Good morning, ladies and gentlemen, and welcome to the Trican Well Services Fourth Quarter 2024 Earnings Results Conference Call and Webcast. As a reminder, this conference call is being recorded. I would now like to turn the meeting over to Mr. Scott Matson, Chief Financial Officer. Please go ahead. Great. Thanks very much for joining us, everybody, and good morning. Just to give you a quick outline of how we intend to conduct the call today, I'll give a quick overview of the quarterly results, and then Brad will provide some comments with respect to the quarter, our current operating conditions, and our outlook for the near future. We will then open up the call for questions. As usual, several members of our executive team are in the room here today and available to answer any questions you might have, and we'll generally be around for most of the day to do some follow-up questions as well. Just before we get into the nitty-gritty, I'll 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 2024. 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 31st, 2024, 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 2024 MD&A. Our quarterly results were released after close of market last night and are available both on SEDAR and our website. My comments will draw comparisons mostly to the fourth quarter of last year, and I'll also provide some commentary about our quarterly activity and our expectations going forward. Our results for the quarter were quite similar to last year's Q4 on generally solid activity, albeit with a different job mix driven by the well design and the nature of projects being undertaken. Customers also completed some projects that carried forward from Q3 into Q4 that were either delayed or late starting due to permitting and access challenges experienced in Q3. Revenues for the quarter were CAD 275.5 million, with an Adjusted EBITDA of CAD 55.6 million, or 20% of revenues. Not quite as strong as the Adjusted EBITDA of CAD 56.4 million, or 22% of revenues we generated in Q4 of last year, but still solid in this environment. Adjusted EBITDAs for the quarter came in at CAD 58.6 million, or 21% of revenues. 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 financial noise associated with changes in our share price as we mark to market these items. On a consolidated basis, we generated positive earnings of CAD 27.6 million in the quarter, which translates to CAD 0.14 per share, both on a basic and a fully diluted basis. Trican generated free cash flow of CAD 33.9 million during the quarter. Our definition of free cash flow is essentially EBITDAs less non-discretionary cash expenditures, which include maintenance capital, interest, current taxes, and cash-settled stock-based compensation. You can see more details on this in our non-GAAP measures section in the MD&A. CapEx for the quarter totaled CAD 18.7 million, split between maintenance capital of about CAD 14.2 million and upgrade capital of about CAD 4.5 million. Our upgrade capital was dedicated mainly to the electrification of the third set of ancillary frac support equipment and ongoing investments to maintain the productive capability of our active equipment. For 2025, we have an approved capital budget of CAD 70 million, which will be focused on a mixture of ongoing maintenance capital and targeted growth initiatives, including the electrification of another set of ancillary frac support equipment, investments in our logistics fleet, and supporting infrastructure. As noted in our press release last night, Trican is undertaking a significant technology modernization initiative, starting with our base financial system and implementing a world-class integrated ERP platform. Our existing systems are functioning effectively, but we need to continue moving forward on the path of modernizing our technology platform to enhance operational efficiency, streamline internal processes, and help position the company for future innovation. Trican anticipates ongoing technology enhancements over the next few years, including the incorporation of artificial intelligence and enhanced data analytics capabilities to remain competitive in an evolving digital landscape. The investment for 2025 is anticipated to be approximately CAD 10 million, which will be presented as a component of our G&A expense in accordance with IFRS reporting requirements. The balance sheet remains in great shape. We exited the quarter with positive working capital of approximately CAD 128 million, including cash of about CAD 26 million. With respect to our return of capital strategy, we repurchased and canceled CAD 3.1 million shares under our NCIB program in the fourth quarter. On an annual basis in 2024, we repurchased and canceled CAD 20.8 million shares at a weighted average price of CAD 4.56 per share, representing 10% of the outstanding shares at the beginning of last year. Subsequent to Q4 2024, we've repurchased and canceled an additional CAD 1.4 million shares and continue to be active with our buyback program when market trading prices are at levels that provide a favorable investment opportunity for us. As noted in our press release, the board of directors approved a dividend of CAD 0.05 per share for this quarter, reflecting an increase of 11% from our previous quarterly dividend. The increase essentially offsets the reduction in share count as a result of the company's ongoing NCIB program and will keep the annual expected dividend payout in the CAD 36 million range. Distribution is scheduled to be made on March 31st, 2025, to shareholders of record as of the close of business on March 14th, 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 over to Brad. Okay. Thank you. In my comments, I'll sort of bounce around between Q4 and 2025. But again, please read the disclaimer as I do make some forward-looking observations. Overall, the quarter went very well. It was, in fact, one of the best quarters of the year, which is kind of unusual for Q4 because now we're kind of seeing a sort of a slowdown going into Christmas. But, you know, as Scott was saying, we had a lot of work bumped from Q3 into Q4. So Q4 actually ended up better than we had expected. And we're really happy with the results given where gas prices were last summer and into the fall. You know, I would say in general, you know, we get asked a lot about cost inflation and what is happening, especially with respect to the U.S.-Canadian exchange rate. And in general, cost inflation has stopped or is really muted compared to the past couple of years. And in fact, we've actually experienced some cost reductions in certain areas. And we'll just continue to look for alternatives and do our best to mitigate volatility of the exchange rate because a lot of what we buy is coming out of the U.S. But I say in general, I think the cost inflation is a thing of the past for now. And we'll talk about that with respect to tariffs in a moment. So in the fracturing division, there's really no changes that are happening there. You know, the division's doing very well. Q4 revenue was up about 17% year over year, and EBITDA was up about 13% in the fracturing division. We are experiencing less Northeast BC work, but it's being replaced by more Duvernay work in Alberta, which, and the Duvernay, as everybody knows, is very service-intensive, big, high-pressure fracs, lots of sand pumped. So we're happy to make that trade. And, you know, when Northeast BC gets more active again, you know, the Duvernay will be obviously additive to what we have going. And we've talked about this in the past. You know, our fifth Tier 4 fleet was designed specifically for the Duvernay and high-pressure areas of the Montney, and that equipment continues to outperform and is doing very well. You know, our fracturing operations have not changed their focus. It's still the Montney, the Duvernay, and the Deep Basin. And I don't expect that will change anytime soon. On the cementing side, you know, we're continuing to be very happy with the performance of this division. We consider ourselves the technical leader. I think our customers consider us the technical leader, and really, the only reason people don't use us is we are a premium-priced service, and we think we have a value-added offering, and we will continue to be, so that division is operating really well. Very high utilization rate in Q1. It was a little lower in Q4 just because a lot of the rigs were focused in the heavier, oilier plays, which we're not currently active in, but in Q1 so far, the rig count is up 18 rigs year over year, and our cement rig count is up 14 rigs, so, you know, we had a great market share of the incremental work that's being done this year. You know, overall, we're about 35% market share in the basin, but in places like the Montney, Duvernay, and Deep Basin, you know, we can be as high as 80%. But we're, you know, if you look at the basin as a whole, excluding the heavy oil areas, which we don't have operating bases in, we're at about 47% of the market share in cementing. So it's been a great division for us. We will continue to invest in it, and we hope to grow it in the areas that we're not currently active in. On the coiled tubing side, we've made good progress in coiled tubing. You know, we've been focused on growing this. You know, we've talked a lot about it. It's just, it's great field margins, but just too small. And in Q4, our revenue was up 12% year over year, and, you know, EBITDA was up almost 80%. But, you know, those are small numbers. Our utilization in Q1 so far is really high. You know, we continue to basically run full out in that division with actually, you know, more demand than we have equipment for currently. And we'll continue to try to grow that as, you know, increased scale is required to realize the profitability potential of that. And it's, like I say, it takes a lot of fixed costs. I mean, there's a lot of downtime with changing reels and different coil sizes. And so scale is important in that business. We are looking forward to the strategic partnership with AECO and that was the tool company that we talked about in past calls. That's a tool that's focused on sort of the very oily multilateral well designs, places like, you know, the Clearwater and east into the heavy oil. That's an area that we're not currently active in at all with respect to our coil division. So that'll all be additive market share for us as that tool gets deployed. Just on the outlook for 2025, again, you know, we're very happy with Q1 to date. We're forecasting 2025 to be basically a repeat of 2024. You know, I don't think Q1 will be as strong as last year's Q1, but we're expecting more level loading throughout the year. So from an activity and a financial results perspective, you know, I would say 2025 basically just mirrors 2024. Of course, the hot topic now is the potential introduction of U.S. tariffs and particularly 10% tariffs on oil and gas imported from Canada into the U.S. Will Canada, you know, have retaliatory tariffs, which seems to be the tone that we're getting out of the government today? This, of course, just introduces uncertainty and potential volatility. You know, will it impact activity levels with our customer? You know, it's still too early to draw any firm or definite conclusions. You know, at this point, there's way more questions than answers. A 10% U.S. tariff on energy, we don't expect it to have a big impact on activity here in Canada because, you know, with the tariff introductions, the exchange rate has gone up. So, you know, customers may be getting a lower price, but when you convert it to Canadian dollars, you're mitigating a lot of that downside. You know, the retaliatory tariffs from Canada on U.S. goods coming into the country is probably our biggest concern. You know, we've about half the sand we pump, it comes from the U.S. And when we preliminary analysis shows that there will be, that could result in about CAD 15 per ton tariff on sand coming into Canada. And we'll continue to look for alternatives, things like parts and chemicals. You know, we're not really sure where that's going to shake out yet, but we're actively looking for alternatives to sourcing those from places other than the U.S. And unfortunately, the Canadian government has introduced the concept of exclusionary provisions for tariffs on products for which there is no alternative, such as sand. The economic impact is overly punitive. You know, that would apply to a lot of the parts and the sand that we're bringing in from the U.S. We're hoping when this all shakes out, that actually the tariffs will not impact us. You know, to mitigate that risk, we'll just continue to look for alternative sources. We can get chemicals and parts out of China at relatively attractive prices. You know, there, the issue is always just quality concerns is really the only issue. We'll continue to monitor this going forward and do our best to mitigate the impact of that. You know, fortunately, natural gas prices have firmed up the strip for the summer and the winter of 2025 at very economic levels. You know, our customers are able to hedge gas if they want to. Certainly, this basin goes around at CAD 350 Ecosse without any problems at all. You know, and the financial discipline that's been displayed by our customers over the last few years means that, you know, their balance sheets are in great shape. You know, their programs are very level loaded from quarter to quarter and year to year. A lot of the gas basin has high liquids components. So when there are periods of low gas prices, it's offset by condensate pricing, as an example. So we're expecting, like we still expect 2025 to be a good year, even though there's lots of sort of tariff concerns in the media right now. You know, on the pricing side, we did experience some pricing pressure in Q4 just because some of our competitors weren't quite as busy as we were. That has all subsided. We're not really seeing, you know, big pressure on any pricing so far in 2025. I think everybody's boards are pretty full up, and so everybody's busy, and I think it's just more focused on doing, you know, doing work and servicing the customer. We still expect that the Montney and the Duvernay will be the focal point of activity in this basin. The Duvernay is working out as well or better than expected. You know, it's very, very frac intensive, uses, you know, high-pressure treatments, lots of sand, you know, with long laterals, so whether you're cementing or fracking or running in coil, you know, those are big service-intensive wells that, you know, we're very happy to be a part of, and again, you know, we've built that Duvernay-specific frac fleet that's been performing very well, and it's fully utilized. You know, we wish we had built a couple of them, actually. On the sand side, you know, we've, I just want to just give an update on the agreement that we entered into with Source. You know, we are building a transload facility in Northeast BC just to service that market. As a reminder, there's only one rail line running into Northeast BC, and so a lot of that sand gets trucked. We invested alongside Source into a transload facility, which will be fully operational in Q2 of this year. We have had construction delays, but I think we can confidently say at this point that it will be ready and fully operational with sand storage in Q2 of this year. The idea behind that investment is to reduce the trucking times from Grande Prairie into Northeast BC, which can have 12-hour round trips. And so if we can rail the sand into Northeast BC and truck from there, you know, we can use our trucking fleet much more efficiently and deploy our own trucking fleet to our customers where, you know, we can make a margin opposed to having third-party trucking get passed through to the customer, which we, you know, we do not make any margin on. So, you know, that logistics, given how much sand is being pumped in this basin now and how much sand is going into the wells, you know, last-mile logistics and your ability to strategically transload it will be an important driver of profitability going forward. On the technology side, I don't think really a lot has changed since our last call. You know, we're reviewing a few different pumping technologies, and we're trying to figure out, you know, what is next. But the ultimate goal in all of the technology that we review or we trial is that it has 100% natural gas-fueled operations. You know, the natural gas operations are what the customers want. You know, it's much less expensive than diesel, burns cleaner. It's available, you know, on pretty much everybody's pad. And the issue there is just, can you get enough of it, and can you treat it to get it to the right pressure and liquids content and temperature, of course. But, you know, we've looked at, we're using the Tier 4 technology, which is about 75% substitution. We've trialed electric pumps. You know, we're building electric ancillary equipment that's performing really well. You know, we're keeping an eye on the turbine space. We're looking at the 100% natural gas recip engines. You know, each of these technologies has their own pros and cons. But typically, the issues are, you know, will it run with variable gas quality? You know, what's the physical footprint of it on location? And can you get a return on it? You know, the issue a lot with electric, which has run very well, whether it's the ancillary equipment that we built or the actual frac pumps that we trialed. You know, they run well, but it's a big footprint because of all the electrical generation equipment that's required. And it's costly. And so it's hard to get a return out of that equipment with today's rates. You know, on the electric ancillary equipment that we're building, that equipment has performed very well. The blender performance is far superior to the conventional designs of the past. You know, we wish we had more of it, frankly. All of our customers pretty much would like to see that equipment on their location, so we'll continue to invest in that space, and what we're finding is it's lower R&M costs, a few less people required to operate it, you know, less hydraulic lines, etc., so it performs well in the cold. You know, I think overall, it's been an overwhelming success, and when you combine the electric ancillary equipment with our Tier 4 pumps, you know, we're looking at 80%-85% substitution on location with, you know, natural gas for diesel, so the customers are happy because the fuel costs are greatly reduced. Just on the strategy, on the corporate strategy side, again, there's been no real changes here. You know, even though things might feel a little choppy due to the tariff talks, we're still very bullish on Canada. You know, we view Western Canada as a very attractive place to operate. You know, the Montney in Northwest Alberta and Northeast BC is second to none in North America. The returns are very good in this play. And, you know, on the play, you know, the question we get asked a lot is sort of where are we from a life cycle of the Montney? And, you know, it feels like it's the second or third inning at the most. And you compare that to the places in the U.S. where they're probably in the seventh, eighth inning of those plays. So I think, you know, having exposure to the Montney and the Duvernay gives you a very long runway. And, you know, we're excited to see our customers are active and making money in those plays. So, you know, we consider Western Canada to be a great place to continue to invest in and grow. LNG Canada will finally be exporting gas this year, I think in the next six months or so. You know, once at full capacity, it exports over 10% of the natural gas production in Canada. So this will, without a doubt, have a very positive impact on natural gas pricing, particularly Station 2, which is Northeast BC. So, you know, obviously, we're looking forward to that and anticipate the gas pricing to firm up in Canada in the future. TMX is also operational now and not full. So it provides a growth outlet for the oily customers, and they are able to get global pricing and reducing their differentials. So that's, you know, that's also additive to the LNG exports. You know, overall, our priorities have not changed. We want to build a resilient, sustainable, and differentiated company and deploying technology and discipline to provide good returns. You know, we want to invest in high-quality growth opportunities, whether they're on our own equipment or new service offerings. We'll just continue to look and make sure that we're getting a return that's in excess of our cost of capital. And then along the way, because we do generate a lot of free cash, we'll provide a consistent return to our shareholders with the dividend in particular, and then also use the NCIB when it's appropriate. And as Scott talked about, you know, we have a very clean conservative balance sheet. So we have the financial capacity to act on opportunities as they arise. You know, I want to just point out, you know, we've been very, very active in the NCIB in the last few years. You know, this has provided a very good investment for us. You know, we actually think of this as M&A. You know, we're basically buying our own company. We're not, but, you know, that NCIB will have to compete with sort of the organic opportunities that we're seeing. I would say at this stage, you know, we are seeing more sort of acquisition and organic growth opportunities than we have in the past. I cannot comment on those at this time, of course. You know, we're always looking at things and, you know, some you're successful on, hopefully, but, you know, the bid-ask is always the issue. But, you know, I do want to say we probably expect more volatility on the NCIB this year than we have in the past years just because there's so many good things for us to look at at this time. And, you know, as Scott mentioned, we upped our dividend by about 11%. And the idea here is we want to keep our aggregate payout in sort of CAD 36 million-CAD 38 million a year range. And, you know, we'll just adjust that dividend accordingly. And we'll look at that every year at about this time. But, you know, I expect that we should be able to provide dividend growth going forward. I think I'll stop there, Operator, and we'll go to questions. We will now begin the question and answer session. To join the question queue, you may press star, then one on your telephone keypad. You will hear a tone acknowledging your request. If you are using a speakerphone, please pick up your handset before pressing any keys. To withdraw your question, please press star, then two. We will pause for a moment as callers join the queue. The first question today comes from Aaron MacNeil with TD Cowen. Please go ahead. Hey, morning all. Thanks for taking my questions. Brad, I wanted to get into this, you know, Montney versus Duvernay dynamic. You know, we saw higher proppant volumes in the quarter, higher revenues. Margins were a little lower, at least than what I was expecting. You know, is that that dynamic playing out? And then, you know, you mentioned the fit for purpose equipment in the prepared remarks. And I guess I'm just wanting to understand the R&M dynamic of doing arguably higher intensity work. Yeah, I'll answer that one first. It's heavy-duty equipment. It's built to operate, you know, for a long time at higher pressure. It does result in lower R&M. You know, we're not going to get into the details of that, obviously, for competitive reasons. You know, it's thought, you know, what you know, why the customers like it is, you know, it's less downtime on location, less pumps, smaller footprint, you know, a more reliable operation. Yeah, but overall, you know, if you're doing a given frac with these pumps versus sort of a conventional non-heavy-duty spread, you know, you would have less equipment and then thus less people. You know, we look at it from a cost perspective. It's a win. From a reliability perspective for, you know, not just for us, but for the customer. So I hope that answers the question there. I can't give you, obviously, details exactly on R&M dollars. But, you know, from a Duvernay versus Montney perspective, yeah, yeah, you're right. There's more sand being pumped in these Duvernay wells than you see on the average Montney well. You know, I would say the average Duvernay well is more fracturing intensive than the average Montney well. And, you know, the margins going down, I would say, were more a matter of sort of price competition in the market and more than sort of, I would say, there's no other, that would be the primary driver of why the margins were slightly lower that we saw year over year. The issue that we're always dealing with, of course, is, you know, a lot of the sand we buy comes out of the U.S. and the exchange rate, you know, worked against us in Q4, you know, versus the prior year or even, you know, the year to date last year, so. Gotcha. Maybe just to ask the question a bit differently, like CapEx is down year over year a little bit. I know it's growth maintenance split could be different, but like if you're going to do more Duvernay wells than Montney wells this year or the mix is changing and, you know, all of the, you're kind of assuming a repeat year, maybe with more proppant pumped year over year, like should that, and again, I know you expense some of this stuff, but just trying to get your sense of, you know, the impact of the switching to the Duvernay dynamic. I don't think there will be sort of a significant impact of any kind because, you know, the equipment performs so well. If you take a, I guess, a non-heavy-duty pump and deploy it into the Montney, your R&M is going to go up materially for sure. You know, and that's why we built that spread or we designed that spread like we did is, you know, we anticipated that the Duvernay would pick up, you know, pick up steam and momentum. And, you know, we wish, like I said, I wish we had more of that equipment, frankly, because it's pretty much sold out every day. But if you were deploying sort of what I would say normal equipment into the Duvernay, you would expect a material change in R&M. But because we're using the heavy-duty, we're really not experiencing any changes in R&M. That's what I was looking for. Yeah. I know it was a very long-winded answer, but. Nope. That's great, Brad. Thank you. On the, you know, tech modernization investment, I guess two questions. Do you think there's any synergies on the back end of implementing the ERP? And then, you know, on the advanced analytics side or AI, like are you just positioning at this point? Are you actually seeing something come down the pipe on that front? Yeah, I'll just, Scott will comment on this after. But, of course, like this project, like everything else, you know, we don't spend a dime without a positive, you know, an attractive IRR. Certainly, we wouldn't be spending money on this technology if we didn't think it was going to be, you know, a positive NPV project. You know, part of the issues with Trican's is, you know, it's a very old company, right? And so you've got a mix of new and old. And but the benefit of being as old as we are is we have collected an incredible amount of equipment data that's very valuable. You know, we expect that maybe not this year, but next year, we will be able to use AI to mine that data. You know, particularly with respect to, you know, predictive maintenance and overall maintenance, you know, we have a lot of very good pump and engine data here that is going to be valuable. You know, thank the, basically the operations and engineering team that, you know, they had the foresight to collect that data. Gotcha. I guess I'll turn it back. Thanks. Thanks, Aaron. The next question comes from Keith Mackey with RBC Capital Markets. Please go ahead. Hey, thanks and good morning. Maybe if we could just start out, Brad, can you give us a bit more color or a bit of a rundown on the coiled tubing market? Just, you know, I know you've talked about it, you know, as being a little as a priority for you, but a little bit small as it currently is. Like how fragmented is that market? Who do you normally find you compete with? Do you find it's more of a price-sensitive market versus a service quality market? Just what are the key factors you see that make that, you know, look like an attractive place for Trican to be? Yeah, I mean, the longer the well, just from, you know, just in general, the longer the wells get, you know, the more stages we have for, you know, you are seeing a growing demand for coil to do clean outs and drill outs. I wouldn't say the fracking through coil has, if anything, that has declined, you know, and if we use coil to open and close sleeves, etc. So we like the market. We do think it's a growing market. It's just a natural evolution of this basin with, you know, how it's unfolding. There's not a lot of players in the deep coil market. You know, I think it's the obvious people like us and our competitors at Element and STEP and a few other private companies. But, you know, the issue with coil is there's a lot of physical infrastructure required and a lot of investment in various, you know, coil sizes because your ability to compete in the market, you know, is do you have the right coil in the right place on the right day? And, you know, do you have the team that can execute, you know, very well once you get to location? And I think, you know, we have all of that. And so we're going to continue to try to grow it. And of course, like everything, of course, it's price sensitive. But, you know, I think we're finding we have good field margins. And, you know, we're typically in coil and cement, you see a little more price stability and discipline than you would see on the fracturing side. So we're just going to continue to grow it. And like I said, we have good field margins, but we have a big infrastructure and big fixed costs in that division. And so, you know, it's not as nearly as profitable as we would like, but it doesn't take a lot of growth, you know, to get that to a point where it's showing attractive returns. And I can't really, I'm not prepared to sort of give you any more details than that on the call. Fair enough. Okay. Thanks for that. Maybe just turning to the tariffs for a second here. Sand certainly has been one potential expense that stands out. You know, if you add CAD 15 a ton, maybe that's CAD 75,000-CAD 125,000 a well, I would think. So maybe just on that, how much of your sand has been, say, pre-bought or is already in Canada for, you know, the next, like do you have sand for the next quarter to two already in Canada, or is there going to be more that will have to be imported if we do see tariffs? And if we do see tariffs, what's your ability, you think, to pass those costs through to the customer? Yeah, I mean, keep in mind, you know, you have sort of 50-100 rail cars of sand going into a well. So there is not a lot of storage in Western Canada. Like, I want it to be like a week's worth of sand. One week's worth of sand. Yeah. So So about 50%-60% of what we pump comes from the U.S. So no, you know, unfortunately, it's not like parts, you know, where you can pre-buy it to avoid tariffs. There's just too much of it physically. It takes up too much space. And, you know, you want to keep it dry and all that jazz. So there's not a whole lot you can do about the sand other than, you know, we are obviously going to advocate through ourselves and through, you know, organizations like Enserva that we're going to advocate to the government that it should not be tariffed because there is no alternative. You know, the domestic providers cannot ramp up production enough to meet the demand for U.S. sand today. You know, they would literally have to more than double our domestic production. You know, that takes years, you know, years and a lot of money of investment. So there's nothing we can do about it now. And so the worst case scenario, we do get the $15 metric ton tariff. Yeah, of course, you know, we'll pass that along to the customers. But I, you know, I think we have probably one of the best cases that there is for that exclusionary provisions that, you know, have been talked about by the government. So I'm hoping this is just noise. It doesn't, you know, I don't think it'll come true. Yeah, fair enough. Okay. That's it for me. Thanks very much. The next question comes from Waqar Syed with ATB Capital Markets. Please go ahead. Good morning and great quarter and congrats on that. Brad, I saw that your number of parked crews have dropped from five to four, the pumping fracking crews. And overall horsepower has not really changed. So is it that you're not dedicating more horsepower per crew or what's the rationale for that? Yeah, exactly. You know, we've tried to sell as much of the really old gear as possible, but, you know, quite frankly, we were delinquent in making that change. You know, and just for anybody that's listening, we're referring to our parked equipment. You know, we've gone from five to four crews and it's because, you know, these frack crews just keep getting bigger. And so when you, we sort of take our idle capacity and divide it by 20, we're realizing, you know, there isn't five crews worth of pumps there. We have lots of blenders and all the other equipment, but, you know, your typical Montney or Duvernay spread just takes a lot of pumps. And so it feels more like three or four, frankly, than it does five. Okay. Now, your revenues in fracturing were higher in Q4 versus the Q1 of 2024. And when I look at the utilization that you have, you know, it's dropped from 71% in Q1 to 64% in Q4, but yet the revenues were higher. Is it mostly being driven by more sand being pumped in Duvernay and all, or is there some other driver as well? Yeah, I would say that's a primary piece of it, right? Like higher sand volumes and depending on the programs that are being executed, that really drives it, right? Like that job mix, I mean, I don't, not from a specific perspective, but yeah, that job mix and what you're doing in any particular quarter has a big impact on that, Waqar. So if you've already, you know, generally the EBITDA in Q4, how did the fracturing, how did that compare to the EBITDA in Q1 of 2024? Lower. So Q4 was lower. Okay. Fair enough. That makes sense then. All right. And then from just a revenue perspective in Q1, fracturing revenues, you could still exceed last year's Q1, right? Even though the EBITDA may be lower? No. I don't think so. I think overall the quarter is a little slower than I just got to pull up some numbers. I think we're generally lower, Waqar. Revenue end. You're talking Q1 of this year versus Q1 of last year? Yes. On the fracturing side, yeah. Yeah. They're pretty close, but I would say there's, on the cost side, the revenues are very similar, but the costs have gone up because of the exchange rate. So we're expecting, you know, less EBITDA, you know, obviously. Okay. And then, you know, EBITDA per well, is it higher in Duvernay versus Montney well? EBITDA per well? Yeah. For you. Or EBITDA per crew? Yeah. On average, yes. Like the average Montney versus the average Duvernay, I would say yes, it's higher. And is free cash flow as well? Because I'm sure it, you know, it has an impact on your equipment as well, more in Duvernay. Yeah. Again, that goes back to the, you know, what we were talking about with the equipment design. So yeah, like the EBITDA should result in, you know, annual free cash flow that's higher because, you know, we're just not seeing, you know, the equipment perform so well. We're not seeing increased R&M. Okay. And then, Scott, on the G&A side, you know, as we include the CAD 10 million charge for AI/ML, is the G&A run rate going to be around 13 million- 14 million per quarter now in 2025? Yeah. I mean, it'll be very similar to what we saw this year, just with that incremental 10 stacked on top of it, which will be pretty even throughout the year. Okay. Great. I think that is all I have. Thank you very much, sir. Thanks, Scott. Once again, if you have a question, please press star, then one to join the question queue. The next question comes from John Gibson with BMO Capital Markets. Please go ahead. Morning, guys. Congrats on the strong quarter here. Just following on your M&A comments in the preamble, it seems like there's a lot of opportunities out there and understanding if you don't want to get specific, but would these opportunities be sort of horizontal or add-on businesses or more, I guess, add-ons to your primary frack and cementing work? Yeah. I would say in general, there's always both. That's both, you know, obviously about all I can say. Okay. Fair enough. What I would say is we're not, we're certainly not afraid to add a new business line if we, you know, we think we can add value and provide good service to the customer and that that business line will provide the kind of returns that, you know, we require. You know, you want to have it, you want to, it has to make sense, of course, but, you know, we're not afraid to sort of step out of our three, you know, three divisions and look at other stuff. We're happy to look at opportunities outside our space. Okay. Got it. Just thinking ahead to LNG Canada, potentially moving gas as early as mid-year. Are you starting to have conversations with customers around incremental activity or is it more wait and see until we actually start to see gas moving, kind of like what happened with TMX last year? I mean, both, depending on the customer, but I would say just given all the media with the tariff talk and all that jazz, you know, we're not, I would say, I would say, you know, people are in more of a wait and see mode. Okay. And then last one, can you talk about how much equipment you and your competitors have on the sidelines right now in Canada? And I guess just taking into account intensity changes and the frac fleets have sort of increased, has this capacity shrunk over the past few quarters, I guess? I don't think it's shrunk because I don't think there ever was a whole lot of spare capacity. I think people, you know, I think the market in general thinks there's more spare capacity than there is. You know, like I said, yeah, I think we finally sort of got around to maybe recognizing our spare capacity more accurately as looks like sort of three or four spreads than it does five. And if you look at our competitors, I mean, there's very little, there's very little spare capacity out there that's, you know, actually functional. Yeah. And remember too, like if you have a 12-year-old diesel pump, nobody wants it. Right? They want brand new Tier 4s with, you know, upgraded transmissions and pumps and, you know, we're, you know, we get tons of questions about electric. And so, yeah, there's in theory spare capacity out there, but the amount of investment it would take to make it competitive, it would be significant. And the time it would take, you know, to add a Tier 4 engine to it, you know, that's a year. So, you know, I'm actually really glad you asked that question because I think it's important for, you know, your side of the street to recognize that when we see increased activity, you know, due to, you know, better gas pricing in LNG, etc., that we are able to respond, but not very much. Right? So it'll, the frac fleet in Canada will tighten up very, very quickly. You know, we're kind of humming along in a sort of a perfectly balanced state, which I think sort of gives people the impression that there's a lot more capacity than there is, you know, to take on more activity. There really isn't, and like, you know, we talked about it in this call and prior calls, like, you know, the pumping times and the sand volumes and the pressures, it's hard on equipment. You know, and so if you were to compare how much of your Canadian fleet would be down, you know, us and all of our competitors, how much of the Canadian fleet would be down on any given day due to maintenance, it's higher. Right? These Tier 4 engines are very finicky. You know, and as we sort of keep pushing forward on technology, as everybody knows, you know, things get a little more finicky. And so, you know, we used to be sort of, you used to plan sort of 15% of the fleet to be down on any given day. I'd say that's probably closer to 18% now than it is, you know, roughly. It changes from, you know, quarter to quarter, obviously. But so, you know, one of the, that's a really part of the reason, like we're very bullish on our business in the next five years is, you know, it's fracturing intensive and the services sector, the service sector's ability to respond is not really there. You know, it's going to tighten up very, very quickly. Can I just ask one follow-on then? I guess like if demand calls for two more Tier 4 fleets in the back half of the year 2025, is it fair to say that, you know, the basin really couldn't service them right now? Yeah. You're absolutely right. We, on any given day, or sorry, on almost every day without exception, we don't have enough Tier 4 pumps, and I would assume it would be the same everywhere else. That's just today, you know, and any increased activity is, you know, we're going to, we're already out of Tier 4 gear. You know, we wish we had built, you know, seven of those electric backsides. Not, you know, we had three and more on the way, but, you know, we wanted to evaluate the technology before we jumped in, you know, headfirst, but, you know, that's, you know, the blender performance in particular has been fantastic. Sorry, I'm going to sneak one more in then along the same lines. How much would a Tier 4 fleet cost now with, I understand there's a lot of moving parts, but with some tariff implications put in there? Yeah. Like 45% to 55%. Just the FX would be the increase. But if you were to build a new Tier 4 fleet and you put electric ancillary equipment with it, it would be sort of 55-ish, 60 maybe? Yes. Got it. Really appreciate your responses. I'll turn it back here. Thank you. Okay. Yeah. Sorry, Waqar. Go ahead, please. This concludes the question and answer session. I would like to turn the conference back over to Mr. Fedora for any closing remarks. T hanks, everyone. Thanks for your time. I know there's lots of calls happening on days like this, but Scott and I and the rest of the team will be around for the rest of today and tomorrow if you have any follow-up questions. But thank you very much for dialing in. This brings us to a close of today's conference call. You may now disconnect your line. Thank you for participating and have a pleasant day.