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 and 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.

So 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 31, 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 $275.5 million with adjusted EBITDA of $55.6 million or 20% of revenues not quite as strong as the adjusted EBITDA of $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 $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 $27.6 million in the quarter, which translates to $0.14 per share both on a basic and a fully diluted basis.

Trican generated free cash flow of $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 $18.7 million, split between maintenance capital of about $14.2 million and upgrade capital of about $4.5 million.

Our upgrade capital is 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 $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 supporting 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 $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 $128 million, including cash of about $26 million.

With respect to our return of capital strategy, we repurchased and canceled 3.1 million shares under our NCIB program in the fourth quarter. On an annual basis in 2024 we repurchased and canceled 20.8 million shares at a weighted average price of $4.56 per share, representing 10% of the outstanding shares at the beginning of last year.

Subsequent to Q4 2024, we've repurchased and cancelled an additional 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 $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 $36 million range. Distribution is scheduled to be made on March 31, 2025 to shareholders of record as of the close of business on March 14, 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.

Great, 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, 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. We're really happy with the results given where gas prices were last summer and into the fall.

I would say in general, 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 is really no changes that are happening there.

The division is 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 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 when Northeast BC gets more active again, the Duvernay will be obviously additive to what we have going. And we've talked about this in the past.

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. 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, we continue to be very happy with the performance of this division.

We consider ourselves the technical leader. I think our customers consider us a technical leader.

And really the only reason people don't use us is we are a premium price 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 oily plays which were not that 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, we had a great market share of the incremental work that's being done this year. Overall, we're about 35% market share in the basin.

But in places like the Montney, Duvernay and Deep Basin, we can be as high as 80%, but we're – and we're – if you looked at the basin as a whole, excluding the heavy oil areas which were – we don't have operating bases and 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.

We've been focused on growing this. We've talked a lot about it.

It's great field margins, but just too small. And in Q4, our revenue was up 12% year-over-year and EBITDA was up almost 80%.

But those are small numbers. Our utilization in Q1 so far is really high.

We continue to basically run full out in that division with actually more demand than we have equipment for currently. And we'll continue to try to grow that as 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 AECOs.

And that was the tool company that we talked about in past calls. And that's a tool that's focused on sort of the very oily multilateral well designs, places like 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 added of market share for us as that tool gets deployed.

Just on the outlook for 2025, again, we're very happy with Q1 to date. We're forecasting 2025 to be basically a repeat of 2024.

I don't think Q1 will be as strong as last year's Q1, but we're expecting more level loading throughout the year. And so, from an activity and a financial results perspective, I would say 2025 basically just mirrors 2024.

And 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.

and will Canada have retaliatory tariffs, which seems to be the tone that we're getting out of the government today. And this of course just introduces uncertainty and potential volatility.

And will it impact activity levels with our customer? You know, it's still too early to draw any firm or definite conclusions.

At this point, there's way more questions than answers. But a 10% U.S.

tariff on energy, we don't expect it to have a big impact on, on activity here in Canada, because with the tariff introductions, the, the exchange rate has, has gone up. So, customers may be getting a lower price, but when you convert it to Canadian dollars, you're mitigating a lot of that downside.

The retaliatory tariffs from Canada on U.S. goods coming into the country is probably our biggest concern.

About half the sand we pump comes from the U.S. Preliminary analysis shows that that could result in about a C$15 per ton tariff on sand coming into Canada.

And we'll continue to look for alternatives things like parts and chemicals. 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 or the economic impact is overly punitive. And that would apply to a lot of the parts in the sand that we're bringing in from the U.S.

And so we're hoping when this all shakes out, they're actually the tariffs will not impact us. But to mitigate that risk, we'll just continue to look for alternative sources.

We can get chemical in part out of China at relatively attractive prices there the issue is always just quality concerns is really the only issue. But we'll continue to monitor this going forward and do our best to mitigate the impact of that.

Fortunately, natural gas prices have firmed up the strip for the summer and the winter of 2025 is at very economic level. Our customers are able to hedge gas if they want to.

Certainly this basin goes around at $3.50 AECO without any problems at all. And the financial discipline that's been displayed by our customers over the last few years means that their balance sheets are in great shape, their programs are very level loaded from quarter-to-quarter and year-to-year.

A lot of the gas basin has a high liquids component, 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.

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.

You're not really seeing big pressure on any pricing so far in 2025. I think everybody's boards are pretty full up and so everybody is busy and I think it's just more focused on 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. And the Duvernay is working out as well or better than expected.

It's very, very frac intensive, uses, high pressure treatments, lots of sand, long laterals, so whether you're cementing or fracking or running in coil, those are big service intensive wells that we're very happy to be a part of. And again, we built that Duvernay specific frac fleet that's been performing very well and it's fully utilized and we wish we had built a couple of them actually.

On the sand side, I just want to just give an update on the agreement that we entered into with Source. We are building a transload facility in Northeast BC just to service that market.

As a reminder, there is only one rail line running into Northeast BC and so a lot of that sand gets trucked. So 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 Grand Prairie into Northeast BC, which can have 12-hour round trips.

And so we can rail the sand into Northeast BC and truck from there. We can use our trucking fleet much more efficiently and deploy our own trucking fleet to our customers, where we can make a margin opposed to having third-party trucking get passed through to the customer, which we do not make any margin on.

So that logistics, given how much sand is being pumped in this basin now and how much sand is going into the wells, 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.

We're reviewing a few different pumping technologies and we're trying to figure out 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.

The natural gas operations or what the customers want, it's much less expensive than diesel, burns cleaner, it's available 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 we've looked at – we're using the Tier 4 technology, which is about 75% substitution.

We've trialed electric pumps, and we're building electric ancillary equipment that's performing really well, we're keeping an eye on the turbine space, we're looking at 100% natural gas recip engines. Each of these technology has their own pros and cons, but typically the issues are, will it run with variable gas quality, what's the physical footprint of it on location, and can you get a return on it?

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, 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.

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.

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, less hydraulic lines, et cetera.

So it performs well in the cold. I think overall it's been an overwhelming success.

And when you combine the electric ancillary equipment with our Tier 4 pumps, we're looking at 80%, 85% substitution on location with 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 has been no real changes here. Even though things might feel a little choppy due to the tariff talks, we're still very bullish on Canada.

We view Western Canada as a very attractive place to operate. The Montney in Northwest Alberta and Northeast BC is second to none in North America.

The returns are very good in this play. On the play, the question we get asked a lot is, where are we from a life cycle of the Montney?

And it feels like it's the second or third inning at the most when you compare that to the places in the U.S. where they're probably in the seventh, eighth innings of those plays.

So I think, having exposure to the Montney and the Duvernay is gives you a very long runway. And we're excited to see our customers are active and making money in those plays.

So 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. And 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 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 differential.

So that's also additive to the LNG exports. 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. 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, we have a very clean, conservative balance sheet. So we have the financial capacity to act on opportunities as they arise.

We – I want to just point out, we've been very, very active in the NCIB in the last few years and this has provided a very good investment for us. We actually think of this as M&A.

We're basically buying our own company and we're not. But that NCIB will have to compete with sort of the organic opportunities that we're seeing.

And I would say at this stage, 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.

And we're always looking at things and some you're a successful long hopefully, but the bid ask is always the issue. But 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 this time.

And as Scott mentioned, we upped our dividend by about 11%. And the idea here is, we want to keep our aggregate payout sort of C$36 million to C$38-million-year range.

And we'll just adjust that dividend accordingly and we'll look at that every year at about this time. But 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.

Hey, morning all. Thanks for taking my questions.

Brad, I wanted to get into this Montney versus Duvernay dynamic. We saw higher proppant volumes in the quarter, higher revenues margins were a little lower at least than what I was expecting.

Is that dynamic playing out? And then 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?

Yes, I'll answer that one first. So it's heavy duty equipment.

It's built to operate for long time at higher pressure and it does result in lower R&M. We're not going to get into the details of that, obviously for competitive reasons.

But it's not, what – why the customers like it is, it's less downtime on location, less pumps, smaller footprint, a more reliable operation. And yes, but overall, if you're doing any a given frac with these pumps versus a sort of a conventional non-heavy duty spread, you would have less equipment and then thus less people.

So, we look at it from a cost perspective, it's a win. And from a reliability perspective, not just for us, but for the customer.

And so I hope that answers the question there. I can't give you obviously details exactly on R&M dollars, but from a Duvernay versus Montney perspective.

Yes, you're right. There's more sand being pumped in these Duvernay wells than we're, you see, on the average Montney well, it's at the average Duvernay well is more fracturing intensive than the average Montney well.

And 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.

And the issue that we're always dealing with, of course, is a lot of the sand we buy comes out of the U.S. and the exchange rate worked against us in Q4 versus the prior year or even the year to date last year so.

Gotcha. Maybe just to ask the question a bit differently, CapEx is down year-over-year a little bit.

I know it's growth maintenance split could be different, but if you're going to do more Duvernay wells than Montney wells this year or the mix is changing and all of the, you're kind of assuming a repeat year maybe with more prop and 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 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 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.

And that's why we built that spread or we designed that spread like we did as we anticipated that the Duvernay would pick up steam and momentum and 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. Perfect.

Yes, I know that was a very long-winded answer, but…

Nope. That's great, Brad.

Thank you. On the tech modernization investment, I guess two questions.

Do you think there's any synergies on the back end of implementing the ERP and then on the advanced analytics side or AI, are you just positioning at this point? Are you actually seeing something come down the pipe on that front?

Yes, I'll just, Scott will comment on this after. But of course, like this project, like everything else we don't spend a dime without a positive an attractive IRR.

Certainly, we wouldn't be spending money on this technology if we didn't think it was going to be a positive NPV [ph] project. Part of the issues with Trican, it's a very old company.

Right. And so you've got a mix of new and old.

But the benefit of being as old as we are is, we have collected an incredible amount of equipment data that's very valuable. And we expect that maybe not this year, but next year we will be able to use AI to mine that data.

And particularly with respect to predictive maintenance and overall maintenance, we have a lot of very good pump and engine data here that is going to be valuable. And I think basically the operations and engineering team that they have the foresight to collect that data.

Got you. Well, I guess I'll turn it back.

Thanks.

Thanks, Aaron.

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 I know you've talked about it 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 look like an attractive place for Trican to be?

Yes. I mean, the longer the well just in general, the longer the wells get, the more stages we have or you are seeing 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. If we use coil to open and close sleeves etcetera.

So we like the market. We do think it's a growing market.

It's just a natural evolution of this basin with how it's unfolding. There's not a lot of players in the deep coil market.

I think it's the obvious people like us and our competitors at Element and STEP and a few other private companies. But the issue with coil is, there's a lot of physical infrastructure required and a lot of investment in various coil sizes because your ability to compete in the market is do you have the right coil in the right place on the right day?

And do you have the team that can execute very well once you get to location? And I think 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 I think we're finding we have good field margins. And we're – you 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 it's not as nearly as profitable as we would like, but it doesn't take a lot of growth 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. If you add $15 a ton, maybe that's $75,000 to $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 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?

Yes. I mean, keep in mind, you have sort of 50 to 100 railcars of sand going into a well.

So there is no – there's not a lot of storage in Western Canada like it could be like a week's worth of sand.

One week's worth of sand?

Yes. So in about 50% to 60% of what we pump comes from the U.S.

So no, unfortunately it's not like parts where you can pre buy it to avoid tariffs. There's just too much of it physically that takes up too much space.

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 we are obviously going to advocate through ourselves and through organizations like Conserva that we are going to have the case of the government that it should not be tariffed because there is no alternative.

The domestic providers cannot ramp up production enough to meet the demand for U.S. sand today.

They would literally have to more than double our domestic production. That takes 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 tonne tariff.

Yes, of course, we'll pass that on to the customers. But I think we have a probably one of the best cases that there is for that exclusionary provisions that have been talked about by the government.

So I'm hoping this is just noise, it doesn't I don't think it will come true.

Yes, fair enough. Okay.

That's it for me. Thanks very much.

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?

Yes, exactly. We've tried to sell as much of the really old gear as possible, but quite frankly we were delinquent in making that change.

And just for anybody that's listening, we're referring to the parked equipment. We've gone from five to four crews and it's because these frac crews just keep getting bigger.

And so when you we sort of take our idle capacity and divide it by 20, we're realizing there isn't five crew's worth of pumps there. We have lots of blenders and all the other equipment, but 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, it's dropped from 64% – 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 An [ph] or is there some other driver as well?

Yes, 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 – it's not from the specifics perspective, but yes, that job mix and what you're doing in any particular quarter has a big impact on that will occur.

So and if you worry, generally the EBITDA in Q4, how did the – in factoring, 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?

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, for revenue end. You're talking Q1 of this year versus Q1 of last year?

Yes. On the fracturing side, yes.

Yes. 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 less EBITDA obviously.

Okay. And then EBITDA per well, is it high in Duvernay versus Montney well?

EBITDA per well.

Yes, if that was true?

Yes. 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 has an impact on your equipment as well. More in Duvernay.

Yes. Again, that goes back to the what we were talking about with the equipment design.

So, yes, the EBITDA should result in an annual free cash flow that's higher because we're just not seeing the equipment perform so well. We're not seeing increased R&M.

Okay. And then, Scott, on the G&A side, as we include the C$10 million charge for AML [ph], is the G&A run rate going to be around C$13 million to C$14 million per quarter now in 2025?

Yes, 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, Keith.

Morning, guys. Congrats on a 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 frac and cementing work?

Yes, I would say in general, there's always both. That's 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 think we can add value and provide good service to the customer and that business line will provide the kind of returns that, we require. You want to have it, you have to make sense, of course, but we're not afraid to sort of step out of our three divisions and look at other stuff.

But 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, we're not, I would say, 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 in 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, I think the market in general thinks there's more spare capacity than there is.

Like I said, 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 actually functional.

And remember too like, if you have a 12-year old diesel pump, nobody wants it. They want brand new Tier 4s with upgraded transmissions and pumps.

We get tons of questions about electric and so [indiscernible], in theory there's 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, to add a Tier 4 engine to it, that's a year.

So, I'm actually really glad you asked that question because I think it's important for, your side of the street to recognize that when we see increased activity, due to better gas pricing in LNG, et cetera, 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. 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, to take on more activity.

There really isn't. And we talked about it in this call, prior calls like the pumping times and the sand volumes and the pressures, it's hard on equipment.

So if you were to compare how much of your Canadian fleet would be down, 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, and as we sort of keep pushing forward on technology, as everybody knows, things get a little more finicky. And so, it 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, roughly. It changes from quarter-to-quarter, obviously.

But so, one of the, really part of the reason, like, we're very bullish on our business in the next five years is, it's fracturing intensive. And the services sector, the service sector's ability to respond is not really there.

It's going to tighten up very, very quickly.

Can I just ask one follow. And 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, the basin really couldn't service them right now?

Yes, you're absolutely right. We, on any given day, I'm 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.

Any increased activity is, we're going to, we're already out of Tier 4 here. We wish we had built, seven of those electric backsides.

Not, we have three and more is on the way. But, we wanted to evaluate the technology before we jumped in, head first, but that's, the blender performance in particular has been fantastic.

Sorry, I'm going to sneak one more. And then along the same lines, how much would a Tier 4 fleet cost?

Now, with understanding, a lot of moving parts, but with some tariff implications put in there?

Yes, 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, we'd be sort of 55-ish, 60 maybe.

Yes.

Got it. Really appreciate your responses.

I'll turn it back here.

Thank you. Okay.

Yes, sorry. Operator, go ahead please.

Thanks 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, thank you very much for dialing in.