This conference call transcript was computer generated and almost certianly contains errors. This transcript is provided for information purposes only.EarningsCall, LLC makes no representation about the accuracy of the aforementioned transcript, and you are cautioned not to place undue reliance on the information provided by the transcript.
spk02: calls, you require immediate assistance, please press star zero for the operator. This call is being recorded on Tuesday, March 12, 2024. I would now like to turn the conference over to Steve Glanville. Please go ahead.
spk08: Thank you and good morning. Welcome to our Q4 and year-end 2023 conference call. My name is Steve Glanville and I'm the President and CEO of STEP Energy Services. I'd like to invite Klaas Diemter, our Chief Financial Officer, to provide an overview of our financial results for Q4 and the full year. And then I'll provide some comments on operating conditions in 2023 and what we're seeing in 2024. And then we'll open the call up for questions.
spk04: Thanks, Steve, and good morning, everyone. Before I begin, I'd like to remind listeners 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 Q4 2023 MD&A. 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 annual information form for the year ended December 31, 2023, or more complete description of the business risks and uncertainties facing STEP. The AIF, along with our financial statements and MD&A, are available on our website and on CDAR. Finally, please note that all numbers are in Canadian dollars unless noted. Otherwise, I know around where possible. Most of my comments will pertain to the fourth quarter of 23 with additional discussion around the 2023 year as a whole. Full details again can be found in our ND&A. Fourth quarter consolidated revenue is $195 million, which is lower than Q4 revenues of $251 million. Budget exhaustion and commodity prices were a factor, but we also had approximately $30 to $35 million of scheduled work that slipped out of the quarter. The Canadian work largely pushed into Q1, setting up for a highly utilized first quarter, but the U.S., unfortunately, did not. We were on the wrong side of an M&A transaction with one crew and the second crew had their pad pushed later into the quarter to the point where it would have conflicted with another client's start date. For the 2023 year, STEP generated $946 million in revenue, second only to the 2022 revenues of $989 million. Turning to consolidated adjusted EVA, STEP earned $18 million in Q4 2023 as compared to $49 million in Q4 2022. Similar to revenue, adjusted EBITDA was lower in Q4-23 due to the decreased activity. However, earnings were also eroded by higher fixed costs, an increase in operating expenses related to preparing equipment for a busy Q1, and some one-time costs. For the full year, STEP earned $164 million in adjusted EBITDA as compared to $199 million in 2022. Our consolidated adjusted EBITDA margin was 17% for the year versus 20% last year, which although lower year over year, it is still considered a notable achievement in a lower activity environment and given the fixed cost nature of the pressure pumping business model. STEP earned $50 million or $0.67 per diluted share in net income on a full year basis in 2023, despite the tough Q4, which showed a net loss of $5 million or $0.07 per diluted share. For reference, our net income in 2022 was $95 million, which included a $38 million impairment reversal on property and equipment. I'll turn now to the geographical regions of Canada and the U.S. to provide some key highlights on the quarter. In the Canadian segment, Q4 revenue was $112 million, down 29% from Q3 2023 levels, but our full-year Canadian segment revenue of $580 million was up year over year, setting a new Canadian revenue record. Canadian fracturing was $82 million in the quarter, down 36% from Q3-23. Revenue fell quarter over quarter due to the typical Q4 slowdowns, as previously mentioned, including decisions by some clients to push Q4 projects into Q1, as well as a change in fracturing job mix to include more lower-intensity completions, which have a lower revenue profile. Notwithstanding the slower Q4, full-year revenue results in the Canadian fracturing business were very commendable and posted a new record of $461 million, up from last year's record of $454 million in revenue. The Canadian Coil Tubing Business Unit, which also includes ancillary fluid and nitrogen pumping crews, generated Q4 revenues of $31 million, in line with Q3 revenues of $30 million. Revenue on a year-over-year basis was also up, coming in at $120 million. Q4 segment adjusted EBITDA was $15 million versus $41 million in the third quarter of 2023. Adjusted EBITDA margin was 13%, which was down from 26% in Q3. Full-year adjusted Canadian EBITDA in 2023 was $134 million, or a margin of 23%, coming in just below the prior year's record of $136 million, which reflected a 24% margin. Turning to the U.S., Q4 revenue of $83 million was down 15%, versus Q3 23 revenues of $98 million, and our full year revenue was $366 million, down from $421 million in 2022. U.S. coil tubing Q4 revenue was $43 million, which was up 10% from a year ago, although down sequentially from the third quarter. We ran 12 units in Q4, which is unchanged from the third quarter and is up from 11 units a year ago. In U.S. fracturing, Q4 revenues of $40 million were down 15% from the third quarter and down 59% from a highly utilized Q4 in 2022. As mentioned a moment ago, we had about $17 to $19 million in scheduled revenue disappear from the quarter due to M&A and shifting client schedules, which hurt our fracturing business in the quarter. Full year revenue of $186 million was lower than the $297 million earned in 2022, due in part to the utilization challenge experiences through the year, but also due to the shift in client-supplied sand, which reduces revenue and margin for pressure pumpers. Adjusted EBITDA of $7 million was down from $15 million in Q3. Adjusted EBITDA margin was 9% down from 16% in Q3. Full-year adjusted EBITDA in the U.S. was $46 million or a margin of 13%, down from the previous year's EBITDA of $80 million or 19%. Turning now to the allocation of our cash flow in our year and balance sheet. We spent $40 million on capital in the quarter, up from the $25 million we spent in the third quarter. Our full year spend was $105 million in 2023 compared to $100 million in 2022. Our Q4 capital spend was the highest quarterly spend for the year, partly due to the completion of various capital projects, but we also accelerated payments on a number of large invoices right at the end of the year, to take advantage of the benefits associated with early payment and possession, ultimately transitioning working capital into capital assets. Our working capital fluctuates with the seasonality of our business, and we expect it to tick higher at the end of Q1 as a highly utilized quarter pushes up our AR balances. We ended the year with a net debt of $88 million, down from approximately $142 million a year ago. Going further back since 2018, we are extremely proud of the accomplishments that we've achieved there, We've paid down almost $230 million of net debt since that time. This reduction of debt is the first phase of our shareholder return framework, and we've seen that value accrue to equity holders. In addition to adjusted EBITDA, one of STEP's other key non-GAAP measures is free cash flow. STEP calculates free cash flow as cash from operating activities, less changes in non-cash working capital, sustaining capital investments, term loan principal repayments, and lease payments. We had negative free cash flow in the fourth quarter, but our full year free cash flow was $83 million compared to $112 million in 2022. This translates to $1.15 per share, a 29% yield, which is comparable to the prior year's results of $1.56 per share, which was also a 29% yield. More details are available in the non-GAAP measure section of our MD&A. Finally, we are very pleased to announce that we started a normal course issuer bid in late December. the second phase of our shareholder return framework. On a number of different metrics, we feel that our equity is undervalued. As an example, our book value per share is $4.93, and the replacement cost of our assets is in the $18 to $20 per share range. We are authorized to purchase and cancel up to 3.6 million shares, and we have been active in the market, having bought back just over 800,000 shares already, and we intend to remain active. I'll now turn it back to Steve for his comments on operations and outlook.
spk08: Yeah, thanks, class. I have said this before in previous calls, but I want to highlight how important it is to look at completion sector as a project-based business, which requires us to evaluate the success of the business year over year rather than quarter over quarter. Each quarter has its challenges with shifting client schedules, but the fourth quarter in particular has become less predictable And as a consequence, we're seeing lower utilization compared to the first and third quarters. It's not just the typical budget exhaustion. It's also that the pads are becoming larger and larger. So we're less and less likely to see work kick off in late November or early December because of the Christmas holiday season. In the same vein, these large pads also make it easier to work through the second quarter, which was historically our weakest quarter. We're obviously happy to see the second quarter utilization pick up, but we need four quarters of utilization in this sector. This creates a more stable operating environment for service providers, allowing them to keep their workforce steadily employed, which improves safety and operational efficiency, and ultimately will drive costs down for E&P companies. We hear a lot that we're moving into a manufacturing or mining phase of this industry, so we need to change how we operate to reflect that. I'm proud to say that 2023 was our second best year ever in terms of top line revenue and adjusted EBITDA. Just a couple of things I want to draw your attention to here. The first thing, despite the challenges presented by weaker oil and gas prices, 2023's revenue only dropped by 4% year over year, which we see as a positive signal that the OFS sector is becoming more disciplined in their pricing. The second thing is there's three of our four business units outperform their 2022 top line revenue figures, which clearly reflects the resiliency and flexibility of our operations and the teams of professionals who come to work each day with a mindset to deliver safe, repeatable and exceptional services to our clients. In 2023, just over 60% of our revenue came from Canada, led by a fracturing business. We ran five fracturing crews in Canada, four of which are focused on the large-scale, technically challenging work in the Montigny and Duvernay, with the fifth focused on smaller-scale, lower-pressure work, often in conjunction with our co-tubing division. The fracturing division delivered outstanding results, recording its highest ever divisional revenue and making a significant contribution to the Canadian EBITDA. 2023 wasn't without challenges as the volatility in commodity prices led some clients to defer work out of 2023, which affected our utilization. A key trend that we benefited from was a significant increase in profit intensity per well. We have a slide in our IR deck that shows how the sand required to frack Montigny wells is starting to approach the levels we have seen in the Permian for several years. We expect to see this trend continue, with Edumene expected to be a fast follower. To address the growing requirement for sand handling and hauling, we added capital to our Canadian logistics team and now have one of the largest internal hauling fleets in the basin. This capacity has greatly improved field efficiencies for these sand intensive operations as it reduces reliance on third party hauling and minimizes non-productive time. In co-tubing operations, despite the impact of volatile commodity prices and client decisions to defer work to 2024, STEP operated nine co-tubing units. We saw a decrease in operating days, but an increase in revenue per day year over year. STEP is committed to bringing the best technology to the market. An example of this is Canada's largest and deepest fleet of E-line capable co-tubing strings. Our co-tubing Our coal tipping division set a company depth record of 8,101 meters, demonstrating our technical capabilities and expertise in the deep complex wells in the WCSB. I also want to highlight our pump down services. We have seen an increase in plug and perf operations in Canada, creating this opportunity to bolster our pumping services. Our professionals in pump down services have built capacities in this business segment and a reputation for delivering exceptional service to our clients. They have opened doors to additional opportunities, and I'm very proud of what this team has accomplished in 2023. Turning now to the US, our fracturing service line faced significant headwinds right out of the gate in 2023. If you recall, in late 2022, many analysts, if not most, were forecasting gas over $5 per mm BTU, and oil over $90 WTI, but very quickly in Q1 we saw prices come off, and we saw the private operators slow down their capital programs aggressively, leaving many frack crews looking for work. This trend was exacerbated by the E&P M&A activity, where 1 plus 1 often does not equal 2, further reducing demand for fracturing services. We saw the industry shrink through the year from a peak of about 300 frack crews to about 225. Our crews can compete with the best in the US delivering excellent diesel substitution and pumping hours per day, but we're not prepared to sacrifice our equipment in a mad rush for the bottom. So we made the difficult decision to transfer some fracturing equipment back to Canada so we can stand up the sixth crew. On paper, it was an easy decision as returns are stronger in Canada, but these decisions also have a human impact. And for a company with Steps culture, we don't make these decisions lightly. We're also very pleased with our U.S. co-tubing business. The acquisition we made in September of 22 was a key factor in our ability to expand this business into the northern U.S. operating regions. Our decision to add a 12th co-tubing unit as well as transfer one of our southern units to the north drove a year-over-year increase in operating days of up to 30%. This team also set a depth record of 8,252 meters or 27,075 feet. We're also seeing growing interest in our equal technology in the US, which we believe will be a differentiator for STEP going forward. Turning to the outlook, as we look to 2024 and beyond, headwinds persist in the current market environment. However, we believe STEP is well positioned to navigate these uncertainties and capitalize on opportunities. The long-term outlook for oil field services remain constructive, and we see a slight shift in the narrative surrounding the importance of oil and gas in the energy mix. We are proud to operate in Canada and the US countries with abundant natural resources and the technical expertise to deliver safe and affordable energy globally. The completions of major energy infrastructure projects in both Canada and the US, like the Trans Mountain Expansion Project, LNG Canada's facility and numerous LNG projects in the U.S. will support increased drilling and completion activity in our sector. In the near term, the volatility in commodity prices is expected to continue, but I'm confident in the initiations that we have put in place to reduce the impact on our business. For example, our strategic investment in Tier 4 dual fuel assets, which reduce diesel consumption in place of cleaner burning natural gas, coupled with our technical capabilities deliver the expertise that leading EMPs rely on to complete their programs. Our ability to optimize asset performance, consistently operating up to 22 hours per day, contributes significantly to completing wells faster and more efficiently. We have control over our value chain and strong relationships with our profit suppliers. Moving on to our capital program, In late 2023, our board approved a capital budget of $120 million, with just under half allocated to maintenance capital and the balance to optimization capital. By the end of 2024, we expect 75% of our fleet will be dual fuel capable, with a target of 90% by the end of 2025. We're taking a cautious quarter-by-quarter approach to spending this capital, recognizing the extremely low gas prices are creating some uncertainty about activity levels in the near term. We're continuing to explore the opportunities that exist with next generation technology, but the cost of this equipment would require a client capital commitment, similar to what we saw with our first tier four dual fuel fleet. In Canada, Q1 2024 has been exceptionally busy, especially in the fracturing service line. The deferral of work from Q4 into Q1 meant that our crews were pumping right out of the gate, so the cold weather in January had minimal impact on our operations. Our coal-tipping crews got going a little bit later, which is typical for the service line as they follow a fracturing. One more quick word on the cold weather. We usually take for granted the standard of living we have here. I wanted to express my extreme gratitude for the hardworking professionals, not just in our company, but across the sector who work day and night on the coldest nights in Canada and the hottest days of Texas. So we can enjoy this amazing standard of living. We have a moral responsibility as a major energy producing nation to export this prosperity to the world. There is increasing concern around the impact of drought in Canada and how that will affect or how will affect the availability of water for our clients. Our teams are engaging in discussion with clients and our product suppliers about solutions that will reduce the amount of fresh water used in fracturing operations. We have brine-tolerant chemistries and alternative fracturing systems such as nitrogen or carbon dioxide that reduce water consumption, and we even have proprietary fracturing systems that use liquefied petroleum gas to eliminate water completely. We still got almost three weeks of work left in March, but I can say that our fracturing, co-tubing, and pump-down crews have never been busier, and I'm extremely proud of the work that these teams are doing. Our Q2 calendar is filling up as well, while there is still a handful of RFPs that will determine just how much work we'll see in the quarter, as well as the second half of the year. We'll have more to say on our second half activity expectations at our Q1 conference call in May. In the United States, our two fracturing fleets in the Permian have experienced consistent activity in Q1, supported by securing long-term work scopes with active producers. The oversupplied U.S. fracturing market will continue to see some near-term softness in pricing and utilization. Our 12th co-tilling fleets have maintained steady activity and we may see an opportunity to add a 13th unit given the demand for our services. Pricing the coal-to-be market is down modestly relative to 2023, but has proved more resilient than what we're hearing in the fracturing market. Visibility in the second half of the year hinges on the natural gas pricing. Strengthening prices in the third and fourth quarters will bring stability to the fracturing market. Finally, at the beginning of the year, we launched our nitrogen industrial services. that not only focus on completion activities and supporting services, but provides our nitrogen pumping expertise to large scale projects in the midstream and industrial facilities. We see tremendous opportunities in this market and look forward to establishing a stronger presence there. With that, I will thank you all for your continued support and a special acknowledgement to the professionals at STEP. We have managed extremely well through another year of fluctuations, and uncertainties. But we have also accomplished great things and achieved many milestones. Thank you for all you do. Operator, we would be pleased to take any questions.
spk02: Thank you. Ladies and gentlemen, should you have a question, please press the star followed by the one on your touchtone phone. If you'd like to withdraw your question, please press the star followed by the two. If you're using a speakerphone, please leave the handset before pressing any keys. One moment, please, for your first question. Your first question comes from Cole Pereira from Stifel. Please go ahead. Hi.
spk05: Good morning, all. So one of your competitors guided to EBITDA being lower year over year. I realize you're a bit different. You're bringing another fleet into Canada. But hard not to think that completions activity isn't lower year over year. So how should we be thinking about STEP, you know, maybe in the US and Canada on a year-over-year basis?
spk04: I think, Cole, what we're seeing here is there's still some RFPs that are in play here for the back half of the year. We have more capacity here in Canada than we did last year, so I think it would be reasonable to expect a higher level of activity here in Canada. Conversely, we have less presence in the U.S., and then just given the gas price issues down there, reasonable to think that GR is going to be a little bit weaker on the fracturing side.
spk05: Got it. And then going back to the U.S., can you just remind us, are those two fleets down there on long-term contracts, or is there any spot exposure there?
spk08: Yeah, Colt, Steve here. Yeah, they're on, I would say, long-term contracts, but the undisciplined pricing that we've seen in the U.S., it's just, you know, it's a very, very fragmented market today. So, you know, those are at risk, but I think there's some opportunity for us, you know, to continue to look at high utilization in the basin.
spk05: Okay, got it. That's all for me. Thanks. I'll turn it back.
spk02: Your next question comes from John Gibson from BMO Capital Markets. Please go ahead.
spk09: Morning, all, and thanks for taking my questions. Just first in terms of margins, Q4 was obviously impacted by the deferred revenue in Canada and the U.S. How would margins have performed during the quarter absent these deferrals? I know Q4 is a ways out, but how do you think about limiting some of the impacts going forward if additional work gets deferred?
spk04: Yeah, good question John. Thank you for that. So that 30 to 35 million was work that was on the board scheduled and then with particularly well in bulk GRs actually with very short notice the work was pushed. So if you think about our fixed cost structure, all those costs are largely continuous. So the work that we lost there, that 30 to 35 million, that would largely have been a kind of a gross margin direct margin type of margin profile. So higher certainly than our typical EBITDA numbers. So I think there have been a significant uptick in our EBITDA had we been able to capitalize on that. So as we think about Q4 of this coming year, Steve talked about it in his script, we are more cautious around what Q4 utilization looks like. The challenge we have here is if we've got work scheduled, there's very little that commits a client to keeping that intact. And for various reasons, that work can shift. So if you lose work in June or July, there's always some spot work that you can pick up. But if you lose work at the end of November, middle of December type of stuff, It's very hard to backfill that work. So, you know, we work through that with our sales guys. They work extremely hard with their clients to dial that in. At the end of the day, we're somewhat subject to the mercies of the market.
spk08: Yeah, I just add on to that, John. Like our clients are extremely disciplined on their capital. And we even tried to, as knowing our Q1 is basically overbooked, we tried to get some of our clients to move some capital into December and November, and it was a no-go. And as I mentioned, these pads are getting large, so call it 6 to 10-well pads. Our operators aren't rigging up on the 1st of December because they know it's going to work into the Christmas season. And so they basically have decided to defer it to January. So we're going to look at that for next – for this year coming up, if there's a way that we can minimize the down, you know, the choppiness in the quarter. But just want to remind everyone, this is a go back to it's a year over year. You kind of have to compare on a year over year basis. And with commodity prices being off 30% this year, still is a great year for our company.
spk09: I appreciate that. Thanks for the color. And Paul, I know you touched on U.S. pricing under pressure.
spk01: How has Canadian pricing been to start the year? Sorry, John, how was the Canadian pricing that we said? Yeah, exactly.
spk08: I would say it's holding up nicely. We are seeing some pricing pressure. I would think that, in general, it's holding up a lot better, obviously, than the US. I would consider that the market in Canada is undersupplied here in Q1. And we're going to really look at Q2 and beyond what we do with that six frac crew as of today. If there's no work for it, we're going to park it. So that's kind of the strategy that we have right now.
spk09: Okay, great. Last one for me. You've made great progress on the balance sheet. Wondering what Your capital priorities or capital allocation priorities are short term. Do you expect debt levels to fall a bit further or is it just kind of full go on the NCIB?
spk04: Well, we got a great buying opportunity today on our NCIB. So we'll continue to focus on that here and in the days to come. As noted, we see good value in our equity. Book value of around $5, replacement value of 18 to 20. So we're going to continue to focus on that. You know, as the year progresses, we're, I mean, Steve made a comment there about our capital budgeting. We'll monitor that to make sure that we're calibrating that to kind of our operational cadence. I think there's still room for us to push our debt down lower. We've often talked about a net debt balance of roughly similar to our working capital, so call that in the $50 to $60 million range. We think that's achievable by the end of the year.
spk01: Thanks a lot. I'll turn it back. Thanks, John.
spk02: Your next question comes from Joseph Schachter from Schachter Energy Research. Please go ahead.
spk03: Thanks very much for taking my question, Steve and Klaus. You mentioned in your just recently comments that the first quarter was overbooked. There was an oversupply during Q4. How do things look for Q2 and Q3 and Is it really up to the natural gas price that we need to be looking for a 250 plus or something for the industry to be in equilibrium in Q2, 3, Q4?
spk08: Yeah, Joseph, good morning. We're actually seeing quite a bit of activity in Q2 in Canada. I'll just start in Canada right now. And I think a lot of that is to do with the clients that we've aligned with for the year. Our sales team has done a great job of looking at clients that have kind of full-time projects or a good line of work for the year in 24. We haven't seen any pullback in capital per se today, but obviously that is a concern that we have. Gas at $1.70, or whatever it's trading at today, it's not sustainable. And so we're being cautious with that. I do believe that, you know, the two infrastructure projects that I commented on, LNG Canada and the Transbound expansion is great for the Canadian activity long term. I think just going to see a little bit of choppiness coming out the gate here this year. But as that gets on stream, I think you're going to see a lot more stability in gas prices going forward. And for the US, same sort of thing. We're actually seeing You know, the private operators talking about adding more rigs in the Permian in particular, so more oil-focused regions. You know, you saw EQT pull back gas production. So there's just some things that are, you know, I think we'll set up for a better back half of 24 because of that.
spk03: And my next question is, you mentioned new equipment, e-coil equipment. What is that? What can it do? Is there better pricing for that, better margins? Can you give a little more insight into that?
spk08: Yeah, yeah, no, for sure, Joe. So that's our, call it our StepConnect technologies. And what it allows us to do is read real-time bottom hole temperature, pressure, torque on the bit face as we're milling out these plugs. And the advantage with that is not only does it improve the efficiencies, Ultimately, we want to get to a completely autonomous coal tubing unit so you can basically set it and forget about it and mill it to the end of the well. That obviously reduces the concerns from an operator error perspective, but also from an efficiencies perspective. So it's kind of one step into that technology, and our clients are quite happy with what they're seeing so far.
spk03: Is there higher margins for you on that?
spk01: Yeah, we're seeing some good margins for sure. We run it all internally as well.
spk03: Okay, excellent. Thanks very much.
spk01: Thank you.
spk02: Ladies and gentlemen, as a reminder, should you have a question, please press the star followed by the one. Your next question comes from Keith McKay from RBC. Please go ahead.
spk06: Hi, good morning. So the U.S., as you mentioned, has become a much more competitive frack market of late, given utilization and so forth. Now, U.S. companies are increasingly bringing in electric equipment into the market. And you did mention, I think, that you trialed some electric equipment in the Permian in the quarter. Can you just talk a little bit about what that was, how it came about, and if there's any capital associated with electric equipment or electric frack equipment for 2024, the budget?
spk07: Yeah, good morning, Keith.
spk08: I'll just start by, there's about 60 electric frack crews that are operating in the U.S. today out of, call it 250 altogether frack crews. So there's still a big market of Tier 2 diesel, Tier 4 diesel with dual fuel, and then of course electric. We're curious about the technology. We have been really since 2017 when we got into the frac business. And so we ended up trialing a pump and kind of complete system. And we really, really like it. The challenge, of course, is just the overall capital required for that asset base. And I know there's some creative solutions that we're looking at today to input that, but we do not have that slated on our capital budget for 2024.
spk07: Okay, got it.
spk06: And Steve, how do you think about the competitiveness of your U.S. business then with two fleets running? Do you think you'd need to go electric right away in order to remain competitive, or is there still a... significant enough market where you could make some decent returns with the footprint that you've got in the U.S.
spk07: market as it stands today and through the rest of the year?
spk08: Yeah, I mean, Keith, we're seeing pumping hours per frack fleet that are operating or two that are down there north of 500 hours. per fleet or around that. And so you can generate some good returns with that. We're happy with that. Scale is obviously one of our concerns that we have in the US, but we have been upgrading our asset base. Basically, the two fleets that are active today are substituting high quantities of diesel up to 75%. So it's a very sought after fleet and there's a market for it today. As I mentioned, the 13 pumps that we brought up from the US to Canada to really support our Canadian business were really Canadian pumps to begin with. They were part of the gas track acquisition in 2015. And we'll look at if there's an opportunity to, depending on where these RFPs land, we have a number of them both in Canada and the US that we're participating in. And so we'll just put that equipment where the best margin is in the business.
spk06: Fair enough. Thanks for that, Steve. And maybe just one for class on free cash flow for 2024. You ended the year at about $87, $88 million of net debt. And I think you mentioned you could potentially see 2024 getting down to that $50 or $60 million target. Is that essentially how we should be thinking about backing into free cash flow for 2024? And maybe if you could just talk a little bit about some of the levers into that number that might affect it as well, it'd be helpful.
spk04: Yeah, if you think about where we are today, we're roughly 0.5 times. We anticipate 2024 to be a better year for us. And I think So from a debt perspective, we're continuing to push that down, but there's a little less pressure on us where we feel a little less pressure to continue hammering down that debt. And we're, that's why we introduced that NCIB gains to capitalize on the value gap that we saw there. So, you know, depending on how that market conditions kind of determine the spend there on the NCIB capital, like Steve said, we're going to kind of take that on a quarter by quarter basis. So, and then kind of the, The squeeze here a little bit to a certain extent is going to be on the debt side. We don't have as aggressive of targets that we have to hit this year internally. And we see that we're able to diversify our free cash flow allocation a little bit now.
spk07: Got it. Thanks very much. That's it for me.
spk01: Thanks, Keith.
spk02: And there are no further questions at this time. I will turn the call back over to Steve Glenville for closing remarks.
spk08: Yeah, thank you everyone for joining our Q4 year-end conference call. Look forward to talking to each other in about six weeks from now when we report our Q1.
spk02: Ladies and gentlemen, this concludes your conference call for today. We thank you for joining and you may now disconnect your lines. Thank you.
Disclaimer