Good morning, ladies and gentlemen, and welcome to the STEP Energy Services Q1 2025 conference call and webcast. At this time, all lines are in a listen-only mode. Following the presentation, we will conduct a question-and-answer session. If at any time during this call you need assistance, please press star zero for the operator. This call is being recorded on Thursday, May 15th, 2025. I would now like to turn the conference over to Steve Glanville, President and CEO of STEP Energy Services. Please go ahead. Thank you and good morning. Welcome to our Q1 2025 conference call. We're glad you could join us to hear about the first quarter of 2025 and our outlook for the year. First, I'd like to invite Klaas Deemter, our CFO, to provide an overview of our financial results for Q1, and then I'll provide some comments on operating conditions in the first quarter and what we're seeing as we move through 2025. After that, we'll open it up for questions. Klaas? Thanks, Steve, and good morning, everyone. My comments today will include forward-looking statements regarding STEP's future results and prospects. Please note that these forward-looking statements are subject to a number of known and unknown risks and uncertainties that could cause our results to differ materially from our expectations. For more information on the forward-looking statements and these risk factors, please refer to our CDR filings for this quarter as well as our 2024 AIF. Finally, please note that all numbers are in CAD unless noted otherwise, and I will round where possible. Listeners should also note that during the first quarter, STEP made the decision to terminate its U.S. fracturing division, which resulted in an internal leadership reorganization and the decision to aggregate into one operating segment. Going forward, the information provided will be on one reporting segment as all remaining divisions have similar characteristics. The U.S. Fracturing division termination did not meet the test for discontinued operations as some of the related assets are being transferred to Canada. To provide clarity on the ongoing business operations, we will refer to these results as terminated operations and have provided additional disclosure in our Q1 financial statements and MD&A related to these operations. STEP's Q1 consolidated revenues increased to CAD 308 million from the prior quarter revenue of CAD 148 million. Q1 is typically when client capital budgets reset, so it is our strongest quarter, while Q4 is typically our weakest quarter as client budgets wind down. The contrast between quarters was particularly stark this year given the slowdown induced—the quantity price-induced slowdown that we experienced in 2024. Q1 total revenue included CAD 14 million in revenues related to the terminated U.S. operations compared to the CAD 3 million included in the prior quarter. Prior year Q1 revenues were CAD 320 million, which also included CAD 38 million in revenues related to terminated operations. STEP has expanded the definition of adjusted EBITDA to exclude the results from terminated operations to provide clarity on the company's normal course of business activities. Therefore, please note that adjusted EBITDA from previous periods has also been updated to comply with this definition. Adjusted EBITDA for the first quarter came in at CAD 59 million, or a 19% margin, compared with CAD 8 million, or a 5% margin in the prior quarter, and CAD 71 million, or a 22% margin in Q1 of the prior year. STEP had net income of CAD 24 million, or CAD 0.33 per diluted share in Q1 of this year, compared to a loss of CAD 45 million, or negative CAD 0.62 per diluted share in the prior quarter, which included an impairment of CAD 24 million related to our terminated U.S. operations. Included in the Q1 net income was a net loss from terminated operations of CAD 4 million, compared to a CAD 32 million net loss from terminated operations in the prior quarter, again, which included the impairment. Prior year Q1 earnings were CAD 41 million, or CAD 0.55 per diluted share, which included CAD 1 million of net income from terminated operations. During the quarter, we had free cash flow of CAD 32 million, compared to CAD 17 million negative free cash flow in the prior quarter, and free cash flow of CAD 53 million in Q1 of last year. In the quarter, we spent CAD 17 million on capital expenditures. This was made up of CAD 8 million for sustaining capital, CAD 8 million for optimization capital, and CAD 1 million for right-of-use asset additions. CAD 1.9 million of the CAD 17 million was spent on equipment related to the terminated U.S. Operations to complete the remaining Q1 work scope that the company was committed to. In conjunction with the terminated operations of the U.S. fracturing CGU, the company has a plan to sell a group of assets by the end of 2025. The company has CAD 17.4 million of assets held for sale listed on the balance sheet at the end of the quarter, which includes both inventory and equipment. We also purchased 617,000 shares during the first quarter under our NCIB, and subsequent to the quarter, we purchased an additional 177,000 shares. We see deep value in our shares and will continue to use free cash flow to purchase opportunistically under our buyback program. Finally, STEP ended the quarter with net debt of CAD 85 million, which was up from approximately CAD 53 million in the prior quarter. The swing between Q4 and Q1 is driven by the slowdown in activity in Q4 and the ramp-up in Q1, which results in a large working capital build and draws on our bank line. We saw a CAD 68.2 million increase in working capital since the prior quarter, which was impacted by the higher-than-expected client receipts, again, at the close of Q4 and lower-than-expected receipts at the close of Q1. I'll now turn it back to Steve for his comments on operations and outlook. Thank you, Klaas. By now, you would have had the opportunity to look at our most recent results and read through our operational highlights. I won't reiterate what is included in our MD&A, but I will speak about a few key operational achievements in Q1 and provide our outlook for the rest of the year. Our North American coiled tubing operations posted excellent results, running 22 units throughout the quarter. Long-term contracts with key clients in the Montney and Duvernay, as well as relationships with blue-chip clients in the Bakken, Permian, and Eagle Ford basins, are an important part of our success. We continue to see an expansion of the Coil Plus extended-reach lateral mill-outs, where we completed the first two-and-five-eighths coil tubing job in the Rockies and the first three-mile clean-out using two-and-five-eighths in the DJ Basin. This service line is a differentiator for our company as it allows clients to contemplate longer drilling programs to access more rock volume, with the confidence that they will be able to reach total depth during their mill-out operations. Utilization for our fracturing services business remained extremely high, with crews achieving near-record levels. We ran seven frac crews in the quarter, which included one from our now terminated U.S. fracturing operations. We pumped an incredible amount of sand for the quarter, which was 787,000 metric tons, and we broke our previous record in Canada, which is 631,000 tons for the quarter. For context, that's just over 15,000 truckloads of sand, with one unloading every eight minutes around the clock for 90 days straight. STEP handles the majority of our client's sand, hauling just over 60% of the sand we pumped in Q1. This is a core differentiator that consistently delivers strong margins because we do it exceptionally well. We have built a top-tier team and a reliable fleet that takes the logistical burden off of our client's shoulders. I also want to highlight our capital investment in next-generation technologies as part of our long-term diesel reduction strategy. Just in Q1, through our collaboration with a major OEM, we introduced Canada's first 100% natural gas reciprocating engine designed for fully natural gas-powered fracturing operations. We call it the NGX, and it is purpose-built, which has 3,600 horsepower internal combustion engine integrated with proprietary systems and an advanced automation platform. This engine delivers twice the pumping capacity of a conventional pump and operates seamlessly alongside our Tier II and Tier IV dual-fuel assets. This allows for hybrid completions today and positions us for a full natural gas operation as we continue to expand capacity. Although we only have one of these NGX pumps so far in the field, we have seen diesel displacement rates of up to 90% during initial field trials, which is a game-changer in our space. In addition, we are deploying electric-driven backside equipment, including a blender hydration unit, sand handling equipment, and a chemical additive unit, and we're planning to trial a 100% natural gas-powered tractor for our logistics team. These innovations strengthen our ability to deliver reliable, cost-effective solutions while aligning with our client's evolving business priorities. The current energy landscape is fraught with challenges that have contributed to significant instability. Geopolitical tensions, particularly those related to global trade, continue to shape our industry outlook. The retaliatory tariffs recently implemented by the Canadian government are an immediate concern as these measures will place additional pressure on operating costs. In response, we have engaged with several industry associations and collaborated with peers to submit remission applications. While we do not expect to see the positive outcome of these efforts for several months, we are working closely with our clients to help manage the impact on margins. Commodity pricing has fluctuated over the quarter. That said, natural gas prices have demonstrated a consistent upward trend over the past few years. In the WCSB, approximately 75% of our programs are comprised of natural gas and liquids-rich wells. Additionally, the anticipated launch of LNG Canada's first shipment in June of this year will continue to support capital activity in the region. We have not seen a significant contraction in client spending to date, although we do anticipate a potential slowdown in oil-directed activity if prices fall and remain below the $60 per barrel mark. Looking ahead to Q2, we anticipate the typical seasonal breakup conditions in our northern regions before seeing momentum build in the later part of the quarter and into Q3. The activity levels for both business lines are expected to be comparable to those in the same period in 2024. Our third quarter schedule is filling in nicely, with fracturing clients largely maintaining their previously disclosed programs. Coil tubing is more dependent on call-out work, and as a result, it is more difficult to project. However, we are engaged with many of our leading producers in the basins that we operate in and expect to see good utilization throughout the quarter. We remain cautiously optimistic about the fourth quarter while carefully managing expectations. We will provide an update on Q4 when we release our Q2 results in August. Today, our view is that the disruption caused by the geopolitical events this year has created more uncertainty than usual, which continues to impact commodity prices. We are seeing positive momentum in the natural gas market given the structural changes happening on the demand side, but weakness in oil prices may limit the upside potential as we move into the fourth quarter. We are working to fill the remaining white space in the second half of the year and are actively engaged with our clients to manage the impact of commodity prices and tariffs, demonstrating to them that STEP is a trusted partner through all phases of the cycle. Before I turn the call back to the operator, I want to close by expressing how proud I am of what we accomplished during an exceptionally busy period. Our professionals rose to the challenge, delivered an exceptional client experience, and strong results for our shareholders. Our team's focus on safety, operating efficiencies, and excellence made Q1 and other a very successful quarter. Operator, we are pleased to take any questions. Thank you. Ladies and gentlemen, we will now begin the question-and-answer session. Should you have a question, please press the star followed by the one on your touch-tone phone. You will hear a prompt that your hand has been raised. If you wish to decline from the polling process, please press star followed by the two. If you are using a speakerphone, please lift the handset before pressing any keys. The first question comes from Makar Saeed at ATB Capital Markets. Please go ahead. Thank you for taking my question. Steve, would you please remind us how many Tier IV fleets do you have in Canada now? Yeah, good morning, Makar. We're running about two and a half fleets in Canada right now. Of course, we had mentioned that we're moving some assets into Canada from our U.S. terminated operation, and that will bring in basically another fleet when we see time to deploy that into the field. Once the U.S. fleet comes in, you'll be at three and a half fleets, Tier IV? That's correct, yeah. Thank you. Makar, it's Klaas. It also Klaas. It also depends a bit on how you define the size of a fleet. Depending on which basin they're working in, Deep Basin versus Montney versus Duvernay, that'll affect the size of the fleet as well. As that equipment moves around, three fleets could turn into four fleets. Okay. Fair enough. Once you have this extra fleet, would your number of active fleets in Canada go from six to seven, or would it stay at six? Yeah, Makar, our current plan is to stay at six until we see a bit better commodity price cycle. We think there's opportunity, of course, with LNG Canada kicking off here in a month's time, plus some additional LNG opportunities. We are not going to throw it to the field until we see pricing that's stable. Okay. Fair enough. You have your NGX pump. What is kind of the long-term plan? Do you have a continued upgrading plan that next year you may have an extra fleet of NGX, or what is the long-term thinking there? Yeah, I mean, early stages with the trial, we're pretty happy with how it's performed so far. Like we mentioned, we've been able to have it in the field. A number of clients are excited to try it out. I think the long-term view for us is, as older equipment, we need to retire that. The question is, do you upgrade it to Tier IV or do you put this new technology into the field, which we think is a big game-changer? That is something that the team's working through right now. What I can tell you is the cost per horsepower of this unit compared to anything else that we've seen, it's basically more—it's less cost or cheaper per horsepower. That is what we like about it. It replaces basically two units for one. We are excited to see how that performs. Now, when you say cheaper per horsepower, does that mean CapEx per horsepower for new build and OpEx as well? Would you maybe clarify that a little bit? Yeah, no, it's CapEx for right now, but I do believe that we're going to see some savings. You see that typically as you get new equipment in the field, your R&M is a lot cheaper. I think it comes down to is you're basically using one pump versus two. At the end of the day, you'll have less R&M with it. Okay. Great. Now, you mentioned about potential slowdown in oil-related activity based on oil prices. Have you seen any indication in customer discussions where they're saying that they would like to reduce activity or not yet? I would break it down into the two regions that we operate: Canada and the U.S. I think you're seeing a bit more pressure in the U.S. than we are seeing in Canada. The Canadian business, we operate 75%-80% of our clients are in the natural gas, liquid-rich field. So we haven't seen any type of reduction in CapEx yet. But if oil prices kind of hover in that kind of below $60, kind of mid-$50s, you should expect to see some CapEx reduction. What's different about Canada, particularly the Duvernay, where we've seen quite a bit of activity in Q1 and we're seeing it continue on through Q2, is they're not subject to the tariffs because most of that condensate goes to the oil sands. I think you got to look at it that way as well, Makar. Yeah. That makes sense. What I would say is in the oil-affected regions, Makar, we work for a lot of the larger blue-chip clients. As we look through the Q1 releases, we have not really seen that much as far as CapEx reductions go, maybe 1% or 2%, but have not really seen any significant CapEx reductions in the clients we work with. Is that comment also for the U.S. market for coil tubing, or it's just Canada-specific? Both. Yeah, for both. Yeah. Okay. Great. Thank you very much. Appreciate the color. Thank you, Makar. Thank you. The next question comes from John Daniel at Daniel Energy Partners. Please go ahead. Thank you. Good morning, guys. Steve, if you guys decided to push the accelerator and bring on more of the new pump design, what's the sort of manufacturing cadence from how many could you get this year if you wanted to? Yeah, John, I don't know if we've identified exactly how many we can get it. We're going through this prototype phase. We don't want to hurry up and kind of push the accelerator until we're really happy with the design. So far, it's turned out pretty good. I think we would let us trial it for a little bit before we can commit to anything on the call on this, but we are pretty excited about the ability to expand that business or that technology. I know you guys have had a positive experience with the pump. What is your customer telling you? Do you get the sense that those customers would embrace some sort of contractual arrangement for you guys to build one of those fleets? Yeah, so far, John, the feedback from our clients has been exceptional. We've only had it up for a few clients. The challenge, I think, and this will get fixed, is supplying enough natural gas to the job sites. Today, most of our operators that are in the Montney and the Duvernay do have field gas available. As you can imagine, you're going to be needing a bit higher pressure or larger lines to be able to supply the fleet. That is why when we think about what's the most ideal fleet in Canada, it has a combination of, call it Tier IV, that you have some diesel available to you, but the majority of it would be these NGX pumps, which is 100% natural gas. Okay. All right. That's all I got. Thank you for including me. Thanks, John. Thank you. Ladies and gentlemen, as a reminder, should you have any questions, please press star one. Next question from John Gibson at BMO Capital Markets. Please go ahead. Morning all. Thanks for taking my questions. First, on the balance sheet and capital allocation, I mean, debt came up a little bit. I think that was mostly working capital related. Just wondering where you're going to direct the majority of free cash flow this year. Is it further debt repayment, or could you look to maybe ramp the buyback a bit more? That'll be further debt repayment, John. That's always been our primary focus. Okay. Great. Just on pricing, how much is it down year over year in Canada? Do you see any sort of green shoots for the remainder of the year, or is it sort of to be determined right now? Yeah, I can say that the coil tubing prices have kind of held in line year over year, John. In Canada, I think the U.S., we're seeing a bit of pricing kind of pressure in our U.S. coil tubing business, but not—we're talking maybe 5%, but nothing too crazy. I think on the frac side, what we see is Q1 was extremely busy for all of our pressure pumping peers. I think you saw Q1 kind of holding in there from pricing. As we enter into kind of Q2, Q3, there's some RFPs that we're participating in, and I would say pricing's down kind of a couple of 3-4%. I think for us, it's lower than we'd like. The challenge, I think, that all of us are going to face is just the rising costs of these tariffs. I'm not just talking proppant and coil tubing, talking all of the materials, parts, and etc. It's going to show up in our business. You got to be very careful on how you price these things today because we want to make sure that we are profitable going forward. Okay. Great. Last one from me. You've got some assets held for sale on the balance sheet. Wondering if that's a good price to think about, or is where we stand now the likely scenario that you move that equipment back into Canada or at least keep it? Yeah, we're going through that discovery process right now, John. We did impair the assets at the end of Q4, and we also did some in Q3 there. We are comfortable with the value today. It's a blend of inventory and equipment. Some of that inventory, the plan is we'll bundle that with the equipment. Some of that could come north as well to support Canadian operations if we're not successful in bundling it. That is still a little bit TBD at this time, but I think we're comfortable with the value as it stands today. Okay. Great. Thanks a lot, Klaas. I'll turn it back. Thanks, John. Thank you. We have no further questions. I'll turn the call back over to Steve Glanville for closing comments. Yeah. Thank you, everyone, for joining our Q1 2025 conference call. We'll now conclude it and look forward to having our conference call in August for Q2. Thank you very much, everyone. Ladies and gentlemen, this concludes your conference call for today. We thank you for participating, and we ask that you please disconnect your lines. Service line is a differentiator for our company as it allows clients to contemplate longer drilling programs to access more rock volume with the confidence that they will be able to reach total depth during their mill operations. Utilization for our fracturing services business remained extremely high, with crews achieving near-record levels. We ran seven frac crews in the quarter, which included one from our now terminated U.S. fracturing operations. We pumped an incredible amount of sand for the quarter, which was 787,000 metric tons, and we broke our previous record in Canada, which is 631,000 tons for the quarter. For context, that's just over 15,000 truckloads of sand, with one unloading every eight minutes around the clock for 90 days straight. STEP handles the majority of our client's sand, hauling just over 60% of the sand we pumped in Q1. This is a core differentiator that consistently delivers strong margins because we do it exceptionally well. We have built a top-tier team and a reliable fleet that takes the logistical burden off of our client's shoulders. I also want to highlight our capital investment in next-generation technologies as part of our long-term diesel reduction strategy. Just in Q1, through our collaboration with a major OEM, we introduced Canada's first 100% natural gas reciprocating engine designed for fully natural gas-powered fracturing operations. We call it the NGX, and it is purpose-built, which has 3,600 horsepower internal combustion engine integrated with proprietary systems and an advanced automation platform. This engine delivers twice the pumping capacity of a conventional pump and operates seamlessly alongside our Tier II and Tier IV dual-fuel assets. This allows for hybrid completions today and positions us for a full natural gas operation as we continue to expand capacity. Although we only have one of these NGX pumps so far in the field, we have seen diesel displacement rates of up to 90% during initial field trials, which is a game-changer in our space. In addition, we are deploying electric-driven backside equipment, including a blender hydration unit, sand handling equipment, and a chemical additive unit. We are planning to trial a 100% natural gas-powered tractor for our logistics team. These innovations strengthen our ability to deliver reliable, cost-effective solutions while aligning with our clients' evolving business priorities. The current energy landscape is fraught with challenges that have contributed to significant instability. Geopolitical tensions, particularly those related to global trade, continue to shape our industry outlook. The retaliatory tariffs recently implemented by the Canadian government are an immediate concern as these measures will place additional pressure on operating costs. In response, we have engaged with several industry associations and collaborated with peers to submit remission applications. While we do not expect to see the positive outcome of these efforts for several months, we are working closely with our clients to help manage the impact on margins. Commodity pricing has fluctuated over the quarter. That said, natural gas prices have demonstrated a consistent upward trend over the past few years. In the WCSB, approximately 75% of our programs are comprised of natural gas and liquids-rich wells. Additionally, the anticipated launch of LNG Canada's first shipment in June of this year will continue to support capital activity in the region. We have not seen a significant contraction in client spending to date, although we do anticipate a potential slowdown in oil-directed activity if prices fall and remain below the $60 per barrel mark. Looking ahead to Q2, we anticipate the typical seasonal breakup conditions in our northern regions before seeing momentum build in the later part of the quarter and into Q3. The activity levels for both business lines are expected to be comparable to those in the same period in 2024. Our third-quarter schedule is filling in nicely, with fracturing clients largely maintaining their previously disclosed programs. Coil tubing is more dependent on call-out work, and as a result, it's more difficult to project. However, we are engaged with many of our leading producers in the basins that we operate in and expect to see good utilization throughout the quarter. We remain cautiously optimistic about the fourth quarter while carefully managing expectations. We will provide an update on Q4 when we release our Q2 results in August. Today, our view is that the disruption caused by the geopolitical events this year has created more uncertainty than usual, which continues to impact commodity prices. We are seeing positive momentum in the natural gas market given the structural changes happening on the demand side, but weakness in oil prices may limit the upside potential as we move into the fourth quarter. We are working to fill the remaining white space in the second half of the year and are actively engaged with our clients to manage the impact of commodity prices and tariffs, demonstrating to them that STEP is a trusted partner through all phases of the cycle. Before I turn the call back to the operator, I want to close by expressing how proud I am of what we accomplished during an exceptionally busy period. Our professionals rose to the challenge, delivered an exceptional client experience, and strong results for our shareholders. Our team's focus on safety, operating efficiencies, and excellence made Q1 and other a very successful quarter. Operator, we are pleased to take any questions. Thank you. Ladies and gentlemen, we will now begin the question-and-answer session. Should you have a question, please press the star followed by the one on your touch-tone phone. You will hear a prompt that your hand has been raised. If you wish to decline from the polling process, please press star followed by the two. If you are using a speakerphone, please lift the handset before pressing any keys. The first question comes from Makar Saeed at ATB Capital Markets. Please go ahead. Thank you for taking my question. Steve, would you please remind us how many Tier IV fleets do you have in Canada now? Yeah. Good morning, Makar. We're running about two and a half fleets in Canada right now. Of course, we had mentioned that we're moving some assets into Canada from our U.S. terminated operation, and that will bring in basically another fleet when we see time to deploy that into the field. Once the U.S. fleet comes in, you'll be at three and a half fleets, Tier IV? That's correct. Yeah. Thank you. Makar's class. It also depends a bit on how you define the size of a fleet. Depending on which basin they're working in, Deep Basin versus Montney versus Duvernay, that'll affect the size of the fleet as well. As that equipment moves around, three fleets could turn into four fleets. Okay. Fair enough. Once you have this extra fleet, would your number of active fleets in Canada go from six to seven, or would it stay at six? Yeah. Makar, our current plan is to stay at six until we see a bit better commodity price cycle. We think there's opportunity, of course, with LNG Canada kicking off here in a month's time, plus some additional LNG opportunities. We're not going to throw it to the field until we see pricing that's stable. Okay. Fair enough. You have your NGX pump. What is kind of the long-term plan? Do you have a continued upgrading plan that next year you may have an extra fleet of NGX, or what is the long-term thinking there? Yeah. I mean, early stages with the trial, we're pretty happy with how it's performed so far. Like we mentioned, we've been able to have it in the field. A number of clients are excited to try it out. I think the long-term view for us is, as older equipment, we need to retire that. The question is, do you upgrade it to Tier IV? Do you put this new technology into the field, which we think is a big game-changer? That's something that the team's working through right now. What I can tell you is the cost per horsepower of this unit compared to anything else that we've seen, basically, it's less cost or cheaper per horsepower. That's what we like about it. It replaces basically two units for one. We're excited to see how that performs. Now, when you say cheaper per horsepower, does that mean CapEx per horsepower for new build and OpEx as well? Would you maybe clarify that a little bit? Yeah. No, it's CapEx for right now, but I do believe that we're going to see some savings. You see that typically as you get new equipment in the field, your R&M is a lot cheaper. I think it comes down to is you're basically using one pump versus two. At the end of the day, you'll have less R&M with it. Okay. Great. Now, you mentioned about potential slowdown in oil-related activity based on oil prices. Have you seen any indication in customer discussions where they're saying that they would like to reduce activity or not yet? I would break it down into the two regions that we operate: Canada and the U.S. I think you're seeing a bit more pressure in the U.S. than we are seeing in Canada. The Canadian business, we operate 75-80% of our clients are in the natural gas liquid-rich field. So we haven't seen any type of reduction in CapEx yet. But if oil prices kind of hover in that kind of below $60, kind of mid-$50s, you should expect to see some CapEx reduction. What's different about Canada, particularly the Duvernay, where we've seen quite a bit of activity in Q1, and we're seeing it continue on through Q2, is they're not subject to the tariffs because most of that condensate goes to the oil sands. I think you got to look at it that way as well, Makar. Yeah. That makes sense. What I would say is, in the oil-affected regions, Makar, we work for a lot of the larger blue-chip clients. As we look through the Q1 releases, we have not really seen that much as far as CapEx reductions go, maybe 1% or 2%, but have not really seen any significant CapEx reductions in the clients we work with. Is that comment also for the U.S. market for coil tubing, or it's just Canada-specific? Both. Yeah, for both. Yeah. Okay. Great. Thank you very much. Appreciate the color. Thank you, Makar. Thank you. The next question comes from John Daniel at Daniel Energy Partners. Please go ahead. Thank you. Good morning, guys. Steve, if you guys decided to push the accelerator and bring on more of the new pump design, what's the sort of manufacturing cadence from how many could you get this year if you wanted to? Yeah, John, I don't know if we've identified exactly how many we can get it. We're going through this prototype phase. We don't want to hurry up and kind of push the accelerator until we're really happy with the design. So far, it's turned out pretty good. I think we would let us trial it for a little bit before we can commit to anything on the call on this, but we are pretty excited about the ability to expand that business or that technology. I know you guys have had a positive experience with the pump. What is your customer telling you? Do you get the sense that those customers would embrace some sort of contractual arrangement for you guys to build one of those fleets? Yeah. So far, John, the feedback from our clients has been exceptional. We've only had it up for a few clients. The challenge, I think, and this will get fixed with us supplying enough natural gas to the job sites. Today, most of our operators that are in the Montney and the Duvernay do have field gas available. As you can imagine, you're going to be needing a bit higher pressure or larger lines to be able to supply the fleet. That's why when we think about what's the most ideal fleet in Canada, it has a combination of, call it Tier IV, that you have some diesel available to you, but the majority of it would be these NGX pumps, which is 100% natural gas. Okay. All right. That's all I got. Thank you for including me. Thanks, John. Thank you. Ladies and gentlemen, as a reminder, should you have any questions, please press star one. Next question from John Gibson at BMO Capital Markets. Please go ahead. Morning all. Thanks for taking my questions. First, on the balance sheet and capital allocation, I mean, debt came up a little bit. I think that was mostly working capital related. Just wondering where you're going to direct the majority of free cash flow this year. Is it further debt repayment, or could you look to maybe ramp the buyback a bit more? That'll be further debt repayment, John. That's always been our primary focus. Okay. Great. Then just on pricing, how much is it down year over year in Canada? Do you see any sort of green shoots for the remainder of the year? Is it sort of to be determined right now? Yeah. I can say that the coil tubing prices kind of held in line year over year, John. In Canada, I think the U.S., we're seeing a bit of pricing kind of pressure in our U.S. coil tubing business, but we're talking maybe 5%, but nothing too crazy. I think on the frac side, what we see is Q1 was extremely busy for all of our pressure pumping peers. I think you saw Q1 kind of holding in there from pricing. As we enter into kind of Q2, Q3, there's some RFPs that we're participating in, and I would say pricing's down kind of a couple of 3-4%. I think for us, it's lower than we'd like. The challenge, I think, that all of us are going to face is just the rising costs of these tariffs. I'm not just talking proppant and coil tubing, talking all of the materials, parts, etc. It's going to show up in our business. You got to be very careful on how you price these things today because we want to make sure that we are profitable going forward. Okay. Great. Last one from me. You've got some assets held for sale on the balance sheet. Wondering if that's a good price to think about, or is where we stand now the likely scenario that you move that equipment back into Canada or at least keep it? Yeah. We're going through that discovery process right now, John. We did impair the assets at the end of Q4, and we also did some in Q3 there. We're comfortable with the value today. It's a blend of inventory and equipment. Some of that inventory, the plan is we'll bundle that with the equipment. Some of that could come north as well to support Canadian operations if we're not successful in bundling it. That's still a little bit TBD at this time, but I think we're comfortable with the value as it stands today. Okay. Great. Thanks a lot, guys. I'll turn it back. Thanks, John. Thank you. We have no further questions. I'll turn the call back over to Steve Glanville for closing comments. Yeah. Thank you, everyone, for joining our Q1 2025 conference call. We'll now conclude it and look forward to having our conference call in August for our Q2. Thank you very much, everyone. Ladies and gentlemen, this concludes your conference call for today. We thank you for participating, and we ask that you please disconnect your lines.