STEP Energy Services Ltd.

Good morning, ladies and gentlemen, and welcome to the STEP Energy Services first quarter 2024 conference call. At this time, all lines are in a listen-only mode. Following the presentation, we will conduct a question and answer session. If any time during this call you require immediate assistance, please press star zero for the operator. This call is being recorded on Thursday, May 9, 2024. I would now like to turn the conference over to Steve Glanville, President and CEO. Please go ahead.

Thank you and good morning. Welcome to our Q1 2024 conference call. My name is Steve Glanville, and I'm the President and CEO of STEP Energy Services. I'd like to invite Klaas Deemter, our Chief Financial Officer, to provide an overview of our financial results for Q1, and then I'll provide some comments on operating conditions thus far in 2024, and what we're seeing for the remainder of the year. And then we'll open the call for questions. Over to you, Klaus.

Good morning. Thanks, Steve. Before I begin, I'd like to remind listeners 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 Q1 2024 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 for a 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 all numbers are in Canadian dollars unless noted otherwise and I will round where possible. STEP had an exceptional Q1 with consolidated revenues of $321 million up from both the Q4 and Q1 2023 revenues of $195 million and $263 million respectively. Adjusted EBITDA for the quarter came in at $80 million as compared to $18 million in Q4 and $45 million in Q1 of the prior year. And free cash flow was $53 million for the quarter compared to negative $4 million in Q4 and $17 million in Q1 of last year. These results are mainly attributable to higher utilization, exceptional operating efficiencies, and tight cost management in the quarter, as well as the transfer of some U.S. fracturing equipment to Canada. Stepper in $41 million for $0.55 per diluted share in net income for Q1 of 2024 compared to a loss of $5 million in Q4 or $0.07 per diluted share and $20 million or $0.26 per diluted share in Q1 of 2023. These first quarter results demonstrate the powerful economic potential of steady utilization and is a template for what this company is capable of doing. Turning now to the geographical regions of Canada and the US, I'll provide a few key highlights. In the Canadian segment, Q1 revenue was $241 million and was a record quarter for the company. As a reminder, previous high watermark was 174M achieved in Q1 of 2023. Compare this to 112M for Q4 of last year. Canadian fracturing revenues were approximately 198M in the quarter, up from both Q4 and Q1 of the prior year, representing STEP's highest revenue quarter for Canadian fracturing. Steve will touch more on this, but the key factor in this performance was strong client alignment, which enabled STEP to operate extremely efficiently and maintain high utilization through the quarter, increasing operating days to 450 from 233 in Q4 and 312 in Q1 of 23. The Canadian Coil Tubing Business Unit, which also includes ancillary fluid and nitrogen pumping crews, also generated a record quarter, earning revenue of $43 million, surpassing the revenue of $31 million in Q4 and $35 million in Q1 of 2023. Operating days were also higher for this service line, increasing to 615 days from $510 in Q4 and $572 in Q1 of 2023. Q1 segment Adjusted EBITDA for the Canadian region was $72 million versus $15 million in Q4 and $45 million in the first quarter of 2023. Pricing has come off a bit in Canada this year, but the higher utilization and tight cost management gave the company better leverage on its fixed cost structure, resulting in an adjusted EBITDA margin of 30%, up from 13% in Q4 and 26% in Q1 of 2023, both quarters that had lower utilization. Turning to the U.S., we had Q1 revenues of $79 million, down from $83 in Q4 and $89 in Q1 of last year. Q1 fracturing revenues of $38 million were down 6% from Q4 and 23% from the first quarter of 2023. U.S. fracturing had three active fracturing fleets in Q1 of last year, but only two active fracturing fleets in Q1 of this year and Q4 of last year. Utilization was steady through much of the quarter, with some weakness towards the end of the period. U.S. coral tubing Key 1 revenue was $41 million, which was down 3% from Key 4, but up 4% from a year ago. Utilization was affected by inclement weather conditions in both the southern and northern operating basins during the quarter, but was down only marginally from Key 4 and was up from Key 1 of 2023. Adjusted EBITDA of $13 million was up from $7 million in Q4 and $5 million in Q1 of 2023. Adjusted EBITDA margin was 16% up from 9% in Q4 and 5% in Q1 of 2023. Turned out of the allocation of our cash flow on our balance sheet, we spent $36 million on capital in the quarter, up from $27 million in the first quarter of 2023. Our Q1 capital spend can be divided into 11 million of sustaining capital, 19 million of optimization capital, and 5 million of right-of-use asset additions. Approximately two-thirds of the ROU asset additions were units that we had been renting on a short-term basis and have now converted to a long-term lease. Our cash flow commitment won't change, but the reclassification will result in a slight boost to our EBITDA. The intensity of the work scope in the first quarter resulted in a substantial working capital build of $49 million, Our working capital fluctuates with the seasonality of our business, and as expected, working capital is higher at the end of Q1 compared to Q4 due to the high utilization in the quarter, pushing up our AR balance. We expect working capital to go lower at the end of Q2 as we harvest these receivables. A consequence of our working capital build is that we ended the quarter with the net debt of $108 million, up from approximately $88 million at the end of last year. Debt reduction remains a core focus of our management team, and we expect that this balance will reduce at our Q2 release and continue reducing through the balance of the year. Going back to 2018, the company has paid down over $200 million of debt. 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 the steps other key non-GAAP measures is free cash flow. We had free cash flow in the first quarter of $54 million compared to $17 million in Q1 of 2023. This translates to free cash flow of $0.72 per diluted share or 20% quarterly yield, which is higher than the prior year's Q1 23 results of $0.23 per share or 7% quarterly yield. Our rolling four-quarter free cash flow per diluted share is $1.62 or 46% yield. You can read more details on this in the non-GAAP measures section of our MD&A. Finally, I'd like to provide an update on our normal course issuer bid, which began at the end of 2023. To date, STEP has purchased just over 1.5 million shares at an average price of $4.16 per share, of which just over 900,000 shares were repurchased in Q1. For reference, our book value per share at Q1 was $5.56, substantially higher than where we're trading at today. We continue to see excellent value in step shares, and we'll continue with our share buyback program. I'll now turn it back to Steve for his comments on operations and outlook.

Thanks, Klaas. Let's start by reviewing the current market dynamics. In the first quarter of 2024, we saw a divergence in pricing trends between natural gas and crude oil. Mild winter conditions across North America and Europe contributed to high natural gas supply levels, keeping prices low. We've seen major energy players like EQT and Chesapeake Energy and others curtail production and reduce capital programs to manage volumes, but storage levels have continued to grow in Canada and the U.S. Conversely, crude oil prices rallied, supported by ongoing production restraint from OPEC+, and concerns over tensions in the Middle East. Despite this, U.S. drilling rate counts remained stable, with modest increases in oil-directed rate count, offset by declines in gas-directed drilling. The Canadian market was relatively stronger, with rate counts tracking at or close to the upper end of the five-year range through the quarter. As classes highlighted, Q1 was an incredible quarter for our company. We achieved record quarterly revenue, demonstrating the torque in our business from combining steady utilization, high intensity work programs, and a commitment to operational excellence. I want to draw your attention to a few highlights. In Canada, we saw significantly fracturing revenue growth driven by improved efficiencies and higher intensity well completions, reflecting strong client alignment and technical leadership. We deployed a sixth fleet in Canada in the first quarter based on client-backed commitments and saw a substantial increase in operating days. As you can see from the stats we show in our MD&A, our fracture utilization improved significantly from Q1 last year, increasing from 69% to 83%. The higher intensity was reflected in the amount of prop and pumped, which increased in Q1 2024 to 559,000 tons. 150% increase over Q4 2023 and almost a 90% increase compared to Q1 of 2023. The amount of sand we pumped is staggering. All the sand gets to the well site on a truck, meaning that we had nearly 14,000 loads of sand delivered to our job sites. We hauled a significant amount of this sand ourselves with our industry-leading logistics fleet, providing additional value to our clients as well to our company. Activity for STEP's co-driven ancillary pumping and fluid services was also strong throughout the first quarter. We had high utilization on our fluid pumping services and added a tenth coil unit to our fleet, enabling us to set a record for the amount of running meters and revenue record for this combined service length. This outstanding performance could not be possible without strong alignment with our valued clients. We strive to deliver outstanding service to our clients, and earn a fair return for our stakeholders. Managing the challenges of weather, drilling delays, and subsurface issues requires service providers and clients to work together to make things work, and we thank our clients for their flexibility. Our U.S. operations delivered improved profitability this quarter despite running fewer fleets, thanks to higher operating efficiencies and a focus on cost management. The improvement in efficiencies is evident in the profit pump, which increased by 27% compared to the prior year, despite a decrease in operating days by 28%. Our coal tubing utilization was higher than last year, despite some challenging weather conditions in both the southern and northern basins. We continue to see strong results from this business, with a focus on client alignment, delivering some of the most complex milling programs for the largest operators in each basin. Our success in the first quarter underscores the importance of evaluating our business on a year over year basis, rather than a quarter over quarter. We continue to focus on high utilization model coupled with high pumping and profit intensities. This model reflects our culture of continuous improvement and operational optimization, which is integral to our success. Additionally, this quarter underscored that the model is most effective when it is executed by the best professionals in the business. I'm incredibly proud of the work our teams of operations professionals did this quarter. Their drive towards excellence, their tenacity, and focus on exceeding client expectations is the main factor in our reputation and success. I'd like to discuss several key differentiators that set STEP apart, including our technology and performance. Our strategic investment in equipment enhancements, such as upgrading our asset base to Tier 4 dual fuel capable systems, have proven to be significant differentiators for our company. Clients are increasingly interested in reducing diesel consumption during operations and our dual fuel capable assets. along with our operational expertise and process, can displace up to 85% of diesel consumption. In our recently published 2023 ESG report, we highlighted that approximately 26.7 million liters of our client's diesel was displaced with natural gas using dual fuel equipment in 2023. In this past quarter, we displaced 17.5 million liters representing substantial savings for energy producers as they seek ways to reduce diesel consumption and associated emissions. This quarter, STEP achieved several records. In addition to the amount of profit pumped by our Canadian business units, STEP's fracturing service line set monthly pumping records in both geographic regions, achieving 629 hours in one month in Canada and 547 hours in the U.S. This underscores the capabilities of the professionals operating and managing these service lines, as well as the exceptional alignment with key clients that made this possible. During the quarter, STEP reactivated one quill tubing spread, bringing the total active spreads in Canada and in the U.S. to 22, which is among the largest fleets in North America. The fleet continues to set depth records in the U.S., where we had a depth record of 8,356 meters, or 27,413 feet during the first quarter. On the topic of quilt-tibbing services, wells are becoming increasingly complex, with long laterals exceeding three miles in length. As quilt-tibbing services evolve, our technology offering, like StepConnect, which is a real-time data acquisition tool conveyed by an E-line string, allows clients to optimize complex well operations and achieve cost savings. In a recent post-project analysis, we determined that a client saved approximately 15% of the project budget using StepConnect. Additionally, the tool significantly enhances operational consistency and supports real-time decision-making in these complex extended laterals. We are industry leaders in deploying this technology, and our clients are seeing the benefits. Finally, I want to emphasize our geographic diversity as a key differentiator. Our ability to deploy assets between the US and Canada was evident in Q1. We moved fracturing equipment from the US to Canada based on a client-backed work program, allowing us to allocate resources to the basins that keep the fleet highly utilized, supporting our high utilization model. This quarter's results demonstrate the benefits of our geographic diversity, enabling us to optimize margins and leverage market opportunities effectively. The medium to long-term outlook for the North American energy sector remains positive, with major infrastructure projects like the TMX and the upcoming LNG initiatives expected to strengthen the market. We anticipate some near-term volatility in our U.S. fraction division in Q2, but are seeing our coal tubing division pick up some of that slack. We'll see a bit of a spring breakup slowdown in Canada mid-quarter, But overall, we expect a good quarter for Canada. Visibility into the second half of the year is good. We expect an active Q3 to carry into Q4. What is likely, that activity will ramp down in a mid-quarter as our clients reach the limits of their capital budgets and achieve their production targets. Q4 is becoming increasingly difficult to predict, so our outlook is similarly cautious. Our strategic priorities focus on generating free cash flow to continue our dual-pronged shareholder return model of debt reduction and share buybacks, as well as upgrading our asset base. We believe in our business value and our commitment to delivering shareholder returns to technological leadership and operational excellence. Finally, I want to recognize our exceptional professionals at STEP Energy Services for their dedication and achievements. Now I invite the operator to open the floor for any questions or comments.

Thank you. Ladies and gentlemen, we will now begin the question and answer session. Should you have a question, please press star, followed by number one on your touchtone phone. You will hear a prompt that your hand has been raised. Should you wish to decline from the polling process, please press star, followed by number 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 the line of Keith Mackey from RBC Capital Markets. Your line is now open. Please ask your question.

Hi, good morning. Just wanted to start out in Canada for a second on that sixth fleet. Can you just talk about the outlook for utilization running six fleets in Canada? I know you've got some ability to move equipment back and forth across the border. Do you expect to keep all of that equipment in Canada and utilized in an acceptable manner, or do you think some of that footprint might have to change throughout the year?

Good morning, Keith. It's Steve. Good question. We've made that decision back in Q4 based on our client-backed program to move some assets up from the U.S., as we see our work schedule um you know obviously q2 with the with the typical seasonal breakup uh we'll see a bit lighter utilization but our our team of course is looking for a well-deserved uh kind of a nice reset um but we do see activity for six frac fleets in the q3 and then as well as in the q4 so our plan is to continue to operate that but We will shut it down if we see prices drop, and it's an oversupply, but we think the market's pretty balanced right now.

Yeah, okay, got it. And just continuing that comment about a balanced market, and you also, I think, mentioned pricing is down a bit year over year. Can you talk about what you think the current state of the market means for pricing going forward? Do you see it being kind of flat from Q1, or Or is there going to be some move up or down, do you think?

I think, Keith, we demonstrated that, you know, obviously we're happy with where the prices are at, but it all is all based on high utilization. And I think our clients are realizing that. They see the value in keeping a dedicated frack fleet or what we've proven is from a From an efficiency standpoint, we can gain margin as long as they can provide the hours to us. And I think, you know, pricing, of course, is important, but more to that is not having gaps in our schedule. And I think that's where the industry really needs to lead to is just keeping that asset base active.

Yeah, okay, got it.

I'll leave it there. Thank you very much. Thank you.

Your next question comes from the line of Wakkar Syed from ATB Capital Markets. Your line is now open. Please ask your question.

Good morning and congrats on a great quarter. Steve, I just wanted to understand a little bit about the concept of client alignment. Does that mean that you're picking up clients that can... you know, provide you with efficiencies that your fleets can deliver, or is it more so you're choosing clients, or are you just with the existing client base, are you working better together as a team to create those efficiencies?

It's been an interesting dynamic, Waqar, and thank you for recognizing a great quarter that we had. As you've seen, our clients are getting larger through acquisition. And I would say that we saw that in the U.S. primarily last year, as well as some in Canada. But really what we talk about client alignment is, for us, is aligning with clients that have full-steady programs. And Sorry, I'm just hearing a bunch of typing. Is that you, Waqar? Is that maybe the operator?

No, it's not my end. I thought it was on your end. No, it must be the operator.

So, sorry. But, yeah, really what we're seeing is our clients are consolidating. They have, you know, the Montney, of course, is a world-class resource that we have in Canada. And we're just seeing operators or clients having programs that are lasting, you know, a full year of activity. with a full-time frack crew. And I think that's where you gain, back to my point about efficiencies, we're able to haul a majority of our sand that's pumped in Canada with our logistics team. And when you couple that all together, you really have, I would say, a finely oiled machine on creating the margins that we're happy with.

And if I can just add to, we were delivered and targeting certain clients that had that large work scope for cars. So we've got three clients or kind of two big ones and then a number of very solid ones that are kind of just a bit smaller that provide steady work scope. So it's much easier for us to forecast utilization when you've got these longer term commitments from clients.

And as well, like with our bundled services offering that, you know, a couple of these clients, you know, Not only do we provide fraction service, we provide pump-down services and coil tubing.

So this efficiency gains then and this client alignment, you think, is sticky at least through the course of this year?

Yeah, this year and we believe into next year as well.

Okay, great. Second, on the U.S. side in the Permian, there was some wording in the MD&A which leads to me believe that you may be thinking of maybe relocating some assets, or could you talk about what your plan is for your U.S. dual fuel fleets?

Yeah, as of today, we're happy with our size of operating the two fleets in the U.S. I don't think it's a surprise to anybody that the pricing isn't where we need it to be. It needs to go higher. And, you know, the crews that have left the Hainesville or the gas markets to kind of rush to the Permian hasn't benefited us at all or really a lot of the frack companies. So I think, you know, we do have a niche offering with our dual fuel technology. There's still 40% of the frack fleets that are operating today are strictly using diesel. So we do have that advantage. And, you know, I guess what car, as we've mentioned before, is our diversity of having operating basins in both the US and Canada, this allows us to put that asset base where we see the best margin.

Sure. So when you think of relocation, you're not thinking of moving from Permian to the north of the US or some other base in the US. If you ever think about it, it would be relocation to Canada.

Yeah, I would say right now we're focused in West Texas and the Permian.

Okay. And just one final question. Of the 490,000 horsepower that you have, how much horsepower is fully active today?

Yeah, we would basically consider all of it active, WACAR.

Okay. When you look at these large paths, we were on a pad in Canada for like 62 days from the time we rigged up to the time we rigged down. And in order to be pumping at 22 hours a day on average, you need to make sure you have an additional asset base that's available to basically come in. and provide relief for maintenance. And so in order for that, you have this taxi squad of assets that we've talked about in the past.

Right. Okay. Great. Well, thank you very much, and congrats again on a great quarter.

Thank you, Wakar.

Your next question comes from the line of John Gibson from BMO Capital Market. Your line is now open. Please ask your question.

Morning and congrats on the strong quarter again. I'm just wondering, John, first on the cadence of spending from producers in Canada, are you seeing a lot more front waiting at the beginning of the year now? I guess what I'm wondering is, pending all things come together, could you achieve these results even if it's on sort of a monthly basis at some point in the back half the year?

Great question, John. And we, I mean, our clients that we've aligned with in the past have typically been front end loaded. call it the first three quarters. They're quite active. And then, as unfortunately we demonstrated in Q4, not a great quarter to continue to have fixed costs, which are very high in this business. So I think we've troughed on the natural gas perspective, I hope anyways. And I would see more activity if gas were to reach $3 in the back half of this year. We are not modeling that today. We're being quite conservative for kind of Q4. But I guess, John, it doesn't take much, right, where people move capital forward. What we saw in Q1 was everyone was full. The calendars were full. And I think from our client's perspective, we were fortunate enough to have a March that we didn't have an early thaw season. or else there would have been a lot of work that never got done in the quarter. So just bearing that in mind, I believe, you know, if we do see, you know, obviously LNG Canada, you know, starts off taking product, call it this time next year, perhaps even earlier, I do believe that there'll be some more activity that we see in Q4.

I think one thing to add to, Steve, you talked about is the size of these pads. Yeah, if a pad hasn't started by kind of mid to late November, clients are very reluctant to start, just given the challenges of keeping water heated over a holiday break and things like that. So that's where we saw that in last year and key for of last year where the work in the working kind of late and mid November, it just ran down considerably. You know, LNG Canada could be a catalyst that would change that for this coming year. Obviously, gas prices weren't that attractive at the end of last year, but the client's focus is to have things wound down comfortably, but before the end of the year. There's some that we can incent with some attractive pricing to work into December, but by and large, it's getting more difficult to convince them of that as these paths get bigger and bigger.

Okay, great. Second one for me, you touched on last mile logistics being a constraint. Obviously, you've done a lot of work on this front, but wondering how you frame this in terms of monetization.

Are you charging clients for last mile or just gaining more work based on your availability to do so?

No, we're definitely charging for that, John. I think we looked at this opportunity a number of years back of You know, we've seen obviously profit intensity increase per stage to really, you know, compare itself to the Permian. And the difference, of course, in the Permian, you have localized sand mines. In Canada, we ship up about 80% of our profit that's shipped up on rail. So for us, it's really quite a, I would say, an orchestrated event to be able to have about 60 trucks running around the clock 24 hours a day, providing profit to all of our frack fleets. And I would argue our team is one of the best in the business to be able to gain those efficiencies. So, you know, there's two benefits with that that we see. Number one is, you know, we can provide profit to crews that are pumping faster, being more efficient. So we have that flexibility. And two is just isolating us from any third-party charges. That increase typically in Q1, we see an increase of third-party trucking costs. So we're isolated by having our own fleet.

Okay, great. Last one for me.

On your U.S. business, it's obviously been challenged on the FRAC side, but offset by more stability and coil tubing.

How do you think about these two things offsetting each other for the balance of the year in terms of margins?

Yeah, the quilt tubing business, we obviously like that. We've stood up a 13th quilt tubing unit in the U.S. You know, when we started looking at these three-mile laterals, it's quite amazing the technology that we're able to see with our StepConnect and knowing how much further we can get. You know, the string designs, you know, two and five-eighths, quench and tempered strings were able to, they're about $400,000 a string. So for us, it's managing that, getting the most life out of that pipe. And you have to do that with the data that's provided to you. And so investing in our real-time data acquisition, our real-time information to be able to monitor that is important. So we do see gains in the quilting business for this year. I think we've proven, John, that there's at one time it used to be a pretty low barrier to entry on the coal tubing side. Now there's been, you know, some consolidation that has happened. And, you know, to get into this business here, about $10 million per spread of coal tubing assets. And then, of course, when you add the cost of these strings, you need to make sure that you're financed properly for that. And secondly, on the frac side, Um, I, I think we've troughed, um, you know, there's been some discipline recently on laying down frack crews by, uh, by a lot of the larger players. And I'll just go back to where we're happy running our two fleets currently today. Um, our team has done an amazing job of, uh, managing the costs through this. And, uh, we'll just, you know, it's, it's not, um, It's not a business that we're going to be able to kind of quadruple our size in the near term, but it is something that we're still proud of to have, and it still generates good margins.

Great. I appreciate the responses and great work. Thanks, John.

Your next question comes from the line of Joseph Fachter from Fachter Energy Research. Your line is now open. Please ask your question.

Good morning, Stephen Kloss. I have two questions. Looking at the vacant use data, it shows the rig count up 29% for Canada, 120 rigs up from 93 a year ago. But it shows the gas side, you know, only up about 2%, you know, 60 rigs working. But it shows oil 60 versus 34. Of your six frac fleets, are all of them working for natural gas liquids in the What mix do you have of this mix, you know, working for the oil side versus the liquids-rich Montney play?

Yeah, I would say, I mean, it's really good information to highlight, Joseph. I appreciate you talking about that. You know, when we look at rig count, it's hard to actually get a number of rigs per fleet ratio just because a lot of the The rigs are working in the heavy oil, which, of course, doesn't require simulation services. But what we will basically have five Montney Duvernay type fleets from a horsepower standpoint, and the sixth fleet is what we consider more focused on shallower oil plates like the Cardium, the Viking, and even the Bakken. So that's sort of how we operate today is sort of five in the Montney and the Duvernay. and one elsewhere, but they have wheels. They can travel to different basins.

On margin, of course, fabulous utilization and margin. Are we looking at this being peak, given, as you mentioned, that you had long utilization, 22 hours a day of utilization? Is that 30% about as high as you're going to be able to go, or what's your thoughts on that?

Q1 is typically the best quarter that we have. Q3 comes close, but just the Q1 performance is unlikely to be matched again for the rest of the year. And that's typical for most years.

Okay. And in terms of bookings for, you know, later this year into 25 with LNG Canada startup, are you seeing more bookings in the on your BC side of the business, or is it, you know, north to west Alberta that is getting the bulk of your business going forward?

Kind of a little bit of both, Joseph. We are seeing, I mean, you look at the BC rate count, it's, you know, call it post-breakup. It's been the highest it's been in five years. So obviously some, the activity is showing up for LNG Canada. I think that I think we need to, you know, from our understanding is that the. Coastal GasLink pipeline is full and it's basically flaring gas right now, so they are taking product. And I I guess I would expect some additional drilling rigs to hit the field kind of Q4. You know, talking with the drillers, they do expect that as well as the high spec rigs to be sold out and you know, I'll just couple that comment, Joseph, with the efficiencies from the drilling rig side. You know, they're drilling these montany wells in, you know, 10 or 11 days. And it takes us about, you call it three to four days to frack these montany wells, depending on the number of stages. So you can kind of look at a ratio of, call it two drilling rigs to one frack crew for the montany if things go, you know, from a pad drilling perspective.

Super. Thanks very much for answering my questions, and congratulations on the great quarter.

Thanks, Joseph.

We don't have any further questions at this time. Presenters, please continue. We have a follow-up question from the line of John Daniel from Daniel Energy Partners. Your line is now open. Please ask your question.

Guys, thanks for including me. Hopefully you can hear me. Just one question. As you guys do more of these three-mile laterals with the coil business, have you seen legacy stick pipe customers officially make the conversion, or are these always sort of coil tubing enthusiasts? I'm trying to see the transition in the market.

John, a bit harder to hear about. Maybe I'll repeat the question that I thought I heard. You're wondering if these three-mile laterals are – with our success of our coil tubing being switched from a snubbing unit or service rate perspective to coil? Is that the question? Yeah. Yeah. We're definitely seeing some interest, particularly with our step connect technologies. The advantage with that is on these lower pressure reservoirs that typically have been used with stick pipe We're seeing success deploying that technology because we can really monitor the bottom hole pressure. So the advantage of that just allows us not to be stuck in the hole. It minimizes that risk. So I think going forward, you're going to see that as well as some other technologies that are coming out to be able to put additional weight on bit on these long horizontals. Okay. Thank you. Sorry for the issues with the phone.

No worries, John. Thank you.

We don't have further questions at this time. Steve, please continue.

Yeah, I'll just close off by thanking everyone for your interest in STEP Energy Services. We had a wonderful quarter. We're proud of that, and we look forward to our call that will happen for Q2 this summer. Thank you very much.

This concludes today's conference call. Thank you for your participation. You may now disconnect.