STEP Energy Services Ltd. (SNVVF) Q2 2023 Earnings Call Transcript

STEP Energy Services Ltd. (OTCPK:SNVVF) Q2 2023 Earnings Conference Call August 3, 2023 11:00 AM ET

Company Participants

Dana Benner – Senior Advisor-Investor Relations

Stephen Glanville – President and Chief Executive Officer

Klaas Deemter – Chief Financial Officer

Conference Call Participants

Waqar Syed – ATB Capital Markets

Cole Pereira – Stifel

Keith MacKey – RBC

Josef Schachter – Schachter Energy

Bill Austin – Daniel Energy Partners

Jim Byrne – Acumen Capital

Operator

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 a question-and-answer session. [Operator Instructions] This call is being recorded today, Thursday, August 3, 2023.

I would now like to turn the conference over to Dana Benner, Senior Advisor, Corporate Development and Investor Relations. Please go ahead.

Dana Benner

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 focused commentary.

We’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 30, 2023, for a more complete description of business risks and uncertainties facing STEP. This document is available both on our website and on SEDAR.

During this call, we will also refer to several common industry terms and certain non-IFRS measures that are fully described in our MD&A, which again is available on SEDAR and on our website. With that, I will pass the call over to Steve.

Stephen Glanville

Yes. Thanks, Dana, and good morning. Welcome to our second quarter conference call. My name is Steve Glanville, and I’m the President and CEO of STEP Energy Services. Hopefully, you’ve had the opportunity to look through our 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 bans and an early and unpredictable start for the wildfire season. In the U.S., we posted healthier margins in fracturing, while our U.S. coiled tubing division had another record quarter.

Before I turn the call over to Klaas, 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 records set 1 year ago, it was still a very strong quarter, and would have been stronger if work wasn’t delayed, due to the wildfires in B.C. 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 0.6x adjusted EBITDA. Although we continue to plan for more debt retirement through strong free cash flow, we have given ourselves some strategic latitude. 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 am happy to report that our Tier 4 dual fuel fracturing fleet is complete and working for our Canadian clients, and we’re seeing displacement rates of up to 85% to 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 Klaus, our CFO, to give our review on our key financial highlights.

Klaas Deemter

Thanks, and good morning, everyone. Before I start, a quick reminder to listeners that all numbers are in Canadian dollars, and I’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 that being as being so perfect, that it could be call lightning in a bottle.

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 comes through disciplined cost management in both geographic regions, particularly in the U.S. for 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 about $33 million.

Sequentially, net income was down from the $20 million earned in Q1 but that quarter share-based compensation expense recovery of $5 million, versus an expense of just over $1 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 and 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 easy to assess this quarter, and we’re seeing it 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 for volatile commodity prices, but also 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 defining revenue in line with the reduction in the posturing days and proppant pump. But I’ve noted that we supply and manage the logistics on 95% of the profit this quarter, which is a key factor in controlling costs and delivering an exceptional client experience. Our coiled tubing division was more or less flat year-over-year, and our number of CT days fell by 6%, while revenue [indiscernible] down about 2%.

These results are pretty — fall within the range of normal spring rank 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 coiled 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 to 791 days. Utilization rose a bit sequentially as did revenue per operating [indiscernible]. 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, but 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 client 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 assets for the quarter, which preserved margins. The record coil tubing recovering — sorry, the record coil tubing and the recovery in fracturing, resulted in an adjusted EBITDA margin 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 in the field. We’re very careful about how we allocate capital, and we also note in our MD&A that we’re accelerating our Tier 4 dual fuel buildouts in the U.S. as well.

This acceleration will increase our 2023 budget by $6 million to about $105 million for the year, which results 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 net 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.

[Indiscernible], our latest book value per share has increased to $4.68 from $4.55 at March 31 and versus $3.33 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.

Stephen Glanville

Thanks, Klaas. Looking at the quarter as a whole, we are very pleased our U.S. coil tubing 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, and need fracturing put up what may be the best results of any fracturing company operating in Canada this quarter, and Canadian coiled tubing held its own during spring break up.

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 in reverse to the fracturing crews in Northern Alberta, Colton Cruise in Texas, members of our first-class logistics and supply teams, or office-based professionals who has 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 the 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 on 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 2 of the project for train 3 and 4, which would add another 2 BCF a day to Western Canadian takeaway capacity towards 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 clothing 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 Decades 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 Haynesville oil 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 set times to grow lift. 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 an addition to our existing fleet of 26 Tier 2 dual fuel pumps. We can also bring additional deep capacity coil tubing units on the U.S. market — as the U.S. market grows. I want to turn to our regional outlook. Starting in Canada, STEP’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 rigs 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 levels 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 treatment. 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. coil 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, it’s one of our West Texas-based deep coil tubing crews set a new depth record, reaching a remarkable 27,075 feet of over 8.2 kilometers during a post-frack clean. They beat our previous record by almost 500 feet. This was a deep and complex well that our exceptional [indiscernible] professionals and deep capacity equipment made possible for this client.

The second quantify well pad, a Montney pad, for one of the largest E&P companies in North America. STEP frac FRO2 achieved a new daily pumping record of 5,196 tonnes of proppant 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.

Question-and-Answer Session

Operator

Thank you, sir. Ladies and gentlemen, we will now begin the question-and-answer session. [Operator Instructions] One moment, please, for your first question.

Your first question will come from Waqar Syed at ATB Capital Markets. Please go ahead.

Waqar Syed

Thank you for taking my question. Steve, first of all, congrats on getting a very high 85 percentile substitution for your new Tier 4 crew. So congrats on that. Just started the gates you’re being 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 — the new fuel has 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 a Tier 4 DGB?

Stephen Glanville

Yes. Waqar, thanks for acknowledging our the 85% displacement that we’re seeing on our near — new Tier 4 fleet. So it’s — in addition to that, I guess one thing — before answering your question, in regards to reliability, we’ve been seeing higher efficiencies and uptime because of that fleet. So that is obviously great to see in our business, and we should expect to see that going both from a margin improvement standpoint. In regards to your question, the fleet that we have in the U.S. are very homogeneous. We have engines that are very — the same with the MTU engines. And they’re quite different than what the previous, call it, Tier 2 kits that you could add by the dual gas blending kits. And the difference is, is that there are direct injections. So they’re more ported into the cylinders of the engine.

So we have less slippage natural gas slippages 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, and we’re seeing up to a 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 on 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.

Waqar Syed

Great. And then just staying on the topic of T4 DGB fleets. Are you considering — or what’s the long-term plan, let’s say, for your fleet in Canada, in terms of converting to Tier 4 DGB?

Stephen Glanville

Yes. 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 the Tier 4 engines as our Tier 2 engines 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.

Waqar Syed

Yes. And then just last question on your contracting to the larger E&Ps in the U.S. delegated contracts, certainly improves the business visibility. Now these clients supported materials, does that type of contract continues going forward or is there any — is there any flexibility that you see that contracts may change? Are you going to stick with those terms?

Stephen Glanville

We’re really happy with how our sales and operations team have aligned ourselves with clients that have larger programs that provides obviously consistent utilization. We’ve looked at all the numbers. We’re really happy with returns on the numbers that we’ve received. And it provides some great stability, Waqar for our U.S. business.

We have three frack crews in the U.S., we’re not a very large player currently today. We were up to 4. We shut down one crew in Q1, as we mentioned in the past. But it provides us a great platform of growth. We’re only going — grow it makes sense to do that.

Like we mentioned, we’ll add coiled tubing capacity, if we see it. We’ll add frack capacity only if there’s a long-term contract in place in the U.S., and that’s what the team is focusing on. So 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.

Klaas Deemter

Just specifically around your question that goes around proppant. Is that what you’re asking, Waqar? Yes, so these…

Waqar Syed

That’s right. Yes, so. Go ahead.

Klaas Deemter

You’re seeing clients take on more of that proppant, just the availability of sand down there. Last year 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, lot of cases. Yes.

Waqar Syed

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

Stephen Glanville

Thanks, Waqar.

Operator

Your next question will come from Cole Pereira at Stifel. Go ahead.

Cole Pereira

Morning, all. 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 were you also lump Tier 4 dual gas blending into your future plans as well?

Stephen Glanville

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

Cole Pereira

Yes. Sorry. So obviously, — just to clarify, are you planning on continuing to upgrade to Tier 4 dual gas blending engine, or just the aftermarket by fuel kits?

Stephen Glanville

Yes. So in the U.S., we currently had 80,000 or 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. 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.

Klaas Deemter

DGB is a — I’m going to say a trademark and maybe 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 cash, we can’t call them DTV. So that’s why we’re going to talk more generally around dual fuel. So just U.S. versus Canada, NTU versus Cat distinction.

Cole Pereira

Okay. Got you. 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?

Klaas Deemter

Yes. 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 5 frack 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 50% already booked, maybe even higher for Q1 of next year.

Cole Pereira

Okay. Got it…

Stephen Glanville

My commentary earlier throughout Q2, if you take a look at what we did collectively as a group of pumpers in Q1 and the rest of the industry, there’s 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.

Cole Pereira

Okay. Perfect. That’s all for me, thanks. I’ll turn it back.

Stephen Glanville

Thanks, Cole.

Operator

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

Keith MacKey

Hi, thanks and good morning. Just wanted to start out on the fastest transition time you did in the Montney, that 1 minute 42 seconds. Can you maybe just run through the — some of the big factors that led to that? I’m sure there are some with people, process, technology, et cetera. Maybe just give us the flavor of that and maybe discuss how low you think that number can go?

Stephen Glanville

Yes, Keith, I mean, obviously, you’ve seen the transition into our industry go from — call it, 13 pumping hours per day. That’s as an average that we saw in 2020 time frame. So now we’re upwards of 18 and 19 pumping hours per day and even higher. And that — 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 remotely operate valves of the wellhead so you can — you don’t have anybody in the hot zone, and so you’re allowing basically to have 1 wellhead open, and your — when the frack stage is done, the other wellhead is open in an hour and 42 minutes — I’m sorry a minute in 42 seconds. So there’s technology — but as you can imagine, the logistics and just the overall setup of these locations, it’s more like a factory process now. I talked about the record of close to 5,200 tonnes being pumped in a 24-hour period. That’s a 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 keep 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 as we have the ability to control those costs and control the lead times to get profit. And we really saw, as 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’s lots of — call it, sand delays, people trying to find sand. And so us having a lot of control over our logistics just creates a differentiator in our space.

Keith MacKey

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

Stephen Glanville

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 optimal proppant placement, stage design, and so that has really transferred into the Montney, where we’re seeing more intensity, higher proppant loadings per stage, more stages on a horizontal length. I think in the U.S., what the — in particularly in the Permian is they have regional mines that are within, call it, 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 a totally different surface geography with rocks and not beaches. So that’s a lot different in Northern Alberta than it is in in West Texas, so. But I think in the U.S., what we’re seeing is more stability from an activity standpoint, a lot more rigs that are active as 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 Montney, 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 is being drilled up, and I have commented about this before is our — the decision to get into ultra-capacity or deep capacity coiled tubing, basically showed the value in Q2, where we were milling out these 3-mile laterals, so they drill them down 2 miles and they’re out 3 miles. So very, very long lateral lengths. We have the technology on the [indiscernible] side to be able to get to those lengths, and we believe that’s what we need to be positioned in the future.

Keith MacKey

Thanks very much. That’s it for me.

Operator

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

Josef Schachter

Good morning, Klaas and Steve, and congratulations on the quarter and the improvement to the balance sheet. First one for Klaus. In the presentation [Technical Difficulty].

Stephen Glanville

Sorry?

Josef Schachter

In the presentation…

Klaas Deemter

[Indiscernible]

Josef Schachter

Hello?

Klaas Deemter

Yes, we got you. Go ahead.

Josef Schachter

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

Klaas Deemter

That’s a very detailed question. I’m going to ask to — tell you what, Josef, give me a call after the conference call here, and we’ll go through that here.

Stephen Glanville

I think it’s probably more because in the U.S. that we are having more client-supplied sand is where my head goes to Josef, right off the bat.

Josef Schachter

Okay.

Stephen Glanville

So let Klaas get back to you on that.

Josef Schachter

Okay, thanks. And these for Steve. Steve, you mentioned, of course, that you’re doing more longer reach coiled tubing laterals that are with all the specialized deep equipment you’ve got and it went over a couple of examples of that. The coiled tubing side, of course, has got with less drilling and less completions, that slowed down. Is there any other color you can throw on the coiled tubing?

Why it’s such a $26 million a year ago, $47.5 million this year. Anything else specifically that you can add to the color why you had such a big increase in the revenues?

Stephen Glanville

Yes, scale really matters, Josef to us. We basically deployed three additional coil 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 these — the competing services that we have on the coil 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 coiled tubing.

And when you get to those depths, of course, the coiled tubing business, really differentiates itself because this time really matters, right? Getting these wells online is faster is really the big savings for the client, and we’re able to do these in — call it, 2 days that we’re building out wells, which is tremendous. And the technology from the bottom hole assembly, which is required to [mellow], these plugs has improved the ability to put weight on the end of coil out 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 measurement. So our team of professionals know exactly what’s on weight on bit, so we can increase our efficiencies that way.

Josef Schachter

And lastly — last one, 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 if it takes some time for all the supply to tighten up if some of your competitors bring in equipment from the states?

Stephen Glanville

I would say, currently, today, I mean, there’s been a decrease about 30 frack crews from the peak of Q1. And that’s great to see. So there’s some discipline in retiring assets before dropping price. And I think that’s the discipline that we expect going forward. There is — since the Patterson and next year announcement, currently, there’s 4 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 Josef in the next, call it, one year, 1.5 years 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 a dual you are going forward.

Josef Schachter

Okay. Super. Congratulations, and again thanks for taking my questions.

Stephen Glanville

Josef, just a quick question here. So you did — I caught up with where you were going there on that materials and inventory costs. So, yes, we were — we had a much higher proportion of client-supplied sand in the U.S. last year, and that will also drive high revenue numbers. So last year was quite — yes, 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.

Josef Schachter

Okay. Super. Thanks for info. Thanks, Klaas.

Klaas Deemter

You’re welcome.

Operator

Ladies and gentlemen, once again, [Operator Instructions]. Your next question will come from Bill Austin at Daniel Energy Partners. Please go ahead.

Bill Austin

Hey guys, how’s it going.

Stephen Glanville

Well, well, Bill. Good to hear from you.

Bill Austin

Yes. So one thing I wanted to touch on is like, as you guys consider 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 frack players in the U.S. ?

Stephen Glanville

Great question, Bill. And we’ve looked at a lot of opportunities, particularly the small privates to add. Really, we would like to double our fleet size in the U.S. to get up to 6 or 7. The challenge that we — we trade at such a low multiple right now.

And when you look at that, trying to the bid ask for some of these is at a large spread, and then when you dig a little bit deeper into some of these fleets that are currently active are older technology. So when you add perhaps the asking price plus the refurb cost, it makes more sense probably to build new. And so that’s 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 outward. Unless there are some fleets that are available today that have deal for capability. That’s our vision going forward from a growth perspective.

Bill Austin

That makes sense. And then one other slightly different subject, but the — you guys have talked a lot about long-term contracts, but 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 will reverse itself as 2024 picks up. So another way to think about it is the company is bidding for dedicated work in ’24, would that [indiscernible] might currently be better on the spot market?

Stephen Glanville

I’ll — 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, I think out of the 115 drilling rigs that are down from the peak, and probably close to 80 of them are small privates. So I don’t know, I think I’ll answer that by — if oil stays in around this $80 mark perhaps goes to 90 by the end of this year.

There’s some opportunity for 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.

Bill Austin

Yes. Okay yes, makes sense. Thanks.

Operator

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

Jim Byrne

Yes, good morning guys. Just one for me, on the balance sheet. Steve, you mentioned you obviously continue to pay down debt. Is there a point where our goal in mind — I guess, in the short term, and there’s a common point where you just slow down some of that debt repayment and then look for other capital allocation opportunities?

Stephen Glanville

I mean I — [our total] be less than $100 million of debt by the end of this year is curve — our forecast. And when we look at into 2024, our goal is to get our debt to a working capital number, so call it $60 million to $70 million of debt. And I’d consider that basically 0 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 lead to Tier 4, where we get higher margins in our business, redeploy some capital to or some idle assets, for example, like coil tubing.

And perhaps there’s some M&A opportunity in the future. But for us, right now, it’s continued 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 our laser being focused on repaying back debt and giving us in a great position.

Jim Byrne

Okay. That’s perfect. Thanks, guys

Stephen Glanville

Thanks, Jim.

Operator

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

Stephen Glanville

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

Operator

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.