Trican Well Service Ltd

TSX:TCW

Earnings Call Transcript 2021-Q3

[Operator]

Welcome to the Trican Well Service Third Quarter Results Conference Call. [Operator Instructions] The conference is being recorded. [Operator Instructions] I would now like to turn the meeting over to Brad Fedora, President and Chief Executive Officer. Please go ahead.

[Bradley P. D. Fedora, President, CEO & Non]

Thank you very much. Good morning, ladies and gentlemen. I would like to thank you for attending the Trican conference Call. With me today is Scott Matson, our CFO; and Todd Thue, our COO.I would like to please refer you to our website www.tricanwellservice.com, and on that website you will find a disclaimer that we'd like you to read in conjunction with this call.First, Scott Matson, our Chief Financial Officer will give an overview of the quarterly results, I will then address issues pertaining to current operating conditions and near-term outlook. We would then open the call for questions and the 3 of us will be available here to answer any question that anybody may have.I would now like to turn the call over to Scott.

[Scott Matson, Chief Financial Officer]

Thanks, Brad. So again, just before we begin, I'll point out 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 were implied in drawing conclusions or making a projection as reflected in the forward-looking information section of our Q3 2021 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. Some of these risks and uncertainties may be further amplified due to the ongoing effects of the COVID-19 pandemic. So please refer to our 2021 Annual Information form and the Business Risks section of our MD&A for the quarter ended September 30, 2021, for a more complete description of the business risks and uncertainties facing Trican.So during this call, we'll also refer to several common industry terms and use certain non-GAAP measures, which are more fully described in our quarterly MD&A. And as Brad noted, our quarterly results were released after market closed yesterday, and are also available on SEDAR and our website.So with that, we will talk a little bit about the quarter. Most of my comments will draw comparisons to the third quarter of last year. And I will also provide a bit of commentary with respect to our results on a sequential basis as compared to Q2 of 2021.So the quarter started off strong with positive momentum continuing out of a very solid Q2, with a generally positive Q3 with continued strong commodity prices driving improved activity levels across all of our service offerings. Revenue for the quarter was $164.5 million, a step change up sequentially from Q2 levels as we moved out of break up and into the back half of the year, and up more than double compared to the $74.1 million we saw in Q3 of last year.WTI averaged just over $70 per barrel during the quarter, up sequentially from an average of about $66 a barrel through Q2 and up significantly from an average of around $40 a barrel in Q3 of 2020. AECO gas pricing averaged about $3.39 per Mcf for the quarter, which was also up sequentially from Q2 levels and quite a bit stronger than the $2.14 per Mcf we saw this period last year.Continued strength in commodity prices resulted in an average western Canadian rig count of approximately 160 during the quarter, up compared both to Q2 of this year and to the same period of last year. The rig count through October has continued to climb a bit, and we do expect it to continue to pace higher as we move through the remainder of this year and into what looks like a very strong winter drilling season.These factors led to higher activity levels across most of our service lines compared to the same period of last year and as compared to Q1 of this year -- sorry, Q2 of this year.Continued stronger activity, ongoing improvements in the efficiency of our operations and continued focus on profitability, including the structural fixed cost improvements we've implemented over the last 12 to 18 months have led to significant improvements in all key financial categories as compared to Q3 of last year.Fracturing operations were up sequentially from Q2 of 2021 and significantly busier as compared to the same period of last year. Proppant pumped was up 84% as compared to Q2 of 2021 and nearly triple as compared to last year's Q3.We maintained 6 fracturing crews throughout the quarter, with utilization increasing to 85% for Q3 of 2021 compared to 42% in Q2 of 2021, as we came out of break up and into a period of much higher activity.Operations continue to be heavily focused on pad-based locations, which helps minimize both downtime and travel time between jobs and improves our overall efficiencies. Fracturing margins remained healthy through the quarter, and were a significant factor in the strong financial performance of the company for the third quarter.Our Cementing division also had a good third quarter, strong activity driven by the overall increase in rig count, with activity skewed towards larger jobs resulting from primary work in the Montney and Deep Basin areas. Coiled tubing activity was down a bit sequentially, but utilization was backstopped by a number of core customers.So as expected, with continued increasing activity levels, we are seeing inflationary pressures on all sides. Costs for our key inputs such as fuel, cement, chemical and sand, have all seen increases in the past few months, and the pressure is constant. Our supply chain group has done a great job in getting ahead of these and managing these trends, but they continue to come at us on a daily basis.Our focus remains on controlling costs and passing along these increases as much as possible to help preserve our margins. Adjusted EBITDA came in at $31.2 million, a significant improvement over Q3 of 2020 and just over double our EBITDA from Q2 of 2021. It's important to note that our adjusted EBITDA calculation does not add back cash level stock comp expense, which was $1.1 million for the quarter. This expense fluctuates, along with the movement in the company's share price, which saw an appreciation of just under 11% over the terms of the quarter. It also includes expenditures related to fluid and replacements, which totaled $2.3 million during the quarter and were expensed in the period.Also of note, this quarter contained virtually no contributions from the Canadian emergency wage and rent subsidy programs as compared to the prior 2 quarters, which saw significant contributions from those programs.On a consolidated basis, we generated profit from continuing operations of just over $9 million in the quarter or $0.04 a share. And we're very pleased to show positive earnings on a year-to-date basis. We generated cash flows from operations of about $8.8 million for the quarter, following strong operational performance, but did see an expected increase in working capital through the quarter as our activity levels increased.Capital expenditures amounted to $10.6 million, which was split between our capitalized maintenance and our ongoing capital projects.Company's full year 2021 capital budget remains at $58 million, with approximately $20 million of that allocated to maintenance and infrastructure capital requirements and $38 million allocated to growth capital. The growth capital amount is primarily related to our previously announced program to upgrade conventionally powered diesel pumpers with Cat Tier 4 Dynamic Gas Blending engines. These engines can displace up to 85% of the diesel fuel required with cleaner burning natural gas, thereby reducing carbon dioxide and particulate matter emissions. These upgrades are a key part of Trican's overall ESG strategy and are a prime way of supporting our customers and meeting their individual ESG goals as well.We exited the quarter with $37.6 million in cash and cash equivalents on hand, positive noncash working capital of $66.5 million and no drawn bank debt.Finally, with respect to our normal course issuer bid program, we were quite active in the market during the third quarter, repurchased and canceled just over 7 million shares at an average price of about $2.60, and we continue to view share repurchases as a good long-term investment opportunity for a portion of our capital in the context of returning capital to our shareholders.So with that, I'll turn things back over to Brad, who will walk us through his views on operating conditions and a bit of our strategic outlook.

[Bradley P. D. Fedora, President, CEO & Non]

Okay. Thanks, Scott. I'm going to make some general commentary, and I'll try to keep my comments as short as possible that give you a bit of a flavor of the marketplace that we're working in today.Q3 was a really strong quarter in the context of what's happening out there. We started very strong in July, and we were very active with a core group of customers. We run large pads that enabled us to work efficiently through most of the quarter. The quarter began with about 140 rigs running, and we averaged just under 160 rigs for the quarter, peaked at about 172 at the end of September, and we're currently back down to about 165 rigs, and we seem to be sort of maintaining that level now for the last month or so.And just in general, when you think about the rig count and frac demand, generally, what you want to do is deduct the heavy oil rigs from the rig count and then divide the remaining number by about 5. And so there's roughly 5 conventional rigs per frac crew. And so that gets us to about 26, 27 crews today, which is, in fact, what we have, so the market is generally quite balanced.We maintained really good market share in our Cementing group, roughly 35% to 40% of the market. And our cementing is very much focused in the Deep Basin in the Montney in both B.C. and Alberta.COVID did have an impact on the quarter. Even though it was a good quarter, we actually had expected it to be better. We had rigs down in the second half of the quarter. Starting in sort of late August and throughout September, there was definitely reduced activity levels just due to the sort of the COVID case spike that Alberta experienced that took rigs down. And of course, that means just less demand for frac crews.We did have our own COVID issues in the field that made some of our operations slightly less efficient, although we have -- we do have enough staff that we can respond very quickly to any issue that we may encounter and the delays in our operations are very extremely short lived. But even the delays to the office by the office in Calgary, we did think actually impacted the quarter.Throughout the quarter, we pumped about 480,000 tonnes of sand. 277,000 of those were internally sourced, meaning that the customer supplied the rest. In general, that's not really a negative, but certainly isn't a positive trend. We do typically charge corkage for customer-supplied sand, but we do want to keep an eye on that, and we want to make sure that we don't reduce our opportunities to make a profit. And so we generally try to gravitate towards customers that allow us to provide sand and chemicals. About 60% of the proppant that was pumped in Canada was Ottawa white versus the domestic sourced sand. And Ottawa white is almost invariably comes from the U.S.We continue to see increases in the tonne of sand pumped per well. As customers remain focused on these resource plays and placing more sand on a per meter basis to get as much gas flow as possible. And we get asked a lot, what inning are we in with respect to sand tonnage per well. And the answer is, we really don't know, but we do think we're sort of in the 7 to 8 or 9th inning of how much sand goes into a well. And what we're seeing now is there's still -- everybody is still gravitating towards the standard tried and true method. But there is a little bit of experimentation with respect to less or more sand on a per well basis or just even the spacing. So it's always very difficult to tell you what inning we're in with respect. But it's -- in general, it's a positive trend and generally means more revenue per well for us.Our areas of focus has not changed. We're very focused in the B.C. and Alberta Montney and the Deep Basin. We are active throughout the basin, but certainly, 80-plus percent of our revenues would come from the Deep Basin and the Montney play in general. And even though commodity prices or gas prices have really spiked, obviously, so has oil. So activity has picked up in all areas of the basin, but we remain focused with the Montney and the Deep Basin.From a crew perspective, nothing's changed. We ran with 6 frac crews throughout the quarter, about 17 cement crews and about 6 coil crews. And in fact, we still sit there today.On the pricing side, we've been really vocal about the need for price increases since early spring. I think it was year-end 2020 and after Q1 of 2021, I was quite vocal about the need for price increases. And generally, I would -- regrettably, I would say, achieving those price increases were much harder than we expected. We just did not get any support from our competitors. We're still, even to this day, seeing some stink bids that would absolutely shock you in the context of what's happening. E&P cash flows are at record highs. So our strategy hasn't changed with respect to moving prices up. We're just trying to run a sustainable business. And I think actually, the customers appreciate the need for a price increase more than our competitors do because they know we're not gouging them. We're just trying to run a sustainable business. But definitely, prices need to go higher.Fortunately, we didn't necessarily get the price increases we were looking for, but we did get them. So we did offset -- more than offset inflation, and the customers were very receptive to us passing on any inflationary cost increases that we were experiencing. Late in the quarter, we did talk about price increases again, and we have had price increases recently in all of our service lines, particularly fracturing and cement, as we're basically operating at full capacity as an industry.We expect inflationary costs to continue. That's certainly not going away, and we'll stay diligent on sort of informing our customers about those costs and making sure that we can recover those costs to avoid any kind of margin erosion.On the cost side, I'm happy to report that we've kept our G&A and our fixed costs constant, even reduced them in certain areas. So as the activity and the revenues have gone up, we're diligent about making sure we keep our costs down. We've implemented lots of initiatives throughout the company over the last few years, and we're continuously looking for new ways to manage our company more efficiently. And what this means is as, obviously, as costs stay constant, as revenues going up, that ratio gets better, and that's what operating leverage is. And that's the great thing about the pressure pumping business in an up cycle. It's fairly exciting, and there's a lot of operating leverage.Because we kept our costs constant in an increasing market, we did have good EBITDA and free cash flow in the quarter. And I really want to focus -- I want to try to focus the conversation around free cash flow, just given the age of the fleet, whether it's in Canada, the U.S. doesn't matter. But just given the age of the fleet, I mean the maintenance, whether it's expense or capitalized or it doesn't matter how you treat G&A, whether it's on the income statement or it's in the divisions. I want to make sure that we talk less about EBITDA and more about free cash flow because, of course, that's all that matters. And free cash flow sort of catches everything. And so I think we need to sort of get away from focusing on EBITDA and talk more about free cash flow just to account for all the differences on how people treat maintenance and G&A.Now on the supply chain and on the supply chain side, I mean, it's certainly an area of concern. It's been a major issue in managing our business throughout these higher activity levels. We've done a very -- our group, I'd like to thank our group continuously because they have done a fantastic job of managing our supply chain and making sure that we have product on a timely basis at good prices, but the entire supply chain industry-wide, whether it's parts, chemicals, sand, doesn't matter, it's all starting to feel stress. And as we know, they're better at passing on price increases than we are. So we're actively working with our suppliers to ensure that we not only have good prices, and we have long-term relationships with making sure we actually have the products when they're needed.We have -- as expected, we had inflation across the entire supply chain in the last sort of 6 months especially. Although I have to say the inflation was less than we expected, things like diesel, obviously, floats with oil price. But third-party trucking and logistics, the demand for those goods and services are much higher than the supply.On the sand side, Tier 1 sand suppliers out of the U.S. are basically operating at capacity because it's not just what the mine can produce, but it's -- how much of that sand can you put in a rail car. There's only so many railcars available, so many rail lines operating in Canada. And so that system feels fairly stressed and the increased sand volumes that we're pumping is putting a strain on our logistics and we've now sort of -- we'd have to focus on making sure that we have access to transload facilities, particularly in Northeast B.C. But again, our supply chain group has done a fantastic job at making sure that this has generally seamless through what has been a very sort of stressed inflationary environment.On the chemical side, we've all seen what's happened to shipping costs and container availability. A lot of the core chemicals that make up the fluids that we -- or the fluid systems that we sell, they do come from China and the U.S. And so we've anticipated the delays that we have actually been experiencing. And we're always looking for substitutions and working with our suppliers to make sure that we have the supply that we need at a reasonable price. And again, I think we've done a really good job of that.On the cement side, we experienced losses to many product issues, but the summer construction season is over now, so we should be good for the winter. And even things like hotel costs just due to COVID, with the labor cartages that we're experiencing in the hospitality sector, everything has been affected. And it's just all that happens is you have to make sure you're doing a much better job at managing that. And the companies that manage it well will be rewarded.So the outlook for the rest of the year and into 2022, I mean, we have fairly good visibility, I would say until break up. And our schedule is very busy until break up.E&P cash flows are at all-time highs almost. And there are wells that they're drilling are paying off in a matter of months, not a matter of years. And that's a good thing. We certainly need our customers to make money so that the industry can be healthy. And as a result, we've had a really good start to Q4. October is very busy. We should be busy right up until Christmas. December is always a bit of a -- it's unpredictable, just because you have winter weather, and it's hard to know when the season will shut down around Christmas. But the indications we're getting from customers is that we're going to start-up immediately after Christmas. And by the time Q1 starts, we should be running almost full blast. So we're looking forward to a good Q4 and a really good Q1.The basin in our -- certainly our service remains very focused on sort of gas plays. Both obviously, gas prices and condensate prices are extremely high. And so we're seeing lots of activity there. But even the oil plays at these levels are very attractive. And so the whole basin is busy, and it's really stressing the system, which generally is a good thing.The rate count has stayed steady. We think it will stay steady for the rest of the quarter, and it will obviously slow down for Christmas, but we expect that it's going to immediately pick up.Regardless of what you're hearing, we do expect that 2022 will be a busier year than 2021. I mean, how much, is very customer dependent. But certainly, our customers are signaling to offset, to expect easier busier activity levels. And that's a great thing, as I was saying, we're basically up. There's 27 frac crews in basin, and all of those are being used today. And so any increases in activity levels, which we're expecting, starting early in Q1, will require more frac crews on the road, and that's going to stress the system. That will drive prices higher no matter what.Our customers are obviously very, very focused on returning capital to shareholders. But certainly, at these commodity price levels, they are going to be busier for next year, and that's going to be good for both activity and for pricing.Because of all of that, we are expecting price increase in early Q1, both just to offset inflation and to return our business to some sort of reasonable sustainable level so that we're able to actually generate earnings and reinvest in our equipment. And as I've discussed before, the frac fleet in Canada is old. The most recent frac fleet delivered to Canada was the Spring of 2016. And so the equipment has been used hard. Pumping times are long. It wasn't that long ago when pumping times were sort of 14, 15 hours a day, and now they're almost expected to be 22, 23 hours a day. So the equipment has been used hard, which means it's going to need a lot of capital reinvestment to keep the equipment that's running today continuing to run. And if we want to pull equipment off the fence, it's going to take time and money to make that equipment useful in the field. So because of all of this, we are expecting a price increase in Q1. And certainly we'll be, at the very least, passing on any inflationary cost that we get.From a crew size perspective, like I say, we've kept our crews pretty constant, and we will keep them constant for the remaining of the year at 6 frac crews in particular. We're always monitoring this, but I'm going to use this opportunity to talk about the people issues that we're experiencing. The people will be the biggest bottleneck for crew activations for the next year, minimum. And it is different this time. You've never seen this kind of market where the number of people wanting to work in the oil patch and the demand for those people, they're completely separated.And certainly, we expect this to loosen up when some of these government programs are shut down and just the travel restrictions are loosened with respect to COVID. But there's -- literally every company in the oilfield services space is looking to add people. And at the same time, so are the Safeways and Walmarts and hotels and restaurants. So we really need the government to shut these subsidies down to get people back to work, because the oil patch pays very well. And so once we get people wanting to go back to work, we can start recruiting across the country, and we will attract people back to this industry, but it will be tough. And we expect that this is probably a permanent change in the way we do our business. Now we don't take for granted that we can just hire people when we need them. What we found, we've been actively trying to hire now since Q2, and it's been a lot harder than we expected. We've been fortunate we have hired. We're up over 130 people on a net basis, but we still have more to go.And as I'm going to talk about in a bit, in order to bring more equipment into the field, we do need more people and that is a challenge. And what that means is when you're planning sort of equipment reactivations, whether it's parts or people, that cycle of bringing equipment off the fence is certainly going to be longer this time than it has in the past. And it will be measured in terms of months, not weeks by no means.I do -- probably a good point for me to talk about the basin in general, when you talk about increasing activity levels. The market is sort of perfectly balanced from a supply and demand perspective today, and we expect that balance to get out of WACC here in 2022. There's about 1.8 million horsepower operating available in Canada. We're operating about 1.2 million. But I want to stress that out of the 600,000 extra horsepower or idle capacity that exists today, Trican owns about half of it. And so when we think about upside in the fracturing or the pressure pumping space, basically, half of that upside is going to come to our company from a -- just purely from an equipment perspective. So we're really excited about 2022 and 2023. We think we're extremely well positioned to capitalize on any incremental growth in activity in this basin.On the technology and ESG side, we're always looking at technology advances within our industry, particularly on the digitization of the data and the data collections that we can use to be more efficient in how we operate our assets. We'll be focused on this over the next few years, particularly in the AI space to reduce our maintenance costs.Maintenance is one of our biggest costs. Between capitalized and expense maintenance, it's quite substantial. So anything we can do in that space to reduce those costs or even just reduce the downtime is extremely helpful. So we'll be very focused on the digitization of the data in the next few years.We very recently released our inaugural 2020 sustainability report. That report can be found on our website. It's been very well received. It's a start and it's certainly not where we're ending up with. We just permanently -- we just hired a permanent ESG person to really herd the caps within our company and take on strategic initiatives in the ESG space. And in general, our industry has done a very good job of ESG over the years. But we need to use this sort of investor and public demand for more focus on the ESG as a platform to showcase all the things that we've done and to sort of publish or measure and publish what we've done and get those out into the public because we really have sold ourselves short as an industry in the ESG space over the next -- over the last 5 or 10 years. And so I think the sort of focus on ESG is a good thing, not just for us but for our industry. And we're really -- I think we're taking a lead on that, and we're allocating resources internally to make sure that we get this right and hopefully, it becomes a competitive advantage for us.We have a very -- obviously, very healthy balance sheet, no doubt. We have the cash balance. And so we have the flexibility to look at anything. And whether it's ESG technology, et cetera. We're in a very fortunate position to be able to look at anything. And if it makes sense from a returns perspective, we'll pull the trigger and make those investments. And our customers are very interested in new technologies. And in general, I would say they understand that some of that technology needs to come with price premium. So we've had great conversations with our customers over the last 6 to 9 months, and we'll continue to do so.We've done a great job on the environment side with reducing emissions, particularly with the new Tier 4 pumps, idle reduction technology and just even our fluid systems to reduce the amount of fresh water that we use. But we've also done a good job on the governance side, and the woman that we've hired, she's going to make sure that we up our game on the social side, so the S component of the ESG. And we're going to make that part of the company's culture going forward. And that helpfully will distinguish us in the marketplace.So just I'm going to make some comments. I'm not going to talk about the capital in detail. We're happy to take questions on that, but I'm going to talk about the Tier 4 engine upgrades that we've been doing. And so we will be activating the first Tier 4 fracturing fleet in Canada, and that will be coming this November.The pumps are now going into the field as we speak. We're extremely excited about this, and we're proud to be the first company to roll out a low-emissions fleet in Canada. We expect that this will be the standard in the next few years. We have had some delays in manufacturing, but nothing significant and an actual fully functioning spread with 100% DGB engine, we should have in the field operating by November. And of course, that fleet is going to term lien.And so we -- previously, we had said that, that will be our 7th frac crew. And actually, we have changed our mind on that. We are going to stay at 6 frac crews. And we just don't have the people to put the 7th frac crew on the road right now. And so this new Tier 4 gas engine, the frac pumps will displace the old Tier 2 diesel equipment that we've been using. And so we are expecting that we're going to get our staff in place to call this is 7th spread for sort of January 1. And certainly, you see it to be on schedule for that.And we haven't had any cost overruns. Initial reports from the field on the few pumps that are out there already have been really good. We've been getting great gas substitution, which, of course, is the idea behind this technology. We get up to 85% diesel displacement, which is a big cost savings for the customer. And just as importantly, it's helping reducing emissions from diesel and from methane. So we're very happy with how the equipment has performed to date.It is important to note that this equipment is priced at a premium. I want to make sure that our shareholders understand that, of course, we're not investing $20-plus million to upgrade equipment and not expecting a return on that investment. So the customers have been receptive to that. They understand that the cost savings that they're experiencing from a fuel perspective is a positive thing and the emission reduction is a positive thing and that we need to share in that as well. So we've had lots of great conversations, particularly with term lien on getting this equipment to work, but we are charging a premium price for this equipment.Manufacturing on the second Tier 4 DGB spread has already started, and it will continue to unfold over Q4 and Q1. And so we will have our second Tier 4 natural gas fleets available probably early Q2 of next year at the latest. And we expect, as I said, we expect this technology will become a standard in the next few years.On the M&A side, very quickly, we remain focused on getting our existing equipment that we own into the field. That's by far the most profitable thing that we can do. Our company is set up to operate a much larger fleet. So any time we bring the fleet off the fence and put it into the field, all of that field margin and that contribution margin goes straight to our bottom line. And so by far, that is our best investments. And when we're buying shares back at book or even sub-book or slightly above book, that obviously was a very attractive investment as well.So on the M&A side, we're always open for the right transactions, and we're always looking, but our focus is differentiating ourselves from an equipment perspective and getting our idle equipment to work. We're always looking -- we're always available to the right deal, but we're trying to do what makes the most financial sense for our investors.I think I'll stop the call there, and I'll hand the call over to the operator. So thanks for listening, and we'll take questions from here.

[Operator]

[Operator Instructions] Our first question comes from Andrew Bradford of Raymond James.

[Andrew Bradford, MD, Equity Analyst & Head of Energy Research]

Brad, that was really good update. A couple of questions here. I want to start maybe with the Tier 4 equipment. So as I understand what you just said that you changed your mind, you're not expanding this to a 7th crew, but that is what your plan is starting in January. So as it comes out in the field, it's simply displacing equipment that was already there. Is that what I'm understanding you to say?

[Bradley P. D. Fedora, President, CEO & Non]

Yes, correct. We didn't change our mind. We just underestimated the difficulty in getting people. And so we couldn't staff the 7th crew today.

[Andrew Bradford, MD, Equity Analyst & Head of Energy Research]

Right. And but you anticipate that you will be staffing the 7th crew in the first quarter. Is that what I understood?

[Bradley P. D. Fedora, President, CEO & Non]

Yes. We're at least sort of halfway there already. So it's good. It allows us to -- we haven't had any issues with COVID or holidays or the hunting season. We're able to operate sort of uninterrupted, because we do have some extra people. And so we're about halfway done on our 7th crew. So we're feeling confident that we should be good to go by Jan 1.

[Andrew Bradford, MD, Equity Analyst & Head of Energy Research]

Okay. And just on the labor issue. So as you described some COVID-related issues late in the third quarter, I guess, maybe even beginning early in the fourth. Maybe could you describe what kind of protocol you put into sort of mitigate this impact on yourselves going forward? And then like as you do that, maybe describe what kind of impact that's having on your labor shortage issue? Because even if we look just at the health care industry, you might expect that, that would be a fairly easy slam dunk in terms of implementing vaccination protocol, but still, we're hearing that people are being dismissed from their jobs and stuff. And I wonder if what you're seeing in the oil patch now?

[Bradley P. D. Fedora, President, CEO & Non]

Yes. Starting October 15, so roughly a month ago, we put in the new policy, just in response to things were somewhat getting out of hand from a COVID positive case perspective in Alberta. And we were seeing it impacting our field operations. Luckily, we are able to get through it, no problem. But I think we took the lead in the pressure pumping space, and about a month ago we said that effective on October 15, you either have to be fully vaccinated like 2 vaccinations. We don't care which ones they are. We have to be fully vaccinated or you have to provide a test before you show up for your shift if you work in the field on your own dime and you have to take your test on your own time. And if you work in the office, you have to provide a test result every Wednesday or something like that.But I mean, the point of this was, there's lots of testing happening on customer locations, but we were having the issue of people were showing up, getting on the crew van. And by the time they got to the customer location, we found out, well, some of them are testing positive. But now it's too late, they've been in the crew van with 20 people or so, right? And so we want to make sure that before you even show up to our base, you're COVID-free. And that will allow us to plan and deal with logistics way better.And we had lots of griping about it, but I can tell you, it didn't last long. And many, many people in the organization actually sent us notes saying, thanks, right? Like everybody has their issues, whether it's grandparent or children that they feel are exposed. They don't want to go to work and get COVID, right? And so they were happy to let or sort of lower the hammer on making sure that we do whatever we can to make sure that when you come to work, one of your safety concerns is not getting COVID from one of your coworkers. So we didn't have any problems with it at all. We have literally only lost 1 person that is refusing testing and refusing vaccines. We have 950 people. So we will be just fine.

[Andrew Bradford, MD, Equity Analyst & Head of Energy Research]

Okay. That's good to hear. And from your discussion, you said that your clients are -- your customers are telling you to expect more demand. You spoke a bit about reactivating spreads and that you have of the spreads that are available to be reactivated, half of them belong to you and that this will all require some costs. And I think it would be helpful if you could just sort of maybe describe that a bit more. You are going to have a 7th spread working in the first quarter. And it sounds like you're going to have an 8th, much larger spread, by the second quarter. Does that sort of fulfill the incremental demand that you're imagining or that your customers are talking about? Or do you think that there's going to be further reactivation beyond that?

[Bradley P. D. Fedora, President, CEO & Non]

Yes, the demand, like if you think about 200 drilling rigs, you take out the heavy oil rigs, and there's roughly 5 rigs per frac crew, like we need 35-ish crews. We're not going to get there as an industry. We have 26, 27 today. And as we're finding, we couldn't even add 1. We never experienced this in the past, right? Like, we're struggling to add 1. It's going to take 6 months to add a 7th crew to our fleet. So there's no way we're going to get there. And that's a good thing, maybe finally get this price up off the floor from COVID levels and have real businesses.So we're not at all concerned about the fact that we're adding 2 crews. Stress comes from making sure we can get the people to add 2 crews. We're fortunate that we can afford all the investments that are required. But as an industry, there is significant capital investment to reactivate equipment and significant efforts to get the people to run that equipment, and it's going to be very, very difficult to get to 35 crews for next year.

[Andrew Bradford, MD, Equity Analyst & Head of Energy Research]

Okay. I wonder if you could then maybe reconcile for me. This is my understanding as well. But I wonder if you could reconcile that with the idea that you are seeing your existing customers think that by competitors, which can only really happen, I think, if they have windows or they're trying to secure a new anchor customer, something to that effect. That must mean that they have available space. And I'm trying to reconcile the tightness of the industry with these windows that you -- that must exist across the…

[Bradley P. D. Fedora, President, CEO & Non]

We think about that all the time, because -- we were having a hard time making sense of exactly that. I think what it is, is maybe we just have more predictability or our customers are -- maybe we're lucky to have the customers that are giving us sort of long-term scheduling that we're -- we don't have a lot of angst over our schedule in January, February already. It's October and already we're sort of booked for Q1. Whereas if you're a company that doesn't have long-term customers or customers that don't give you -- if every month, you're fighting to fill your board, even though the board gets filled every time, there's still -- you're still anxious about that white space that's a few weeks out.And then it just drives that kind of pricing behavior to make sure that the board gets filled. If they just had a bit of faith, like do some basic math, and you may not see it today, but it will get filled, right? I mean, we don't have the capacity to take on a bunch of work that we don't already have booked, right? And so it's got to get done. And so I think what's happening is just the anxiousness over the lack of predictability a couple of months out is driving that pricing behavior. I mean, I don't -- that's the best I can do, because we obviously think about this all the time.

[Andrew Bradford, MD, Equity Analyst & Head of Energy Research]

Yes, okay. Last question here, I promise. So you have -- you're currently pushing the Tier 4s equipment into the patch. You'll have that -- you're set to form a 7th seventh crew in the first quarter. You'll have another crew, another ESG crew in the second quarter. So -- and you also said that this will become the industry standard. So how long do you think that you have this first-mover advantage where a Tier 4 crew is differentiated before it becomes -- before Tier 4 crew just becomes called a crew?

[Bradley P. D. Fedora, President, CEO & Non]

Andrew, you probably know this better than I do. A year, 18 months.

[Andrew Bradford, MD, Equity Analyst & Head of Energy Research]

18 months. Okay.

[Bradley P. D. Fedora, President, CEO & Non]

I don't like -- I don't obviously know what our competitor…

[Andrew Bradford, MD, Equity Analyst & Head of Energy Research]

Let me ask it slightly differently. If you decided that a third crew was a really good idea, when would you anticipate being able to put that third crew into the field?

[Bradley P. D. Fedora, President, CEO & Non]

It would be late next year if you have the foresight to plan it with the engine manufacturer.

[Andrew Bradford, MD, Equity Analyst & Head of Energy Research]

Okay. So if you order today, it would be the end of -- a year from now. Is that correct?

[Bradley P. D. Fedora, President, CEO & Non]

Yes, at least.

[Operator]

Our next question comes from Waqar Syed of ATB Capital Markets.

[Waqar Mustafa Syed]

Brad, with rising service intensity, what are you seeing on the maintenance CapEx per crew or per horsepower? Any numbers that you can share with us?

[Bradley P. D. Fedora, President, CEO & Non]

Yes. I mean it's generally going up. Todd knows this stuff better than I do. So I'll maybe hand it over to him.

[Todd G. Thue, Chief Operating Officer]

It's just -- so the run rate or percentage of expense has not increased substantially. It's kind of -- it floats with the activity of the equipment and the hours that it's run. So it's inching up slowly, but not -- it's not taken a giant step up.

[Waqar Mustafa Syed]

Would it be somewhere in the $2.5 million, $3 million per crew on an annual basis?

[Bradley P. D. Fedora, President, CEO & Non]

What was that?

[Todd G. Thue, Chief Operating Officer]

We didn't quite catch that.

[Waqar Mustafa Syed]

Yes. Would the maintenance CapEx per crew be around $2.5 million to $3 million annual?

[Bradley P. D. Fedora, President, CEO & Non]

Higher.

[Scott Matson, Chief Financial Officer]

Higher than that.

[Todd G. Thue, Chief Operating Officer]

Probably a little higher than that, Waqar.

[Waqar Mustafa Syed]

Okay. And I was excluding fluid ends that you guys expense. So it's more in the $3 million to $5 million range?

[Todd G. Thue, Chief Operating Officer]

Yes, I think that's probably.

[Bradley P. D. Fedora, President, CEO & Non]

Yes. And just a lot of it is obviously dependent on the pressures that you're working on in the certain -- whatever the customer base that you have, right? So if you're doing low-pressure oil, it might be lower than that. But if you're banging away in the Montney, it's 70 MPA or something like that, and it's going to be $5 million. And it also depends, is that -- was that pump build in 2009 or was it built in 2015. So it's -- that's why we're kind of flaking our answer because there's so many variables that go into. But it's -- if you had to model it as an industry average, I mean, I think you're safe using $5 million a crew per year.

[Waqar Mustafa Syed]

Okay. And then in the U.S., Zipper fracs are becoming fairly common now, and we're also seeing a lot of Simul frac. Are you seeing those trends develop in Canada as well?

[Bradley P. D. Fedora, President, CEO & Non]

It's not new. I wouldn't say it's common, but if my understanding of what you're saying with the Zipper frac or you're fracturing to a opposing wellbores, that's been happening for quite some time now.

[Waqar Mustafa Syed]

Yes. So Zipper crew would be, I think, here in the U.S. to say that it's -- you fracture 1 and you're plugging and perforating next one, while Simul frac today is like you're fracturing both wells the same time and then the 2 other wells that you are plugging and perforating at the same time. So everything is running.

[Bradley P. D. Fedora, President, CEO & Non]

Yes. That's common. You're plumbed-in, for lack of a better word, to the pad as a whole. And so your operations are uninterrupted almost.

[Waqar Mustafa Syed]

And so you're seeing that in Canada?

[Bradley P. D. Fedora, President, CEO & Non]

That would be the norm in the Montney.

[Operator]

Our next question comes from Cole Pereira of Stifel.

[Cole J. Pereira, Associate]

So you're very active with the buyback in the quarter. And obviously, you need to continue investing in the fleet. But how do you think about the return of capital avenues such as dividend?

[Scott Matson, Chief Financial Officer]

Yes. We're looking at that. We do have a growing cash balance and we're happy to hold cash, don't get me wrong. But there's only so much cash that should be held. We're not going to discuss maybe the exact levels at this point, but we do feel we may exceed those sort of internally imposed thresholds by the end of next year. And so certainly, dividend conversations have started to enter into Board discussions, but there's not really anything more to report at this time. There's many things to consider when you talk about dividends, but we're bullish for this industry for the next few years for sure.

[Cole J. Pereira, Associate]

Okay. Perfect. That's helpful. And just wanted to confirm as well. So for Q1, you do expect to generate true, call it, net pricing. And how confident are you that this doesn't get eroded by further cost inflation somehow?

[Bradley P. D. Fedora, President, CEO & Non]

It'll get eroded. It's just a matter of how much. But we do think back to the supply and demand of the rig count versus the frac crew count, that's going to get out of WACC in Q1. And so even the people -- the companies that have no vision beyond the end of the week, even they'll respond with pricing increases. And so we'll finally get these prices lifted off the COVID floor and back to something more reasonable.When you look at the pricing today versus even 2, 3 years ago, it's -- the amount of erosion that's taken place is incredible. It's absolutely incredible. And yet at the same time, the pumping efficiencies are greatly increased. And so we just have to stop. We need to start running the business properly here as an industry, and I think that will happen in Q1.

[Operator]

Our next question comes from Keith MacKey of RBC.

[Keith MacKey, Analyst]

Just wanted to maybe follow-up on the comment you made about sand logistics being tight, Brad. Is there any more -- any more you can say about that? Like do you expect sand availability, whether it's from transportation or actual production to impact operations over the next, call it, couple of quarters? Or is it just a matter of managing the tighter logistics, but things should be okay?

[Todd G. Thue, Chief Operating Officer]

The sand supply, as Brad mentioned, the sand supply from -- out of Wisconsin in the U.S. is approaching maximum levels of what they can produce or ship to Canada. It's probably the planning and the logistics part of it and the transloading is the important piece to take out the high demand cycles or try to plan with your customers about reducing the high demand cycles. But there's a higher concentration of activity into Northeast B.C. So there is some limitations to transload. And then just -- there's only 1 rail line going in there as well. So probably near term, no shortage worries, but longer term, definitely needs to be some changes or increase to supply logistics and transportation.

[Keith MacKey, Analyst]

Got it. Okay. So is that just on the U.S. sand? Or could it be substituted with local sand as needed?

[Todd G. Thue, Chief Operating Officer]

It certainly could be. Sometimes that's a customer preference about which sand type they would want to use in their treatment. So there is adequate Tier 2 stand supply in Western Canada to fill their void if there was one. Just transportation, again, because the location of that has to come from Central Alberta, mainly up into Northeast B.C. There, again, that requires transportation, whether that's rail or trucking.

[Keith MacKey, Analyst]

Got it. Okay. And one more for me, just to go back to pricing, don't want to harp on it too hard. But one of your peers hosted the call this morning and discussed double-digit pricing increases for next year, call it, North America wide, sounded like maybe Canada didn't dip as hard in the last couple of years as the U.S. So may not increase quite as much through the next year. But given the shortage that you foresee in Q1, which might perpetuate through the rest of the year, would you have a similar view of pricing, where things will end up throughout next year beyond -- maybe just beyond the supply/demand imbalance you might see in Q1? Or are you now more pessimistic or optimistic about that level of pricing improvement?

[Bradley P. D. Fedora, President, CEO & Non]

Well, I hope he actually opens up the books to its Canadian operation and has a look at his pricing. He certainly needs double-digit pricing increases to even compete with the rest of us. So yes, but as an industry, I would think double-digit price increases are likely by whether it's Q1 or Q3, it's likely. They're just -- and this is not even a customer resistance issue. Like this is a frac company issue. I think the price erosion that's occurred, it's incredible, right? It's 40% in the last couple of years. So if we can all just relax and do some supply and demand work and get more comfortable with where we're going to be, I think that those kind of price increases would be totally reasonable.

[Operator]

[Operator Instructions] Our next question comes from Josef Schachter of Schachter Energy Research.

[Josef I. Schachter, Author & President]

Brad and Scott, congratulations on the much improved quarter. I have 3 questions. First one, going back to the dividend, which is something you're contemplating with the Board in 2022. We saw how you ought to do a special dividend, because I didn't want to handle a commitment on a regular basis. Are you looking at special dividends if you want to keep your cash balance? Or is there any concern about prospects going forward in the industry if competitors don't give the pricing you need to justify spending more?

[Bradley P. D. Fedora, President, CEO & Non]

Yes. Like dividend discussions are philosophical in nature, and we understand the issues with service companies paying dividends, and we don't want to put something in and then have to take it out in a couple of years, and that's usually what happens. So when we think about dividends, we think about really low base dividends or special dividends or maybe no dividends, right? I mean, maybe we up our NCIB activity, and we -- our return of capital comes in that form. It's early, early days, and we're open to anything, and we're not going to back ourselves into a corner by any means and get ourselves into a position where we have regressed over what we did. And dividend or dividends to me, whether they're regular or special, it's -- I'm certainly a fan of the special dividends just to maintain flexibility. But like I said, maybe we allocate the money via the NCIB instead or maybe we find a great deal to do next year, and we don't do any kind of dividends or NCIB, like it's -- we're evaluating all our options, and we'll do a thorough analysis and be very thoughtful about what we're going to do. And I can assure you that whatever we decide to do, we won't have regrets over and we'll do whatever is best for returns and what's best for the shareholders.

[Josef I. Schachter, Author & President]

Okay. Second question, the 8th crew, frac crew, Tier 4, that you bring you on in the spring of 2022, you've announced the term lien with a customer for the first fleet. Is there 1 customer for that second fleet? Or is it 2 or 3 companies that have done in consortium to tie it up between them?

[Bradley P. D. Fedora, President, CEO & Non]

We're still -- we don't like to talk about the customers unless we sort of have specific permission from them to discuss it. So I don't really want to talk more about that. But the equipment would be for our core customer base.

[Josef I. Schachter, Author & President]

And just like term lien, thought it was something to inform the Street about because of the ESG improvement. Do you think at some point, these customers would be wanting to also disclose and you're just waiting for them to do that?

[Bradley P. D. Fedora, President, CEO & Non]

I don't want to speak for them.

[Josef I. Schachter, Author & President]

Okay. Last one for me is growth. You mentioned that there might be something that could be an acquisition. On Slide 3 of your new presentation, you go through the 4 quadrants: drilling cycle, completion cycle, production cycle, full cycle, technical expertise. Are you looking at acquisitions to add on top of your 3 basic businesses right now? Or are you looking to grow the 3 basic businesses?

[Bradley P. D. Fedora, President, CEO & Non]

Yes, we're open to any of that. Like it's -- you sort of look at the board of acquisition opportunities, and it's all of the above, right? There's things you'd like to do within each division, and there's new divisions to add. So we're not -- like there's so many things that go into the evaluation. But first and foremost, it's return on that investment. So we're open to any of them.

[Josef I. Schachter, Author & President]

And if you're looking at acquisitions, would it be also to grab manpower? Would that be something where if the equipment was decent, and you're able to get the man power, given the manpower shortage and the question about adding a third Tier 4 unit, would that be something that would fit in the equation?

[Bradley P. D. Fedora, President, CEO & Non]

Yes, absolutely. Absolutely. I mean, it's -- consolidation for cost efficiencies used to be the sort of the main motivator. And now it's not only cost efficiencies from the consolidation, getting crews is a material issue now. And as long as the equipment is modeled and tiered, it's something for sure we look at, yes.

[Operator]

Our next question comes from Aaron MacNeil of TD Securities.

[Aaron MacNeil, Equity Research Analyst]

It's going a little late today. Brad, just more of a high-level question for you. In the past, you were one of the early adopters of variable salaries and other sort of small things that make big differences to kind of the resiliency of the business. I guess I'm wondering at a very high level and with consolidation among your customers, is there anything you can do in terms of contract structures or things that have improved the stability of pricing through the cycles?

[Bradley P. D. Fedora, President, CEO & Non]

I wish. Our best opportunity is things like the Tier 4 engine technology, where you're truly adding a valued service that nobody else can add. And the customers understand that it's not commonplace at this stage and they understand the value of the service that you're providing. And so given that they know what we know, which is this industry has had no investment and it's been written hard and put away wet now for 7 years. And so when something good comes along, you better grab it and you better hold onto it. Because as we all know, it's -- the LNG prices around the world are looking pretty attractive. When if you actually cared about the environment, you'd encourage as much Canadian natural gas activity as possible.So we're really bullish on this industry in Canada for the long term. And I think our customers, they understand that we're at an odd point, right, which is all old equipment at the beginning of what is going to be very, very increased demand. And so we're using new technologies as a way of changing that contract structure and for the most part, it hasn't been easy. We'll have it die hard as we all know, right? So maybe having to move up the chain a little bit to get people to understand the value in long -- securing equipment long term.So the short answer is on a general scale, no, but on certain assets, yes, we're trying to do our best to get away from this sort of you're only as good as your last well kind of mentality.

[Operator]

This concludes the question-and-answer session. I would like to turn the conference back over to Mr. Fedora for any closing remarks.

[Bradley P. D. Fedora, President, CEO & Non]

Okay. Thanks, everyone. We appreciate your time, and we appreciate you dialed-in to listen to us. We'll wrap the call up now. But certainly, Todd, Scott and I are available for questions throughout today and tomorrow. I think everyone knows how to get ahold of us, and we'll do our best to make ourselves available. Thanks again.

[Operator]

This concludes today's conference call. You may disconnect your lines. Thank you for participating, and have a pleasant day.