Good day, ladies and gentlemen, and welcome to the STEP Energy Services Q3 2023 conference call and webcast. At this time, all lines are in listen-only mode. Following the presentation, we will conduct a question and answer session. If at any time during this call you require immediate assistance, please press star zero for the operator. This call is being recorded today, November 2, 2023. I would now like to turn the conference over to Dana Benner, Senior Advisor, Corporate Development and Investor Relations. Please go ahead. Thanks, operator, and good morning, everyone. Welcome to STEP's third quarter 2023 conference call and webcast. The quarter produced many excellent results, especially in the context of lower year-over-year drilling rig counts in both the U.S. and Canada. I am pleased to introduce today's roster of speakers. Steve Glanville, our President and CEO, will give some opening remarks. Klaas Deemter, our CFO, will follow with an overview of the financial highlights before turning it back to Steve for some strategy and outlook-focused commentary. We will host a Q&A session to follow. Before I turn it over to Steve, I would like to remind everyone that this conference call may contain forward-looking statements and other information based on current expectations or results for the company. Certain material factors or assumptions that were applied in drawing conclusions or making projections are reflected in the forward-looking information section of our Q3 2023 MD&A. Several business risks and uncertainties could cause actual results to differ materially from these forward-looking statements and our financial outlook. Please refer to the risk factor and risk management section of our MD&A for the quarter ended September 30, 2023, for a more complete description of business risks and uncertainties facing STEP. This document is available both on our website and on SEDAR. During this call, we will also refer to several common industry terms and certain non-IFRS measures that are fully described in our MD&A, which again, is available on SEDAR and on our website. With that, I will pass the call over to Steve. Thanks, Dana, and good morning. Welcome to our third quarter earnings call. My name is Steve Glanville, and I'm the President and CEO of STEP Energy Services. Hopefully, you've had the opportunity to look through our earnings release. As you see, there's a lot going on at STEP, and there's a lot of good news to talk about. First, it was another strong quarter for the company. Despite lower drilling activity versus last year in both the U.S. and Canada, three of our four business units achieved higher year-over-year revenue. Both Canadian fracturing and coiled tubing bettered last year's top line, while U.S. coiled tubing put up its thirteenth quarter in a row of sequential revenue growth and the fifth record quarter in a row. This rising trend line of revenues validates our claim that we are the industry leader in deep capacity coiled tubing in North America. Once again, there are two important numbers in the quarter that I would like to highlight. First, the CAD 52.3 million of adjusted EBITDA we generated is the best level in a quarter this year and also in line with consensus. Second, our net debt has been reduced below CAD 100 million, and by quite a bit. In fact, net debt ended the quarter at just under CAD 90 million, which is down roughly from CAD 116 million in Q2. The balance sheet continues to improve and is now less than 0.5 times trailing twelve-month adjusted EBITDA. Historically, that would have been considered an unlevered balance sheet, but now we just call it a strong balance sheet. In these results, we also announced a major new client commitment in Canada, which is two years of significant fracturing work with a leading Montney producer, one that essentially leaves us undersupplied to meet all of our Canadian client demand as we look into 2024. We are going to address that with a solution that we will talk about shortly. I will return at the end of our earnings call to address our strategy and outlook. First, I want to turn the call over to Klaas Deemter, our CFO, to give some financial highlights. Thanks, Steve, and good morning, everyone. Before I start, a reminder to listeners that all numbers are in Canadian dollars, unless noted otherwise, and all rounded where possible. Full details can be found in our Q3 financial statements and MD&A, which is posted on SEDAR and on our website. As noted, the third quarter was another strong one for the company. Despite a 15% lower year-over-year rig count in the U.S. and 7% lower rig count in Canada, we grew our consolidated revenue by 4%. Turning to the bottom line, Adjusted EBITDA was CAD 52.3 million, which was our best quarterly number this year. Achieving this profitability in the face of volatile commodity prices, combined with declining rig counts and overall service activity, is a testament to the quality of our people. In the past, these conditions would have led to a significant downturn in profitability for the service sector, but on a year-over-year basis, our company's EBITDA performance is virtually the same. We've earned about CAD 145 million in Adjusted EBITDA year to date, which includes the expensing of CAD 5.5 million in fluid ends this year. For the same period last year, we also earned CAD 150 million when we did not expense fluid ends. Achieving this result hasn't been easy. The weakness in the oil and gas prices earlier this year and the general volatility since then has meant that we had to constantly optimize our operations and focus on cost control. Although our Q3 consolidated Adjusted EBITDA was lower than the CAD 58 million reported one year ago, the positive trend line of increasing EBITDA this year is something we're proud of. Turning to Adjusted EBITDA margins, the consolidated number in Q3 was 21% of revenue compared to 24% one year ago. We've said before that pressure pumping is a project-based business that doesn't fit neatly into calendars. So again, looking at it on a year-to-date basis, we're at 20% this year, right in line with the 20% we earned last year. Net income for the third quarter was CAD 0.28 per diluted share, compared to CAD 0.21 in Q2 of this year and CAD 0.43 a year ago. Through nine months, we've earned CAD 0.74 per diluted share versus CAD 1.09 last year, although last year's EPS benefited from a CAD 33 million impairment reversal on property and equipment. Canadian activity levels in both fracturing and coiled tubing were affected by a combination of the lingering effects of wildfires and floods experienced in Q2, as well as the volatile commodity prices, which caused some clients to defer work to 2024. Fracturing saw a 12% year-over-year increase in revenue, due in large part to the significant increase in sand pumped. We continue to see sand intensity per well rise, which is demonstrated in the higher sand pumped per day. We haul the majority of our own sand, providing a more consistent client experience as well as reducing our costs. We're extremely proud of the contribution that our logistics teams makes to this business. Revenues were flat year-over-year in coiled, although overall activity levels were also negatively affected by fires and floods. The increase in revenue per day is a positive signal, and we see opportunity building in this service line. STEP has been known as a technical leader in coiled tubing since our inception, demonstrated by our technical innovations such as our STEP- Connect and E-Coil. Our equipment and personnel are second to none, and the depth record of 8,101 meters that was set in early October is further testament to this capability. Total Adjusted EBITDA of CAD 41.2 million was higher sequentially and year-over-year. While the margins have come under some pressure relative to the same period last year, our EBITDA margin of 26% was lower on a year-over-year basis, negatively affected by lower utilization, cost inflation and some pricing pressure. I will point out, however, that total year-to-date adjusted EBITDA of CAD 119.4 million at a 26% margin is ahead of last year's pace in both absolute and relative terms. Turning to the U.S., the sector is contending with a significant slowdown in activity. Commodity price volatility, and particularly natural gas, led the average drilling rig count 15% lower on a year-over-year basis. Fracturing crew counts are also down 17%, leading to pricing pressure and some margin compression. Fracturing revenue was down 30% year-over-year, due in part to the shift in job mix. In 2022, we supplied more sand for our clients as supplies were tight, whereas in 2023, sand supplies have loosened, allowing clients to source their own sand, which reduces revenue and margins to STEP. Utilization on our fracturing crews was lower sequentially and year-over-year, largely due to a slow period in June and July. August and September were highly utilized, however. Another trend worth noting, again, is the continuing increase in service intensity, as shown by the higher year-over-year increase in sand pumped per day. This is made possible by higher average pumping hours per day, as well as more horsepower per crew. Our coiled tubing service line set another record for quarterly revenue, fifth time in a row. The U.S. coiled tubing revenue was $50 million, up 38% from a year ago and up 5% from the record second quarter. We ran 12 units this quarter, which is unchanged from the second quarter and up from roughly 9 units a year ago. The acquisition of the four deep coiled tubing units from ProPetro that we made a little more than a year ago has been a significant factor in this success, giving us equipment that can reach the deepest wells being drilled today. To put this Q3 performance into context, coiled tubing operating days were up 9% from the second quarter, even though the underlying U.S. land rig count was down. We've seen particular success in the northern regions, which have not had access to the technical capabilities that STEP can bring. Similar to our Canadian coiled division, our U.S. division also set a depth record, milling down to 8,252 meters, or 27,075 feet in the language of our U.S. friends. I want to turn now to margins. The US segment as a whole posted adjusted EBITDA of $15.4 million, which was down from $20.8 million a year ago and $18.3 million in Q2. The associated adjusted EBITDA margin was 16% this quarter, versus 20% a year ago and 19% in the second quarter. We've been fighting the lower trend line of US activity all year, and our results reflect that. We're continuing to carefully monitor our costs and wait for a resumption in drilling activity that is widely expected to increase in 2024 from today's levels. Turning to the balance sheet and our free cash flow, we have more good news to report. As noted, we set a net debt target to close at the close of 2023 of less than CAD 100 million, and we're extremely pleased to see our net debt come in at just under CAD 90 million, one quarter early against our target and down from CAD 160 million at the end of Q2. Measured against trailing twelve-month adjusted EBITDA, the ratio is now less than 0.5x, which marks an excellent balance sheet in this sector. Going further back, since 2018, the company has paid down almost CAD 230 million of its net debt. This reduction of debt has been a pure transfer into equity value. Free cash flow in the quarter was over CAD 37 million, as compared to roughly CAD 40 million a year ago and CAD 35 million in Q2, a consistent trend line that is not showing the marks of seasonality that we used to see in this sector. On a trailing twelve-month basis, free cash flow is just over CAD 111 million. I want to make a point here: Our company is generating substantial free cash while also investing into our fleet of equipment. We remind investors again that we have the best long-term track record among Canadian-based pressure pumpers of fleet reinvestment, as measured by gross CapEx versus long-term depreciation of major assets. This matching has helped us preserve long-term fleet quality and occurred despite the extreme downturn experienced in 2014 to 2021. We also compare very favorably, favorably on this metric against our peer group of North American pressure pumpers. Turning to capital spending, including leases, we spent just under CAD 28 million in the quarter, up modestly from the 23 spent in the second quarter. Current projects include adding dual fuel kits to one of our U.S. fracturing fleets, which is already running Tier 4 pumps. We are also in the midst of upgrading a second fleet of Canadian Tier 2 pumps to Tier 4 dual fuel, a project that should be finished in the second quarter of 2024. On completion, we will have 38 pumps in Canada with the most modern Tier 4 dual fuel technology and 32 in the U.S., bringing our total dual fuel fleet to 68% of our total horsepower count, the majority of which will be Tier 4. These upgraded pumps are dispatched individually to the field as soon as they are finished, so the benefits scale in for our clients and also into our financial results. As of this Q3 earnings report, we also announced the first phase of our 2024 capital budget. Long lead times continue to be a challenge across our industry, as they are in many supply chains across the world, so we approved a CAD 60 million budget for sustaining and critical optimization capital. Similar to last year, we anticipate releasing the full 2024 capital budget in Q1 2024, which is likely to include additional optimization capital. We're very mindful of the need to strike a balance between continued deleveraging with investing opportunistically as client demand warrants and as return thresholds are met. Our 2023 capital budget remains at CAD 105 million, with the remainder expected to be spent in Q4 and the first half of 2024. Finally, our latest book value per share has increased to CAD 5.06 from CAD 4.68 at June 30, and from CAD 4.08 a year ago. This is a full year accretion to the equity holders of roughly CAD 74 million or about CAD 1 a share. With that, I'll turn it back to Steve for some key remarks on our outlook and strategy. Thanks, Klaas. In Canada, we have posted some great results, and our performance is set to improve even further, thanks to a major new contract for fracturing services, work with a leading producer in Canada's top natural gas play, the Montney. We were awarded this work because of our consistent track record of exceptional performance in the basin. The agreement includes the supply of ancillary services, such as pump downs as well. High performance requires great people with a deep understanding of how to run well-maintained, relevant equipment with safety and efficiency top of mind. This is something we are very proud of at STEP. We invest in our people, our processes, and our equipment, and the results clearly reflect this. Meeting this additional demand will require a strategic solution, and because of our geographic diversity and strong balance sheet, we can deliver that solution. We plan to transfer some fracturing equipment from the U.S., where the market is currently not as strong. Now, let's go through a more detailed discussion about the Canadian and U.S. outlook. The outlook in Canada is clearly very positive for us. Activity in the fourth quarter is going to slow down a little in both business units, as it does most years due to budget exhaustion and the holiday season. During this period, we anticipate a greater mix of smaller Canadian fracturing jobs, which can impact our operational efficiencies. On the Canadian coiled tubing side, we expect steady utilization extending into early to mid-December. We plan to use this brief slowdown to perform necessary equipment maintenance and prepare for what appears to be an exceptional busy winter. Looking ahead to 2024, where several events are set to have a positive impact on our industry. Completion of both the Trans Mountain oil pipeline and Coastal GasLink natural gas pipeline is on the horizon, and both will begin receiving volumes for eventual export. This is a significant milestone for our industry, both also for Canada, as all Canadians stand to benefit from these long-term projects and the revenues they generate for the various levels of governments. STEP is fully committed to contributing to the production of these incremental volumes with a strong emphasis on sustainability. We have already upgraded one of our Canadian fracturing fleets to Tier 4 engines with dual fuel capability and have started the upgrade process for a second fleet, which will be fully deployed in Q2 of 2024. Our first quarter, our first quarter Canadian calendar is almost fully booked, supported by the recent major contract wins we have mentioned, as well as increased budgets from multiple clients year-over-year. Currently, we are on the verge of being undersupplied in our Canadian fracturing services divisions, so we're taking proactive steps to optimize our consolidated fracturing fleet, and as mentioned, we'll relocate some assets to Canada late in Q4 of this year. We expect first quarter sand volumes to hit record levels, which underscores the growing importance of sand logistics in meeting clients' expectations and job efficiencies. STEP has one of the largest internal hauling fleets in the basin with specialized hauling equipment, and we intend to grow our Canadian sand hauling fleet in 2024 to match our additional fracturing demand. This will be critical in maintaining our standards of operational excellence. Looking beyond the first quarter, we have strong reason to believe that our clients' efforts to level load their annual programs will once again benefit us in Q2. Overall, Canadian fracturing is looking very busy in 2024. On the coiled tubing front, we expect an increase in activity compared to 2023, due in part to our well-maintained equipment, our extended reach capabilities, and exceptional service delivery, which has helped us gain market share. Turning to the U.S., even though we are moving frac equipment north to support our increased utilization levels in Canada in early 2024, we remain committed to the U.S. and continue to see the long-term potential as LNG projects support activity in U.S. natural gas basins. Given the U.S.'s prominent position in global oil and natural gas markets, and the rising service intensity per well needed to support production volumes, we anticipate a growth need for our services in the years ahead. In the near term, the fourth quarter will remain choppy, as the U.S. land drilling count appears to have only recently bottomed after a year-long decline. The tightening of the U.S. rig count to frac fleet spread is likely to result in a temporary oversupply of U.S. fracturing assets and continued softness in the spot market pricing. STEP's 12 active U.S. coiled tubing units should remain highly utilized for much of Q4 until the typical holiday season begins in late November and again in mid-December. Over the last several months, we have strategically shifted CT units of our southern region of our business, due in part to some pricing softness, and into the northern U.S. operating areas, where pricing has remained steady. Our leading-edge coiled tubing technology, expertise, and capabilities, reaching extended depths beyond 27,000 feet or 8,200 meters, make these units very attractive offering for clients in all major basins. Looking ahead to 2024, we expect the U.S. land drilling rig count to begin a gradual arc higher, resulting in a faster pace of completion activity. Higher oil prices are increasing E&P free cash flows, which should provide additional support. Natural gas demand will increase later in 2024 as new pipeline infrastructure comes online to deliver significant committed export volumes to the next wave of LNG facilities. According to the current U.S. Department of Energy forecast, there will be an additional capacity of nearly 4 billion cubic feet per day in U.S. LNG exports online by late 2024, with another 4 BCF required by the end of 2025. This represents approximately a 60% growth in a little over a year based on the current export volume of around 13 BCF per day. This remarkable growth is exactly why we are investing in the U.S. market. Unfortunately, the mismatch between infrastructure and commodity demand may result in uneven fracturing activities levels throughout the U.S. for the first half of 2024. In any event, we will do our best to position equipment and people strategically and ensure we are prepared as the U.S. resumes its growth trajectory. With that, I want to thank all of the employees of STEP, people we call professionals in all capacities, for their valuable contributions this quarter. We cannot deliver results like this without all of you. Operator, we'd be pleased to take any questions. Thank you. Ladies and gentlemen, we'll now begin the question and answer session. Should you have a question, please press star one. If you want to withdraw your question, please press star two. Your questions will be pulled in the order they are received. If you are using a speakerphone, please lift the handset before pressing any keys. One moment please, for your first question. Your first question comes from Keith Mackey from RBC. Please go ahead. Hi, good morning, and thanks for taking my question. Just wanted to start out on the equipment you're moving from the U.S. to Canada. Can you just run through, you know, how much horsepower is it? What is the spec? Is there capital or much capital required to bring it into service? And will this be the exact equipment that's working on the new Montney contract you've mentioned? Yeah, Keith, good morning. It's Steve here. Yeah, so the equipment is basically horsepower is what we're moving from the U.S. to Canada, and it's really horsepower that we obtained through the GasFrac acquisition. It was Canadian-built assets. So they are cold-weather operating assets. We had moved them down to the U.S. to look at standing up our fourth crew back earlier in the year. And so we just obviously have looked at ways to increase the margin of our business, and the benefit that we have, having both geographies, is that we can move these assets to where we're getting the best margin. So that's the whole intent of this, Keith. And so it's 12 pumps, so we'll call it 30,000 horsepower that we're moving up to Canada. We'll reevaluate this at the end of Q1. As you know, Q1 is looking extremely busy for us, and we'll reevaluate it and see if there's another market that we can put these assets into if we're not happy with this one. Got it. Okay. Okay, and then just for clarity then, how many equipment or how much equipment or how many crews do you plan to run in the U.S. going through 2024? Is this going to, you know, is this action gonna take your fleet count down to 2, or will you still be able to run 3 fleets through 2024 in the U.S.? Well, currently today, we have two fleets that are on long-term contracts. The third fleet has been busy through kind of Q3 and into Q4 here. Our plan right now is to look at a long-term contract for that third crew. And so eventually, you know, we're looking at continuing to run three crews. ... Got it. Okay, I'll leave it there. Thanks very much. I just want to reiterate, Keith, that, like, the RFP season in the U.S. has been very active, and just waiting to hear on some results from a number of RFPs that we've been participating in. Okay. Appreciate that color. Thank you. Thank you. Your next question comes from Cole Pereira from Stifel. Please go ahead. Hi, morning, all. So you had previously talked about how some of your competitors activating equipment had, you know, put a bit of a lid on pricing. I mean, there's obviously a lot of tailwinds going into 2024 here, but, you know, isn't moving the spread from the US kind of bring about a risk of the same happening? We've been very clear, Cole, in the past that we would only bring equipment or refurbished equipment with long-term contracts, and that's what we have in place today, is long-term contracts. Yeah, but I can understand that, but isn't there a risk that the market turns to oversupply and then, you know, general market prices, including the rest of your fleet, either stays the same or gets priced down? We don't see that. We see our client base that we're currently working for today increasing their capital budgets for next year. And, you know, I think there's some really good stories coming for the Canadian market. As I mentioned, with LNG Canada, we're starting to see a ramp-up of activity. You know, we've seen it from a drilling rig standpoint. The Montney and the Duvernay are going to see additional capital being spent in 2024, and so I believe the Canadian fracturing market will be undersupplied for Q1 and perhaps balanced for the remaining of the year. Got it. And then just, you know, thinking about the U.S. coiled tubing business, can you just talk about that in a bit more color? Is it, you know, really just the depth capacity there that, you know, is driving a lot of your success? Is it, you know, the broader scale, et cetera? Yeah, Cole, I think there's been a couple factors. You know, number one, we talked about the wells are getting deeper. In fact, we have a client that's talking about a four-mile lateral, not a three-mile lateral. So, of course, that is, that's great news for our business. And secondly, there's been a number of M&A, you know, transactions that have happened in the U.S., and I think what this is demonstrating is that, like, it's a pretty sophisticated business nowadays. Coiled tubing is not just buy a coiled tubing unit and hire some people and go out and run it. It's becoming extremely technical. It requires lots of resources, and we demonstrated that, you know, from a, from, you know... You need scale to be able to absorb the overhead and the, you know, the engineering, et cetera, to be able to support it. We're really happy with how our U.S. has developed into a fantastic business for us. Got it. Okay, that's all for me. Thanks. I'll turn it back. Thank you. Your next question comes from John Gibson from BMO Capital. Please go ahead. Morning, all. Thanks for taking my questions. First, on the balance sheet, obviously, nice to see the debt move below your target threshold. I guess as we move forward here, do you expect your capital allocation priorities to change, maybe towards something like a buyback, just given where your valuation sits? Hey, good morning, John. It's Klaas. Thanks for the question. It's something that we spend a lot of time thinking about, and as 2024 really comes into view, I think it's becoming increasingly prominent and along our list of items to deploy capital to. At this point, I think we want to see kind of where the Q1 RFP season finally settles in, and as Steve noticed there, just noted earlier, there are still some bids that are outstanding. So as we get a better feel for what 2024 looks like, that's certainly something that's going to be under strong consideration. Okay, great. Thanks. Second one for me. You talked about sand constraints, being quite restricting right now. As we head into next year, do you see them impacting you or your peers' activity levels, you know, if demand continues to rise? So, particularly Canada, I'm assuming you're talking about, John? Yeah. Yeah. Yeah. Yeah, our team has done an amazing job of procuring and locking up a sand for Q1. I think the basin is going to see, you know, probably a 30% increase in sand pumped for Q1. And so with that, you need obviously lots of planning, lots of transload storage, lots of onsite storage, and of course, as I highlighted, just hauling, the ability to haul multiple loads of sand to these well sites in a short period of time. And, you know, Klaas and I were actually on a job with one of our clients in September, and the transition times that we're seeing between stages is, like, 90 seconds now. So there's really no shutting down of equipment. They're quickly swapping over to the next well. And so that, you know, you think about the amount of, I would say, demand required to be able to keep a operation running 24 hours a day, you need a lot of infrastructure, and that's what we've been investing in. And we believe, as we've kind of procured our current volumes for Q1, we believe that we're in a really good position. Now, with Canada, it's, you know, we have a sort of a monopoly on a rail system that we have, and a lot of times tariffs do show up in the quarter, and we're hoping that that will be avoided. Got it. Thanks. Last one for me is more of, I guess, a high-level question in the U.S. I guess I understand activity levels ebb and flow both north and south of the border, but longer term, where do you see your U.S. fleet going? Or are you comfortable keeping it at sort of like that 2-3 fleet level? Yeah, I think you're gonna see budgets reset starting in Q1 of 2024. What we've seen is the private drillers in the U.S. have really throttled back, and that's where most of the rig count has dropped, is because of the smaller privates. But, you know, if you look at the overall permitting, and we have the advantage of looking at drilling rig permits, and the permitting for small privates have actually increased about 45%. So to me, that means it's right around the corner, starting in kinda Q1, that we're gonna see drilling rigs going back to the field. It's really tough, I think, to use drilling rigs also as a metric of, you know, frack activity, just because of the amount of efficiencies that have been gained on the drilling rig side. You know, we've been monitoring it really closely. We're a three fleet business down in the U.S. We've been extremely diligent at repositioning ourselves to clients that have longer term contracts, a lot of work scope, and we're happy with our positioning. Just the margins need to improve in that business. I think I'm speaking for a lot of the companies, it's very difficult to run a capital-intensive business in the U.S. That was our decision to move some assets into Canada for Q1. Got it. Thanks. I appreciate the, the intel. We'll turn it back. Thank you. Your next question comes from John Daniel from Daniel Energy Partners. Please go ahead. Hi, guys. Good morning. Just I wanna stick with coiled tubing for a second. The two records that you guys achieved in terms of total depth is pretty cool. I'm just curious, what's the max capacity, if you will, for lack of a better word? And then how do you convince those customers that might be reluctant to use coiled for those extreme depths to, you know, kinda come back and look at what you've just done? Hey, John. Good morning, and great to hear you on the call. Yeah, you know, I'll go back to, like, 12 years ago when we started this business out as a private coiled tubing company. We were building rigs to handle 6,000 meters of two and three-eighths coil, or call it 20,000 feet. The business obviously has accelerated on the coiled tubing front in the last decade, and particularly the last three or four years, we're seeing, you know, 30,000 feet of two and five-eighths coil that our reels can handle. You know, let's call it 34,000 feet of two and three-eighths. I believe that as we, as we have demonstrated, coiled tubing is gonna continue to be a very, very important part of the operators, you know, kind of cycle of the well, being able to get everything cleaned out. And as the wells get deeper, of course, trip times, if you're using a service rig or a snub unit, take a long time. So that's where coiled tubing accelerates. And using our technology, John, from a E-line perspective, where we're running real-time bottom hole information, it's only increases our efficiencies. And I, and I think that's where, like, that's where STEP is gonna be focusing on, is just becoming experts at these extended reach wells and be able to create efficiencies for the, for the client. Okay. Sticking with coil and, but pivoting to, to M&A, I mean, I think what we've seen is, you know, going back 10 years, right? It seemed like every cat and dog wanted to be a coiled tubing player, but a lot of them never turned out to be that successful, and you're one of a handful that have done a good job. There's still a few small, you know, two, three unit type players in various basins across the U.S. What's the appetite to consolidate stuff that's that small, or is it, or is it too small to be a waste of your time? Just any perspective or thoughts on, on that. Yeah, we look at a lot of M&A opportunities that come across our desk, and we'll continue to see if they fit our business. It has to be the right type of equipment. That is something that is very important for us, it's very important to our professionals to run great equipment that we provide them. But yeah, I mean, we demonstrated that we are a consolidator by working with Sam at ProPetro, and- Sure ... that has turned out really well. And so, you know, I think, John, you understand this more than anybody, it's, it's how do you do a deal at a discounted valuation to your peers- Right ... or to a private operator? Fair enough. Well, it's the records are very cool, by the way. Sorry, I sound like a nerd, but it's just, it's pretty eye-opening. So congratulations on that. Yeah, and I just wanna highlight that the records in the U.S. at 27,000 is with 2 5/8 coil and not 2 3/8, and that's a big difference. ... Yeah. And is there a max limit? I don't know if you answered that one, or if you did, I somehow zoned out. What is the max limit you could hit with that, do you think? Well, real capacity is, call it, 30,000 feet in today's real designs. But, you know, we're looking at other options to be able to go deeper than 30,000 feet of 2 5/8. We'll look forward to seeing. We haven't hit the limit yet. Okay. Thanks, John. Thank you. Your next question comes from Waqar Syed from ATB Capital Markets. Please go ahead. Thank you. Steve, the fleet that you're moving from the U.S., what would be the cost to mobilize it? And would it have an impact on Q4? Similarly, you're also moving some quality of units up north, and so in total, what kind of cost impact that could be in Q4? Yeah, I think it's, you know, good question, Waqar. Pretty immaterial, 'cause we'll use our own professionals to haul it, so it's the price of small amount of labor and some diesel costs. So pretty small compared to, like, a drilling rig, for example. It's on wheels. We don't need permits. And the import-export tax has been already paid on that because it is a Canadian-built fleet or the units that we're sending up is Canadian, so it's not a big cost. And we're hoping to do that kind of in that December timeframe so that we're ready for Q1 in Canada. Okay. So the crew should have a full quarter impact in Q1 then? Yes. Yes. Are there any refurbishment costs that would be required? Or is it up, you know- No, they- be up and running? No, they're operating. So they're basically part of our taxi squad fleet in the U.S., and so they are operating units today. So we'll have to do, obviously, some minor fluid changes to get to winter operating conditions, but in general, they're in great shape. Okay. And then just looking into Q4 kind of revenue projection, certainly a lot of moving parts here and there. But, you know, historically, maybe 10%-15% quarter-over-quarter decline that we see in Q4. Do you see something similar this year, or it could be, you know, higher than that? I think that's probably a good number, Waqar. We're still. You know, there's a number of discussions with clients that, particularly in Canada today, of moving some additional work into December. But it's funny, it's, you know, budgets reset and it's, we go crazy in Q1. So there's some appetite to want to do that, so that could change things. As we've talked about in the past, is we're a project-based business and things move around, you know, quite frequently. But what I guess what I can say about 2024 is that we've aligned ourselves with clients that have long-term contracts, and that's something that we, you know, we're pretty excited to be able to mention. You know, in Canada, particularly, it's just, it seems like it, the activity is going to really increase and have a busy Q2. Okay. And these 11 pumps that you're moving from the U.S., are these the Tier 4 dual fuel or... No? So they were purchased and built through GasFrac, so they're actually a Caterpillar Tier 2 engine. They're diesel currently today, and as we run them through Q1 and see where the... You know, we'll be looking at upgrading that as the end of life of those assets become at that point to put Tier 4 on them. Okay. And just one final question. This two-year contract that you gained in the Montney, is this in Alberta or British Columbia? The operator has assets in both BC and Alberta. Okay, great. Well, thank you very much. Appreciate the color. Thank you, Waqar. Thank you. Ladies and gentlemen, as a reminder, should you have a question, please press star one. Your next question comes from Josef Schachter from Schachter Energy Research. Please go ahead. Super. Thanks very much, and, thanks, Steve and Waqar, for taking my questions. First thing, of course, with the balance sheet improvement, the question was asked about an NCIB. Is also on the table a dividend, you know, start small and, you know, as cash flows improve and balance sheet continues to improve, look at using that lever as well for return to shareholders? Yeah, we're not going to commit to either one at this moment right now, Josef. I would say all options are on the table. We obviously have our major shareholder, ARC Financial, that has a 55% ownership. So that's one of the considerations that we take into account as we think about what makes the most sense from a shareholder return framework. I would just emphasize, too, the debt reduction that we've seen, that's been our primary kind of means of returning value to shareholders, and we've seen a significant appreciation as we in our share price as we pay down. So we're very focused on driving those returns and NCIB or dividend, or continued debt reduction. We'll make the decision based on what makes the most sense for the company. On the unit that's coming up with that can be converted to, you know, Tier 4, are you looking for contracts that will cover those costs, or do you expect STEP to be the one to cover those costs? Or can you build that into a contract price with someone that would give you a long enough time to recover those costs versus yourselves? Yeah, Josef, it's Steve here. Good question. We demonstrated last year a really unique contract that we've talked about in the markets, about a longer-term commitment where they've injected some capital, so that they have a little bit of, you know, kind of a toehold in the contract. We, I think that's the best solution out of anything, is that we work together with our clients and, you know, the benefits that we're seeing with Tier 4 and displacing up to 85% of diesel costs, it's material for our clients that are saving upwards of, you know, call it $10 million a year on diesel costs. So ideally, that's the direction I believe the whole industry should go, is, you know, getting some long-term commitments. I think the challenge in Canada is just the overall... There are not a lot of large clients compared to what they are in the U.S., where you have a dedicated fleet to operate. Okay. And, lastly, you talked about the sand issues, and how you're trying to do the logistics, to deliver to the site. Is the problem also on the rail, where there's insufficient capacity on the rails to move the sand to your, you know, locations that you need? Is, you know, is that something that, that you have to worry about if they're busy moving wheat or grain or lumber or cars or, you know, or coal? You know, how, how do you-- how is the... How is that, an issue for you? And, is that something that, that is a challenge from year to year? Yeah. I'll answer that by saying I'm not a rail expert to begin with. But I do know there's expanded capacities that are coming with the number of transload facilities in Canada, where they can handle unit train cars, which is great for the industry. It minimizes the downtime. And so there's that going on. There's obviously been a number of regional mines. I think there's three in Canada right now that have stockpiled for the winter busy season. And I think just being ahead of it really makes a big difference. And hence we mentioned our ability to, you know, kind of have on-site storage as well as in trucks. We'll have over 60 trucks running sand that call it 43-ton or over 40-ton of sand per truck. So that's a huge benefit that we have to be able to, you know, number one, keep it—keep our costs internal, but also number two, is just control the overall costs and delays of keeping our frac crews super efficient as we control that whole supply chain. Okay. And if I can sneak one more in. If we head into 2024, and we're starting to fill Coastal Gas, and LNG Canada gets announced, is there an opportunity for you to move your EBITDA margins over, back to the 29% of a year ago or over 30% in the next year or two? We definitely talk about that, Klaas, when I talk about that lots in regards to. You know, we're still not back to replacement economics in our businesses or all of our pressure pumping businesses. It's so cyclical as we've, you know, as we've seen coming out of COVID, and then the slowdown, even in the U.S., only a year and a half later. I believe with... You know, our thoughts are, as LNG, both in Canada and the U.S., is gonna create more of a stable type of business. And, you know, if we see Trains three and four get announced on LNG Canada, which we're assuming that it's gonna be announced in the next, call it, six months, I think that is-- that's the real big win, I think from an energy services sector. That's just a lot of gas that's gonna be moving, so you can't get a molecule of gas out of the ground without our services. Yeah. Super. That's, that's it for me. Thank you so much, and congratulations on the improvement in the balance sheet. Thank you, Josef. Thank you. There are no further questions at this time. Mr. Glanville, please proceed with the closing remarks. I just want to thank everyone for joining the call. It's been an exciting quarter for us, and we, and we look forward to the rest of the year and into 2024. Thank you very much. Ladies and gentlemen, this concludes your conference call for today. We thank you for participating and ask that you please disconnect your lines. Thank you.