STEP Energy Services Ltd.

Good day ladies and gentlemen and welcome to the STEP Energy Services Q2 2023 conference call and webcast. At this time all lines are in listen only mode. Following the presentation we will conduct 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 Thursday, August the 3rd, 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 second quarter 2023 conference call and webcast. It was another excellent second quarter for the company. 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 focus commentary. He'll 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 Q2 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 June 30th 2023 for a more complete description of business risks and uncertainties facing STEP. This document is available both on our website and on CDAR. 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 CDAR and on our website. With that, I will pass the call over to Steve.

Yeah, thanks, Dan, and good morning. Welcome to our second quarter conference call. My name is Steve Blanvel, and I'm the President and CEO of STEP Energy Services. Hopefully, you've had the opportunity to look through our results. As you see, it was another excellent quarter for the company, and more importantly, it was an excellent second quarter, which historically has been a challenging one for a Canadian-based energy services company. Spring breakup conditions typically suppress activity to such a degree that companies often spend the second half of the year making up traction loss in Q2. This is the second year in a row that we have achieved impressive results because of our alignment with very active Canadian clients and our best-in-class sand and logistics management group, which navigated spring road bands and an early and unpredictable start to the wildfire season. In the U.S., we posted healthier margins in fracturing, while our U.S. co-tubing division had another record quarter. Before I turn the call over to class, I'd like to highlight two numbers. First, we posted $47.4 million of adjusted EBITDA, which was ahead of consensus and also higher than our first quarter number of $45.3 million. Although we didn't reach the $55.2 million record set one year ago, it was still a very strong quarter and would have been stronger if work wasn't delayed due to the wildfires in BC and Alberta and also the flooding in some key operational areas. Second, our net debt position improved to approximately $116 million, down from $133 million from Q1. On a trailing 12-month basis, our net debt is down to 0.6 times adjusted EBITDA. Although we continue to plan for more debt retirement through strong free cash flow, we have given ourselves some strategic latitudes. Historically, this amount of leverage would have been considered an unlevered balance sheet. We now call it a strong balance sheet, and it will get stronger, even as we continue to upgrade our equipment to meet the growing performance demands of our clients, including lower emissions. And speaking of upgrades, I'm happy to report that our Tier 4 dual-fuel fracturing fleet is complete and working for our Canadian client, and we're seeing displacement rates of up to 85%. which is reducing operational emissions. I will return at the end of the call to address our strategy and outlook, and now I'll turn it over to Klaas, our CFO, to give a review of our key financial highlights.

Thanks, and good morning, everyone. Before I start, a quick reminder to listeners that all numbers are in Canadian dollars, and they'll round in most cases. Full details can be found in our MD&A. I'm going to start with a consolidated snapshot of our income statement. followed by some country-specific detail, and then we'll close with some balance sheet commentary. As noted, the second quarter was not a strong achievement by the company. We didn't quite match last year's record-breaking Q2, but it was still an excellent one in many ways. Revenue for the quarter was $232 million, and adjusted EBITDA was $47 million. This figure also includes $1.1 million for fluid ends in Canada, something that we began expensing in 2023. This quarter compares to the $273 million in revenue that we earned last year and $55 million of adjusted EBITDA in last year's second quarter. That quarter has been described by some as being so perfect that it could be called lightning in the model. On a sequential basis, revenue was down 2%, but our adjusted EBITDA was 5% higher than the $45 million we earned in the first quarter, and our margin improved to 20% in Q2 from 17% in Q1. This improvement is partly driven by job mix, but also it comes through disciplined cost management in both geographic regions. particularly in the U.S., where the land rig count fell roughly 15% from its peak from last year to the end of June. Net income for the second quarter was $15 million, or about $0.21 per share on a fully diluted basis, as compared to $38 million, or $0.54 per share, a year ago. Note that last year's second quarter benefited from an impairment reversal of $33 million. Sequentially, net income was down from the $20 million earned in Q1, but that quarter had a share-based compensation expense recovery of $5 million. versus an expense of just over a million in this past quarter. Turning now to our Canadian segment, as Steve noted, spring breakup remains a factor in the Canadian business, but we're starting to see more clients recognize the value of planning for work in the second quarter. With a bit of foresight, clients with large pad work can realize incremental savings relative to Q1 or Q3. Increasing Q2 work has been a goal of our company as it level loads the demands, not just on our business, but the entire WCSB infrastructure network. Everything from sand to wireline to water can be easier to access this quarter, and we're seeing in the quarterly results that we've posted this last few years. Second quarter revenue of $136 million in Canada was a great result, considering that we had to deal not just with volatile commodity prices, but also with drought, fires, and floods. This was down $29 million from Q2 last year, but despite all the headwinds we faced, we were able to increase our adjusted EBITDA margin performance, improving from 24% last year to 25% this year. Canadian fracturing saw a decline in revenue in line with the reduction in fracturing days and profit pumped, but I've noticed that we supplied and managed the logistics on 95% of the profit this quarter, which is a key factor in controlling costs and delivering an exceptional client experience. Our coal tubing division was more or less flat year over year. Our number of CT days fell by 6%, while revenue itself was only down about 2%. These results fall within the range of normal spring rake-up activity. In short, we're really pleased with how both Canadian divisions performed. Turning to the U.S., we saw really good progress versus Q1 levels in both business lines. Total revenue of $96 million was down 11% from last year in Q2, but up 8% from Q1 this year. In coil tubing, we put up another record quarter of revenue with 12 CT units, up from an average of 11 units in the first quarter. We had sequentially higher operating days, up 14% from Q1, the 791 days. Utilization rose a bit sequentially, as did revenue per operating day. We're really starting to see the benefits of scale, which was made possible by the acquisition we made in Q3 of last year. That's really starting to pay off. In short, our strategy of becoming one of the largest deep coil providers in the U.S. is paying off, and our breadth of regional exposure between northern and southern U.S. is proving its worth. In U.S. fracturing, we saw similar revenues to Q1, but we had a much larger percentage of clients supplied sand than we did in Q1, which has the effect of increasing margins as sand typically is a low margin pass-through. We had higher sequential utilization in Q2, but we also saw some of the same market softness quoted by our U.S. peers, although our Q1 experience had already accelerated tighter cost control actions for the quarter, which preserved margins. The record coil tubing and the recovery and fracturing resulted in an adjusted EBITDA margins of 19% in the second quarter, up significantly from the 5% we had in the first quarter. The U.S. market has been more challenging this year for STEP, but we are pleased with how the business has responded to these challenges. We generated $35 million of free cash flow in the quarter, creating the means for us to continue investing into our equipment. We have one of the best records of matching capital spending to depreciation across our industry. which is a sign of a well-maintained fleet. Steve already touched on this, but we're very excited to see our first Tier 4 dual-fuel fleet hit the field. We're very careful about how we allocate capital, and you'll also note in our MD&A that we're accelerating our Tier 4 dual-fuel build-outs in the U.S. as well. This acceleration will increase our 2023 budget by $6 million to about $105 million for the year, with the result that by year-end, almost 60% of our horsepower in Canada and the U.S. will be dual-fuel capable. We also used our free cash flow to continue reducing debt, closing the quarter at $116 million in that debt. Our leverage has now come down almost $200 million since 2018, with the benefit of that accruing to our equity holders. We will continue to stay focused on reducing this through the second half of the year. Finally, our latest book value per share has increased to $468 from $455 at March 31 and versus $333 a year ago. That is a full-year accretion to equity holders of over $108 million, or about $1.35 a share. With that, I'll turn it back to Steve for some key remarks on our strategy and outlook.

Thanks, Klaas. Looking at the quarter as a whole, we are very pleased. Our U.S. co-tipping division continues to raise the bar with respect to performance levels. Our U.S. fracturing division rallied from a difficult start to the year due to client delays. Canadian fracturing put up what may be the best results of any fracturing company operating in Canada this quarter. and Canadian coal tubing held its own during spring breakup. This really does sum up our strategy, business line and geographic diversity. Supporting this strategy, these results are achieved with great people and our well-maintained modern equipment. And while I'm on the topic of great people, I want to share something about STEP's people philosophy. You may have heard us call our employees professionals. The word professional is used very deliberately and refers to the fracturing crews in northern Alberta, cultivating crews in Texas, members of our first class logistics and supply teams, our office space professionals who surround me every day, and every other valuable member of our company. We empower all of our people to lead with professionalism and to excel in their roles each day. This is certainly evident in results like this in a second quarter. Our view of people as professionals is a big part of our secret sauce, and they are the reason we can achieve what we do. Circling back to our strategic position as a diverse energy services company, we know that the most successful companies in our sector will have strong positions in both geographic markets, which include the best oil and gas plays in North America. A major driver in our industry is LNG development, and the momentum continues to grow. The tone in Canada is positive and it appears that Shell is roughly on track to begin commissioning the LNG Canada project a year from now, with the first gas exports expected in 2025. Shell appears to be favorably disposed to moving forward with phase two of the project for trains three and four, which would add another two BCF a day to Western Canadian takeaway capacity toward the end of the decade. Although the decision is at least a year away, these developments are making Canada a more constructive market for fracturing and quotating services, a market that is less dependent on domestic oil and gas prices. On the U.S. side, another LNG project was sanctioned at the beginning of the third quarter, which is called Next Decade's Rio Grande Project. This will add another 2.5 BCF a day of export capacity. This adds to numerous gas pipeline projects that are currently under construction or have been recently approved, including the Williams Louisiana Energy Gateway project that will transport about 1.8 BCF per day of Hainesville gas to the Gulf Coast. In fact, by the end of the decade, the U.S. is on track to double its natural gas export capacity via LNG. It is a market step times the growth. As part of this, we are currently in the process of upgrading 16 of our existing U.S. Tier 4 fracturing pumps to dual fuel capability, which is in addition to our existing fleet of 26 Tier 2 dual fuel pumps. We can also bring additional deep capacity coal tubing units on the U.S. market as the U.S. market grows. I want to turn to our regional outlook. Starting in Canada, SNEP's second half looks solid, although we have had some work deferred into 2024, which our clients believe will be more constructive and less volatile pricing environment. The laying down of drilling rings by one major E&P company may also decrease the number of completions operations and lead to a bit more competition in the market. However, we believe the activity level should remain solid to support the volumes required by LNG Canada. In addition, the recent strengthening of global oil prices could sustain the overall completions market until we move to a busy winter season again. As well, Q3 will be our first full quarter with our new Tier 4 fracturing fleet, which will contribute to operating margins in line with the investments made into this improvement. In the U.S., for the second half of the year, we have chosen to align with larger E&P companies with very active fracturing programs to retain high utilization but we've made a modest sacrifice in pricing to accomplish this. As our U.S. competitors have noted in the recent conference calls, the 15 plus percent pullback in U.S. land drilling levels will reduce the pace of industry completions in the third and perhaps fourth quarter. So we think our alignment with active and predictable clients is the right business strategy in the near term. Having said that, Stronger oil prices and a modest uptick in U.S. natural gas price should lead to a more constructive 2024 fracturing market. In U.S. quo tubing, we see a plateauing of activity at the high levels of the second quarter, which should generate very good results in the back half of the year. Before I turn the call back to the operator, I want to close by first noting a couple of major step operating achievements in the field. But first, one of our West Texas-based deep co-tubing crews set a new depth record, reaching a remarkable 27,075 feet. That's over 8.2 kilometers during a post-frack clean-out. They beat our previous record by almost 500 feet. This was a deep and complex well that our exceptional crew of professionals and deep capacity equipment made possible for this client. The second on a 5-well pad, a Montney pad, for one of the largest E&P companies in North America, STEP Fracture FRO2 achieved a new daily pumping record of 5,196 tons of profit pumped in a 24-hour period. In addition to this record, STEP recorded the client's fastest stage transition time of 1 minute and 42 seconds. This exemplifies the best-in-class service we deliver to our clients and the execution of flawless and safe operations. Operator, we are pleased to be taking any questions.

Thank you, sir. Ladies and gentlemen, we will now begin the question and answer session. If you would like to ask a question, please press star followed by the number one on your telephone keypad. If your question has been answered and you would like to withdraw from the queue, please press star followed by the number two. And if you are using a speakerphone, please lift the handset before pressing any keys. One moment, please, for your first question. Your first question will come from Waqar Syed at ATB Capital Markets. Please go ahead.

Thank you for taking my question. Steve, first of all, congrats on getting a very high 85% substitution for your new Tier 4 crew. So congrats on that. Just out of the gates, you've been able to achieve such high efficiencies. My question is regarding the new Tier 4 conversion kits for the U.S. market from diesel to dual fuel. I've heard in the past that you get high natural gas leakage from these conversion kits. Not the specific ones that you think, but in general, the view is that dual fuel emissions are not as good, although you save a lot on the natural gas conversion side. What's your experience been in terms of comparing dual fuel emissions versus diesel or versus the TFO DGB?

Yeah, well, Kark, thanks for acknowledging the 85% displacement that we're seeing on our new Tier 4 fleet. In addition to that, I guess one thing before answering your question, it's in regards to reliability. We've been seeing higher efficiencies in uptime because of that fleet, so that is obviously significant. great to see in our business and should expect to see that going forward from a margin improvement standpoint. In regards to your question, the fleets that we have in the U.S. are very homogeneous. We have engines that are very the same, which are the MTU engines, and they're quite different than what the previous, call it Tier 2, kits that you could add by a you know, the dual gas blending kits. And the difference is that they're a direct injection, so they're more ported into the cylinders of the engine, so you have less slippage, natural gas slippage, like you would typically have in a Tier 2 fleet, which goes into more of the air system. So that's what we're adding. We have 26 of them that are currently in the U.S., today on our Tier 2 fleet, we're seeing up to 60% substitution and even higher in certain conditions depending on the temperature of the gas. You need to have that gas colder so as it heats up in the summertime, we don't get as high as displacement. So the team is working hard at getting some chillers or making that gas colder. So the decision that we made to go with the upgrade of our Tier 4 fleet. We basically have 80,000 horsepower of our Tier 4 fleet. And so we're going to be slowly adding that for the rest of the year to convert one fleet of that to this technology.

Great. And then just staying on the topic of Tier 4 DGB fleets, are you considering... What's the long-term plan, let's say, for your fleet in Canada in terms of converting to Tier 4 DGB?

Yeah, we have basically a sustainability and optimization CapEx plan that's spread out over the next two to three years. We've looked at our end-of-life use on our assets, and we'll continue to upgrade to Tier 4 engines as our Tier 2 engines expand. get to that 20,000 to 25,000 engine mark. So that's our plan today. We're going to continue to invest into low-emission engines for our fleet. And by the end of 2025, we plan to have 90% of our fleet basically on dual fuel.

And then just last question on your – contracting to these large E&Ps in the U.S., and these dedicated contracts. This certainly improves the business visibility. Now, these client-supported materials, does that type of contract continue going forward, or is there any flexibility that you see that contracts may change, or are you going to stick with those terms?

We're really happy with how our sales and operations team have aligned ourselves with clients that have larger programs. It provides, obviously, consistent utilization. We've looked at all the numbers. We're really happy with returns on the numbers that we receive. And, you know, it provides some great stability for our U.S. business. We have three frat crews in the U.S. We're not a very large player currently today. We were up to four. We shut down one crew in Q1, as we mentioned in the past. But it provides us a great platform for growth. We're only going to grow where it makes sense to do that. Like we mentioned, we'll add cold tubing capacity if we see it. We'll add track capacity only if there's a long-term contract in place in the U.S., and that's what the team is focusing on. We're really happy with the position that we have. We have visibility to high utilization crews for the remainder of the year, and our team is looking into 2024 and 2025 currently today.

Just specifically around the question that goes around profit, is that what you're asking, Bukhar?

That's right. Go ahead.

So you're seeing clients take on more of that profit, just the availability of SAM down there? Last year, it was a lot tighter, so we saw a lot of pumpers supply sand. And now this year, we're seeing clients source their own sand in a lot of cases.

Yeah. All right. Sounds good. Thank you very much. Appreciate the color.

Thanks, Ricard.

Your next question will come from Cole Pereira at Stiefel. Please go ahead.

Morning, all. I just wanted to clarify your earlier comments on the upgrade program. So going forward, do you have a bit more of a preference to Tier 4 with the aftermarket bi-fuel kit, or would you also lump Tier 4 dual gas blending into your future plans as well?

Paul, will you be able to maybe rephrase that question?

Yeah, sorry. So obviously you... Just to clarify, are you planning on continuing to upgrade to Tier 4 dual gas blending engine or just the aftermarket buy fuel kits?

Yeah. So in the U.S., we currently had 80,000 horsepower Tier 4 assets, but they weren't dual fuel capable when we received them in 2018. And now the market obviously has improved that technology significantly. And so this kit that we have is an aftermarket kit that is very similar to call it the CAT DGB fleet that is well-known in the industry.

DGB is a trademark, maybe I'm not saying that quite right, but it's a CAT-specific term, dynamic gas blending, whereas dual fuel is a more generic term. So because we have dual fuel kits in the U.S. that are not on CATs. We can't call them DGD. So that's why we're going to talk more generally around dual fuel. So it's kind of U.S. versus Canada, NTU versus CAT distinction.

Okay, gotcha. And on the Canadian side, I mean, you talked about some of the strong near-term outlook. Have you really seen much in terms of customers firming up plans for 2024, and if so, can you maybe add some color on that?

Yeah, I can share a little bit, Cole. We're definitely seeing an increase in client calls for getting calendar space for Q1. I would say it's probably earlier than we've ever seen today, so currently our plan is to stay with our five frat crews in Canada. We don't plan to add any until the market comes to a very undersupplied position. And I would say today we're kind of 50% already booked, maybe even higher for Q1 of next year.

My comment there earlier around Q2, if you take a look at what we did collectively as a group of pumpers in Q1 and the rest of the industry, the capacity constraints are becoming very, very apparent, particularly around sand. and logistics. So pushing more work into Q2 and also advancing some into Q4 is something that we'll be having a lot of conversations with our clients.

Okay, perfect. That's all for me. Thanks. I'll turn it back.

Thanks, Colt. Your next question will come from Keith Mackey at RBC. Please go ahead.

Hi, thanks, and good morning. Just wanted to start out on the fastest transition time you did in the Montney, that one minute, 42 seconds. Can you maybe just run through some of the big factors that led to that? I'm sure there are some with people, process, technology, et cetera. Maybe just kind of give us the flavor of that and maybe discuss how low you think that number can go.

Yeah, Keith, I mean, obviously you've seen the transition rate into our industry go from call it 14 pumping hours per day. That was an average that we saw kind of in 2020 timeframe. So now we're upwards of 18 and 19 pumping hours per day and even higher. And there's a lot of factors into getting that efficiency so high. One, of course, is the main one is working with our clients to understand every minute of available time that we have. And For this client in particular, we've been working with for quite some time looking at ways to improve. And so there's technology that's available that basically allows you to, you know, kind of remotely operate valves of the wellhead so that you don't have anybody in the hot zone. And so you're allowing basically to have one wellhead open and when the frack stage is done, the other wellhead is open in an hour and 42 minutes or so. I'm sorry, a minute and 42 seconds. So there's technology. But as you can imagine, the logistics, just the overall setup of these locations, it's more like a factory process now. You know, I talked about the record of close to 5,200 tons being pumped in a 24-hour period. That's 133 B train loads of sand or 266 loads, single loads. So it's a very, very well orchestrated process that we have in the field to be able to achieve that. And we, in Q2 alone, we were able to haul 90% of our own product internally. And I think that's a key highlight for our efficiencies gained in the quarter is we have the ability to control those costs. and control the lead times to get profit. And we really saw, you know, as, you know, the wildfires were suppressed, and we saw the industry really ramp up, call it the middle of June. I think every one of the Canadian pressure pumpers were extremely busy at that time, and there was lots of, call it, sand delays, people trying to find sand, you know, and so us having a lot of control over our logistics just creates a differentiator in our space.

Thanks. And maybe just to follow up, you've got an interesting position given you operate in the Permian and the Montney, you know, Permian in the U.S., Montney in Canada. Can you just talk a little bit more about the the differences and similarities in those two markets in terms of things like pumping intensity, your ability to get compensated for that pumping intensity and whether there's some convergence in, you know, in mountain intensity and operations, you know, to the Permian and how you think that might affect where things go over the next, you know, 12 to 18 months, say.

I'm not a geologist, Keith, but what I can tell you is that the U.S. have done a great job of understanding the rock, understanding kind of optimal profit and placement stage design. And so that has really transferred into the Montney where we're seeing more intensity, higher profit loadings per stage, more stages on a horizontal length. I think in the U.S., in particular in the Permian, is they have regional mines that are within, call it a 100-mile radius of where the work is. And so that's a big advantage for them down there to be able to keep their costs low. Of course, in the Montney, not a lot of regional mines in that area. We have totally different. surface geography with rocks and not beaches. So that's a lot different in northern Alberta than it is in west Texas. But I think, you know, in the U.S., what we're seeing is, you know, more stability from an activity standpoint, a lot more rigs that are active. There's 300-plus drilling rigs working in the Permian today. And I see Montney. obviously not getting to that type of scale, but it's very, very early stages of the montany when you look at it from an overall depletion standpoint. I think you're going to see a lot more activity there in the coming future. And we're seeing, obviously, in the Permian where perhaps there's the Tier 1 acreage that's being drilled up, and I've commented about this before, is our The decision to get into ultra capacity or deep capacity cold tubing basically showed the value in Q2, where we were milling out these three-mile laterals. So they drill them down two miles, and they're out three miles. So very, very long lateral lengths. We have the technology on the cold tubing side to be able to get to those lengths, and we believe that's where we need to be positioned in the future.

Thanks very much. That's it for me. Thanks, Keith.

Your next question will come from Joseph Schachter at Schachter Energy. Please go ahead.

Good morning, Klaus and Steve, and congratulations on the quarter and the improvement to the balance sheet. First one for Klaus, in the presentation... Sorry? In the presentation... Hello? Hello?

Yeah, we got you. Go ahead.

Okay. In the presentation of expenses, materials and inventory costs 60.6 versus 93.3 a year ago. Any specific reason why those came down so much?

That's a very detailed question. I'm going to have to tell you what, Joseph, give me a call after the After the conference call here, and we'll go through that here. I think it's probably more because in the U.S.

that we are having more clients. Supply and send is where my head goes to. Joseph, right off the bat.

Okay.

But let Klaus get back to you on that.

Okay, thanks. And this is for Steve. Steve, you mentioned, of course, that you're doing more longer – reach coil tubing laterals that are kind of with all the specialized deep equipment you've got. And you went over a couple examples of that. The coil tubing side, of course, has got, you know, with less drilling and less completions, that's slowed down. Is there any other color you can throw on the coil tubing? Why it's such a, you know, 26 million a year ago, 47.5 this year? Anything else specifically that you can add to the color of why You had such a big increase in the revenues?

Yeah, scale really matters, Joseph, to us. We basically deployed three additional quilt tubing units starting in this year, and we saw really in Q2 the full effect of our 12 units being highly utilized. As we think about the competing services that we have on the cold tubing side, which is typically service rigs or snubbing units that are drilling out plugs, when I talk about 27,000 feet, it's very, very hard for a service rig to keep up to the efficiencies of cold tubing. And when you get to those depths, of course, the cold tubing business really differentiates itself because just time really matters, right? Getting these wells online faster is really the big savings for the client. And we're able to do these and call it two days that we're building out wells, which is tremendous. And the technology from the bottom hole assembly, which is required to mill out these plugs, is improved. the ability to put weight on the end of coil of 25,000 feet or more has really improved. So it's just a number of new technologies that we've been incorporating in our business, including our Step Connect that we talk about, which is our E-line string inside of coil that we can read bottom hole, basically measurements. So our team of professionals know exactly what's on weight on bit, so we can increase our efficiencies that way.

Okay. And lastly, you mentioned that you wouldn't add any more equipment at this point. Are you seeing any of your competitors moving on that and that we might see a bit of an oversupply or take some time for all the supply to tighten up if some of your competitors bring in equipment from the states?

Yeah, let's see. currently today i mean there's been a decrease about 30 frat crews from the peak of q1 and uh that's that's great to see um so there's some discipline in retiring assets before you know before kind of dropping price and i think that's sort of the discipline that we expect going forward um there's since the patterson and you know next year announcement uh Currently, there's four companies in the U.S. that control 70% of the market. And we like that. We're positioned really well to continue with that growth. I believe what we're going to see, Joseph, over the next, call it a year, year and a half, that a lot of the diesel fleets that are currently active in the U.S. will most likely be parked because of the advantage of using dual fuel and or electric. And that's where I believe there will always be a place for diesel fleets in certain areas, but for us, our strategy is to get our fleets on dual-fuel going forward.

Okay, super. Well, congratulations, and again, thanks for taking my questions.

Joseph, just a quick question here. I caught up with where you were going there on that materials and inventory cost. So, yeah, we had a much higher proportion of clients supplied sand in the U.S. last year. and that will obviously drive high revenue numbers. So last year was quite a bit higher. So if you take a look at that as a percentage of your total operating expenses, that's why it's higher.

Okay, super. Thanks for the info. Thanks, Klaus.

You're welcome. Ladies and gentlemen, once again, if you would like to ask a question, please press star 1 now. Your next question will come from Bill Austin at Daniel Energy Partners. Please go ahead.

Hey, guys. How's it going? Going well, Bill. Good to hear from you. Yeah. Hey, so one thing I wanted to touch on is, like, as you guys consider, you know, some potential M&A opportunities, and you talked a lot about the shift to dual fuel already, How attractive are some of the small private track players in the U.S.?

Great question, Bill. And, you know, we've looked at a lot of opportunities, particularly the small privates, to add. You know, really, we like to double our fleet size in the U.S. to get up to six or seven. The challenge that we have, we trade at such a low multiple right now. And when you look at that, trying to, you know, the bid ask for some of these is quite a large spread. And then when you dive a little bit deeper into, you know, some of these fleets that are currently active are, you know, older technology. So when you add perhaps the asking price plus the refurb costs, it makes more sense probably to build new. And so... That's kind of our strategy going forward, Bill, is to look at longer-term contracts, provide the client with the latest technology that's available, and grow the business that way. Unless there's some fleets that are available today that have dual-field capability, that's kind of our vision going forward from a growth perspective.

That makes sense. And then one other slightly different subject, but, you know, you guys have talked a lot about long-term contracts, but, you know, there's also a lot of chatter right now about some spot market pricing pressures. Do you guys have a sense that that drop was just short-term and it'll reverse itself as, you know, 2024 picks up? You know, so, like, another way of thinking about it is if a company's bidding for dedicated work in 2024, Would that quote currently be better on the spot market?

I mean, you guys received lots of information, Bill, and I think what we've picked out of all the information that we digest and strategize over, it's the public E&Ps, super majors, they haven't dropped much from a drilling rig standpoint. It's been the smaller privates. Quick to react. on commodity prices um you know i think out of the 115 drilling rigs that are down from the peak and probably close to 80 of them are are you know private small privates so i don't know i i think i'll answer that by you know if oil stays in around this 80 mark perhaps goes to 90 by the end of this year there's some opportunity for you know going to the spot market but We really like our position today. It just provides us some growth opportunities and stability for our U.S. business.

Yeah. Okay. Yeah, makes sense. Thanks. Thanks, Bill.

Your next question comes from Jim Byrne at Acumen Capital. Please go ahead.

Good morning, guys. Just one for me on the balance sheet. Steve, you mentioned, you know, you obviously continue to pay down debt. Is there a point where, or a goal in mind, I guess, in the short term, and there's come a point where you just kind of slow down some of that debt repayment and look for other capital allocation opportunities?

I mean, I We'll be kind of less than $100 million of debt by the end of this year is part of our forecast. And when we look at into 2024, our goal is to get our debt to a working capital number, so we'll call it $60 to $70 million of debt. And I'd consider that basically zero debt. At that time, we have some strategic opportunities on what we do with the free cash flow. I believe what's best from a shareholder perspective today is continue to upgrade our fleet to Tier 4, where we get higher margins in our business, redeploy some capital to some idle assets, for example, like quilt tubing. And perhaps there's some M&A opportunity in the future, but for us right now, it's continuing to focus on debt repayment. And we like talking about these stories, Jim, that we are We have a very strong balance sheet today. We haven't been in this position for a few years, and I think this shows you kind of our laser beam focus on repaying back debt and getting us in a great position.

Okay, that's perfect. Thanks, guys.

Thanks, Jim.

There are no further questions from the phone lines, so I will turn the conference back to Steve Glanville for any closing remarks.

I just want to thank everybody for joining our Q2 2023 call and look forward to our results in Q3. Thank you very much.

Ladies and gentlemen, this does conclude your conference call for today. We would like to thank everyone for participating and ask you to please disconnect your lines.