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Trican Well Service Ltd
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Good morning, ladies and gentlemen. Welcome to the Trican Well Service First Quarter 2018 Earnings Results Conference Call and Webcast. As a reminder, this conference call is being recorded. I would now like to turn the meeting over to Mr. Dale Dusterhoft, President and Chief Executive Officer of Trican Well Service Ltd. Please go ahead, Mr. Dusterhoft.
Thank you very much. Good morning, ladies and gentlemen. I'd like to thank you for attending the Trican Well Service conference call for the first quarter of 2018. Here's a brief outline of how we intend to conduct the call. First of all, Robert Skilnick, our CFO, will give an overview of the quarterly results. I will then address issues pertaining to operating conditions and near-term outlook. We'll then open the call up for questions. I'd now like to turn the call over to Rob to discuss the overview of the financial results.
Thanks, Dale. Before we begin, I'd like to 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 applied in drawing a conclusion or making a projection as reflected in the Forward-looking Information section of our MD&A. A number of business risks and uncertainties could cause the actual results to differ materially from these forward-looking statements and financial outlook. Please refer to our 2017 Annual Information Form dated March 29, 2018, and the Business Risks section of our MD&A for the year ended December 31, 2017, for a more complete description of business risks and uncertainties facing Trican. Our first quarter results are available on SEDAR. Please note that we have changed our non-GAAP measures disclosure in the MD&A, which now provides for more discussion around GAAP measures. Our current MD&A now makes reference to adjusted EBITDA, previously reported as adjusted operating income. Operating income is no longer reported. However, we have segregated our income statement such that users can calculate this metric as the company had previously presented it. Further information in respect of non-GAAP measures is described in our MD&A. We experienced sequential improvement in activity levels as well as gross profit and adjusted EBITDA. This is evidenced by the increase in total profit pump to 484,000 tons from 397,000 in the fourth quarter. Although sequential activity levels improved, operational challenges due to extreme cold, some customer inefficiencies in the back half of the quarter and an insured fire event did result in utilization being below our expectations. Industry pricing dynamics remain stable throughout the quarter. We did not see single well spot price degradation for fracturing services like we did at the end of the fourth quarter. This resulted in pricing being relatively consistent with the fourth quarter as first quarter pricing for hydraulic fracturing services averaged $665 per horsepower on the approximate 322,000 average working horsepower. Overall, margins in our fracturing business remains strong as our operating margin in the service line calculated as revenue minus nondepreciation cost to sales was 21%. This margin included a deduction of approximately 4% for fluid and expenses. Activity and other services, mainly cementing, coiled tubing, nitrogen and fluid management, experienced a typical sequential improvement in activity levels, although certain weather challenges experienced in fracturing services also affected our coil, nitrogen and fluid management services. During the first quarter, cement maintained a strong and steady market share of the rig count, declining as the rig count did in March. The impact of sequential activity improvements and stable pricing resulted in first quarter revenue of $306 million and adjusted EBITDA of $54.9 million. Adjusted EBITDA is net of $8.5 million for fluid end cost. Despite the improvement in both activity and adjusted EBITDA, we did incur a net loss for the period. The net loss of $28 million was largely due to the period loss recognized on our Keane investments of $54 million. That Keane investment value decreased during the first quarter due to a partial monetization, which generated proceeds of $33 million, and the decrease in Keane Group Inc. share price from $19 at December 31, 2017, to USD 14.80 at March 31. We announced our second half 2018 capital program of $37 million, which will bring our total estimated capital spending for the year to $70 million. Of the $37 million growth capital, $19 million relates primarily to equipment required to service the larger job sizes and additional investments in coiled tube to improve our capabilities in certain of the deeper areas. Planned second half maintenance capital expenditures of $17 million remain consistent with our previously announced first half maintenance program of $16 million. Additionally, our maintenance capital program contemplates reactivation of all of our currently idle fracturing equipment, although we only have plans to man one additional crew at the present time. Having all fracturing equipment activated allows us to rotate our horsepower through our fleet, which will improve maintenance levels and customer service. It also allows us to add incremental fleets to the market quicker, should customer demand increase later in 2018 or in 2019. Staffing additional fleets is still an issue in Canada, which slows our ability to add equipment to the market as it takes 3 to 4 months to hire and train additional fracturing crews. We remain in a strong financial position, with roughly $101 million of debtless cash and a working capital balance of $212 million. In the near term, we expect to utilize our free cash flow to further improve our balance sheet and invest into our NCIB program. Longer term, we will continue to evaluate the best investment alternatives for our free cash flow that will maximize long-term shareholder value. Since the inception of our NCIB program, we've purchased approximately 18.6 million shares at a weighted average price of $3.89 per share. We will continue with our NCIB program but at a slightly more moderate pace. We continue to view an investment in our shares as an attractive use of extra cash flow and a slower pace of the buyback in the coming couple of months as simply a reflection of the seasonal cash flow changes that occur through spring breakup. I'll now turn the call over to Dale, who will be providing comments on operating conditions and strategic outlook.
Thanks, Rob. Although we saw a sequential improvement in our activity levels, the first quarter of 2018 presented a number of operational challenges. For the most part, these operational challenges seem to affect the broader industry. And as a result, we did not see competitive pricing pressures from our peers for our fracturing services like we did late in Q4 '17. The stable pricing environment allowed us to maintain top decile industry fracturing margins. Our cement business continue to maintain a strong market position as our customers look to Trican for capital expertise in this service line. Our coil tubing and other service lines were affected by weather, and a decline in natural gas well work, which resulted in lower volumes of nitrogen being pumped. These services were at the low end of our margin expectations. Through our capital budget, we are investing in our coil tubing units and associated pumping businesses and are focused on improving margins in these service lines throughout the remainder of the year. Later in the first quarter, we experienced a fire on a fracturing job site. There were no injuries, and as a result of the incident -- there were no injuries as a result of the incident due to the professional response of our staff. The incident did result in the loss of a blender,3 fracturing pumps and some accelerated equipment. The equipment is fully insured and direct financial losses is expected to be limited to approximately $1 million of insurance deductibles. The indirect cost of the incident was approximately $1.5 million to $2 million of loss gross profit. We have 3 24-hour fracturing crews working continuously through April and May. We have previously anticipated 4 fracturing crews would work during this period, but restricted access had limited the additional crew to working only a few days in April. Due to large amounts of snow and wet field conditions in Q2 2018 relative to Q2 of last year, the spot market in April, May has not been the strong as it was last year. We are fully booked in June for our fracturing crews, but realized utilization will be largely dependent on how quick our customer's leases dry and amount of rain during the month. As usual, Q2 financial results will be difficult to predict. However, we do anticipate that to be below the results we saw last year. We are encouraged by the price improvements of oil liquids that our customers are experiencing and our customers' abilities to shift their capital programs to these type of plays. We have received some inbound calls about the potential for increased activity and incremental fracturing equivalent, which is indicative of a positive sentiment towards further investment into certain oil and liquids-rich plays, although we anticipate that the majority of our clients will be cautious throughout Q3, demonstrate capital discipline and not increase their capital budgets at this time. We have already seen a shift to oil liquids activity, and in particular, increased activity in the East Duvernay and fully expect this trend to continue. This trend will lower our average fracturing fleets utilization in the third quarter as our customers continue more exploratory single well activity in the liquids-rich plays rather than high-efficiency pad activity. This trend will result in our fleet having lower average utilization compared to last year as we spend less time pumping on pads and more time rigging in and moving. Pricing has remained flat through the third quarter. We like the long-term potential of the Canadian pressure pumping market. Cash flow is improving for our clients, and some competitors are moving equipment out of the basin, resulting in improved supply-and-demand balance for going forward. There's very little excess equipment in Canada to handle an increase of activity if our customers increased their capital budgets. We have only 5 larger pressure pumping competitors in Canada, which makes it on a much more disciplined market with no Canadian competitors having much equipment at this time. We believe that market access issues will improve in the long term, and Canada will be a strong market for many years to come.As Rob noted, we announced our second-half capital program. As we anticipated, the increase in fracturing density of completions requires the company to make investments into our maintenance capital expenditures programs, and these expenditures in the second half will be very similar to our maintenance expenditures in the first half of 2018. Part of our maintenance capital will be used to activate all of our idle fracturing horsepower, and the cost of $3 million to $4 million to activate all of our remaining part equipment is consistent with what we have messaged in the past. We have been active in bringing parked equipment into are active fleet through Q1 and Q2 and we'll continually -- continue to gradually add horsepower as the year progresses. We continue to exercise financial discipline with respect to incremental growth capital dollars. We are investing some money into growth initiatives, including sand storage equipment, upgraded blenders, upgrades to our coiled fleet and other items that should either improve our efficiency or ultimately increase our revenue. However, we will keep investments into larger scale capital programs to a minimum until we have fully deployed our idle equipment. Given our prudent capital program, we will continue to reinvest a meaningful portion of our excess cash flow into our share buyback program. We will look at M&A opportunities, but we'll be selective and ensure that the investment aligns with our strategy, as was the case with Canyon acquisition. I want to thank all of our staff for their contributions. As we approach the 1-year mark to the Canyon acquisition, the effort put forth by our employees to bring these 2 companies together and ultimately build on the best of both companies is nothing short of impressive. I'm confident these efforts have laid the groundwork for future success. Thank you for your attention today, and your interest in Trican. And I'd like to turn the call over to the operator for any questions.
[Operator Instructions] Our first question comes from Mr. Sean Meakim of JPMorgan.
So as you look towards the back half as we get out of spring breakup, I just thought it'd be helpful to maybe talk about what are some of the kind of key timing and [bogeys] that you have out there as you're trying to flex your fleet with respect to deploying incremental horsepower, being able to -- having the proper reactability to what client budget -- customer budgets may look like in the back half? Share a little bit more of the puts and takes of how the second half could unfold depending on what the market gives you.
Yes. So the one crew that we're planning on activating, and that's the only one that we have plans for now to man, we'll add some time in Q3. I don't know the exact timing. It's primarily due to staffing issues. We have existing customers that want that crew, so that one will go into existing relationships where customers have either expanded their programs or have given us a little bit more of their percentage of their work. So that's not really new work that will bring in with new clients. The other equipment, as I said, we're just activating it and adding it to our fleet. What we're looking for is customer commitments before we put that equipment to work. And the commitments we're looking for is pricing that's kind of current margin levels and some assurance that there's a full-scale program. We're not putting it to the spot market or on a speculative basis.
Got it. That makes a lot of sense. And so then, thinking about some of the shift and job mix, do you expect -- for example, so as you go through breakup here, you're expecting more single-well work as opposed to more of the larger well pads than any you would have anticipated? Can you give us a sense of how we should think about the impact to revenue per job and as well as maybe profitability, just kind of the -- some of the puts and takes there as you think about, on the one hand, some of those jobs? Should we maybe, on a per-job basis, maybe price better? But perhaps that lack of -- the lower utilization of course drags in the margin. Just thinking about how those pieces interplay will be helpful.
Yes. So the -- I'll start, and then Rob can jump in and also try and answer. But basically, if you looked at our businesses, it is -- with pricing pretty stable, it is primarily -- our margins are primarily driven by utilization. And utilization for us is kind of 2 aspects. One is number of stages per day. So basically, 24-hour crew, if you could be pumping 15, 16 hours a day and pumping sand out of well, that's very good utilization for us. And if you get '18 to '20, you are really doing well. And then the other part of it is, how many days per month you're working. And if you looked at our customers' work plans through Q3, there's going to be a lot more days moving between wells, and the stage count won't be quite as high as it would have been last year when we were sitting on some pads and just turning out stage after stage at very high utilization with few moves. So we were sitting on pads for a lot longer period of time. So both of those, together, will combine to lower the number of pumping days that we're going to have during the quarter and a little bit on the number of stages on some of these wells. But it's primarily the days that we're actually pumping because we're moving a lot more.
Yes. And then ultimately, Sean, the impact is there's a little bit more grind towards your fixed cost structure because you're not making as much margin on a move day in between wells as you do because you're sitting on a pad, pumping. So...
Right. That it all makes sense. And just kind of follow up to that line of thinking. So third quarter last year was kind of perfect storm in terms of -- in a good way in terms of you know they really kind of maximize uptime and push out a lot of profitability. As you look forward, do you get a sense that the seasonality in terms of being able to maximize that time is shifting such that perhaps third quarter becomes the high watermark for the year in many cases? Or is it really just still ultimately somewhat dependent on breakup, and therefore, maybe there's not -- as good of a trend line that we think there could be?
Yes. I would say, if you looked at the trend for the last, you can probably go back 3 years, third quarter has been our strongest fracturing quarter. And it's a combination of a few things, but the biggest one is, is that our customers are drilling a lot of more of their wells in Q1 and fracturing them once the weather warms up, and it's because of the large amounts of water that we pump. The cost of keeping water from freezing, and that is pretty expensive. And so customers shift to starting their work when water doesn't freeze, basically. And then the only aspect on Q3 that's a bit of a wildcard last year, we didn't see this, is just the amount of rain we get. And so if -- in winter, though, we can move around quite often a little easier on some of the locations because they're frozen. But in the summertime, last year was a good example, it can go from very dry when we have a very dry summer and we're able to have no moving issues at all. And then in some other years, you're seeing a wetter summer, which can affect your utilization. So that still swings things. I'd say we're -- our commentary is kind of factoring in more normalized weather, not the perfect weather that we saw last year, where we really had very little weather disruptions.
Our next question comes from Ian Gillies of GMP.
With respect to the outlook, can you maybe provide a bit more detail on why you're adding equipment, despite the fact you think activity is going to be down year-over-year? I mean, why not just let the market stay tight and pricing move higher and make up maybe some of those inefficiencies from single well pads through higher pricing?
Well, we're adding that one crew to the market because we have customers that are going to do that work. And if we don't do that work, then someone else is going to do that work. And I don't think there's -- our read is, is that the market is pretty balanced in Q3, and there's probably not enough equipment to do that work with our clients. Do we want to drive up more prices? Well, yes, we're always looking for price increases. But if we've got loyal clients that are loyal to Trican, we're also going to make sure we service their work rather than leave them high and dry with no serious company to do it. And these are clients that are -- that Trican has worked with for many years. So that's the reason for adding the one crew. The rest of the crews, as I said, we're not planning on adding anything else at the moment, and we'll see how the market plays out.
Yes. And I -- just to clarify, like given the changing job mix, we just can't get through as many of the wells this year as we would have last year with the crews we have given the nature of the work, Ian, because they're just moving more pumping on average less than we would have in Q3 of last year, if that makes any sense. So in theory, we need another crew to do the work with the wells on the job board we've got.
But then is it fair to assume then, I guess, that EBITDA per fleet is going to be going lower, and return on capital and FX is going to be going weak -- is going to weaken, just given change in job mix?
Yes, absolutely. It's not a lot, but there's a little bit of impact on that, for sure, because you're not getting the same utilization that you were, say, in Q3 '17.
And then, I guess, with respect to the price outlook, I mean, with -- as you think about adding crews and with the view into maybe Q4 and Q1 next year with these higher oil prices, do you think there is the potential to increase pricing? I know previously, the customers have been quite sensitive in Canada to that, but given the increase in commodity prices, is there any sort of opportunity?
Yes. There's always an opportunity, but it all depends on supply and demand. And so if there's a substantial tightness in the market, then you can move prices more meaningfully. If there's just a moderate supply/demand balance, you can usually get your cost recovery or any kind of increases that will affect your margins.
Okay. And Rob, maybe a bit of an update on the NCIB and how you're thinking about that, maybe through Q2, Q3, Q4, especially given some of the cash flow characteristics and with the CapEx budget, I mean, do you still expect to be active?
Yes. We're going to be active in the next -- our next meeting date through the end of July. So between now and that time frame, we'll be active, but we're just pulling it back a little bit because we'll start building our working capital. We're -- we have a little bit of an unwind here in May, and then it's going to build back up in June. So we'll -- it'll build up through July, and then at the end of July, we'll revisit it and reset it again there. But we'll stay active just not quite as active as we were over the last 3 months.
Okay. And Dale, one last one for me. I mean, earlier in the year, you had talked about just some strategic initiatives to move into some more, I guess, technology-focused pieces of the business, whether it be chemicals or other things along that nature. I mean, can you provide a bit of an update on where you are along some of those lines?
Yes. We're pursuing them organically. And so we're -- we basically have initiatives to increase our chemical sales into the United States, basically, where we've got -- we don't have any equipment there, and we can sell chemistry to various parties down there, customers and other service companies. And so we have organic initiatives there. I'd say that we're kind of on-target from where we thought we'd be, but it's an early phase start-up mode and that we're just basically in the sales mode without getting a lot of realized revenue yet and a lot of leads, and we'll see how that transpires. On the pipeline and industrial services side, we've had the growth in that sequentially and year-over-year in the first quarter and continue to pursue organic opportunities to grow that service line as well.
Our next question comes from Taylor Zurcher of Tudor and Pickering.
As we think about over the back half of the year, you talked about trying to firm up some of the spot contracted fleets to more of a firm term-contracted basis. I'm curious today, is there any pricing delta between the 2 sort of contracted fleets today, spot versus firm?
No, the prices are in line with both of those.
Okay. And then realized you're just today have plans to reactivate one fleet here in Q3 or next quarter in Q3. But thinking beyond that, conceivably, if you were to -- if you had demand to reactivate an additional fleets for some of the single well pad work noted earlier, that's going to be -- that's going to impact the efficiency and utilization, EBITDA per fleet. So curious, how do you think about the mix of sort of EBITDA margin and acquired term to reactivate a fleet beyond the one you're doing in Q3, assuming it's for some of this oily single-well-pad type work?
What we look at is return on capital. That's the measure when we're using when we're activating the fleets more than, say, margin. So we're looking at what returns our equipment can get. And if it meets our return on capital criteria, then we look at activating it. And then, of course, price is a component to that. Utilization is a component to that. Job size is a component to that. And yes, of course, cost structure. So all of those things go in to it, so it's not just one item. In terms of the other reason we would add it is, we would want commitment from our clients or commitment from a group of clients. So not planning on adding anything to the spot market to chase work or chase market share. It would be clients coming to us to say, "we've got x number of wells we have to do. We don't have a crew for it. And can you take that on?" And if you look at our client list, this is probably coming out of existing clients more than anything because we have a number of long-term clients that we will continue to service.
Okay. Okay, that's helpful. Last question for me, just housekeeping around the NCIB. Realized that the pace of investment will moderate from here. But with the stock price, where it's at today, would you be comfortable drawing down the revolver to fund additional share repurchases before you generate more cash flow over the back half of the year? Or will all additional investment, the way you see it now, be funded from operating cash flow?
Yes. I mean, there's -- generally, we're just funding it from free cash flow. There's obviously period shifts in just how the working capital comes in from time to time. But yes, we're just basically funding it from free cash flow.
Our next question comes from Ben Owens of RBC Capital Markets.
On the first quarter, do you guys have an estimate of how much utilization suffered due to the weather-related delays and the customer delays? Just trying to get a sense of how much revenue was maybe left on the table, or maybe in terms of number of frac days that were lost.
I mean, we don't have that number of frac days, but if you said, essentially, we had 2 crews tied up for one month on inefficient work, I think, is a fairly -- a safe assumption there.
Okay, that's helpful. And then on the cost side, do you guys have a number for how much you'd to spend on excess sand shipping cost in the quarter?
Yes, I don't have that number right in front of me here, Ben. But it was -- if you look at it on a per-ton basis, our overall sand costs on the transport side was up about $2 a ton on an overall total basis. So what percentage of that, I think the majority of that. We might have actually even had a slightly lower sand pricing in Q1. So it might be a little bit higher transportation element to that.
Okay. And it's the one that I had. You guys noted the labor as a concern. And I was just curious, if the incremental demand did materialize in the back half of the year, where you had demand for the equipment that you're activating but not crewing, how realistic do you think it would be that you could staff a few of those crews before the end of 2018?
Yes. It takes us 3 to 4 months to hire. And so we're in the process of kind of staffing up right now for one that we'll add in Q3. We'll see how that works out, but I'd say 3 to 4 months almost minimal to hire and train. And so if you -- if we got one out in some time in Q3, it's probably the best we could do is one more in the second half of the year.
Our next question comes from Greg Colman of National Bank Financial.
Just wanted to start by talking about a little bit more on the sand storage equipment that you're pursuing with your increased capital budget or rather clarify each to capital budget? Can you give us a bit more color as to exactly what you're picking up and what the expected impact is going to be?
Yes. Just the on-site sand storage equipment, Greg. Well, basically, it allows us to handle the larger jobs and the larger sand volumes, Greg. It's -- and it makes us more -- much more efficient. And so it's specialized sand storage equipment that, I think, more than anything, makes us more efficient on location, both in terms of storage and operational, pumping of it.
And what we're talking about on previous questions regarding the costs in Q1, would this investment have mitigated that impact? Or is this independent from that impact, and that impact was regarding to something which would still be third-party?
No. The cost that we're talking about there is on the actual last-mile hauling of the sand because we were hauling it all, all over the place. So that's the costs we're talking about on the sand side.
And your investment in sand, it wouldn't have any impact into -- on those costs?
There'd be some efficiencies on the amount of sand and how long it takes to unload sand on location. But what happened in Q1 is we were not hauling sand from the optimal transload facilities. That was due to the rail issues that we experienced. So if we kind of -- if you simplify the -- we've -- if we couldn't get sand in one location because of a rail issue, we would truck it from 200, 300 kilometers further to try and get it to location, so that was the issue that we saw in Q1 that was really related to the rail side.
Got it. I guess, what I'm trying to dial in on costs associated with this are, it's out in your increased capital budget, but what are the benefits that we should be baking in going forward? Or...
Yes, I think what and try to get at, Greg, is it would help to the Q1 issue dramatically, but it should reduce time on site of third-party trucking and even our trucks for hauling sand onto location.
Do you think of it on a return on capital basis or payback period? And if so, how would it compare to -- I mean, your existing capital deployed?
It is going to be very comparable to that. In fact, stuff -- equipment like this seems to pay back quicker than even a whole fracturing pump.
Okay, got it. Just moving on for a bit. You -- talking about the fluid ends and just the changing in the way you're expensing versus capitalizing them. Previously, you had guided to about $22 million of fluid and expenses on a full year basis, but we saw almost half of that in Q1 with -- just coming up to $9 million for the first quarter.
Yes, I think in the...
Sorry, go ahead.
Sorry, Greg. I think in the annual MD&A, we've disclosed $25 million to $30 million expected cost for the full year. So the $8.5 million is kind of in that range.
Yes, you've got to consider that Q2 is not that active too, right? So $8.5 million for Q1 makes sense.
And just a couple of quick ones here. Dale, in your prepared remarks, you talked about horsepower outflow from the country. Would you be willing to quantify that at all? We've seen, obviously, a press release or 2, giving us a few numbers but wondering how much horse you're seeing leaving Canada?
Yes. I think it's best that you get that from our competitors because they're the ones that are moving it out. We have our own number, but it's a bit of a ballpark, so we don't always know for sure. So...
Yes, it was worth the shot.
Glad to have it.
And then just lastly, for me, on the balance sheet, you guys are generating some strong free cash flow here, even buyback. It was great to see the share count going down. And these are all good things. But you did mention strategic M&A, and we're just running some theoreticals on how much capital you would look to deploy. What should we be thinking about in terms of the post-M&A balance sheet environment for Trican sort of in the what you'd be willing to stretch to? Is it something you would compare to your EBITDA? If so, what kind of ratios would you look at? Or is it something versus sort of an asset base?
It's dependent on the quality of the EBITDA largely, Greg. Like if it's cyclical, that lowers our appetite for leverage. If it's fairly stable through a full cycle, that increases our appetite. So we don't have a fixed target debt-to-EBITDA ratio that -- on the funding side of it.
It sounds like, Rob, you've got some goal post there, though. And what would be the low high?
Yes, I mean, we look at it all the time. I would say it's fairly fluid.
[Operator Instructions] We have a question from Jon Morrison of CIBC Capital Markets.
Apologies on beating the dead horse here, but just going back to the equipment reactivations. Given the shift in mix is going to require more equipment in the field, why not prioritize more loyal customers versus less loyal customers in Q3, let the market tighten, give up some market share rather than taking on the work that'll potentially degrade EBITDA for crew or weaken ROIC at this point?Yes, I realize we're squabbling over one, really, man crew, but just [indiscernible] versus high level.
Okay. So first of all, it's incremental to our financial results. So when we add a crew to our business, the financial -- the pricing that we're getting -- adding to crew at return in capital that we're adding to the crew at, it's good for us. It's good for the company. And we'll, of course, do the math on what a price increase will do as compared to adding additional crews, and so we have our own internal forecast there. But the other thing you have to realize is that, we -- the -- all of our -- all of the service companies in Canada, client list, have shrunk a lot. So there's not as many active customers there. They're all valuable customers. And we're not going to heave-ho a customer that we have done work for, for a number of years just to drive up prices in the basin. If there's an increase across the whole basin and all of our clients can't get equipment, then, of course, prices move up. That's the way the world works. But to drop one off of our list that we've been -- that's been loyal to us for a number of years. That's a tougher decision.
And I think, Jon, just to add onto that, I think if you look at the operating margins in our fracturing service line, which we discussed in this outlook here, I think they're fairly robust. So I think there's probably some room for others to catch as well.
And that's where you would say that maybe the field margins remain flattish but the corporate lifts with each incremental crew that you bring on?
Exactly.
Can you just talk a little bit about the strategic advantage of bringing on the additional unmanned capacity from a maintenance cost perspective?
Yes. Basically, it just -- it allows us to have more equipment that we can rotate through our maintenance. So right now, if you're tight on fracturing pumpers, which is really what we're bringing back, if you're tight on fracturing pumps, you have to -- you higher maintenance costs because you're running more third -- running a more of a -- through third parties to get fixed on a short-term basis. So if you were to use a simple example is, if you had extra capacity of 5 and you need all 5 of those, you need to get those fixed as quick as possible. If you have extra capacity of 10, you have the leeway to 5 get of them fixed and 5 get fixed at a lower cost down the road. So overall, it helps our cost structure, but it also allows us to give better service to our clients because they're not ever waiting for us to be repairing equipment and there's just more capacity in the system. So it's a kind of a double win for us as a company. And then if we want to activate them in the future by matting them and adding them to the business, it's easier to do so. And the money is already being spent on them, and they're working in the field.
So it's fair to assume that the incremental benefit, from a maintenance and customer flexibility perspective, likely more than offsets the small cash costs that put that out in the field, in your view, out in the next 12 months?
Yes, absolutely. And as everyone knows, there's a large variety of jobs in our world. So it's a Saskatchewan well, maybe only around 3 or 4 pumpers. But up in the North Duvernay, Fox Creek play, we're running 25 to 30 pumpers. And it also gives us the flexibility to take on clients. If our client is in different areas, the financial justifications there just allows us a lot more flexibility in the company to be able to do that by having these extra pumpers in.
Do you think that impacts your ability to push price as the market does tighten and customers know that you have ready-to-go equipment off the fence?
Well, we're not -- I don't know if it impacts our ability to push prices because we're not activating that equipment unless we get the right price. And as we kind of talked about it earlier, right now, our operating margins in the field and fracturing are very good, as Rob said in his commentary. And Incremental equipment added is good. We've got to continue to see that and we've got to continue to kind of see a positive environment for us to be able to add any more.
And I think, if anything, there just remains a little bit of an overhang as long as you got equipment parked. There's maybe a little bit more a tendency for customers to think that there's lots of equipment in the basin. And don't worry, it's all going to come back. But until all the equipment is actually pull off the fence and proved it can work, that overhang -- it's a way to get rid of that just theoretical overhang that people might think that's there.
And Rob, I realized it's a small number, but from a timing perspective of that, that will go through the P&L, is that all going to be Q2, Q3, for the reactivation costs?
$3 million or $4 million, that should be largely capital.
Okay. So the expense item is going to be relatively small?
Yes. It's going to be much more smaller, yes. It's [indiscernible] $2 million or $3 million through the rest of the year.
Just in terms of the guidance you guys gave around Q2 directional comments, does that contemplate cooperative weather for you to hit kind of those goalposts that you put out there in terms of the strong June? Or it's basically fairly strong line of sight?
Yes, what we said is bookings are good in June. But we don't know exactly how actual activity and utilization will play out in June because of weather. And right now, our leaning is towards there's more snow. It's going to take a little bit longer to dry up in North. And that could create some utilization and issues in June. So even though the bookings are there, we may not get all the work in June because of weather. And then the other factor, of course, is rain in June, which we've had in the past. That one, we can't predict. So overall, I wouldn't say that we're pushing a real bullish June. We're saying that the bookings are there, and let's just see how this plays out.
Okay. Rob, just in terms of the comment you made around the change in work in the back half of the year is going to lead you to try to -- have to grind in your fixed costs a little bit more. Can you give a little color on what you meant by that? Is that just incremental guarantees from employees in the field? Or is there incremental fixed costs that you still think that you can grind out of the system?
I think what I was getting at is we just -- because you're earning less average revenue, the average fixed cost is grinding on your margin because your total margin -- overall margin goes down. I think it was -- Dan asked or Ian asked a question of ROI. In theory, we need to have more fleets out to make the same contribution margin. [indiscernible] grind back on our fixed costs because the fixed costs are stable.
Last one, just for me. In the past, you guys talked about diversifying across other service lines in Canada. You talked a little bit about some of the things you're going to do on the chemicals side in the U.S. But are you being shown many opportunities in Canada, given some of the headwinds that we have regionally? And how are you thinking about expectations for sellers versus buying back your stock at this point?
Well, it's kind of the first part of this is, is that everything we look at, we compare it to buying back our stock. And so any acquisition we do has to be strategically fit for us, but also financially, we can -- we do look at it as one of the comparatives as to is it better to buy back our stock. Of course, you have to look at that over the long term, not just over the next 6 months. And so there's a long-term component of that as well. In terms of the number of deals shopped to us in Canada I wouldn't necessarily say there's a lot in Canada. I believe that we've seen -- well, I know we've seen a lot more of coming from the U.S. where private equity players are trying to monetize their U.S. assets. And so we're getting shopped a lot of deals down there, but we're not in the U.S. And we don't have any strategic plans to enter the U.S., so we haven't look at those seriously. But there's been a much more private-equity-type flips of U.S. fracturing companies than there has been anything out of Canada.
Our next question comes from Jeff Fetterly of Peters & Co.
Just a quick question on the cost inflation side. The reference you made in the release in the MD&A, how significant are you seeing cost inflation right now?
Yes. No, I think it was -- we've got on the sand side, we probably got a couple of percentage points in the back half of the year. I think it was that, and chemicals might be a little bit bigger than that. But that's essentially what we're seeing.
And is your expectation that you'll be able to flow those cost inflation, cost input increases through?
Yes. We're going to be working through our customers through the second half. Of course, never easy at the depths of Q2 to walk in our office and do that. But as we come out of the second quarter, we'll be certainly looking at that.
And what is your expectation for cost inflation, specifically on labor and proppant in the second half?
Well, we don't have any expectation for material labor inflation. I think, a couple of points was when I was referring to on the proppant side.
I'm showing no further questions at this time. I like to turn the conference back over to Dale Dusterhoft for any closing remarks.
Yes. Thanks for your interest in Trican today, and we certainly look forward to talking to you in the middle of summer after we release our Q2 results. Have a great day. Bye.
Thank you. Ladies and gentlemen, this does conclude today's conference. Thank you for your participation, and have a wonderful day. You may all disconnect.