing, but we had a lot of volatility in Q2, and so it really didn't shake through from an activity perspective. But I think you'll see that division really perform well in the second half.

We're still focused Montney, Duvernay and the Shaunavon oil plays, so nothing has changed from a strategy perspective. In the Trican deep frac division, where we're making the natural gas investments, everything is going very well. We're viewed as a technical leader in the industry. Wells are getting longer, more stages, more sand in the wells. That means longer time on location. And now almost 30% of our work is in the Duvernay, which is a very pressure pumping-intensive play.

And a couple of years ago, we built sort of customized equipment just for the Duvernay play given the pumping pressures and durations. And so that is bearing fruit with lower maintenance costs, lower downtime and the ability to take less equipment on to location because we're not having to take a bunch of spare equipment for breakdowns. There's this trend in sand consumption or placement continues. I think post COVID in 2021, the basin consumed about 4.5 million tons of sand. This year, it's going to be 8.5 million to 9 million tons, and there's lots of forecasts for it to grow as high as 12 million to 15 million tons per year.

So we've been making investments in our last mile logistics, and we expect that to basically run at 100% utilization for the foreseeable future. And efficient logistics are absolutely critical for success on a pad. I think we're -- we do the best job of this in the basin. We have one of the largest sand truck fleets in Western Canada, and our customers really value that service offering. We received our first 100% natural gas cat engine, and it's been in the field now for a while. performing very well, actually a little bit better than expected. Those new frac pumps with those engines will replace 2 of conventional pumps.

So we'll have less people, less equipment, ability to pump at higher pressures for longer. And when you combine those 100% natural gas pumps with the electric backside equipment, we're basically almost consuming 100% natural gas on location, giving savings of up to $200,000 a day. So it's a huge win for the operator. It's great for maintenance. It's lower footprint on location. It's a win-win for both us and our customers.

We expect the full fleet to be operational in Q4 of this year. The pumps sort of come out one at a time once you work the kinks out of the first one. And so we'll have that -- we'll have a 10-pump fleet of those 100% natural gas engines in Q4 operating. We have -- we expect to receive our first natural gas fueled truck, semi-truck for hauling sand in August of this year. We've been working with customers on how we're going to get fuel infrastructure built in the field. They have a very, very long range. So currently, we'll operate those in the Grande Prairie area in Northwest Alberta and running CNG in a semi-trailer or semi-truck is about a 60% reduction in fuel costs and lower maintenance. So again, it's going to be a win for us on fuel expenses.

In the Iron Horse division, their Q2 went pretty much as usual. I think there was a lot of chatter on the Boards about why our EBITDA didn't go up given the Iron Horse division. I just want to remind everybody that Iron Horse experiences a traditional breakup. They're not additive to EBITDA in Q2. They're negative to flat at best. So that's not an addition. You'll really see the impact of that division in Q3 and Q4 of this year. Their customers are messaging higher activity levels as long as oil prices stay high, obviously, we've got crack spreads over $70. So there's lots of incentive for people to develop their oil plays right now.

And they're experiencing the same issues as the other frac division with higher intensity on a per well basis, the stages and sand volumes are growing, but that just means more time on location. So that's good for us in the long term.

The Cement division continues to operate really well. We're growing our market share in areas where we weren't currently present, which is Northeast Alberta in the heavy oil sands area. They had a great Q2 from an activity revenue perspective. But unfortunately, their costs are going up just as high as the activity is. So they had a good activity quarter, but it's sort of as expected EBITDA quarter. We're working on electrification in that division as well. And we expect that we'll have our first hybrid cement unit delivered in Q4 of this year. And that basically plugs right into the rig for power, reduces hydraulics, less breakdowns, less R&M, less fuel costs. So that's again, it's a win for us. And we continue to perform -- outperform our competitors in this space. We have basically a 50% market share in the Montney and the Duvernay, and we just recently completed the longest well in the history for Canada, just over 9,600 meters. I think that was for [ Paramount ].

So everything is going very well in that division. We're making investments in our bulk blending plants to reduce blending errors, dust exposure to our staff. We expect that to transfer into higher quality of service for our customers. On the coil side, everything is going well there as well. As these wells get longer, and we work on technology to get our coil out to an extended reach, we continue to spend more time on location with our coil. Those jobs get bigger. We're seeing that division grow year-over-year and just the investments we've

made in our coil string inventory to deal with these longer wells is really starting to pay off. So I'll just touch on the outlook now. Nothing's changed. Q3, the second half of this year and Q3 and Q4, they all look good. The trends for this industry in Canada. There's no other place we'd rather be. Weather, you're going to have weather impacts, whether it's Q2 in and around the winter, don't get fussed over the sort of very, very short-term hiccups that do not transfer into any long-term impacts on the business.

Again, I would refer you back to our Q1 comments about June. When we have a record rain month, there's no way around it that's going to impact our operations, but it doesn't impact the year or any long-term perspectives on the business. We are experiencing cost inflation due to oil prices. As diesel prices go up, it just -- it goes through everything from groceries to cement products. And so we're working hard to get our prices up to offset those cost increases, but that's always a challenge. It always will be.

You don't always get the cooperation from your competitors that you would hope you would get. But I would say, generally, our customers understand the issues that we're dealing with and are working with us to make sure that these cost increases don't have long-term impacts on our margins. We still view Western Canada as a great place. We're expecting increasing activity for all the reasons that we've referred to before. The oil egress has really increased. The LNG is going well. We expect this to be a growth basin for years to come.

The 5 areas of growth that we're counting on is increased activity in the industry, market share growth just due to the fact that we have industry-leading and most technically advanced equipment, well intensity growth, meaning more sand, more stages, just means more time on location for us and cement and coil expansion as those businesses are getting increased focus from the new people in place that are running those divisions.

And lastly, our last mile logistics. As the sand volumes grow, -- we expect that we're going to grow our last mile logistics fleet, trucking fleet. We're an industry leader in efficiency in that space. So we'll continue to rely on that as we go forward. And I don't think anything will change. I think you'll see the Duvernay grow in significance, but the bulk of the activity will be split between the Duvernay, the Montney and the Deep Basin in general. So just on to value for shareholders long term and return of capital. As Scott mentioned, we're debt-free. We completed the Iron Horse acquisition. We paid all that debt off ahead of schedule. And so now we're sitting here with a completely clean balance sheet and a little bit of positive cash. So that will enable us to go on the hunt for attractive acquisitions and lean in a little harder on our NCIB as everybody knows, we subscribe to a diversified return of capital strategy, which is a combination of a sustainable dividend, the NCIB and M&A opportunities when they represent good value.

We're always measuring the cost of buying our own shares with the cost of making acquisitions or theoretically what those acquisitions would cost. And so we move cash around to what we think is the best, lowest cost alternatives. And in the past, it was buying our own shares back, but we actually are fairly excited about various M&A opportunities that seem to be available in the current market. We'll work through those. We'll be diligent. And if we find a good deal, we'll certainly act on it. We have more than enough capacity to act on any acquisitions that we feel will be additive to our company.

Long term, we're still sort of expecting that approximately 50% of our free cash will get returned to shareholders in one form or another. And that will vary from year-to-year just based on opportunities that are available and versus our NCIB. So we're not afraid to use our bank lines to buy our stock to buy -- to make acquisitions just as we did in the past and as we did with the Iron Horse transaction. So nothing's changed.

Our priorities are build a resistant, sustainable and technically differentiated company, invest in high-quality growth and upgrading opportunities to ensure a good service offering for our customers and provide a consistent return of capital to our shareholders through the dividend and NCIB when appropriate. We feel really good about what the next 6 months and the next 5 years brings. We're the largest, most technically advanced pressure pumper in the market with the best balance sheet, and we're operating in a basin that has arguably the most upside when you compare Western Canada to all the various plays in North America. So we feel really good about the business, and we're looking forward to showing it. So I think I'll stop there, and we'll go to questions.

And our first question comes from the line of Aaron MacNeil with TD Cowen.

Brad, I'm hoping you could give us maybe a bit more detail on the activity outlook for Q3, given your comments on the second quarter and the third quarter is often your best quarter of the year. So I guess just to clarify, are you expecting that some of the Q2 activity as a result of rain was deferred into Q3 or Q4? Like are we setting up for maybe an outsized second half in your view?

Yes. It's too early to make those predictions. The answer to that is yes, depending on the division. like we're -- and Iron ore is a good example. Like there -- you take activity out of Q2 and move it into Q3, it's pretty much just a one-for-one timing change. Depending on the other divisions, you may get it or you may not based on the fact that we're busy, we can't get to everything now. And so you might end up losing a bit of work here and there just due to availability and the fact that sometimes customers just aren't willing to wait. So I don't want to make predictions on an outsized Q3. I mean we think Q3 is going great.

You made a comment about, it's typically our best quarter of the year. Like what we've seen now is Q3, Q4 and Q1 are all pretty similar. And I think last year, we had a bunch of work bump out of September and it moved into Q4, which kind of level loaded those 2 quarters. So hopefully, if it stays like that, it's really helpful from a staffing perspective. If we can kind of keep the workload level for most of the year, breakup is breakup. There's nothing you could do about it. But from an efficiency, a cost efficiency perspective, you don't want to staff up for short periods of time.

And so whenever possible, we're trying to build a book of business that's fairly consistent from sort of July 1 to March 31 because it allows us to -- as you've seen, we're typically the most profitable pressure pumper in North America from a margin perspective. So -- and that's one of the reasons why is we're not afraid to sort of put a lot of work trying to manipulate our book of business to allow us to run as efficiently as possible and not sort of disappoint customers from a timing perspective.

Okay. Yes, that's fair. You also mentioned in the disclosures some sustained pricing pressure. I think last quarter on the conference call, you had sort of hoped that it had hit a trough. What's sort of your latest views on prevailing pricing given that the back half looks pretty decent? And what's your ability to sort of push through the higher diesel prices and other inflationary pressures?

No, I think that comment was accurate. Like I think that was the trough. What's not coming through in our financial results is the loss of sand.

As you know, one of the trends is for our customers supply their own sand, and so we've lost that margin. And just due to competitive pressures, you can't always recover that with cage and things like that. So what you haven't seen in the financial results is just how much work we've done in the background to offset that EBITDA loss over the last couple of years. And so you don't -- even though pricing is maybe moving up, it might not be obvious because it's getting offset with the loss of sand margin at the same time. But I think that comment is valid like I think pricing has bottomed out in the first half of the year, and it just gets better from here.

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

I know it's early, but can you just sort of talk through what you might be thinking for 2027 capital expenditures. You've got the $122 million budget for 2026, including the first 100% nat gas fleet. How should we roughly be thinking about the big pieces for 2027 at this stage of the year?

If I was building your model, I would probably just hold it flat from year-to-year, kind of a redo like if that equipment performs as well as we think it will, we'll build more of it. But so far, the performance of that -- those new 35-20 engines from cat has been really good. I would do a repeat on CapEx. We're a long ways from a Board approval on CapEx, but that's probably a good placeholder.

Okay. Perfect. Can you just speak to maybe the pricing or the margin uplift you're able to get from that equipment? You mentioned a lot of gas savings for your customers from being able to burn natural gas. Like are you at the stage where you can share in a lot of those savings? Or do you still see the market as balanced to slightly oversupplied given the amount of pressure pumping equipment that is out there? I know one of your peers announced a little while ago that they're also bringing a 100% gas fleet to Canada. So what are you seeing on that front?

Yes. So overall, the market is balanced, but the 100% natural gas assets and the electric ancillary equipment is not -- that equipment availability is not balanced. There's only a couple of spreads in the basin. We're the only ones with electric ancillary equipment like blenders and things. So the fuel savings when you look at today's diesel pricing and today's gas prices, it's significant, like it's as high as $3,500 an hour, right? It's -- so we're going to -- I don't want to say how much of that we're going to capture, but it's fair to say we're going to split it. And that fuel savings changes every day with -- as diesel prices change, but certainly, no customers are expecting to get the entire savings. They understand we have to get a return on our equipment. So what exactly that split is going to be, we never disclose that.

And your next question comes from Tim Monachello with ATB Cormark.

Most of my questions have been asked already, but maybe you could just dive into like what your white space looks like through the back half of the year and like the visibility that you have for equipment utilization and what your customers are telling you on the leading edge in terms of activity levels over the next few months?

It's like it's -- there's always white space. If you ever -- you don't have white space, you're not charging enough. I would say the Street estimates, we feel really comfortable with them. So that's probably the best way I could summarize activity levels. When we look at consensus estimates, they look very, very reasonable.

Okay. That's helpful. And then like in terms of market supply/demand, one of your competitors talked about the Canadian market, pretty optimistic long term like you are, but also said that they don't think that the market is ready to absorb net equipment additions. So when you bring in that 100% nat gas spread, do you expect that to be incremental to activity for Trican? Do you think that's going to be displacing a Tier 2 fleet either in your -- within your business or outside?

Well, we hope it displaces somebody's Tier 2 fleet, hopefully not ours. We expect 5x as much demand for that equipment as we have availability. So somebody's fleet is going to get displaced.

Okay. Got it. And is pricing in the back half increasing enough to offset the cost inflation? Or do you think there'll be a drag like maybe even temporarily just on margins just given the pace of...

I would say it's a net zero so far. Pretty much our price increases are just offsetting a lot of like the inflation that resulted from the oil price spike in, I guess, it was March. That was more significant than we actually expected. So we've been playing a bit of catch-up there.

[Operator Instructions] And our next question comes from the line of Colby Sasso with Daniel Energy Partners.

Cost of sales for the quarter rose to 94%, up from 81% in Q2 '25. And it was noted that it was primarily driven by the Iron Horse integration costs. Going forward, we expect -- we do expect like lower 80s run rate for total cost of sales? Or is Q2 going to be seasonally a little bit higher? And just what are your thoughts around that going forward?

I'll turn this over to Scott. But remember, Q2 in Canada is in no way similar to the other quarters. The sales are always lower. The discounts are higher, and we run a relatively high fixed cost business. So just you got to watch your percentages and your ratios there. When you look at Q2, it's not indicative of the other 3 quarters. It's not like in the states where it's pretty flat. There's a huge down dip in activity in Q2 for the most part. And it's way lower. that down dip is way lower than it used to be, but it's still down. And when you have a high fixed cost business, that impacts your percentages significantly.

Yes. The only thing I would add is I think your premise is correct that you'll see a higher-than-expected percentage in Q2. It will moderate as we go through 3, 4 and 1. And it should -- it will normalize out kind of what we've seen historically.

Perfect. And then on your call last quarter, you noted that you had just started work on your first wet sand completion. I just wanted to get an update on how the well went and if you've seen any more interest in wet sand and what -- any thoughts around wet sand are?

Yes. There's lots of interest in wet sand. I mean the market is sort of split in 2 with respect to wet sand. There's the local sort of gravel pit wet sand, which is very low quality. And I don't think you're going to see that really take off. And then there's the wet sand that's coming from the actual like professional sand, frac sand mines. And what we're seeing there is you're sort of skipping the last couple of stages of sorting and drying -- and so you still have very high-quality sand, but just not -- maybe not as refined and certainly not as dry. Like what we love about what we're hopeful about wet sand going forward is it's a lot nicer to handle on location. You don't get all dust. And so from a staff perspective, it's certainly -- it's a nicer product to deal with. It's really early days on wet sand. And I would say we're basically indifferent right?

And it's going to increase some trucking because the sand is heavier because it's wet. And so we're sort of looking at this as, look, the customers choose whatever sand you want. The nice thing about wet sand is it's cheaper, so they're probably going to pump more of it. That's good for us, more time on location and more trucking. And if the customers are happy, great. We want their returns to be as high as possible so that they get busier. So -- but it's really, really early days. It's not like in Texas where you have really high-quality wet sort of local sand available sort of immediately adjacent to the activities to the field activity.

In Canada, it's much more -- it's lumpy. There's a few sand mines spread around the basin, but you have -- you can have very long trucking distances, which can make wet sand uneconomic. So comparing wet sand in Canada to Texas, I wouldn't do that if I were you.

And with no further questions in queue, I will now hand the call back over to Brad Fedora for closing remarks.

Okay. Thanks for your time, everybody. We appreciate it. The management team here is available all day. So if there's any follow-on questions, please call us, and we'd be happy to answer any questions that you have. Thanks again.

Thank you again for joining us today. This does conclude today's conference call. You may now disconnect.

Hello, and welcome to the Trican Well Service's First Quarter 2026 Results Conference Call. [Operator Instructions]

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 Matson, our CFO, will give an overview of the quarterly results for Q1 2026, and then I'll provide some comments with respect to the quarter, 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 are 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 31, 2025, for a more complete description of business risks and uncertainties facing Trican. This document is available both on our website and on SEDAR.

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 SEDAR 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 EBITDAS 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 EBITDAS, we add back the effects of cash settled stock-based comp recognized in the quarter to more clearly show the results of our operations and remove some of the mark-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 $0.14 per share, both on a basic and fully diluted basis compared to the $31.9 million and $0.17 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 of $49.6 million during the quarter. Our definition of free cash flow is essentially EBITDAS less nondiscretionary 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 frac 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 noncash working capital of $142.7 million and net debt of $29.8 million, both measures meaningfully down from the December 31, 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 756,90000 shares (sic) [ 756,900 shares ] under our NCIB 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 $0.055 per share, reflecting approximately $11.6 million in aggregate payments to shareholders. Distribution is scheduled to be made on June 30, 2026, to shareholders of record as of the close of business on June 15, 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.

And 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.

Yes. So we've been very active. It's been a big investment avenue for us, and it's definitely something to consider. We've -- we view the NCIB as M&A, sort of risk-free M&A of a very -- 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 will -- 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 are still generally pretty happy with the quarter.

A lot of tough weather in February, which we always budget for. But certainly, we were dealing with some 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 very focused on our technology and our efficiencies, particularly now with the ability to burn natural gas in our natural gas fueled frac 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. So we are the leader in Tier 4 technology.

I think we have 86 -- 78 Tier 4 frac pumps. So we're the leader in that. And then we have 4 sets of electric ancillary equipment, which is like the blenders, the Chem van, Data van, sand assets, et cetera. And so when you combine our Tier 4 frac pumps with our electric equipment, 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 is 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 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. Condensate pricing, it's well over CAD 100 as high as CAD 145 at one time, I think. So all 4 of our divisions, the 2 frac divisions, the coil and the cement division are all performing well, and we're really happy with the strategic direction of all 4 of those. And I'll just make some comments about each one.

On the Trican frac division, which is the deep work, which is very 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. 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 it's -- you 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. So we are losing some of that, and we're just trying to figure out every way possible to offset that loss. And particularly, we view the logistics offering that we have or our logistics division as the main way that we're going to offset that. And so we've been growing the Logistics division. We have the largest fleet 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 3 of them. We're expecting that to go really well. There'll be a big fuel savings there. They have as far as an 1,100-kilometer range. And so even though the natural gas fueling infrastructure wouldn't -- isn't as developed as we expect it to be in a few years, we don't think that will 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 frac 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 2-for-1 basis, our old equipment. And so we're expecting less people on location, a smaller footprint, able to -- 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. And 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. 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. They continue to add new clients and our customers are coming to them asking their ability to execute given increased programs. We fully expect this 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 Montney 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 all -- that's good for both the customer and us. And 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. So it's really -- the 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, 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 year. But we certainly expect that, 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 the 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. 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 customers' wells 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 going forward, I would say -- 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. 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 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 inflation 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. I think generally, as these volumes grow, the customers want to see 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. 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, 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 U.S., 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 we -- when we look at Canada, we see growth coming from 5 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 just to remind everybody how much that has changed. I think in 2021, there was about 4.5 million tonnes of sand pumped in Canada. And in 2025, it was 8.5 million tonnes. 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 Montney 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 value 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'd 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 a return of capital. We combine that with the dividend that we're paying. And between those 2, we expect that approximately 50% of our free cash flow will get returned to shareholders in one form or another going forward. And of course, that will vary given what's available to us from an investment and organic growth perspective.

But 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 is 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 our corporate priorities remain unchanged: build a resilient, sustainable and differentiated company that the customers value, 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, the NCIB.

And again, it's why would you own this? Why would you want to buy these -- buy our shares? And 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. So we just think this probably just gets better going forward and certainly over the next 5 years. So we're really excited about -- we're really excited about the future.

Maybe I'll stop there, Kathy, and we can go to questions.

[Operator Instructions] Your first question comes from Keith MacKey of RBC Capital.

Maybe just to start out on pricing. I know you mentioned that there was some 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 Brad, what are your expectations for how much slack is actually in the system? And ultimately, what do you think it would take to move pricing up a noticeable amount?

That's not one question. That was about 5 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 just -- we, as an industry, just get better and better at what we do, and we're able to -- 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've now taken a frac crew out of the float. And if that's happening all over the basin, whether it's shallow or deep work, that capacity is just going to tighten up.

I think pricing was particularly low in Q1 because I think there was there was some tough -- some of our competitors were having a tough Q4 and maybe 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, it may be 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, I think optimism surrounding a much more business-friendly government. I think the importance of Canadian oil and gas supply is being -- is really highlighted by what's happening here in the Middle East. Certainly, we've always known it as an industry. And I think now sort of I think 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 will just tighten up the supply and demand equation, and that there will be -- 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 had 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 just the industry as a whole. What -- when is the exact timing, that's not important. That's I think most people are investing in this for the next 5 years, and we certainly don't have any reason to believe that the next 5 years are anything but bullish.

Okay. Makes sense. And I'll follow up with just one question. So the -- you've got one 3520. Can you just run us through when you expect to have that replacement fleet in the field, assuming it is a replacement fleet?

Yes. 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.

Your next question comes from Tim Monachello with ATB Cormark Capital Markets.

Just a quick follow-up to Keith. Are you guys 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?

End of the quarter.

Okay. And then 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 an acquisition?

Say that all again, Tim, you went -- 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 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 think some issues with my headset or something. So can you hear me?

Yes, we got you, Tim. I think I understand your question, Tim. Like I mean 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 next year with stronger oil prices, I mean, that outlook is improving. So do we get back to and exceed that number? I mean, hard to say at this point, but we're pretty optimistic with what we're seeing in the back half of the year.

The next question comes from Colby Sasso of Daniel Energy Partners.

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?

Yes. 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 yes, with sand volumes increasing and obviously, the cost of sand being a very significant portion of their overall fracturing bill, customers are -- 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. But from a -- we're relatively sort of indifferent in many respects. And from a transportation perspective, that sand has still got to move from A to B. There's no shortage of sand to move. And so 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.

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

Congratulations on the great quarter. One question for me is really, you have those 4 frac fleets that are not working at this point. Are you having customer in contact with you to look at maybe mobilizing them in '27? And 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?

Yes. Okay. Thanks for prompting me on this, Josef. 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, diesel frac pumps with diesel engines. They work fine. 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's a few extra frac 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 -- 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 always needs a bit of tweaking here and there. So I don't -- but I don't really have that cost 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 in plays like the Montney and the Duvernay because the world has moved on from those assets. So it's not really -- a customer is not going to come to you and say, geez, I'd like you to bring your 10-year-old diesel fueled frac pumps off the fence and put them to work on my well. They're coming to us saying, like 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 4 frac pumps and our electric ancillary equipment opposed to figuring out where sort of frac pumps built in 2013 are going to end up. The world has advanced considerably since those assets were built.

So if there was a demand increase for modern fleets, would that potentially have to come from somebody bringing a fleet in from the U.S.?

No, we would either build new or retrofit that equipment. But that -- now you are talking about sort of a $30 million to $40 million per fleet investment and probably a 1-year lead time. But 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.

And 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.

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 are 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.

Good morning, and welcome to Trican Well Service Fourth Quarter 2025 Results Conference Call. [Operator Instructions] As a reminder, this conference call is being recorded.

I would now like to turn the call over to Brad Fedora, President and Chief Executive Officer. Thank you. Please go ahead.

Thanks, Rud. Thank you, everybody, for joining us, and good morning. First, Scott, our CFO, will give an overview of quarterly results, and then I'll provide some comments with respect to the quarter, current operating conditions and the outlook over the next few quarters, and then we'll take some calls. There's a few members of our executive team in the room today, so we should be able to answer any questions that come up.

And I'll now turn the call over to Scott.

Thanks, Brad. So 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 are reflected in the forward-looking information section of our MD&A for Q4 of 2025.

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 31, 2025, for a more complete description of business risks and uncertainties facing Trican. This document is available both on our website and on SEDAR.

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 the close of market on Wednesday evening and are available both on SEDAR and our website.

So with that, a brief summary of our quarterly results. And my comments will draw comparisons to the fourth quarter of last year, and I'll provide some commentary about our current activity levels and expectations going forward.

Trican's results for the quarter compared to last year's Q4 were generally stronger as overall operating activity came in a bit higher despite a challenging commodity price environment exiting the year. Our results for Q4 of 2025 also incorporate a full quarter of Iron Horse results following the closing of the acquisition in Q3 of 2025. Oil pricing was challenged as we came through the second half of 2025 and had a significant impact on Q4. Oil-focused customers delayed and in some cases, shelved projects in response to deteriorating economics, significantly impacting the Iron Horse division during the quarter.

But overall, our revenues for the quarter were $322.7 million compared to the $275.5 million we generated in Q4 of 2024. Adjusted EBITDA for the quarter was $73.4 million or 23% of revenues, compared to adjusted EBITDA of $55.6 million or 20% of revenues generated in Q4 of 2024.

Adjusted EBITDAS for the quarter came in at $75.3 million or 23% of revenues, up from the $58.6 million or 21% of revenues in Q4 of last year. To arrive at EBITDAS, we add back the effects of cash-settled share-based compensation to recognize in the quarter to more clearly show the results of our operations and remove some of the mark-to-market impact of the movements in our share price between reporting dates.

On a consolidated basis, we generated positive earnings of $31.9 million in the quarter, which translates to $0.15 per share, both on a basic and a fully diluted basis. We generated free cash flow of $46.6 million during the quarter, and our definition of free cash flow is essentially EBITDAS less nondiscretionary cash expenditures, which includes maintenance capital, interest, current taxes and cash settled stock-based compensation. You can see more details on this in the non-GAAP measures section of our MD&A.

CapEx for the quarter totaled $15.1 million, split between maintenance capital of about $12.8 million and upgrade capital of $2.8 million. Our upgrade capital was dedicated mainly to the electrification of our fourth set of ancillary frac support equipment and ongoing investments to maintain the productive capability of our active equipment.

From a balance sheet perspective, we exited the quarter with positive noncash working capital of $179.2 million. At December 31, we had debt of $79.9 million, net debt of $79.9 million, comprised of loans and borrowings of $92.4 million, which was offset by cash of $12.5 million. Our debt at December 31 was primarily related to the acquisition of Iron Horse and our normal working capital and investing activities during the quarter. This translates into just under 1/3 of a turn of leverage using our trailing 12-month EBITDAS figure and a portion of this is already unwound, and we expect our net debt position to trend downward as we move through 2026.

With respect to our return of capital strategy, we repurchased and canceled 1.4 million shares under our NCIB program in the fourth quarter. On an annual basis, in 2025, we repurchased and canceled 12.1 million shares at a weighted average of about $4.35 per share, representing 6.4% of the shares outstanding at the beginning of the year. Subsequent to Q4 of 2025, we've repurchased and canceled about 300,000 shares, and we 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 $0.055 per share, reflecting approximately $11.5 million in aggregate to shareholders. The distribution is scheduled to be made on March 31, 2026, to shareholders of record as of the close of business on March 13, 2026. And I would note that these dividends are designated as eligible dividends for Canadian tax purposes.

So with that, I'll turn things back to Brad.

Okay. Thanks. I think overall, Q4 went really well and pretty much as expected. We've worked hard in the last few years to try to create a customer list that has allowed us to be fairly level loaded throughout the year with maybe the exception of a little bit of Q2, but it seems to be working. Our quarters all now seem to be quite similar in volumes, and that's a great advantage from a staffing and an equipment allocation perspective as you can rightsize the business for the entire year, you're not just staffing for the peaks and then absorbing the costs during the valleys. So I think all of that has gone really well for us.

I mean, as usual, it seems like in Q4 lately, we did experience some pricing pressure. Just some of our competitors are less busy than we are, and they're trying to fill their board. We generally just sort of get through that. Of course, we don't live in a vacuum, but most of our customers are all very long-term relationships, and we seem to get through a lot of that. Obviously, we have much improved natural gas prices compared to the last 18 months. So that has helped. I mean it's been a very warm winter in Western Canada. And I think we've done a really good job of sort of fighting our way through that. We had very much spring-like conditions for the bulk of February and lots of January.

So it's been a little bit choppy, but I would say we're having a good quarter, and we always factor that into our forecasting. And so I think Q1 will be very much in line with consensus. I don't think there'll be any big surprises there, even though we did have some tough weather to deal with.

Our customers are still very focused on technology and efficiency. I think we've done a really good job with this. Particularly, they want to burn natural gas in place of diesel anytime they can just due to the cost savings and the lower emissions. And so our pumping assets, in particular, and our electric equipment, that's [indiscernible] leading the industry with that regard. We're very fortunate to have a customer list that is focused on technology and does recognize the investments that we've made. And so we're working together to make sure that as their programs develop and evolve, we're making sure that we keep up from an asset and a technology perspective so that we can look at the long term together and say, what is this industry going to look like in 5 years and make sure that we're on the forefront of those changes.

I would say even with the Iron Horse acquisition, most of our work is natural gas. We're probably 70% natural gas and 30% oil projects. So we're happy that natural gas has got back to more reasonable levels. Obviously, oil in the last week or so above $65 or even [indiscernible] very helpful to the Iron Horse division, and that should make for a sort of a much more robust year this year than last year. So we're kind of crossing our fingers that oil prices hang in there.

We have seen a lot of the BC work slowdown but it's been more than picked up by the Duvernay work that we've been doing. So we're not really experiencing any changes there. In many ways, the Duvernay work is right in the backyard of a few of our operating bases. So happy to be in that play.

And I'd say, in general, all 4 of our divisions being Trican frac, Iron Horse frac, Cement and Coil are all working really well. And I'll maybe just touch on all 4 of those divisions.

So the Trican frac, which is the deep fracking, the big pads in Northwest Alberta, Northeast BC. Again, going very well. We've spent the last few years really differentiating our service offering with natural gas pumping assets and electric ancillary equipment on location. We're the only company in the basin that provides a full suite of electric assets on location, and it's been very well received. We've just put into the field our fourth set of ancillary equipment, which includes like blender and chem blending, things like that. So the sand belts, et cetera. So we basically cannot keep up with demand on those electric assets. When you combine the electric equipment with our Tier 4 equipment and in the future, 100% natural gas equipment, you'll have basically almost full displacement of diesel on location. So again, very well received. Without a doubt, we would be viewed as the technical leader in this industry with respect to [indiscernible].

We're still seeing wells get longer using more sand per well. I think this -- in 2025, I think we pumped about 8.5 million tonnes of sand as an industry. And there's lots of analysts that are forecasting that, that's going to grow to over 12 million tonnes per year by 2030. So that's, without a doubt, a trend that we're making sure we capitalize on. And the flip side of that, though, is we are seeing more customer supplied sand, which is fine. Our customers are looking to save money wherever they can, that's okay. We'll try to replace some of that margin with our greatly expanded logistics business. We've really focused in the last few years of building up our logistics because you're dealing with these kinds of sand volumes, and again, I've used some of these analogies before. We've got 50 to 100 railcars of sand being pumped into a well over a period that might only be 48 hours long. And so you're having a B train of sand show up every 12 to 15 minutes on locations.

Getting that logistics part right is a huge driver and efficiency for our customer and profitability for us. So we've done a fantastic job of building out our logistics business. We're not able to actually build it as fast as we would like it just due to availability of drivers. But we will continue to expand that. We're a leader in sand logistics in Western Canada, and I don't see that changing anytime soon.

And just to put this into perspective, we were on a Duvernay well not too long ago, where over a 24-hour period, delivering sand with our trucking fleet, I think we drove over 60,000 kilometers in a 24-hour period, which is 1.5x around the world. So it helps put that in perspective just how important logistics are, especially in a compressed time frame like we're dealing with. So kudos to our logistics team, and we'll continue to highlight that and showcase that to our customers to help continue our differentiation.

We have received now our first 100% natural gas Cat, what are called 3520 natural gas high-rate frac pumpers. The testing of that equipment is going very well. It will be deployed into the field in the second quarter. We expect to have a full suite of a 10-pumper frac spread available and operating by early fall. And what this enables us to do is have less pumps on location, less people, pump 100% natural gas instead of a combination of natural gas and diesel.

So for our customers, it means lower fuel prices, lower emissions. And for us, I think these new assets will be a little bit better at dealing with a variety of field gas. So we should have more efficient operations on that -- in that respect as well. So really looking forward to that. And when you combine those assets with our electric ancillary equipment, we'll have basically 100% natural gas operation.

As well later in the year, we will be receiving our first natural gas semi-trucks. So what pulls the big tractor units that pull the sand around. And we will slowly but surely evolve our trucking fleet to run on natural gas. We're a little ahead of our time with respect to the fueling stations that are available throughout Western Canada. So we are going to be working with our customers in conjunction with them to make sure that there are fueling stations in all the places we need. But really looking forward to this. Again, lower fuel prices should be lower R&M. And just generally, it's nice to see that we are -- we as a service provider are burning the natural gas that our customers are producing every day. So we're working with them in conjunction to really build out a rounded industry.

On the Iron Horse frac side, which is sort of on the oilier coil fracking. Really happy with the acquisition. The integration is going really well. I would say we're very pleasantly surprised with the synergies that we've been able to extract. And with respect to things like fuel, chemical sand, we hadn't really built a lot of that into our acquisition, but I think that is working better than we had hoped or certainly better than we had planned on.

Obviously, we're a little disappointed with oil prices post the acquisition. Field work volumes came down. That's okay. Oil prices have firmed up here, and I expect that they'll be getting up to a level that we were sort of banking on last year. But the acquisition has gone very well. They're the #1 provider in that part of the world, which is sort of Eastern Alberta, Saskatchewan, into Central Alberta. They provided us with [indiscernible] previously, we had almost 0 market share. We'll use their relationships to grow our Cementing business in that part of the world as well. So very happy with that acquisition.

On the Cementing side, Cementing division continues to perform extremely well, very high market share in plays like the Montney and the Duvernay. We have expanded recently into the SAGD market in the Christina Lake area. That's gone very well. We expect that we will be able to grow that sort of area fairly significantly over the next 18 months. I think in Q4, our revenue and jobs were up 33% in Q4 over 2025 versus 2024. So that division continues to perform very well.

We're adding AI technology to things like our bulk plant to reduce blending errors, increasing blend qualities for our customers. So even though we've been active in that business for a long [indiscernible] we're taking advantage of technology anywhere we can to make that division perform even better.

We actually will have what we will call like a hybrid cementing unit soon, too, where it's partially electronic or electric. So getting rid of a lot of the hydraulics that you can have trouble with in [indiscernible]. So I would say slowly, but surely, that division will evolve into sort of an electric style equipment just much like our natural gas or our fracturing assets.

On the Coil side, the buildup of the Coil business is going very well. We have reorganized our management team about a year ago or so. And now that division is getting the attention that it always needed. A great portfolio of customers. We have all the top operators in the basin. We set horizontal and depth records last year. Those -- our performance field has allowed us to add Montney and Duvernay customers. We have lots -- we have a wide variety of oil strings. So I would say that division build-out is going very well, and it's now sort of financially performing more consistent with the other 3 divisions as well. So I think that will slowly surely just grow in size and scale, which [indiscernible].

On the long-term outlook perspective, we're still incredibly bullish about Western Canada. When we look at the plays here like the Montney and the Duvernay in the context of North America, this is the place to be. I think the key with being a service provider in these plays is you've got to be constantly pushing and evolving your -- the technology offering that you have and making sure that as these plays get developed, we become more and more efficient. And we are seen as sort of the technical leader in the pumping space, which certainly we have been.

You're going to have ups and downs based on the gas price, et cetera. But certainly, when you view what's happening on the LNG side, getting up to full capacity this year with more LNG to come, we think there's going to be like a foundation of gas pricing in Canada for the next years and beyond. And certainly, we are very happy with the position that we've built up in place in Northwest Alberta, Northeast BC, which will be fueling LNG.

So it's a great place to be. We're not looking to change any of that. In fact, if anything, we're looking for acquisitions going on, not even with just consolidation [indiscernible] Iron Horse, but other service lines as well, just because we think Western Canada will be a great place to be operating for the next 5 years and beyond.

And where do we see sort of revenue growth come from? It's obviously the well count will increase as the gas price solidifies and grows. We're seeing increasing sand volumes going into each of these wells, which just means more time on location for us. We're seeing our Logistics division expand. And when we look at the Coil and Cement divisions, we think both of those divisions can continue to acquire market share in all of the plays in Western Canada. So again, we are very optimistic about the next 5 years.

Just back to the return on capital that Scott had touched on, we generate -- we continue to generate significant free cash flow. And we expect that we'll maintain a conservative balance sheet. We've always subscribed to a diversified return of capital strategy, meaning a combination of dividends and NCIB. The NCIB volumes will go up and down with the opportunities in the context of the other opportunities. We very much view our NCIB as M&A. But I would expect that over the next few years, we will allocate probably around 50% of our free cash flow to shareholder returns, whether it's in the form of dividends or NCIB. And just we'll always be looking in the context of the market to see what else is available. We're not afraid to use our bank lines. We do hold a conservative balance sheet, but that's to make sure that we have the capacity when we need it.

So we're not afraid to use our bank lines if we find an attractive investment or even organic growth opportunities like we did with Iron Horse. We're always looking for the best possible returns for our shareholders, and we'll allocate capital accordingly.

We are starting to see, I would say, more growth opportunities than we've seen in prior years. And we'll just be very diligent and disciplined when we're looking at acquisitions and good things take time. So we won't get over our skis. We'll just be very analytical, and we'll see if we can get something interesting done in the next few years.

So I just want to stop there, given it's year-end, I just want to say a thank you to our customers and our employees. And as I think everybody knows, Trican is committed to improving its workplace safety and creating an environment for our employees. We operate a very complicated business with large capital requirements. We're in the field 24 hours a day with logistics and engineering support, running specialized equipment in very remote operating areas under what are fairly extreme conditions. Our employees make our field execution look easy. And I can assure you, it is not. So thanks to our customers. Thanks to all our employees for their dedication to Trican and the Iron Horse division, which is now part of the Trican family. And I just want to say thanks to everybody as we can't do it without all the great staff that we have.

So I'll stop there, operator, and we'll turn the call back for questions.

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

First question, you may not want to get into specific customers, but ARC recently removed Attachie Phase 2 from its 5-year plan and has withdrawn its broader Attachie-related guidance. Have you seen any direct impact of this yet? And how are you thinking about it in the context of overall basin demand for pressure pumping on a go-forward basis?

Projects are always being added and subtracted. We're not fussed by that. I mean there's nothing wrong with certain people like ARC sitting back every once in a while and saying, "Hey, can we do this a little differently? Can we do this a little bit better?" I mean maybe they should have used the dust to frac their wells. So -- but we're not too fuss. We're not too fuss by stuff like that. You're going to see that from time to time. It's an active basin. It's a technical basin. It's -- there's not -- that's healthy.

Fair enough. But safe to say you didn't have any exposure to that directly?

No. We do work for them. There's no such -- we don't operate in a vacuum, like when things like that happen, assets get freed up. But no, I mean, we're still very bullish on Northwest Alberta and Northeast BC.

Fair enough. Can you say a bit more about wet sand? How prevalent is it today? How prevalent do you think it will be in the future? And what the potential impact might be on your sand infrastructure assets and logistics businesses?

Yes. Like what Aaron is asking about is there's recently a few companies have been trialing wet sand in Western Canada. And what that means is just using a lower grade, but closer source of sand that generally comes more almost from a gravel bit than a frac sand mine. So it's not sorted. It's not dried, questionable consistency and quality, but it's close, which means it's cheap. Because by the time frac sand gets to location, probably 70-plus percent of the total cost of that sand is just the transportation of it. And so any time you get the opportunity to use a sand source that's very close to the project area, there's a big opportunity for transportation savings.

Now you're -- what you're saving in transportation, you're giving up in sand size, consistency and quality. But [indiscernible] they did it in the U.S. I think we're having a look at it in Canada because it does have -- frac sand today is dried, because it does have water and it makes it a little tricky to operate in the winter. But we're -- the customers are going to trial it. It still needs to get from A to B. And so our logistics group is still going to be very much active in that.

We don't really hold any other fixed assets from a logistics [indiscernible] I think any time the industry has the opportunity to cut costs, which will undoubtedly result in more wells being drilled, I think that's a good thing. But it will be a while yet before the wet sand sort of opportunity gets [indiscernible] very limited volumes at this point. It has been just a handful have been trialed with inconsistent results, frankly.

Our next question comes from John Gibson from BMO Capital Markets.

Just on pricing, you talked about it coming off in Q4 and to start of the year. As we think about the improved commodity backdrop and maybe a pickup in gas-related drilling, how do you expect pricing to go up or down as '26 progresses?

I think it is going to be fairly level here for a while with, I would say, an upside bias just with improving commodity prices [indiscernible] hard to say when, but...

Does it differ per region? Or does it kind of rise and fall across the basin fairly evenly?

I would say it differs with definitely -- there's two very distinct -- there's natural gas and then there's oil with our Trican frac division versus our Iron Horse frac division, they're in two very different commodities, right? So you definitely can have sort of opposing forces going on at any given time. So we definitely would look at the two commodities distinctly there for those two divisions.

Got it. In terms of the new fleet, will this be additive to your current horsepower? Or is it going to replace some older equipment?

No, we certainly hope it will be additive. When we were ordering this and just talking with our customers about what their plans were for the next 5 years, we don't see any reason why this won't be additive. But you may never get the timing exact, but certainly, we ordered this with the intention that it is fleet.

Okay. And then last one for me. I'm not sure if you know the answer to this, but just given your last mile logistics moves over the past few years, along with some of your peers, can you estimate how much capacity you've added to the basin in terms of pumping capacity that was maybe previously constrained?

So what you're asking is, with improved logistics, how much pumping capacity increase does that result in?

Yes. It seems like the last few years, one of the constraints was last mile logistics, and you and your peers have been working on this for quite a while. So I'm just wondering if and when things turn a little bit, what is the incremental sand you could pump or that sort of stuff that was previously constraint?

I couldn't tell you the answer to that off the top of my head. I would say this, though, I think the sand volumes are going to grow faster than our ability to add logistics assets. The sand volumes have grown from 4 million tonnes a year to 8 million tonnes a year in the last, say, 4, 5 years. And I would doubt that the logistics fleet has doubled. There's a long lead time on tractors and trailers and getting experienced drivers that can drive in the conditions that we're asking versus like long-haul drivers. My guess is we'll be fighting to keep up with the growth in sand volumes.

Our next question comes from Colby Sasso from Daniel Energy Partners.

I just wanted to ask, with exports from LNG Canada beginning in 2025 and further LNG exports anticipated in 2026, how does Trican expect these developments to influence the industry? And additionally, how is the company approaching the opportunities created by this emerging market?

Okay. That's a big question. Certainly, LNG, we -- remember when we produce 19 Bcf a day in Canada, when LNG Canada [indiscernible] train, I guess, you call it, is just under 2 Bcf a day. So we -- 10% of Canadian production is now getting exported. And as other LNG assets get added, I think you just -- you put a floor in your natural gas pricing because you're not just selling into the North American market anymore. A lot of the other things we don't talk enough about, too, is our customers have very sophisticated marketing [indiscernible] where they're selling gas, not just to Canadian LNG, but actually into U.S. LNG and other sales point around the U.S. So we're not just relying on a Canadian gas price anymore.

So it should be a foundation of activity going forward that we've never had previously. And so what are we doing? I think I talked about that in the call, which is we're building the most technically advanced fleet, and we're continuing to reinvest our capital into the Canadian marketplace to ensure we're the #1 service provider as this industry unfolds in the next few years. So I think we'll be a direct recipient and our customers will be direct beneficiaries of the capital that we've invested.

Our last question comes from Tim Monachello from ATB Cormark.

I'll try to keep it short here. In terms of the commodity price rally that we've seen in oil and the Iron Horse outlook, it sounded like at least during the Q3 conference call that Q1 was going to be a pretty busy quarter for Iron Horse, and then you'll hit some typical seasonal slowdown. So I guess the reduced sort of outlook for the year, at least the Q3 was coming from the back half. So with commodity prices in that north of $65 range, do you think you can get back to that $80 million mark was sort of initially contemplated when the acquisition was done?

Yes, maybe not this year. Weather in Q1 actually probably affects them more than us, just given the wonky weather we had. So they're having a good Q1, don't get me wrong. But if we -- certainly, if oil holds into at these levels, we'll get back there. Exactly when? I don't know. But the workload is very elastic to oil pricing in that part of the world. So yes, we're still really happy with that acquisition.

Do you get any sense from customers on, I guess, a changing mood or sentiment around what they're going to do in the back half yet? Or is that too early to call here...

Yes. The sense we get is, especially here at the $65 level, oil holds in here, that will -- there will be a direct drilling response to that. You need to have it for more than a couple of days, obviously [indiscernible] but certainly, when you talk to customers, they've got lots of what ifs built into their budgets, right? And budgets go up just as easily as budgets go down. So if we hold in at the $65 level, we would expect them to have a busy second half.

Okay. Got it. And then second question, it sounds like you're building or deploying some new natural gas equipment in other ancillary service lines like in the trucking and Cementing business. Can you talk a little bit about, I guess, the capital outlay that's going to be required over the next couple of years to, I guess, integrate all of that equipment? And I guess, to what degree do you expect to replace equipment that's not natural gas or upgrade current equipment?

Yes. Tim, if we kind of look at 2026 on its own, about half of our capital program is what we would call expansion. So our $120 million split it in half, roughly $60 million of that is expansion. And the bulk of that, about $40 million of it is related to our natural gas fleet. So that's kind of a ballpark number you would need to think about if we go forward, maybe one of those fleets per year would be the maximum we could possibly do just from a timing and the logistics and a build perspective.

But we're certainly not in a -- we're not in a massive rebuild CapEx cycle. As we pick away at things like natural gas tractors and the logistics side, those are small bites as we go through. And then even thinking about the stuff that Brad was talking about around the Cementing assets, those are fairly small bites as well. So I don't see this as the start of a massive CapEx cycle. We're going to pick away on it. And the biggest chunk by far would be kind of looking at that natural gas frac fleet.

Got it. And the one cementing unit, I guess, it's going to be natural gas. Is that an upgrade? Or is that like a new unit?

It's an upgrade. And so it wouldn't be full natural gas tractor and stuff. It's -- a certain part of it will be -- will basically be electric, yes. And so it's called a hybrid unit. We're looking at fully electric, what we would call fully electric units. And what happens is you've got the electric -- these big electric drilling rigs on location. And so we sort of basically for lack of a better way to [indiscernible] when we get there. And so you're -- electrical generation equipment like frac because, of course, that just wouldn't be practical. Your cement jobs don't last that long. So as the rest of the industry sort of generates -- is generating electricity via natural gas on location that allows us to sort of evolve and build out assets that can work in conjunction with them on location.

And we have no further questions. I'd like to turn the call back over to Brad Fedora for closing remarks.

Okay. Thank you, everyone. We appreciate your time and your attention to our call. If there's anything else you'd like to ask, please just call us. We'll be in the office all day today. Thanks again.

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

Good morning, ladies and gentlemen. Welcome to the Trican Well Service Third Quarter 2025 Earnings Conference Call and Webcast. As a reminder, this conference call is being recorded. I would now like to turn the meeting over to Brad Fedora, President and CEO of Trican Well Service Limited. Please go ahead, Mr. Fedora.

Thanks, everyone, for joining us. As usual, first, Scott, our CFO, will give an overview of the quarterly results, and then I'll provide some comments with respect to the quarter, the current operating conditions and our outlook for the rest of this year and early next year. And then we'll open the call for questions. Various members of the executive team are here in the room today and available to answer any questions that may come up.

So I'll now turn this back to Scott.

Thanks, Brad. So 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 are reflected in the forward-looking information section of our MD&A for Q3 of 2025. 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 2024 annual information form for the year ended December 31, 2024, for a more complete discussion of business risks and uncertainties facing Trican. This document is available both on our website and on SEDAR.

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 2024 MD&A. Our quarterly results were released after close of market last night and are available both on SEDAR and our website. So with that, a brief summary of our quarterly results. I'll draw some comparisons to the third quarter of last year, and provide a bit of commentary about our activity levels and our expectations going forward.

Trican's results for the quarter compared to last year's Q3 were generally stronger as overall operating activity came in a bit higher in spite of continued pressure on commodity pricing. Oil pricing, in particular, was hit hard as we moved through September, which led several customers to either delay or shelf projects in oilier plays. Combined with some timing shifts on natural gas-related activities, this took a bit of the wind out of our sails on what was shaping up to be a very strong quarter. Brad will comment a little bit about our outlook on Q4 later.

Our revenues for the quarter at $300.6 million compared to the $221.6 million we generated in Q3 of 2024. Adjusted EBITDA for the quarter was $59.5 million or 20% of revenue compared to adjusted EBITDA of $50.2 million or 23% of revenues generated last year. Just a reminder that our results include the contributions from Iron Horse from the date of acquisition through September 30. I would also note that our results include $2.5 million of transaction costs related to the acquisition that were expensed in the quarter. Adjusted EBITDAS for the quarter came in at $66.9 million or 22% of revenue, up from the $53.1 million or 24% of revenues we generated in Q3 of last year.

To arrive at EBITDAS, we add back the effects of cash settled share-based compensation recognized in the quarter to more clearly show the results of our operations and remove some of the mark-to-market impact of movements in our share prices between the reporting dates. And you'll note that this number was larger this quarter at $7.4 million compared to an average of about $2.3 million over the last 4 quarters, again, due to the movement in our share prices versus June 30. And this is a very good example of why we always focus on EBITDAS when we have conversations versus EBITDA as those numbers can vary pretty significantly period-to-period.

On a consolidated basis, we generated positive earnings of $28.9 million in the quarter, that's about $0.15 per share, both on a basic and a fully diluted basis. Trican generated free cash flows of $35.4 million during the quarter. Again, our definition of free cash flow is essentially EBITDAS less nondiscretionary cash expenditures, maintenance capital, interest, current taxes and the cash settled stock-based comp piece that I talked about earlier. You can see more details on this in the non-GAAP measures section of our MD&A. And again, I would note this figure is impacted both by the transaction costs that I talked about and stock-based comp I quoted earlier.

CapEx for the quarter totaled $18.9 million, again, a split between maintenance capital of about $13.5 million and upgrade capital of $5.4 million. Again, that upgrade capital was dedicated mainly to the electrification of our fourth set of ancillary frac support equipment and ongoing investments to maintain the productive capability of our active equipment.

From a balance sheet perspective, we exited the quarter with positive noncash working capital of about $209 million. As of September 30, we had net debt of $130.6 million, comprised of loans and borrowings of $139.1 million, offset by cash of $8.5 million. Our debt at September 30 was primarily related to the acquisition of Iron Horse and some normal working capital investing activities during the quarter. And a couple of points to note that September 30 debt number translates into just over half a turn of leverage using our trailing 12-month EBITDAS figure, which does not make us uncomfortable given our outlook for the rest of this year and into early 2026. And also a portion of this is already unwound, and we would expect our debt position to trend down as we move through the end of this year and certainly into next year.

With respect to return of capital, we repurchased and canceled about 100,000 shares during the quarter and closed out our 2024-2025 NCIB program. We completed that program on October 4. And under the program in total, we repurchased 13.2 million common shares at a weighted average price of about $4.27 per share. On September 30, we announced the renewal of our NCIB program, which will allow us to purchase up to 18.4 million common shares, representing 10% of our public float as at the time of renewal. This program is scheduled to run from October 5, 2025, through October 4, 2026.

And finally, as noted in our press release, the Board of Directors approved a dividend of $0.055 per share, reflecting approximately $11.7 million in aggregate payments to shareholders. The distribution is scheduled to be made on December 31, 2025, to shareholders of record as of the close of business on December 12, 2025. 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.

Okay. Thank you. And I'll just remind everybody that my comments will include Q3 2025 and forward-looking observations for Q4 and 2026. So please refer back to Scott's disclaimer. Overall, the quarter, it went well. We obviously -- we had a great September -- July and August and then we had a bad September. It's actually one of the worst months of the year for us. But all -- that's just a reflection of work got pushed out of the month into the next month. And that's our business. We don't focus too heavily on the exact timing of the work. I know we live in a quarterly world, but from a business perspective, that doesn't get us too fast. It just got moved. The work didn't go away. So it's not -- it wasn't a concern of ours at all. And as I'll talk later, it's going to boost our Q4.

We're very fortunate to have our customer list. They continue to level out throughout the year. We don't expect that this year is going to be any different. I know there's a lot of talk about budget exhaustion into Q4. We typically don't experience that, and I don't think we're going to experience that this year either. There is a little bit of pricing pressure going on just as some of our competitors don't have busy Q4s. There's a lot of jostling to fill the board, and that always reflects pricing down. And of course, the rig count is down slightly from last year.

Again, those I think, are temporary situations. We still expect to have a good 2025 and certainly a good Q4. We remain gas focused, I'd say, corporately, overall, where about 75% of our work is based on natural gas plays. I know a lot of those plays are liquids-rich, but we're very excited about what we think is going to be a great year in 2026 for gas prices. So it's one of the reasons why we continue to be so optimistic in the context of a lot of -- sort of mooning and complaining about current environment. A lot of the cost inflation has slowed very significantly. We're actually seeing cost reductions on some of our inputs.

A lot of the tariffs that were proposed didn't happen or have been reversed. We've seen fuel surcharges come off. So that's helping sort of offset some of the pricing pressure we're getting, and we're still able to maintain pretty reasonable margins given a more negative price environment. We are experiencing lower Northeast BC work. I don't think that's any secret to anybody that follows the rig count, but it's getting made up for work in the Duvernay. And so -- which is very fracturing intensive. It's very similar to what's happening in Northeast BC.

So all 4 divisions when we think about market share and the customer list that we have, we've got the 2 frac divisions, the cement division and the coil division. All 4 of them are running really well, and we're really happy with our business plan and how it's unfolding. One thing I did want to point out because just reading some of the analyst notes is we exited the quarter with about $135 million of debt, but we also had about $218 million of positive working capital. So it's a timing issue. I don't want anybody to focus on this debt number because it's already come down substantially since month end. And this debt at this level does not concern us at all. I mean we'll likely pay it down, but that will depend, frankly, on what's available to us from an investment perspective. But certainly, debt in the 100 range does not concern us one bit.

In the frac division, in the Trican frac division, it's still going very well. We're viewed as a technical leader in the industry, electric equipment, efficient operations, our engineering, our lab group are working towards or we continue to evaluate 100% natural gas solutions. We're evaluating all of the solutions. And so I think we'll come up with the best one. We continue to add customers in the Montney and the Duvernay in the quarter if frac intensity continues to increase, making the logistics -- our logistics department, which is the largest in the industry, that much more valuable. We're focusing on technology improvements. We will be testing all of the available 100% natural gas pump technologies. And I think we'll choose the one that we think provides the best service at the lowest cost, and we continue to expand our last mile logistics. I would expect that we will add 100% natural gas fleet mid-2026.

On the Iron Horse frac division, we're very happy with the acquisition that we made. We still view this as a combination of 2 best-in-class businesses. The transaction closed August 27. And so we only had 1 month of Iron Horse in our Q3. And it's -- as we talked about in our MD&A in our outlook section, obviously, Q4 for Iron Horse is lower than we had hoped or expected or even modeled when we purchased the company. But that's just oil price related. We think it's temporary. A lot of their oil projects were canceled or kicked down the road until next year. We don't buy businesses for 1 quarter performance. We buy it for the next sort of 10 years. So very happy with that business. They're still seeing sort of more pinpoint completion designs in all of their plays.

The annual frac with fracking through coil or around coil, I should say, is still going to be the main completion technique. And even in the older plays that there are things like the Viking, stuff like they're still seeing sand volumes and stages increasing. And they have a very, very busy Q1. So that division is going well.

On cement. Again, we're very happy with the performance of this division. They've always been viewed as a technical leader in the industry. We have the best equipment, the lab, the blends, the operators. We've actually added rigs to our portfolio despite an overall year-over-year rig count decline. They continue to leverage operating efficiencies and initiatives to reduce downtime, which has enabled them to increase margins in what would be an overall sort of slightly down market. We've developed blends to target the heavier oil basins. We're aligned with all the right E&Ps, all the busy E&Ps. Our market share in plays like the Duvernay is as high as 80%. In the Montney, it's over 50% in the overall basin, our market share has grown has grown year-over-year. So very, very excited about what's happening in that division.

The coil division as well has really started to show its potential. Really pleased with how that has gone. I know we've talked about the coil division for the last several years about focusing on this and making sure that this division performed in line with the rest of our company. And I think that's finally starting to happen now. Q3 was one of the best quarters in the coil division or was one of the -- the coil division's best quarter. It had lots of operational excellence delivered with less than 1% nonproductive time, which is a real achievement to the people running that division.

Our portfolio of customers consists of the top operators in the basin. We set horizontal and total depth records this year in Canada, and that sort of extended reach operations has allowed us to add customers in the Montney and the Duvernay. So we're very happy with what the next sort of 12 to 18 months looks like. And they started to generate financial margins in line with the other divisions. So very happy with how that's worked out.

I'll just talk about the Q4 and touch very lightly on next year. We still believe our premium service offering in all of our divisions continues to be valued by customers, and I think that shows in our financial results. We're, of course, watching oil and natural gas prices. There's always potential for projects to get delayed or canceled or changed into next year. But we -- and we expect that our customers like us are taking a fairly defensive stance in their fall budget season just based on the volatility we've had on oil prices, especially. But we still think 2026 will be better than 2025. Our customers are still talking to us about equipment availability in the next few years. Well, that's a very good sign.

The LNG Canada facility has continued to ramp up its export volumes. It's now exporting in the range of about 1 Bcf a day. Natural gas prices have recovered significantly in the last month. We expect them to get better this winter and into next year. The Duvernay, as we've talked about, continues to be a busy play, very, very fracturing intensive. We were very thoughtful about the long-term development of this play and actually designed a Tier 4 spread around the Duvernay that pumps at higher pressures, higher -- longer pump times. So our equipment is better able to withstand sort of the abuse that, that play gives the average pumper. So it's reduced our R&M costs even though the pumping rates and pressures are so high.

And the Q4 to date has been great. We're still forecasting 2025 to be fairly level loaded between the quarters. And especially in a year like this where we've had so much work bumped out of September into October and November. We expect Q4 is going to be very good. Like when we -- when I read some of the analyst notes, I think this might be being a little underestimated about how busy we are in this quarter. It's likely to be better than Q3 and possibly could be one of our best quarters of the year. So we're not seeing a sharp decline in activity in Q4 like maybe some of our competitors have seen or had planned for.

And nothing's changed from our focus. It's very much Montney, Duvernay. Obviously, the Iron Horse division focuses on the oiler plays. And as oil prices stabilize and start to gain a little momentum, those plays will get very, very busy very quickly.

So just on -- I'll touch on a few other things, one being tariffs. I know we've talked a lot about tariffs in the past. And actually, as it's turned out, tariffs were put on sand and coil. Both of them have been removed. And actually, the tariffs that were paid -- and sorry, I'm talking about the retaliatory tariffs put on by the Canadian government. In both cases, any tariffs that were paid are -- they're telling us they're going to refund them, refund the money. So we're not really seeing retaliatory tariffs being a big issue in our life. A lot of the cement products are made locally. So that's not an issue. And we're not seeing any tariff pressure on things like chemicals yet.

It will affect overall steel prices, of course, from the tariffs that were put on by both the Canadian and the U.S. governments, and that will affect the price of parts and pumps and things like that going forward. But it certainly isn't working out to be as big an issue as we had feared at one time. And there's various industry groups that have done a really good job of lobbying the Canadian government to make sure they're not sort of putting unfair retaliatory tariffs on our business in places like where we don't have a Canadian alternative. So sort of -- I would say we're very happy with how that's worked out.

On the sand logistics side, we focus on this every call, and we're going to continue to focus on this because this is certainly becoming more and more of an issue every year. There's about 8.5 million tons of sand pumped in Canada this year. And some analysts are estimating that this could get as high as sort of 12 million to 15 million tons by 2030. And so when you think about all the sand that needs to move around the basin, whether it's on rail or on truck, this certainly has turned into a logistics challenge, which, of course, we see as an opportunity for profitability. And so we hope these predictions are correct, and we're making moves in our last mile logistics to make sure that we're positioned as having the premier provider of sand from the transload facility to the well site. And there's a lot that goes into it.

You think about some of these locations, they're pumping sort of 50 to 100 railcars of sand over a period of 48 to 72 hours. And that means having a 40-ton B train truck show up every 10 minutes on location. So if you can schedule that correctly, you can run that efficiently. That's an efficiency that our customers certainly value, and we expect to provide to them in the future as the sand volumes grow. So we view this as a real area of focus and actually may be a focus of our M&A in the next few years as well.

On the technology side, I would say things are sort of progressing as we had expected. We're reviewing the cornerstone of our technology strategy is 100% natural gas fueled operations in all of our divisions eventually. But right now, we're mostly focusing on frac. We're evaluating all of the technologies available to us from a 100% natural gas pump perspective, which will allow us to pick what we think is the best -- the most practical technology so that we can provide our customers with 100% natural gas solution. And like I had said earlier, I expect we'll be providing this by mid next year.

So back to the long-term outlook, certainly, nothing's changed from our view. Even though you go through little bumps like we're going through now with commodity prices, it doesn't change the long-term outlook of the industry in Canada. We still think it's a great place to be. We're going to continue to invest in it. We view the Canadian -- the Western Canadian Sedimentary Basin is a very attractive place to develop and grow our business. The Montney is increasingly becoming recognized as the premier play in North America. LNG Canada is going well. We fully expect that, that will go from 1 Bcf to 2 Bcf eventually to 4 Bcf a day in the next few years. So -- and there's other facilities as well that are coming in behind it. So we think the LNG export off the West Coast of Canada is great for the business. All of the plays that will fill that capacity are extremely pressure pumping intensive. So we think it's a great place to grow our business.

And on the -- what's our return on capital strategy. I think, again, nothing's changed there. We continue to generate what we think is industry-leading free cash flow, and we maintain a conservative balance sheet. I would say our views on debt has changed just given how stable this business has become compared to prior cycles. So we're not afraid to have a little bit of debt on the balance sheet. And we do subscribe to a diversified return of capital strategy, which is a combination of a sustainable and hopefully growing dividend with the combination of the NCIB. And since we put the NCIB in 2017, we're over 51% of the shares purchased, which is amazing to think about that in the context of the industry.

And we flex the NCIB up and down in the context of other investment opportunities. And -- so we'll continue to do that. We'll very likely have a very low base level of NCIB, but we're not afraid to really hit the gas or maybe even pull back for a while depending on what else we're seeing and what's happening in the market. Again, we're not afraid to use our bank lines if we find attractive investment opportunities, just like we did with the Iron Horse deal. They wanted all shares. We wanted to pay them all cash. We sort of sought it off somewhere in the middle, but hopefully, we can use our bank lines in the future.

We're -- and our corporate priorities remain unchanged, build a resilient, sustainable and differentiated company, invest in high-quality growth opportunities. Hopefully, they're organic, focus on the logistics side of the business, provide a consistent return of capital for our shareholders through the dividend and the NCIB. So I think, operator, I think we'll stop there, and we'll go to questions.

[Operator Instructions] And your first question today will come from Aaron MacNeil with TD Cowen.

Brad, you mentioned you expect '26 to be better than 2025. I know you also referenced this in your prepared remarks, but we started to see CapEx cuts this quarter, most notably with Whitecap. We're just kicking off earnings, so presumably more producers could follow. I guess I just -- I'm wondering at a high level, what your assumptions are for year-over-year changes in Montney and Duvernay activity and how you think pricing will evolve over the next year?

Yes. Like I don't think we're going out on a limb. I mean we just had 24 months of the worst gas prices this basin has ever seen on an inflation-adjusted basis. Now we've got LNG line maintenance is done. We're talking about sort of a much more balanced or even a negatively balanced gas market in North America as more LNG comes online in the U.S. Our customers have very sophisticated marketing programs. They're not just sitting around relying on AECO or Station 2 gas. But now that sort of all of the pieces are in place, I just don't see how we don't have higher gas prices next year. And this is a gas basin, as everybody knows. So higher gas prices mean better economics.

When our customers have sort of 3- to 9-month payback on wells, how do they not drill those. So -- and of course, everybody takes a defensive stance in their budgeting, just like we do. We take a very defensive stance at this point. But I think there's upside, and I think it will come next year. And that's from an activity perspective. Who knows what's going to happen in the pricing environment? I mean, we all know what I think about how undisciplined this space is and irrational this space is. But when we talk to our competitors, they're blunted for Q1. So are we -- I don't see how prices go anywhere but up from here.

So -- and even if they don't, I mean, we'll figure out how to make a little bit more money with efficiencies. So I'm not expecting big year-over-year changes that we would see 15, 20 years ago. That's not what I'm saying. But sort of 3% to 5% increases in activity, we can work with that. And I just don't see how that doesn't happen given that we've come out of the worst 24 months imaginable from a gas price perspective. We're going into a much more constructive gas market, North American-wide. I think that will just reflect in more activity going forward.

Yes. And again, I wasn't trying to challenge your outlook. I was just more curious if you've had any specific conversations with customers that would indicate that activity was going up year-over-year, but...

Yes, we do, Aaron, I'm sort of challenging myself on my assumptions because I seem to be the only one that seems to think like this right now, which is either a really good sign or a really bad sign. But yes, we do have conversations with customers that I would say are more bullish than maybe what gets put in print.

Got you. Okay. And then just as a follow-up, I wanted to sort of better understand the new natural gas-fired frac spread. It sounds like it's going ahead, but is there any scenario that you would maybe pump the brakes? And then what sort of contract structure and duration should we expect? And maybe as another follow-on, how should we think about capital spending next year, assuming that, that investment goes ahead?

Yes. I would think our capital spending will be in line with the past. We're very careful not to overcapitalize the space. Even though we have, by far, the largest market share in Canada, we don't operate in a bubble. And so we're not just going to flood the market with equipment, even if it is from a technology perspective, the best. But we've been a leader in new technology development over the last -- or since COVID, say. And I don't expect that's going to change. We've had incredible success with our electric backside or all of the ancillary equipment. Our customers continue to demand our electric blenders, very well designed, great performance, great from an R&M perspective.

And so the last piece of that puzzle was the evaluation of all of the available 100% natural gas pumps, and it's all of the manufacturers. It's natural gas -- conventional natural gas engines, turbines, it's electric. We took, I would say, maybe a frustratingly long time to evaluate everything. But I think we have a pretty good understanding of what's available in the pros and cons of the various technologies. So I think we're in a really good position to sort of pick a horse at this point.

And we're always working on R&D projects in the background. We've got to -- I mean, one of the challenges with natural gas pump engines is they want to run at constant speeds, which, of course, is not great when you're trying to increase rates and pressures and stuff like that. So -- in conjunction with a partner, we've developed a variable speed transmission that we want to try. That would go really well with natural gas engines, and it would allow us to pump more efficiently and actually spin off energy into our electric backside.

So there's little things like that, that we're always working on that we may not always be able to talk about. But we'll -- we want to provide our customers with 100% natural gas solution, but we want to make sure that it's a sustainable solution for us as well from a returns perspective. And I think all too often, people jump head first into the latest, greatest equipment design without sort of thinking thoughtfully about, hey, how do you provide your shareholders with a return at the same time as you're providing your customers with a valued service.

And so just not to needle you too much on this, but on the contract duration, do you think you can go?

Sorry. Yes. We don't talk in too much detail about contracts with our customers, and we have various discussions with various customers, but you would expect that the -- we're very fortunate to have long-term customers that have been with us for years. They will, of course, get first dibs on any technological developments we make.

And your next question today will come from Keith MacKey with RBC Capital Markets.

Just like to start out with Q4, if we could. Can you maybe just work out some of the pieces here of how you think Q4 will unfold? Certainly, you did kind of high 50s for EBITDAS in Q4 of 2024. Relative to that, how do you see Q4 of this year playing out, recognizing that there's been some work moved from Q3 to Q4, but then also some of the Iron Horse oil-related work has gone away. So how do you see kind of all those pieces playing together? And obviously, there's always a holiday season that makes things less busy as well?

Yes. we -- if anything can happen, like we didn't see September coming. Frankly, we had a whole bunch of stuff on the board. And then boom, you wake up one day and it's been moved. And that's our business. You have to be prepared to roll with the punches like that. So we were -- we actually didn't realize a month like September was going to turn out like it did until sort of mid-September. So I'm a little hesitant to talk in absolutes here. But if we don't beat last year's Q4, I mean, that would be very, very surprising. And I would think we would beat it by a fairly reasonable amount.

And like I said in my prior comments, this could be one of the best quarter -- this could be the best quarter of the year for us. And so again, I think we've gotten a little too focused on what happened in September as an indication of what's happening in the business. That isn't the case for us. Things get moved around, water availability issues, budget issues. I mean, we're built to absorb those changes. And what we gave up in Q3, we think we're going to gain in Q4. So I'm not going to give you any more color than this, but we expect Q4 to be good.

Maybe you could just talk a little bit more about the sand logistics commentary. Certainly, more sand per well and more wells over time means you need a lot more sand in total. Can you just talk about kind of where the sand is coming from these days? Are we seeing more local sand versus imported sand? I know there was a trial on damp sand in a little while ago with one of your competitors. Can you just talk about some of these trends and where you think the market ultimately goes and where the opportunity is for Trican?

Yes. Those are all good questions. So out of the 8.5 million -- about 8.5 million tons of sand that gets pumped in Canada, about 5 million of it comes from the U.S., so Northern White Tier 1 sand. The other 3 million, say, comes from the Canadian mines. It's hard to predict how this works out because, I mean, the issue with sand is everybody wants to pump more of it. But of course, it's expensive. So everybody is always looking for the lowest price alternative from a sand perspective, and then you have to measure that against the crush strength of the sand that you're putting into your wells. And so that has brought up this wet sand issue.

The idea behind wet sand is you have lower quality, less sorted, less clean sand. And as a result, it hasn't been sorted, hasn't been washed, it hasn't been dried. And so you can have it for less money, you can truck less of it due to the water content, of course. But the idea is that hopefully, the reduction in sand quality is made up for in the reduction of price. And from what we understand, and we are not experts in what happened at either one of these 2 trials. But we -- as what we understand, they didn't go that well. But I think people will continue to experiment with it. It's obviously a lot harder to deploy wet sand in Canada versus Texas when we have 6 months of winter. So you can't move wet sand around if it's frozen.

And there's sort of operational issues on location as well with wet sand in the winter. So it's probably not ever going to be a massive substitute for what's happening today. But I think people are going to continue to experiment with lower cost alternatives and we hope to be there with our customers as they do that. But one thing that is certain is sand has to get moved from A to B, and we're really good at moving sand from A to B. And we have the largest trucking fleet. We will continue to grow that. We'll continue to make investments in storage and transloads if we think they're strategic. But at the end of the day, moving sand from A to B can be a good business if you do it well, and we think we do it well. So that's something that we're going to continue to focus on.

And your next question today will come from Joseph Schachter with SER.

Two questions for me. The first on the ERP platform and using AI, how do you see that integrating? Is it a multiyear thing? You're talking about spending $10 million this year, putting it through under the G&A. Is it going to affect manpower? Is it going to affect the software side that upgrades? How does this affect and benefit you? And how does it affect and benefit the customers?

Yes. Interesting question, Joseph. So I mean, fundamentally, we need to modernize all of our systems and get ourselves into the next level. That will then help us facilitate more aggressively moving into things like AI and machine learning, analyzing pump data, preventative maintenance schemes, all those kind of things, which is a great benefit to us as we move forward. But you're correct that, that should translate into efficiencies from an operations perspective, potentially cost side as well. So it's a long-term process, as you would know. There's lots of conversations about utilizing AI and use cases, but you've got to first have good solid quality, clean data for a period of time to be able to run any of those use cases.

So before we start talking about AI efficiencies and improvements going forward, we've got to get the base level data clean, scrubbed and into a reliable form. And that's really what our platform is driving us towards. So yes, this is a bit of a multiyear exercise. As we move forward, there'll be internal efficiencies that we would hope to gain and that insure -- in turn should benefit our customers as well.

So this will be an ongoing conversation issue?

Sorry, I missed that.

This will probably be an ongoing conversation issue as you make headway there?

Yes. It will be something that we'll continue to talk about and keep forward in our discussion so that you get a clear picture of where we're going.

And Josh, it's Brad. Like the AI, the potential of AI is limitless, right? And it's -- even in a business like ours, who knows what this could do for us from a -- we collect millions and millions of data points on the pumps and the engines every day. And so what do you -- what can AI do with that data? And we certainly hope it will help reduce our R&M costs. Is AI one day, do we have better programming to help our sand logistics get more efficient? Does that help us run the frac? And so we're currently not running it manually, but we have people controlling the computer systems that run the frac.

And so maybe AI or the software will run it a little bit more efficiently than we're running it. And so we're always looking for opportunities to get better with technology. We just got to pick our spots and be aware of the fact that we're not that big of a company, right? We're big enough that we need to invest in this. But at the same time, we got to be careful that we don't waste money on it as well. And I can assure you we will be very thoughtful if we -- when we deploy capital on technology. We'll be looking to get an immediate return for the investment.

Super. Another area to pursue, you mentioned on the last call that when you bought into Iron Horse that you had equipment in the legacy business that might fit because of it's not up to the current standards needed for the big jobs. Are you moving equipment there? Are they using it or upgrading it so that they'll be busy with it in Q1, as you mentioned, that you expect them to have a very busy quarter in Q1?

Yes, exactly. We've got equipment going back and forth from them to us and us to them as we speak. So one of the big advantages of a transaction like this is you get to spread the equipment around to where it's going to be most impactful and most efficient.

Okay. And do you have much in the yard still from the legacy equipment? Or is more of it going to Iron Horse?

Well, there's always stuff kicking around the yard, Joseph, don't get me started here. Yes, there's still stuff there. But that's fine. That's -- we have actually done -- and prior to COVID, the prior team had also done a really good job of cleaning up really old equipment, and we've continued on with that. And so I think we're -- we've done a really good job of making sure we don't turn our operating bases into these old boneyards of equipment that will never see the light of day. We've -- I think we've done a pretty good job of getting rid of a lot of the stuff that will never go back to work. And so anything that we have parked on fences today is something that we think could go to work at any time. And we work very hard. If we don't believe that the equipment can't go to work, we work very hard to get it sold.

And your next question today will come from Tim Monachello with ATB Capital Markets.

Most of my questions have been answered, but I have a few follow-ups. Just around the nat gas fleet that you're contemplating for 2026. What's the lead time on that? And when do you think that might be entering the fleet?

I didn't quite catch all that, Tim. What is the...

Sorry, the lead time -- lead time...

All of this equipment has a 6- to 12-month lead time on it. It doesn't matter what you order these days. Companies like whether it's Cat, Cummins, NOB, et cetera, they -- it's all a long lead time. So we don't expect this fleet would hit the field until next summer, probably at the earliest.

Okay. So that capital investment decisions already made like you're going forward with it?

Not necessarily, no.

Okay. That's helpful. And I assume that, that would have to come with some customer commitment behind it? Or would you do that on spec?

It will likely come with a customer commitment, but we typically test our investment thesis on if the customer commitment went away, would you still want to own it. And so the answer to that is sort of yes to both. But yes, it will likely have a customer commitment, but we wouldn't bring it on if we didn't think we could sell it if the customers get sold or change their mind or whatever.

Okay. That's helpful. Then a follow-up on Keith's question around profit. Any market dynamics, have you seen any changes in terms of customer in-sourcing behavior or willingness or desire to in-source the logistics side of sand in Canada? And if so, how do you move around that? And what does it mean for margins and stuff?

Yes. Definitely, we've seen the trend to more self-sourced sand from our customer base. And that's why we're focusing on making sure that we can make some of that back on the logistics side. So it's one of the reasons I'm saying it's going to be a focal point for the business. There's nothing we can do about the trend other than try to make sure that we're included along the value chain somewhere. And there's corkage fees and things like that. But...

But as we mentioned earlier, I mean, that logistical piece of moving x number of tons from A to B is no small task, right? And so that's something that Trican has got expertise in and has developed over time, and we continue to push forward on. So keeping engaged on the transportation side of things is a bit of a hedge against that motion.

Yes.

Does that come to pass in any of your customers' programs currently? Or is that something that's more contemplated for in the coming quarters?

It's going to continually happening as we move forward. So there's a mixture today of customers that self-source various items, including whether it's sand or chemical or others. So it's just a continued trend as we move forward.

And have you had any pushback on corkage fees or trying to capture margin in logistics rather than...

We get pushed back on everything.

Makes sense. But are you able to push it through ultimately?

Sometimes. I mean most of our customers, like it's -- everyone is different. We're very fortunate that our customer base wants us to be sustainable. And they -- I would say they have a very good understanding of our company economics and what is required to make sure that we're going to be able to provide new technologies and top-tier service. And so we're very fortunate to have the customer and we've had them for 10, 20 years in some cases. So the relationship is very good and lots of the elements of the business are well understood by them. So we'll get through this, and we'll continue to make money.

Okay. That's helpful. Just looking at the acquisition allocations, it looked like Iron Horse didn't come over with much working capital. But the working capital investment in the quarter, I assume, being fairly elevated included funding working capital for Iron Horse. So I'm just curious like with that onetime impact, if you could help quantify what the working capital investment related to Iron Horse was in the quarter?

Yes. I probably won't get into that much detail, to be honest, Tim. Iron Horse did come with a chunk of working capital in it. I would say that funding requirement was not massive. And so most of the working capital build was really a result of a strong July and August, right, that then translates into an elevated balance as you come through September. So I'm not giving you as much detail as you'd like, but a portion of it, sure, but the majority of it would be activity based.

And maybe I missed this in Joseph's question, but how long do you expect this ERP integration to last? And what do you think the 2026 investment in that is going to be?

Yes. We don't -- we would have an ongoing spend as we move through 2026, and we'll be able to give you a bit more guidance on cadence as we get into the year. But we're scheduled to flip the switch midway through the year and then get to sustainable factors at the end of that year, and then we've got to make another decision as to whether we continue forward on different parts of it. So there'll be a chunk of spend in '26 as well.

This concludes the question-and-answer session. I would like to turn the conference back over to Mr. Fedora for any closing remarks.

Thanks, everyone. Thanks for your interest and joining -- taking time to join the call. The management team at Trican will be around for the rest of the day. So if there's any follow-up questions, don't hesitate to reach out, and we should be able to take your call very quickly. Thanks.

This brings to a close today's conference call. You may now disconnect your lines. Thank you for participating, and have a pleasant day.