STEP Energy Services Ltd. (OTCPK:SNVVF) Q2 2022 Earnings Conference Call August 11, 2022 11:00 AM ET
Company Participants
Klaas Deemter – Chief Financial Officer
Dana Brenner – Senior Advisor, Investor Relations
Steve Glanville – President and Chief Operating Officer
Conference Call Participants
Cole Pereira – Stifel
John Gibson – BMO Capital Markets
Josef Schachter – Schachter Energy Research
Operator
Good morning, ladies and gentlemen, and welcome to the STEP Energy Services Q2 2022 Earnings Webcast Conference Call. At this time, all lines are in listen-only mode. Following the presentation, we will conduct a question-and-answer session. [Operator Instructions] This call is being recorded on Thursday, August 11, 2022.
I would now like to turn the conference over to Klaas Deemter, Chief Financial Officer. Please go ahead.
Klaas Deemter
Good morning. Thank you, operator. Good morning, listeners. My name is Klaas Deemter. I’m Chief Financial Officer for STEP Energy. I’m going to turn the call over to Dana Brenner. Dana is our Senior Advisor for Investor Relations and joined us in the quarter.
Dana Brenner
Thank you, Klaas, and good morning, everyone. Welcome to STEP’s second quarter conference call and webcast. It was an excellent quarter for the company, and I am pleased to introduce the roster of speakers, Steve Glanville, our President and Chief Operating Officer will give some opening remarks; Klaas, our CFO will follow with an overview of the financial highlights before turning it back to Steve for some operational insights and closing remarks. We will host a Q&A period to call.
Before I turn it over to Steve, I would like to remind everyone that this conference call may contain forward-looking statements and other information based on current expectations or results for the company. Certain material factors or assumptions that were applied in drawing conclusions or making predictions are reflected in the forward-looking information section of our Q2 2022 MD&A.
Several business risks and uncertainties could cause actual results to differ materially from these forward-looking statements and our financial outlook. Please refer to the risk factor and Risk Management section of our MD&A for the second quarter ended June 30, 2022 for more the description of our business risks and uncertainties facing STEP. This document is available both on our website and on SEDAR. During this call, we will also refer to several common industry terms in certain non-IFRS measures that are fully described in our MD&A, which again is available on SEDAR and on our website.
With that, I will pass the call over to Steve.
Steve Glanville
Yes. Thanks, Dana, and good morning, everyone. Thank you for joining our Q2 2022 conference call. As mentioned, my name is Steve Glanville, and I’m the President and Chief Operating Officer. Regan Davis, our CEO is unable to join us today, so I’ll provide our operational update and commentary about our Q2 results.
By now, you will have the opportunity to view STEP’s results for the second quarter, which was the best in our company’s history. We are very proud of what we achieved. At the start off, I would like to highlight three important factors that contributed to this quarter’s success. First, this is a quarter that showed what we can – what can be accomplished when we as a key service provider work closely together with our clients.
Our employees or as we call them, professionals, did an exceptional job of managing the needs of our clients from an operational efficiency and safety standpoint during the quarter. This is clearly reflected in our record-breaking results. Second, this quarter highlighted the torque and earnings power in our business that is realized when you combine utilization on large multi-well pads with STEP supply product, healthier pricing, and a highly efficient operations team. When those variables work well together, these are the results that can be generated.
Third and final, one of STEP’s key differentiators in our geographic is our geographic footprint. Our results showed a sequential improvement in both Canada and in the U.S., and we believe that there is more to come as the market tightens in both regions. I’ll expand on these points further in my commentary after Klaas provides our financial highlights.
Over to you, Klaas.
Klaas Deemter
Thanks, Steve, and good morning, everybody again. Let that’s review, I want to draw your attention to the most important elements of the quarter. Please note that I’m going to focus on sequential comparisons with Q1 2022 because the delta on a year-over-year basis is so large that it will be particularly meaningful for both investors.
Year-over-year comparisons for the data points I mentioned are available in our MD&A for those who are interested. As Steve noted, this was a record quarter for STEP in many ways, which we saw coming when we took the exceptional step in June of releasing a guidance range around revenues and adjusted EBITDA.
Our final consolidated revenue reached $273 million, which was slightly above our range of $250 million to $265 million. Certain Q3 work crept into Q2, was of course, the top line even higher than we were expecting. This revenue number compares to approximately $219 million in the first quarter of this year, so we were up 24% sequentially.
Consolidated adjusted EBITDA in the quarter was a new record for STEP at just over $55 million, which compares to our June guidance range of $42 million to $50 million. We ended up a bit higher than we expected, partially again due to some of that work getting pulled from Q3 into Q2 and also due to some favorable settlements for insurance and sales tax refunds that were received in late Q2.
Revenue and adjusted EBITDA in absolute terms hit new high watermarks for the company and exceeded the top end of the guidance range. But it’s worth noting that our adjusted EBITDA margin is still only back to 20% on a consolidated basis, which means that this business has quite a ways to go before getting what we would consider to be full – of healthy full cycle margins.
Another way, in order for us to consider investing to add capacity into a tight North American product market, we will need to see our industry embrace the notion of sustainable full cycle pricing and meaningfully better margins than we have produced this quarter.
Our previous high watermark for EBITDA was set in Q3 2017 when we earned $50 million, but that was at a 28.5% EBITDA margin. For context, we were only running coil in the U.S. at that time, in addition to our Canadian business. We’ve now added three large frac crews in the U.S. that are operating at high utilization, and we’re seeing signs of the coil market that has turned the quarter to improve profitability.
When we add all this up, we think this gives investors insight into the embedded cash flow and earnings power of our company going forward. As well, I also want to note that we had positive net income in the second quarter even after adjusting for the reversal of the impairment charge that we took in 2020. If we net out that reversal, net income was still $5.5 million or about $0.08 a share.
Let me pause you for a second, remind listeners that for far too long, the energy services space has not really been able to talk about net earnings because there were none. This is our second quarter in a row of positive net income. And while we’re happy with that, the values are still pretty small in relation to what gets healthy businesses need to generate to reinvest in the longer-term.
Turning now to our individual geographic markets. Revenue this quarter was roughly CAD 60:40 U.S. split. The balance that we are proud of given how excited we are for the underlying growth in the U.S. Canadian revenue was about $165 million, which was up sequentially from the $147 million in Q1.
Long-term followers of this space will know that it is rare for a Canadian-based OFS company to post better results in Q2 than in Q1. STEP was able to achieve this due to a job mix that reflected a high degree of coordination with our clients. We are privileged to work with some of the best clients in our industry.
Clients that literally have the details of their program honed down to the minute. We had an extremely efficient schedule that stacked up large multi-well pads, one after another. And as a result, we were able to largely mitigate the normal effects of the Canadian spring breakup. U.S. frac revenue was up 18% versus Q1, while Canadian coiled tubing top line was just marginally lower than Q1.
Most important numbers that drove the Canadian top line were frac revenue per day moving higher by 67% versus Q1 2022 and proppant pump or state that was up 69% sequentially. Although, the total number of Canadian frac days and stages completed were lower sequentially, this spring break up the daily revenue and size of the stages moved sharply higher, which also speaks to the great execution by our professionals.
Canadian coiled tubing revenue per day was up 34% sequentially, while the number of days was also down 34%. Finally, Canadian segment adjusted EBITDA was just under $40 million for the quarter, up 25% sequentially from Q1. Segment’s adjusted EBITDA margin was 24% versus 22% in Q1 of this year.
Moving to the U.S. side of our business. Revenues were about $108 million, up 48% from the $73 million in Q1. U.S. frac revenues were up 64% sequentially, while CT was up 14%. For context, the U.S. land rig count was up 13% sequentially as reported by Baker Hughes. U.S. frac revenue per operating day was up 58% on 4% higher days.
We pumped 22% more profit in the quarter and completed 28% more stages versus Q1. In U.S. coiled tubing, revenue per day was up 8% sequentially on a 5% rise in coil operating days. We remain encouraged with the direction of the U.S. – that the U.S. coiled tubing business is headed. Finally, U.S. adjusted EBITDA more than doubled from Q1 2022 levels, hitting just over $20 million with an associated margin of 19%, which is up from 14% in Q1.
Turning to the cash flow statement. We generated almost $53 million in operating cash flow before changes in working count, subtracting off sustaining capital of around 10.5% – $10.5 million, sorry, principal payments of $7 million and so other minor adjustments recalculated free cash flow of over $33 million. Substantial free cash flow generation is important to us, and we know that it’s also very important to the global community of energy investors.
Moving to the balance sheet. Net debt ended the quarter at roughly $194 million versus about $214 million at the end of Q1, an improvement of about $20 million. We’re very focused on reducing balance sheet leverage, and we’ve been targeting a net debt to adjusted EBITDA ratio of no more than 1 times by the end of 2022, a goal that we feel is fairly within reach.
Working capital of about $54 million was roughly unchanged versus the end of Q1 2022. So minor movements in receivables, they were up about $13 million was offset with some increase in lease obligations, income tax payable as well as a small reduction in our cost position that would keep contention low.
A quick note on our capital budget. We review this budget quarterly, and we remain disciplined in how we allocate our dollars. We’re not adding incremental spend at this time, so we’ll stay at the improved $57 million. As for those keeping score, you may have noticed that we added some capital leases in the second quarter.
This is a bit of accounting inside baseball, but these are primarily short-term rentals that we anticipated returning through Q2, but continue to use due to the high degree of activity. These leases continue to be paid as if there are monthly rental and can be returned at no cost. And – but because of IFRS, we have to present these as incremental capital spend.
Subsequent to the end of the quarter, STEP announced the amendment and extension of its credit agreement with a syndicate of lenders. In place now was at CAD250 million revolving facility, a CAD15 million operating facility, and a US$15 million operating facility, all with a three-year term to end July 2025. With these changes, STEP gains more flexibility and more certainty with the new three-year term.
And finally, I’ll note that book value per share has risen to $3.20 per share from $2.60 at the beginning of the year, a marker of shareholder creation. As well as if you look at our ROE on a trailing 12-month basis, it’s now just over 18%, a number that’s among the best in the North American pressure pumping space, the one that speaks to what our stuff professionals can achieve in executing with our clients. We like how our equity compares against our peers, and I advise listeners to have a look at our updated IR deck on our website for more comparative information.
Now, I’ll turn the call back to Steve.
Steve Glanville
Yes. Thanks, Klaas. Before I comment on our outlook for Q3, I will share an update about our operations and focus on our U.S. business segment first. Followers of U.S. rig counts and field spending trends will note that the incremental increase of drilling and completions activity has been largely driven by private E&P companies.
In the updated corporate presentation, as Klaas had mentioned on our website, we show a mix of work in both our geographic regions. You will notice on Slide 12 that 60% of our work in the U.S. is with private E&P companies. We believe this is the right mix as a number of the major publicly traded U.S. and international E&P companies have been slower to increase their CapEx budgets in response to rising commodity prices.
By contrast, the U.S. private E&P sector has ramped up operations to grow, which, in my opinion, what the world needs right now. Energy security matters and North American producers are well-positioned to increase supply on the global scale. During this quarter, STEP’s number of fracturing operating days did not substantially change from Q1’s level of activity.
However, we supplied a higher volume of raw materials to our clients. We also saw net price increases resulting from the tightness of the overall U.S. fracturing market. I want to highlight that our U.S. professionals did an exceptional job of managing our supply chain, and we were able to outpace the effects of inflation, which continues to be a variable in the cost of our operations.
Our capacity did not change. We ramped three large fractures in the U.S. and have been – and have seen additional demand for our Tier 2 direct injection dual-fuel fleet, which provides industry-leading displacement rates for our clients. 50% of the onshore U.S. drilling activity is in the Permian Basin, which is supportive of our strategic foothold in the region.
Moving to the U.S. coiled tubing business. We are happy with the progress in the quarter. We continue to run eight spreads, which, as Klaas mentioned, generate both higher utilization and revenue per day versus Q1. We saw ongoing utilization of our equal service of this quarter as well. We anticipate a growing demand for these technical services as operators seek ways to optimize their completion programs.
I would characterize the U.S. coil market as showing good signs of improvement, especially in the complex deep capacity market, which is well suited for purpose-built assets base and professional expertise. We’ll need to see continued pricing improvements to fight the effects of inflation in the supply chain and to continue to attract great professionals to our organization.
Switching over to Canada. In our Canadian fracturing business, our professionals managed our second quarter program as well as I have seen in my 30-year career. Spring breakup can be challenging – can be a challenging time to operate. But despite lower operating days and well count, we were able to achieve terrific improvement in revenue and margin.
As I noted at the beginning of the call, the best outcomes for both E&P and energy service companies happen when the two parties act more as a trusted partner and growth as opposed to one simply working for the other. Our clients large multi-well programs with more stages per well necessitate large volumes of sand and therefore, more intensive operations from a product, personnel, and equipment perspective.
This scenario, coupled with our highly efficient operations during which we use every minute available to us, helping up to 23 hours per day for example. But in an incredible dynamic logistics team that reduced our reliance on third-party sand haulers where the ingredients required to maximize the torque and earnings power of our Canadian frac business in this quarter.
We continue to operate five frac spreads in Canada, four of which are large capacity crews that are focused primarily in the Montney and Duvernay and one fit-for-purpose crew that includes our electric-powered integrated combo unit, which we call the EPIC, which focuses in the Viking and Cardium space.
Turning to our Canadian coiled tubing business. We operate eight deep capacity spreads during the quarter, which generated similar results compared to Q1. It was less busy, as you expect during the breakout period, but we generate more higher or much higher revenue per operating day.
Net pricing improved from Q1, and our job mix was slightly more favorable. We also saw an increase in demand for our ancillary services such as our pump down business and our industrial nitrogen services. Similar to our U.S. business unit for coil, demand increase for our Equian real-time downhole technology, which includes our Step-conneCT tool, and we have line of sight to further utilization as operators explore how accurate real-time data will improve the performance of billing operations.
Just some closing remarks, I want to say a few more things before turning the call over to our analysts. First, Q3 activity in both Canada and the U.S. is showing continued positive trends. In Canada, so far, the Q3 – in Q3, the rig count is up roughly 25% versus the full quarterly average of one year ago.
Our Canadian clients remain very positive about the overall macro and commodity price backdrop. We have visibility to an active frac calendar in the back half of the year. Similar utilization as anticipated in Q3. However, many of the completion programs will be smaller in scale and intensity.
Our strategic clients whose operations are in the shallower basins will ramp up activity in the back half of the year. These smaller-scale programs such as angle fracs generate less revenue per stage because they require less capital on and products allocation. We are starting to gain visibility in the winter completion season. We are seeing some of our clients open – that are open to pulling programs forward in the early – that were set for early 2023 frac into the fourth quarter to capitalize on commodity price and to avoid what we believe is a potential program delays by a tight OFS market in Q1.
We are also having constructive conversations with key clients that are increasing their programs for 2023, something that we’re obviously quite excited about. As the industry stands today, it is my opinion that on any given day, the Canadian fracturing market fluctuates on either side of the balance from a supply perspective.
We see potential for the industry to add capacity later in 2023, particularly of the Blueberry River First Nations treaty negotiations are resolved in a way that opens their territory to development. But it’s our view that the pressure pumping industry would do itself a disservice by adding one more fracturing crew to this market.
Additional horsepower would potentially and very quickly change the market to an oversupply position. Our friends in the drilling sector have shown a discipline that our pressure pumping industry could certainly leverage. Drillers did not stand up additional crews without having a long-term contract in place. Pressure pumpers need to add margin non-capacity and we see our Q2 as a perfect example of how highly efficient operations with minimal downtime on pad and between pads can be profitable for pressure buffers and clients.
STEP is committed to maintaining this disciplined approach and does not intend to deploy additional horsepower in 2022, but we’ll continue to deliver great returns with our existing asset base.
On the U.S. side, the market is clearly in an undersupplied situation, which has helped pricing recover at a faster rate than in Canada. The U.S. land rig count is already up 6% in Q3 from its Q2 average, and this speaks to continued strengthening of demand for completion services. We have started to see refurbished assets, including Tier 4 fleets replace legacy equipment with the cruise titrating over in that market.
We have characterized that fleet as minimal at this point in the market that is clearly straining for more capacity. So on the labor front, labor availability remains a key growth barrier in the U.S. and in Canada. Finding more people in an up cycle is never easy, and our business is not immune. Our ESG commitment remains strong.
We continue to run a North American frac fleet that is over 50% weighted to Tier 4 diesel engines and natural gas dual fuel capability. We will continue to invest our capital in these technologies as the full cycle of our equipment is realized.
Finally, a big thanks to our great team of professionals around me in the field, offices and service centers and who work every day to bring our core values to life, safety, trust, execution, and possibilities. This quarter has clearly shown that when you get those first three things right, great possibilities exist.
Operator, I’ll turn it back so we can open the lines for any questions.
Question-and-Answer Session
Operator
Thank you. Ladies and gentlemen, we’ll now begin the question-and-answer session. [Operator Instructions] Your first question comes from Cole Pereira, Stifel. Please go ahead.
Cole Pereira
Hi, good morning, everyone, and congrats on the quarter. So the U.S. business looked really strong. Just wondering, is that a reasonable run rate for the rest of the year? Or can you push pricing a little bit more? Or could you see that come down just as the work mix evolves?
Klaas Deemter
Hi, good morning, Cole, and thanks for the question. Yes, I mean, we’ve been seeing a dynamic kind of change, I would say, the last probably two months to three months, obviously, a very, very tight market. And we do see some additional pricing increases in the back half of the year, for sure. And you’ll note on kind of Halliburton’s Q2 call, they talk about kind of the tightness of the market, and this is a margin cycle and not a utilization cycle.
Cole Pereira
Got it. And then you talked a little bit about it, but where would you need to see pricing or margins go from here to reactivate that fourth fleet in the U.S.?
Klaas Deemter
Yes. Good question. One thing that we didn’t talk about Cole is our IOR success in the U.S. And part of that fourth fleet is focused on that technology, and we’re seeing great traction with that, and we expect to see some higher utilization with that spread in the back half of the year.
Cole Pereira
Okay. Got it. Thanks. And so there’s some commentary in the release that you expect margins to compress in Canada sequentially due to work mix, which makes sense. And so I just want to clarify that based on some of your comments on the work mix, you would expect the revenue to be sequentially lower as well?
Klaas Deemter
Yes. We’ll see a bit of a decline there in frac revenue, Cole. Those annular jobs are just bothered into less revenue generating and is a bit of efficiency because you’re moving a bit more often. What will offset that is the pricing increases that we’re starting that – are starting to gain traction. So it’s – from a top line perspective, you’ll see that come down a little bit. And then from a margin perspective, I would say we probably should be close to where we were in Q2 maybe a bit better if everything aligns nicely.
Cole Pereira
Okay. Great. That’s helpful. Thanks. And just one more quick one for me, Klaas. Can you just talk about how you see working capital evolving in the second half of the year?
Klaas Deemter
Yes. I don’t think we’re going to see too much of a change, to be honest, Cole. Yes. I think we’re in the range where we’re at right now, I think we’re probably – we’ll see that until we’re at the end of the year, maybe a bit of an increase through Q3, but it’s – I don’t think it’s going to change that much that materially.
Cole Pereira
Okay. Great. That’s all from me. Thanks. I’ll turn it back.
Operator
Thank you. Your next question comes from John Gibson, BMO Capital Markets. Please go ahead.
John Gibson
Good morning, guys, and congrats on the strong quarter again here. I’m leading off Cole’s question. I realized pricing and activity levels continue to trend very positively, although we’ve seen some lower quarters from pumpers in the past where the stars aligned with regard to jobs, pad work, weather, et cetera. Do you think Q2 is more indicative of the ongoing trends in the sector? Or could you maybe scale back expectations a little bit just given the variables that can happen in pressure pumping?
Steve Glanville
John, it’s Steve here. I can’t really – I can’t highlight enough how Q2 turned out for us. It’s a remarkable quarter and the fact that when you couple in high-intensity work that we saw, large pads and additional profit per stage, et cetera. And of course, the higher utilization that gives you the returns in this business.
And as long as you have a good calendar full of that work, you should expect that. As Klaas talked about is, Q3 is – as our clients look at some of the shallower biking work that they weren’t able to get to in Q2, of course, that requires less capital from an equipment standpoint, smaller stages, et cetera, and not as efficient as the Zipper operation. So that’s what we see kind of in Q3. But as we look into Q4 and even into 2023, we’re getting indications from our clients that they’re adding these larger pads like three, six wells, 12 well pads, et cetera, going into 2023. So that’s what we’re optimistic about.
John Gibson
Do you see yourselves getting to a point where you could be more selective just in terms of choosing more of the pad style work going forward maybe in Q4 and into 2023?
Klaas Deemter
Yes. I think Steve talked about the market in Canada right now being a higher side of balance. So that would suggest that we can’t be too picky right now. I know in the U.S., they aren’t able to be a bit more selective in terms of which clients, which pressures they want to work at. The market is just a bit tighter down there.
Heading into 2023, you see the rig count forecast. They’re up in both countries. Steve’s comment here, our clients are talking about increasing programs. So I think maybe in 2023, will probably maybe bit more options there. But I think our goal is to work with our clients to make sure that we get that highly efficient model, and that’s really where we think.
Like honestly, there’s – every time we talk about pricing, that always kind of sets up a bit of us versus them dynamic. But the reality is in a Q3 like Q2, like what we’ve had, and if we can replicate that in other quarters, we make a bit more money on the stage. But when we can finish a pad of three or four or five days quicker for our clients, there’s massive savings for our clients in that when they don’t have to keep all those other services going. They can start flowing right away. So we see this as a real opportunity for us to work collaboratively, and we don’t really see that as a zero-sum game or one wins and one loses.
John Gibson
Last one for me. What is the delta between pricing levels in Canada versus the U.S.?
Klaas Deemter
So the U.S. is closing the gap. Like the margins are still a little bit tighter in the U.S., partly a function of we’ve got five crews running here in Canada versus three in the U.S. Coil were roughly similar. But you can see from the results that we posted that the U.S. is still running a little bit behind. But I do expect that as the year kind of continues to progress, we should start to see that narrow a little bit.
John Gibson
Great. Thanks. Appreciate the color. I’ll turn it back.
Operator
Thank you. Your next question comes from Josef Schachter, Schachter Energy Research. Please go ahead.
Josef Schachter
Good morning, fellows, and again, congratulations on the great quarter. Thanks for taking my questions. First on the accounting issue for Klaas. The move with the impairment reversal of $32 million – $33 million, was that – one, can you give some color on what that was? And is that a one-time item? Or as you activate more equipment and the write-downs that you’ve had, would there be more reversals going forward?
Klaas Deemter
Good morning, Josef. Thank you for the question. It’s one of the – again, I talked about insider baseball IFRS rules. So we took an impairments in Q1 2020, just given the kind of the state of the industry and the floating world that we saw at that time. So we took a general impairment over both of our geographic regions.
And under IFRS, as conditions improve, the required balance – under IFRS every quarter, every year, you’re supposed to take a look at indicators of impairment. And as conditions improve, if you’ve taken a general impairment, then you have to reverse that impairment. So this reverses the full amounts of the Canadian impairment. So that’s kind of a one and done, and you won’t see that coming back.
Josef Schachter
And on the U.S. side?
Klaas Deemter
The U.S. side took a much smaller impairment, and we’ll take a look at that again at the end of the year to see what that would be. But that’s just for contacts, it’s less than $5 million. So we didn’t spend a lot of time concerned with that number.
Josef Schachter
Okay. Good. Thanks. That clarifies that. Thank you very much. Now with the discussions now coming from some of the operators, E&P companies about starting to see drilling for LNG Canada, and also, of course, we’ve got the announcement of wood fire and progress on SEDAR. Do you start seeing discussions with your clients about tying up equipment for longer periods of time? And are the discussions at pricing that is much different than the current pricing that you’re seeing to get that equipment locked up for a longer periods of time working in one area?
Steve Glanville
I’ll take that question, Josef. Good morning. It’s Steve here. We have seen some, I would say, early indicators of that pretty minimal at this time. Obviously, you’d probably see it more from the drilling rig standpoint first. And then, of course, our services would kick in. But we’re really excited about this opportunity, particularly for Canada, LNG Canada with fiber, as you mentioned, and our asset base and we’re having the expertise from a deep capacity coiled tubing perspective, really fits really well for our asset base in that area. And we do expect incremental activity to start happening in kind of 2023, 2024 in particular. And we’ve estimated that if on LNG Canada if they stick to their plan kind of require between two and three additional frac crews up in that area.
Josef Schachter
Okay. And lastly for me, on the contracts that you have right now, are you still running down legacy contracts from a year or two? How much of your business is being priced at what you say at the current market rates? And when do you see the – any old ones running off? Is that a Q4 situation or something that happens in Q1 of 2023?
Klaas Deemter
Go ahead.
Steve Glanville
Yes. We don’t have a lot of long-term contracts, Josef. Most that are more of a pricing agreement standpoint. So we’ve been able to work with our clients really from kind of Q1 on and looking at inflation cost of our business. And they’ve been obviously seeing it in other areas of their business as well and have been working with us to increase our prices because of inflation plus some additional margin that we’re looking for in the business.
So it’s pretty fluid right now. There has been some discussion with some clients in regards to more longer-term activity. And that’s usually kind of concern around tightness of supply. And when you have a frac crew in particular that is creating high efficiencies to their business, they want to keep that frac crew locked up. So we’re having early discussions right now with some client cell long-term contracts.
Josef Schachter
Okay, super. And is pricing changes monthly, quarterly? How do you see that going forward, given, as you said, the tightness is coming? Are you going to try to keep it on a shorter-term basis? Or how or what do the clients want? And where is the comfort zone of re-pricing situations going forward?
Steve Glanville
Yes, a little bit different in the U.S. versus Canada. The U.S. is sort of on a pad-by-pad basis that we are able to really look at our pricing and where the market is at. We’re able to ratchet that up faster. We mentioned that and note some. Canada, we have some extremely strategic aligned clients that we’ve worked with for many years and been able to obviously work with them. They are, I would say, more on a quarterly basis that we’re able to review pricing with them.
Josef Schachter
Okay, super. That’s it from me. Thank you so much, and again, congratulations on the quarter.
Steve Glanville
Thank you.
Operator
Thank you. [Operator Instructions] There are no further questions at this time. I will turn it back to Mr. Glanville.
Steve Glanville
Yes. Thank you, and thanks for joining the call. Then we look forward to our next conference call to refer on our Q3 results. Thank you very much.
Operator
Ladies and gentlemen, this concludes your conference call for today. We thank you for participating and ask that you please disconnect your lines.
Be the first to comment