Thank you. Good morning, everyone.

I’d like to thank you for attending the Trican conference call. With me today is Scott Matson, our CFO; Todd Thue, our Chief Operating Officer; Chika Onwuekwe, our VP Legal; and Daniel Lopushinsky, our VP, Planning and Analysis.

A brief outline of how we conduct -- on how we plan on conducting the calls: first, Scott will give an overview of the quarterly results. I will then address issues pertaining to the current operating conditions and near-term outlook, and then we’ll take questions at the end.

I’d now like to turn over the call to Scott to start things off.

All right. Thanks, Brad, and Good morning, everyone.

And before we begin, I’d just 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 2021 annual MD&A.

A number of business risks and uncertainties could cause actual results to differ materially from these forward-looking statements and our financial outlook. Please refer to our 2021 Annual Information Form and the Business Risks section of our MD&A for the year ended December 31, 2021 for a more complete description of business risks and uncertainties facing Trican.

These documents are available both on our website and on SEDAR. So, during the course of this call, we will refer to several common industry terms.

We’ll use certain non-GAAP measures, and those are more fully described in our annual MD&A as well. And our quarterly and annual results were released after close of market last night.

And again, both are available on SEDAR and on our website. So, with that, I’ll give a very brief overview of our results for the quarter.

Most of my comments will draw comparisons to the fourth quarter of last year, but I’ll also make some commentary with respect to our results on a sequential basis. The quarter started off reasonably strong, positive momentum continuing out of Q3.

Revenue for the quarter was $156.4 million, which is 52% higher than what we experienced in Q4 of 2020. Activity levels across the board were generally higher year-over-year, following improved commodity pricing and significantly stronger general industry environment compared to this time last year.

WTI was just over $71 a barrel during the quarter, up slightly from an average of $70.50 per barrel during Q3 and up significantly from an average of about $42.70 a barrel last year at this time. AECO gas was about $4.50 an Mcf for the quarter, which was also up sequentially from Q3, and again, quite a bit stronger than the $2.52 per Mcf we saw in Q4 of last year.

So, strong commodity prices resulted in an average Western Canadian rig count climbing and averaging approximately 176 rigs during the quarter, moving up slightly from Q3 of 2021 on an average basis, and again, quite a bit stronger than what we saw in Q4 of 2020. So those factors led to strong activity levels and, combined with continued improvement in the efficiency of our operations and sharp focus on profitability, significant improvements in all key financial categories as compared to Q4 of last year.

Fracturing operations were down a bit sequentially from Q3 2021, but were significantly busier as compared with the same period of last year. Activity in the fourth quarter, slightly lower than the third quarter, as our customers exhausted some other capital budgets.

And we saw the usual Christmas slowdown in the second half of December. We maintained 6 fracturing crews throughout the period, with utilization remaining steady at around 86%.

Operations continue to be heavily focused on pad-based locations, which helps to minimize both downtime and travel time between our jobs and helps improve our overall efficiencies. Fracturing margins remained reasonably healthy through the quarter and were a significant factor in the strong financial performance as we moved through Q4.

Our Cementing division remained busy during the quarter, activity a bit more skewed towards smaller, surface-level work versus primary cementing work, and our coiled tubing activity was up a bit sequentially, driven by first-call work for a number of our key and core customers. Inflationary pressures continue to be a major issue across the board.

Costs for our key inputs like fuel, cement, chemical, and sand have all seen multiple increases in the past few months, and the pressure doesn’t show any signs of abating at this time. Our supply chain team remains -- continues to do a great job in staying ahead of and managing these trends, and our focus remains on controlling costs and passing along increases, as much as possible, to help preserve our margins.

So, with that, adjusted EBITDA came in at $28 million for the quarter, a significant improvement over the $16.1 million we saw in Q4 of 2020. Again, important to note that our adjusted EBITDA calculation does not add back cash settled stock-based comp amounts, which were actually a gain of $0.5 million in the quarter.

That item typically fluctuates along with movement in the company’s share price, which dipped slightly at year-end compared to the close of Q3. It also includes expenditures related to fluid end replacements, which totaled $1.3 million in the quarter, which were expensed during the period.

The quarter also included approximately $1.1 million from the Canadian Emergency Wage and Rent subsidy programs, which we expect to be the final contributions that we’ll see from these programs. On a consolidated basis, we generated positive earnings of $9.7 million in the quarter, or roughly $0.04 per share, and we’re very pleased to show positive earnings on a year-to-date basis as we move forward.

We generated cash flows from operations of $20.5 million for the quarter, following strong operational performance, offset somewhat by a bit of an increase in our working capital as we moved through the end of the year. Capital expenditures for the quarter were $26.2 million, split between our own capitalized maintenance programs and our ongoing capital refurbishment program.

This is our previously announced program to upgrade a portion of our conventionally powered diesel pumpers with Cat Tier 4 Dynamic Gas Blending engines. That brought our full-year capital spend in at about $54 million, with approximately $22 million in maintenance and refurbishment capital and $31 million related to our Tier 4 fleet upgrades.

Of that $31 million spent in 2021, about $20 million of it related to our first Tier 4 fleet, which was completed and in service at the end of the year, and $11 million of that related to our second Tier 4 fleet upgrade, which is expected to be completed and in service mid-2022. The remainder of that $17 million related to that second spread is expected to flow through in the first half of 2022.

So, with that, we exited the quarter with about $30 million in cash and cash equivalents, positive working capital of $74.2 million, and no drawn bank debt. With respect to our normal course issuer bid program, we remained active in the market during the fourth quarter and repurchased and canceled approximately 2.2 million shares at an average price of about $3 per share.

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, and he’ll provide some more comments on our operating conditions and our outlook for next year.

Okay. Thanks, Scott.

I’m going to provide more general comments than Scott, and what you’re going to find in my comments over the next few minutes is, there’s going to be sort of a mix of good and bad. But overall, our long-term perspective on this industry, and certainly in the next couple of years, is overwhelmingly positive.

We’re very excited about what is coming our way in the second half of 2022 and in 2023. So I’ll just start by making some general comments.

As Scott was saying, Q4 was characterized as front-end loaded with a busy October, November, and then we had a pretty significant slowdown in December. And even though we were generally active with our core group of customers, as we’re fortunate to have long, long-term, active customer base, the quarter overall was a little choppy.

And what we hadn’t planned for in Q4 was that, as things slowed down in December, we saw, again, this complete reversal of pricing, and we just refused to go there. And so, we had a lot of white space on our board in Q4, and we’re totally comfortable with that.

There is no way we were going to reverse the pricing gains that we had made throughout the year in some desperate attempt to fill in a few days here and there. That makes absolutely no sense.

We maintained a good market share in all of our divisions, and we continue to grow our market share in coil, which is really encouraging. On the cement side, we maintain our sort of 35% to 40% market share, and our areas of focus are the Montney and the Deep Basin.

And so, until the rig -- it’s tough to really grow our market share beyond that. But as the rig count grows, so will our cement crews.

And so, we’ll just stay focused on providing good service, and we’re known as the technical leader in that space, and so that will just be a continued growth area for us as well. And so, we expect all 3 of our divisions to grow as the industry heats up.

And we’re not going to say we’re going to capture incremental market share, because we’re only prepared to take on market share that’s profitable. So we’re not overly concerned with market share.

We’re mostly just concerned with rigs or returns. COVID did impact us and continues to impact us, but it’s not overly significant.

It’s more what it does to the industry broadly. Rigs get shut down; we lose the odd cement crew or coil crew or frac crew here and there.

Our customers are not in the office like they should be. And so, it just generally interrupts the business in the oil patch.

And so, they’re not significant, but they’re sort of more annoying and nagging interruptions in our day-to-day operations. We continue to see fracs develop.

The number of stages per well continues to grow. The amount of sand continues to grow.

So, generally, the long-term trends for this industry are all positive. We’re very focused on the BC Montney and Deep Basin.

We are starting to see our operations expand in some of the lighter oil plays, which we were historically active in but had sort of pulled back from -- our cementing especially is more active now in Southeast Saskatchewan. And we expect activity to improve in all areas.

We’ve got $4 gas, really high oil prices. I’m not even sure what to call them now, but they’re over $90 anyway.

We’ve got condensate pricing at over CAD 115. Our customers’ wells are paying out in a matter of months, so that’s really encouraging.

And of course, what’s most important for our industry is that our customers are making money, and that allows us to expand and return to profitability. The number of crews we’re running really hasn’t changed.

In Q4, we ran 6 frac crews, 17 cement crews, and 6 coil crews, and that’s inched up a little bit. We sort of have 6/7 frac crews today, and we’ve added a few more coil units as CBM becomes more active again, and cementing kind of fluctuates day-to-day.

But we’re generally going to stay fairly resistant to adding crews unless we get significant pricing improvements. We’ve done a lot of work in the company for the last few years on getting costs down, and so fortunately, we are starting to see operating leverage really kick in as revenues expand, and that will continue to just get better as our revenue expands in the second half of this year and next year.

We had decent EBITDA and cash flow in Q4. And sure, we -- it could have been better if we had been prepared to cut prices to fill in white space on our dispatch board.

But again, we don’t think long term, that’s the answer. And we’re in a fortunate position where we don’t have any debt.

We have no balance sheet issues, and so we’re not in a position where we have to take on work, and so we didn’t. We had great free cash flow in 2021, and we expect it’s going to get even better this year.

Overall, I’ll now talk about pricing, as it’s probably why everybody’s dialed in. Overall, the pricing environment has been a little frustrating in the last 3 quarters of 2021 and even in Q1 of 2022.

We’ve been very vocal about the need for price increases throughout 2021, going back almost a year now, and we’re not wavering on that. In fact, given that inflation really hit us hard in Q4, we’re waiting, waiting, waiting for it throughout the year, and we almost got complacent, because it really didn’t show up in any -- with any significance until the fourth quarter.

It’s even more urgent now that we get pricing because we did get -- we actually did get reasonable price increases throughout 2021, and our customers were very receptive to giving us price increases as our costs increase. And most of our customers were more than willing to work with us, but inflation ate it all, and so we really did not gain any net price increases at all.

We still -- even as recently as January, we’re still getting stink bids from some of the competitors in the space, which is odd. But fortunately, that’s really subsided, and we really haven’t seen any crazy pricing behavior now for probably almost a month.

So we’re just going to continue to work with our customers, inform them as our costs increase. They’re very inquisitive as to our management of the supply chain, which is helpful, because we’re able to communicate with them on a more day-to-day basis as to how our costs are increasing.

And so, they’ve been -- they’ve actually been quite receptive to working with us on getting our prices up. Second half, I think we’ll see significant price increases in the second half of the year.

And part of the issue we didn’t -- we’ve had price increases in Q1. They haven’t been as high as I would have thought, and it was kind of an odd quarter in that there was lots of drilling activity in the first 6 weeks of the quarter, but not the corresponding completions activities that we would have expected given the rig count -- for our customers at least, anyway.

And so, everything has been -- lots of drilling in the first half of the quarter, and a lot of the completions activity has been pushed into the second half. And so, there’s -- we’re now going into March, which there’s no way we can get all the work done, and a lot of that work will get pushed into Q2, which will make for a good Q2.

But it really alleviated the pricing pressure in the first half of the quarter, and so what we’re seeing is, pricing is probably going to remain stable now until June, and then we’ll see significant price increases as breakup ends. And so, I think Q3 will be the first quarter where we’ll actually see margin expansion.

And Q3 historically -- I shouldn’t say historically. Historically, Q1 is the busiest quarter of the year.

I think in the last few years, it’s proven that Q3 is our busiest quarter. And so, as Q3 and Q4 budgets, I think, get expanded, we will see -- we will finally capture some of the pricing increases that we’ve been waiting for.

So, on the supply chain side, this is a never-ending grind. We are very fortunate that our group has done a really good job of this.

And whether it’s sand, logistics, chemicals, any input that’s required on the cementing, coil, or fracturing side needs to be actively managed, and our group is actively working with our suppliers to ensure that we have the products needed, especially in a rising market here in 2022 and 2023. And again, as we expected, we experienced lots of inflation throughout our entire supply chain.

And in fact, the price increases were less than we had expected for the first 9 months of 2021, and then actually were more than we expected in the last quarter of the year. And it’s -- there are no exceptions.

Diesel, which is linked to oil price, third-party trucking, which obviously relies heavily on diesel and labor, those rates have gone up significantly. Sand, by the time it gets delivered to Northwest Alberta, Northeast BC, 70% of the cost of sand is logistics and transportation, so of course, diesel costs, labor costs impact that significantly.

On the chemical side, many of the components that go into our chemical products come from China and the U.S., and we need to expect delays and increased costs. But we’re always looking for substitutions, and our suppliers are creative and proactive in making sure we get supply.

But we have to expect that there’s going to be cost pressures there. And even things like hotels, with reduced staff count or reduced staff available, the hotel costs and efficiencies of the costs have gone up.

And in many cases, the service availability has gone down because they just can’t get the staff. So, overall, we expect costs to go up in our industry, just like in all parts of the economy.

And I think Western Canada is also additionally stressed by the fact that we have a fairly finite labor force, and so we’re going to expect sort of cost increases and the supply chain limitations for the next 18 months. So, outlook for the remainder of the year, I think everybody obviously knows E&P cash flows are at all-time highs, and wells are paying off in extremely short periods of time.

That’s great news, right? We had a good 2021, and we expect that we’re going to have a good 2022 and a good 2023.

We are going to continue to have sort of COVID interruptions, but nothing too significant. We always have weather events in the winter, and certainly so far in Q1, there’s no exceptions.

But you have to plan for those, as they happen every year. The basin remains very natural gas-focused, and natural gas prices in the strip is strong.

And so, we expect, again, that the rig count will increase as the year unfolds. We’re currently at about 230 rigs, and we expect that to go up in Q3.

And based on conversations with our clients and equity analysts, we’re all -- they’re all telling us that budgets are going to slowly creep up as we go. And as strong commodity prices invariably will eventually lead to increased activity and better -- and will drive or should drive better margins and earnings growth for Trican.

And we do know that debt repayment and return to shareholders are a focus for our customers. But balance sheets have been largely repaired, especially with our customer base over the last 18 months, and so we do expect that our clients will start to shift some of this, this free cash flow into the projects that have really good economics and quick paybacks.

Some of our clients and some of the people working in the drilling completion groups have never seen returns this good in their -- at any time in their career. When we talk to the drilling rig contractors, they’re backing all this up with their expectations that Q3 will be busier than Q1 on the rig count.

There’s currently about 29 frac crews operating in Canada today, and we estimate that we’re going to need at least 35 in Q3. And so -- or starting in March actually and in Q3.

So, again, it’s just math at the end of the day, and so we will finally get the net price increases we’ve been waiting for. And because we’re not going to get all of Q1’s work done just because it was so back-end loaded, it looks like we’re going to have a really good Q2 again this year.

Last year was our best Q2 ever, and I expect this year will be similar. On the crew size, we get asked a lot, are we going to continue to activate additional crews.

And as Scott was saying, we are adding our second Tier 4 spread, and whether that’s an incremental crew ad or placement crew add, we don’t know yet, and we’ll see what happens this summer. But generally, we’re not going to activate more equipment unless there’s a return there.

And would we activated at today’s pricing? Probably not.

Given the difficulty of getting additional labor and the amount of inflation that we’ve experienced, I’m not sure pricing today would justify an additional crew add. But we will monitor that on a week-to-week basis, and based on the conversations with our customers, we’ll make those decisions.

The good news on that is, because labor is so tight, we will continue to see labor availability as a very significant bottleneck in crew additions, whether it’s in the fracturing industry or the drilling industry. And so, I think the industry overall will be sort of operating at its max capacity from a people perspective.

And whether there is discipline or not, it probably won’t matter, because people just won’t be able to add equipment like they used to. It just takes so much time now to get additional people.

And I think we’ve communicated this many times before, but we did add Crew 7 in our fracturing division. It took over 6 months to get the people to add that crew, and so we don’t expect that’s going to change going forward.

And we do expect labor constraints to be alleviated a little bit as sort of COVID runs its course and people feel comfortable flying from the east to the west, and they’re confident that they’re going to make it home for days off. And so, once that -- once people get more comfort with that, you will see more people on the move from the east, which we have historically relied on fairly significantly.

And so, once those people come back to work, it will alleviate some of the labor issues that we’re dealing with. But in the long term, we expect the labor constraints will be permanent, and they’ll be more challenging in the future, and so we’ll need to do better to refine our strategy on how we’re going to attract labor to this industry.

And this is an issue for everybody. I just want to highlight before we wrap up that it’s about 1.2 million horsepower operating in Canada out of a total fleet of about $1.8 million, so that, of course, leaves sort of 600,000 of excess horsepower that’s currently parked, which could eventually come to work with significant retrofits and people additions.

But it’s important to note that we control about half of that. We own about half of that parked capacity, and we will make sure that it’s brought back into the industry in a disciplined and responsible way, and we won’t do so without making sure that there’s a return there.

On the technology and ESG side, technology has always been a big driver of efficiencies in the oil patch. I don’t think that’s going to change anytime soon.

We continue to stay really well informed on all the technological advances that are happening, whether it’s engines or pumps or transmissions or software packages, maintenance programs, et cetera. And we’re not married to any -- we’re completely agnostic.

We’re not married to any technology. As an example, even though we’ve adopted the Tier 4 engines, which we’re really happy with, we will continue to look at all the different options available, and we wouldn’t hesitate to adopt new technologies.

We’re fortunate to have the balance sheet to be able to make those moves, but we won’t do so unless they provide us with a return. I think there’s too much discussion in our industry about technology without a corresponding discussion about, is it economically viable to implement those technologies.

And hope is not a strategy, as we know, and so the cost of some of the new -- especially on the electric side, the cost of some of this great technology is just -- there’s just no way to ever get a return on the investment. And so, we’ll make sure that whatever technologies we adopt, we’re able to get a financial return on them as well.

And of course, that’s what our customers want. They want us to be healthy and in this game for the long term.

I think in the fall, we released our inaugural 2020 sustainability report. It can be found on our website, and our next report should come out this -- late in Q2 of this year.

And ESG will be -- will continue to be a focus for Trican and -- as it is a focus for our customers. We’re using lots of technology-based initiatives on the E side of it to provide solutions, but we’re also focusing significantly on the S and the G side of ESG as well.

We’ve done a great job, especially on the governance side, and we continue to pursue initiatives to make sure that we’re a good corporate citizen in the communities in which we operate, and we’re going to continue to build out on the S side as the year unfolds. I’m just going to wrap up with the Tier 4 upgrades.

I think Scott mentioned it, but generally, generally, we’ve only been running those now for about 2 months. They arrived in late Q4.

We get our second Tier 4 spread this summer. And again, I want to stress that the equipment will only go to work for premium pricing, as it provides cost and operating efficiencies for our customers.

But we’re extremely pleased with how this equipment has performed in the field. We still have some bugs to work out in the extreme cold, but overall, the equipment is performing as well or better than expected.

The natural gas substitution has been high. This is a trend that we think is going to become a -- is going to continue, and this technology will become a standard in Canada, I think, in the next few years.

On the growth in acquisitions, we’re very -- our primary focus remains on just getting our existing equipment to work, getting our equipment off the fence, eventually, if we can make it profitable. We have a clean balance sheet.

We have a cash balance that provides us whatever the financial flexibility to look at any type of transaction that looks attractive, whether it’s organic growth or M&A growth, and we’re always looking for the right deal. But right now, we think our best investment is on the NCIB, the share buybacks.

We’ve been active in the NCIB in the last few years, and I think we plan on being more active in the NCIB in the next few months. And we view that as one of our best investment opportunities when you just look at the price that we’re buying our own horsepower at versus what we would have to pay in the market, and you look at the EBITDA multiples of other oilfield services companies that may be available for us to purchase, it’s really hard to deviate from this NCIB at this point, and it’s just such a good investment for us.

So, I think I’ll stop there. Thank you, everyone, for your interest and your time.

Why don’t I turn this call back to the operator for questions.

So, it sounds like activity for Q1 is a little bit more back-end loaded. I mean, I’m just curious, you touched on it a little bit, but is it Trican-specific customer programs?

Do you think it’s low DUC inventories across the basin as well? It sounds like your seventh fleet maybe had some white space.

Just curious if you got the sense there was much idle capacity in the market outside of that from your competitors.

No, I don’t think there’s any idle capacity. And don’t get me wrong; sequentially, our Q1 is better than our Q4, and it’s better than last year’s Q1.

That’s not an issue. I just -- given the rig count, I would have expected higher prices.

And yes, there’s always white space. There always is.

And do we have full-time work for our seventh crew? No.

No, we don’t, not until March. And so, there’s always white space, but I think we were a little surprised that we didn’t get more pricing pressure.

And I think it’s just because it -- a lot of the work, not just with our customers but with other customers, I think a lot of the work -- a lot of drilling in the first month and a lot of the completions work got pushed to the second half. And so, any time breakup is looming, there’s a hesitation to increase prices.

And it’s really the only time of year where there’s any significant DUCs in Canada is after Q1. And I think that’s why we’ve seen the last few years, Q2 seems to be getting almost to be a normal quarter.

So, it just -- the problem with this time of year is Q1 work gets spread out over 6 months. There’s still drilling in Q2, but it’s greatly reduced.

But -- and so that just hasn’t -- that’s sort of left the steam out of the kettle on the pricing side. I hope that’s what you’re asking, Cole.

Oh, yes, that’s perfect. And I guess you kind of touched on it a little bit earlier, but can you talk about Q1 net pricing relative to Q4?

I mean is it slightly better? Is it about the same?

Or is it worse?

No, no, it’s -- sorry, are you asking me -- so pricing did go up in all of our divisions on Jan 1. On a net basis, nothing really changed.

Yes.

The inflation just kept on going.

Okay. No, that’s fair.

And then, so as you touched on, I mean, you have to make investments in your fleet, working capital. You got $30 million of cash on hand.

You touched on the share buyback a little bit. But some of your peers and a lot of the E&Ps have committed to a set percentage of free cash flow that they’re returning to shareholders.

I mean, do you think that’s something we could see from Trican here over the next couple of months?

It’s more informal than that. I mean we definitely have a percentage in mind, but it’s -- given we’re in the service industry and our cash flows are a little more unpredictable and volatile from quarter-to-quarter, we don’t disclose sort of what that percentage is and certainly would never be prepared to stick to it.

But yes, generally, we sort of have a dollar amount in mind on a monthly basis going forward. And that number will go up and down as our views on the future change.

You mentioned that customers are keen to secure equipment for the second half of the year. And so, can we just maybe think about how that has impacted, or not, the amount of contracting you’ve been able to do for your forecast second Tier 4 DGB fleet that you expect to come in the summer?

There’s not really much I can say about that. All I can really tell you is that the equipment will go to work for premium prices.

Got it. Got it.

Fair enough. And on the 2 fleets you’ve got in flight and in progress, it looks like you’ve kind of been able to upgrade those at about $570 a horsepower.

How close would subsequent fleets be to that same efficiency, given some of the equipment you’ve got on the fence? And maybe can you talk about your appetite to do that?

The pricing goes up every time you dig deeper into the inventory, just because the equipment is not in great shape or you might need a pump replacement or a transmission replacement versus an upgrade, and it’s probably more segmented than that. It’s more like we need to complete fluid -- power end replacement versus an upgrade.

So your instincts are absolutely correct. The deeper you go into the inventory, the higher the prices go.

But at this stage, the percentage change, if we were to do the next set, probably 10%,10% more.

Got it. Got it.

Okay. And as far as that sort of next-generation type equipment, we saw one announcement from a competitor on that.

Have you seen -- have you had any other, I would say, competition for this type of equipment in tenders or as you’ve been negotiating your contracts?

I think that you’re asking is there -- what’s the interest level? The interest level is very high for the Tier 4 equipment.

Right. And there’s still -- is there any, I guess, outside competition for Tier 4 equipment that you’ve been, say, bidding against?

Or has it really just been you deciding how much to release this equipment for?

Sure. Yes, there’s talk of one of the U.S.

firms bringing a Tier 4 spread to Canada, and lots of empty promises, I think, get made along those lines. But there’s no actual competing equipment on the street at this point.

One of our competitors does have a Tier 4, a single Tier 4 pumper, but not a fleet. And so, really, our main competition at this stage would be are competing against sort of the Tier 2 dual-fuel fleets that we all have.

And what we’re finding is, with the Tier 4 equipment is, the substitution is, of course, higher, which reduces costs. And the pumps and the transmissions have been upgraded, and so it’s a more powerful and efficient pump.

And we’re seeing -- what we’re seeing is the engines are -- they’re much more efficient at burning natural gas, and so there’s almost no methane slip. And with Tier 2 dual fuels, there is methane slip.

And so, from an emissions perspective, the Tier 4s are significantly better than the Tier 2s.

Three quick ones for me. First, are you seeing companies wanting to tie down equipment for long periods of time, with pricing adjusting based on market conditions?

There’s lots of desire for long-term partnerships, from an access to equipment perspective. But there’s -- historically, we haven’t had very much success tying pricing to current operating conditions our commodity prices, and so that it’s not really an avenue we pursue.

More of what we’ve been doing is just explaining to our -- and our customers, they’ve got their own problems. They’re not -- they don’t sit around worrying about us.

So we’re doing a better job at just explaining to them just the significance of the inflation and the need for there to be a return on invested capital. Given the age of the fleet, given that there’s -- given the reliance on fracturing as part of an overall well construction and the complete lack of investment by our industry in the last 7 years, just because the money just wasn’t there.

The sophisticated customers, they get it, right? They understand if they want a healthy fracturing industry, prices have to go higher.

And luckily, they have the cash flows to absorb those. I mean, our price increases are insignificant in the overall scheme of things.

So it’s more informal than that. And I’d like to say there’s long-term contracts with pricing escalators, but that has never been the case, and it likely won’t be the case anytime soon, other than the odd exception here and there.

Okay. And for example, diesel costs, how often -- is there like a monthly adjustment in terms of pricing for some of the big escalation in near-term costs?

Or is this something that happens over more of a quarterly basis? Just to get an idea of, I know you mentioned the inflation pressure and versus the pricing pressure.

Given the last few weeks, I think diesel costs have gone up a lot. How quickly do you have to wait before you can pass those through regarding the pressure on your margins again?

Well, the diesel, like you said, Josef, the diesel prices do change weekly, if not daily. But with our pass-through approach, we’ve been able to pass it through, not immediately, but say within a 30-day period, 15- to 30-day period to our customers, but just to recapture the cost of the fuel inflation.

Okay. And lastly, you mentioned M&A and growth opportunities.

Are you looking just in the business lines you’re in today? Or are you looking at complementary lines?

And I know you can’t go into specifics, but how far -- in terms of just general commentary of what business lines might fit or geographic extension of what you’re doing right now?

Yes. I mean, I would -- I mean, again, I’d keep our comments fairly high level.

I mean, as Brad mentioned, we’re looking at -- we look at everything. Our primary focus is, does it make sense?

Could we change the business and extract additional return out of it? We’re not going to be looking too far afield, other than our core business or something that’s fairly easily tangential to it.

But yes, I probably wouldn’t go much deeper than that.

Scott, I’ve got a couple of just simple modeling questions. Could you provide some guidance on DD&A, G&A and tax rate for 2022?

Sure, so from a tax perspective, I mean, we’re -- effectively, we’ve got a significant portion of Canadian pools, so I wouldn’t expect kind of anything meaningful from that perspective. From a depreciation perspective, maybe on an annual basis, probably slightly downwards, right, just as we grind through some of our older equipment.

But we are replacing and upgrading our fleet as we go along, so it would be down marginally, but I wouldn’t expect it to drop significantly from there. And then, G&A, I think Q4 was probably a bit light, right, just with the amount of [Qs], stuff that flowed through there, et cetera.

So if you kind of looked at Q3 and Q4, that’s probably a decent run rate going forward. So I wouldn’t expect a significant change, certainly, to the upside on that.

Okay. And Brad, you did mention that you expected Q1 revenues to be higher.

And then, although net pricing did not improve, but overall price -- net pricing relatively flat. So, just because of higher revenues, you expect margins to improve EBITDA margins in Q1 versus Q4?

Do you -- are you talking percentages or absolute?

Absolute in both, yes.

Percentages to remain very similar. The dollar amounts will go up, of course, just because of the -- where it was a busier quarter, but percentage margins won’t change much.

Okay. And then, you expect Q2 to be relatively similar to Q2 of last year?

Yes. Right now, that’s certainly our view.

And I probably should stress that March, April, May, June, it’s very, very weather dependent. Over that 4-month spend, the gross amount of work doesn’t -- or the aggregate amount of work probably doesn’t change, but the month in which it may get done certainly can change.

And as everybody hopefully knows, we’re coming into breakup, so as the winter thaws, the roads become susceptible to damage with heavy equipment, and so it really slows things down. So any kind of predictions that are on the board, even though -- and booked and scheduled can all change with weather.

Outside the new engines, are you running any purely diesel spreads today? And do you think that your competitors will have sort of the same sort of profile as you sell, the ones that we can’t maybe see quite as easily?

Yes. We do work -- there is a place for a pure diesel spread, and it’s costly because diesel is a lot more expensive than natural gas.

But from an emissions perspective, Tier 2 diesel engines perform pretty well, so there’s always a place for those spreads. On a percentage of total equipment basis, we would have the highest of the -- or the lowest, I guess, of the diesel, pure diesel spreads.

Only 2 of our spreads today are diesel, and I would think our peers, it’s probably a higher percentage than that.

Is that a function of where you tend to work?

Good question. It would be a function of, yes, where we’re working and our ability to, and also our financial ability to invest in the Tier 4 technology and the Tier 2 dual fuels over the last few years.

That’s a longwinded way of saying I’m not sure.

Yes. Okay.

That’s fair. But maybe just on -- because you say you’re half of the parked equipment, the serviceable parked equipment in the basin.

So then, would the percentage of dual fuel versus diesel in that parked capacity be different than what we’re seeing running today? I would expect so.

The parked capacity would be -- there’d be no dual fuel in the parked capacity today.

Okay. So then, that kind of brings me to the next question, which is, when we talk about bringing capacity off the fence, so to speak, the cost of doing -- I assume, then, that the cost of -- or the producers are probably, from a cost perspective going to one dual-fuel.

Isn’t that a fair assumption?

Yes. I mean, the deep operators are going to want Tier 4.

Right. So then, the cost...

Because of the [indiscernible].

So the cost to convert, or the cost to actually bring the type of spread that the industry is probably going to want -- because I’m coming back to your comment that there are 29 today and industry might have a need for 35. So we’re now looking for 6 spreads of equipment that might be mismatched with the type of fuel they burn vis-à-vis what the customer base wants.

Is that -- am I right in thinking this way?

Absolutely. Unless we ended up with a really active shallow gas market or something like that, which would use diesel.

Then, okay, my last question, then, would be, as we start to pull -- see some of these spreads come off the fence then, are they naturally going to be -- is it your expectation that they’re going to be converted to dual fuel? And will it be some kind of a Tier 2 type of conversion?

Or how would we think about that?

We would never -- well, never is maybe too strong. At this stage, knowing what we know today, we would not bring a fleet off the fence without a Tier 4 DGB upgrade, and a pump upgrade for that matter, right?

I mean we’ve been talking about this now for a year, and I hope the street is starting to understand that the state of this parked equipment is not good. Right?

And again, like the question before you was, are the upgrades getting more expensive as you go deeper into the inventory? And the answer is, yes.

We’re spending $20-plus million on a Tier 4 DGB upgrade, which includes transmission and pumping upgrades as well, or retrofits or significant parts replacements. So, when these spreads hit the street, I mean, they are the state-of-the-art, 3,000-horsepower, heavy-duty, continuous-duty equipment.

But the parked gear that you’re starting with is not that. So this is -- I mean, what you’re getting at, of course, is this is not an exercise, and oh, we’ll just sort of spend sort of $5 million or $6 million.

And then, here, we’ve got a spread that can go to work in the Montney. Okay, maybe.

But not the kind of spread we would want to operate.

Okay. Maybe this will be my last question, then.

That being the case, do you think -- what do you think would be the cost, the least cost? Like, say perhaps one of your competitors perhaps didn’t have access to a Tier 4 Dynamic Gas Blending engine and wanted to do something that was relatively cost-effective, but also accomplish the goal of getting spread into the market.

What do you think that investment would be on that spread? Do you have a guess on that?

Yes, I’ll give you broad number, just because, obviously, I don’t know what’s out there other than our own equipment. But if you just wanted to get it up and running in its current form, whether it’s a Tier 2 diesel or whatever, and you’re happy with the 2,500-horsepower pump, $5 million to $8 million.

And then if you’re, well, okay, we need pump replacements and we need this and we need that, it’s $10 million to $12 million. And then, if you want a Tier 4 DGB set up, then it’s $20-plus million.

And again, if you’re talking an 8-pump spread versus a 12-pump spread, the numbers change. But we’re -- when we think about pulling the spread off the fence, we think in terms of sort of 12, 14 pumps.

Okay. Thank you, everyone.

We appreciate your time. We tried to keep it under an hour.

We are available. The management team here at Trican is available for questions, if anybody would like to follow up with us on a one-to-one basis.

And if not, looking forward to our call in a few months. Thank you.