Trican Well Service Ltd. (TCW) Earnings Call Transcript & Summary

Good morning, ladies and gentlemen. Welcome to the Trican Well Service Second Quarter 2022 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. Brad Fedora, President and Chief Executive Officer of Trican Well Service Ltd. Please go ahead, Mr. Fedora.

Thank you. Good morning, everyone. Thank you for attending the Trican Well Service conference call. I'll just give you a brief outline on how we intend to conduct the call. First, Scott Matson, our CFO, will give an overview of the quarterly results. I'll then provide some comments with respect to the quarter, the current operating conditions and the outlook for the future as we see it. We generally shortened our commentary in an effort to leave more time for questions at the end. Several members of our management team are in the room here today and are available to answer any questions. In the room with me is Chika Onwuekwe, our VP, Legal and General Counsel; Todd Thue, our COO; and Daniel Lopushinsky, our VP, Planning and Analysis. I'll now turn the call over to Scott.

Thanks, Brad. So just before we begin, I'd 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 second quarter 2022 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 Q2 2022 MD&A and our MD&A for the year ended December 31, 2021, for a more complete description of the business risks and uncertainties facing Trican. These documents are available on our website and on SEDAR. During this call, we will refer to several common industry terms and use certain non-GAAP measures, which are more fully described in our 2021 annual MD&A and in our second quarter 2022 MD&A. Our quarterly results were released after the close of market last night and are available both on SEDAR and on our website. So with that, let's move on to our results for the quarter. Most of my comments will draw a comparison to the second quarter of last year, but I'll also provide a few comments with respect to our results comparing ourselves to Q1 of 2022. Revenue for the quarter, $153 million was an increase of about 63% compared to the same quarter of last year. Activity levels during the quarter were generally higher than last year's period with many of our customers not quite able to complete their Q1 '22 programs as cold weather delayed operations at the beginning of the year. So a portion of that work that was expected to be performed in Q1 of 2022 carried forward and got completed in early Q2. Commodity prices remained strong through the quarter, and we had relatively favorable weather conditions throughout, which allowed our customers to work effectively through their programs, resulting in a somewhat more muted spring breakup than many prior years. We realized some price improvements across our service lines during the quarter, a contrast to typical Q2s where pricing often declines, but it didn't really translate into significantly higher margins as better pricing only served to offset continued inflationary pressures based in all of our major cost categories. From an activity perspective, our overall job count year-over-year was relatively flat, but total profit comps, a good measure of well intensity and activity, was up about 7% year-over-year, with average tonnage pumped per job increasing, reflecting the company's strong position in the deep technically challenging work found in the Montney and Deep Basin areas. Adjusted EBITDA for the quarter came in at $19.2 million, a significant improvement over the $14.2 million we generated in Q2 of 2021, especially considering that last year's results included about $6.1 million of contribution from the Canadian emergency wage and rent subsidy programs that did not occur this year. I would also note that our adjusted EBITDA figure includes expenditures related to fluid and replacements, which totaled $1 million in the quarter, $1 million in the quarter and that we expensed during the period. Adjusted EBITDA for the quarter came in at $23.6 million, a significant improvement compared to the $16.2 million we printed last year, again, with last year's results, including the contributions from the wage and subsidy programs I noted earlier. To arrive at EBITDAS, we effectively add the effects of cash settled stock-based compensation back to more clearly show the results of our actual operations without some of the financial noise related to these amounts. We continue to make progress in monetizing some of our stranded assets, including excess real estate, with a number of transactions closing in the quarter, bringing in about $15.1 million in cash proceeds and generating $2.3 million in net gains on disposal. On a consolidated basis, we generated positive earnings of $1.5 million in the quarter or about $0.01 per share. And I would note that achieving positive earnings in the second quarter is no small feat and something that we're very pleased with. We generated free cash flow of about $14.6 million during the quarter as compared to $9.6 million during Q2 of last year. And our definition of free cash flow is essentially EBITDAS less any nondiscretionary cash expenditures, which include interest, cash taxes, cash settled stock-based compensation and maintenance capital expenditures. CapEx for the quarter totaled about $24.7 million, split between maintenance capital of about $4.0 million and our growth or upgrade capital of $20.7 million dedicated mainly to our ongoing capital refurbishment program. And through that ongoing program, we're upgrading a portion of our conventionally powered diesel pumper fleet with low emissions natural gas burning Tier 4 DGB engines. Balance sheet remains in excellent shape, we exited the quarter with positive working capital of approximately $115 million, including net cash of $28 million and no long-term bank debt. And finally, with respect to our ongoing NCIB program, we remained quite active during the quarter and repurchased approximately 2.6 million shares, bringing our total shares repurchased to June 30 to 5.4 million shares at an average price of about $3.63 per share. We continue to view share repurchases as a solid investment opportunity and a portion of our capital continue going there in the context of returning capital to shareholders. So with that, I'll turn things back over to Brad for comments on our operating conditions and our outlook going forward.

Thanks, Scott. Overall, Q2 was better than prior years. We still experienced seasonality in Canada due to the spring falling conditions, and that does restrict access to the well site. So Q2 has no matter how you regardless of the weather or people's intentions, you're always going to have a reduced program in Q2. But fortunately, it appears that the trend now is for a busier breakups than historically we've experienced. And I think it's just a combination of better planning and logistics with respect to multi-well pads, which allows more work to continue on through the quarter. And I think a lot of our customers are bonding roads, et cetera. So the quarter overall was very good. We did have some relatively significant project delays though heavy rains in June pushed a fair bit of our work out of June and into Q3. We continued to see cost escalations in Q2, primarily driven by increased diesel costs. And as everybody knows, diesel prices affect almost everything in all aspects of our business, including products, third-party trucking, just day-to-day life requires a lot of hydrocarbons to make it go around. We continue to see fuel service charges on rails, which are significant, and this obviously impacts our costs on sand and chemicals. We held firm on pricing and flow through the most of the inflation to our customers. We didn't discount any of our prices like historically you have seen, and I think that will be the trend of the future. But inflation is significant, and it takes a lot of effort to keep up with it and make sure that we not only keep up but get ahead of it. And I think we have done that now. When we look at Q3 and Q4, we expect the second half of the year to be quite busy as commodity prices remain high. Our third quarter is fully booked and our Q4 is quickly booking up. And typically, at this time of the year, we have fairly good visibility leading up to Christmas. And from everything that's on the board today, in the second half of this year is going to -- it should be really busy and which should be a great year. We're very happy with our start to the quarter. We're very busy. July should be a great month. We've got really good activity in the field. The weather has cleared up, and I think we're up and running quite efficiently. We've so far this month, we've been setting records in daily sand volumes pumped. We've got all of our people and equipment in the field and operating very, very efficiently. From a frac and cement crews perspective, we think the basin will very soon be approaching capacity, and it should stay at capacity for the remainder of the year. In the coil market, I think we're already there. In fact, I think we've been undersupplied in coil now for the past few months. And if we could, we would probably double our coil division. It's very, very active and the margins are quite attractive. We're operating 7 frac crews and 7 coil crews. Out of the 7 frac crews, 2 of the fleets are the new Tier 4 DGB equipment, which runs on natural gas instead of diesel. And we're operating at about 60% of our capacity in the frac division. So we're running sort of 7 out of 12 frac crews. On the cementing side, we're running about 17 crews. That provides us with an overall market share of sort of 35%. But in the Deep Basin in the Montney, our market share would be quite higher than that. We expect our cementing business to be very busy throughout Q3 and Q4. And as rigs get added to the field, obviously, we are hoping to add more cement crews to try to keep up. Today's rig counts in the low 200s, which is 50 more rigs than we had at this time last year. So again, it's just -- it's more evidence that the second half of 2022 should be very busy. Our customers remain very disciplined with respect to their capital budgets. They're focused on returning capital to their shareholders, paying down debt and I think just taking a very financial approach to their projects. It's important to note LNG activity has started in the field from a drilling perspective. I think we're all expecting the LNG facility in Kitimat to be on stream, I think, in 2025 and the drilling activity now has sort of officially started. And from what we understand, LNG Canada is behind on their gas production. And so we expect that as the months go buy the LNG-related drilling activity will do nothing but increase. We are gaining traction with respect to net pricing. It's been difficult keeping up with inflation to date, but I think we finally sort of beat it with respect to the rate of change. And these improved pricing and higher activity levels that will require additional crews in the field will ultimately contribute to better margins and an increase in free cash flow for the second half of this year. We are expecting margin expansion both in Q3 and Q4 compared to Q1. People are going to be the bottleneck, I think, for the next few years. Any crew additions require a long lead time to try to find people. We are actively recruiting throughout Canada. We have had some successes lately. We take great pride in our staff and the work they do. We're very fortunate that everybody at Trican is very committed and we have an excellent safety record. Without their dedication, we wouldn't be able to operate as efficiently as we have, especially through COVID in the last few years. Retention remains one of our top priorities as we are attracting new people to the industry that are working in the oil and gas industry for the first time. And we're still seeing that the -- there's more attractive lifestyles that they may want to leave for. Fortunately, these are really high-paying jobs, and we're focused on making this as a good place to work for our people. We're starting to see some of the cost inflation stabilize. The rate of change since basically Q4 of last year was extremely steep. And I think that has sort of leveled out a little bit here. And even though the inflation is, I think the rate of change of inflation is slowing. We're still our supply chain is still stressed, particularly in sand. We think the sand mines and the rail is operating basically at capacity, and we do expect some temporary stand shortages to occur in the second half of 2022. And we have a great logistics and planning department. And so when we look at this, one of the services that we're able to offer our customers is just reliable services. And we are well ahead of the -- what we think will be sand and chemical shortages, and we've made plans to make sure that we manage through that as efficiently as possible. We're -- third-party trucking is also one of the bottlenecks in the industry. And just logistics, in general, is moving this much sand around takes a lot of effort, a lot of planning, and we expect this to be extremely tight for the remainder of 2022. There's less trucks in the basin today. So it takes just that much more planning ahead of time to make sure that we're operating as efficiently in the field and minimizing any delays for our customers. It's important to note just on how operations in the field are working today like as an industry, in the last 4 years, we've become extremely efficient with our operations. We've gone from pumping sort of 14 to 16 hours a day to over 22 hours a day now. And up until now the customers benefited from all that efficiency as all that -- all those cost savings were passed on. And we're starting to get some of that back. And I think what we'll see is as margins expand, we'll be able to bring more equipment into the field. We've made great strides with respect to technology and innovation. We're very focused on running the latest state-of-the-art equipment, providing chemical solutions that reduce freshwater consumption and more environmentally friendly products that whether it's isolating water zones with cement using produced water at a fresh water, reducing emissions in the field, we've taken great strides to invest in our technology to make sure that we're providing the best service as possible. Our guiding principle is clean air, clean water. And so when we think about the services that we want to offer, we want to make sure that they're sustainable throughout the next decades, not just through the rest of the year. On the Tier 4 side, we rolled out our first Tier 4 frac spread in very early Q1. We're very happy with the results. We have over 2,400 pumping hours on that crew to date. Our second Tier 4 spread is now in the field. It's not yet an incremental fleet. It has displaced older conventional diesel equipment. And until we can get the staff trained and operating efficiently, we won't have an incremental crew in the field. We expected incremental crude come late this quarter. So that will be our eighth frac spread. We are adding an additional third Tier 4 spread, and that will be field ready by the fall. I'd say sometime in the fall in Q4. We do have customers lined up for this equipment and we're very fortunate that we've had numerous customers test the Tier 4 technology. They've all been very happy with it, and they're basically asking for more Tier 4 equipment than we can provide. We're very impressed with the Tier 4 equipment and its performance to date. It's lower emissions, lower operating costs, high-performance pumps that are more reliable and have less people on -- require less people on location. And of course, all of this results in higher profitability compared to our conventional equipment. We are able to charge a premium for this equipment and the customer is saving on diesel costs. And we do expect this technology to be the standard in Canada in the next few years. And fortunately, for us, we made this call about 1.5 years ago. And so now we've got more than a year ahead start on our competition with respect to getting this equipment into the field. On the return side, I want to make a comment that Trican is very focused on free cash flow and return on invested capital. These are without a doubt, the most important metrics when you're analyzing a pressure pumping company. There's always a tendency to want to talk about EBITDA, but just based on the age of the fleet in Canada and the difference in accounting policies, we urge you to focus on free cash flow and returns on invested capital. We invest based on long-term predicted returns, not operating margin or market share. We continue to sell older more obsolete equipment to try to recirculate that capital into new technologies. And fortunately, for us, if you are looking at EBITDA, a vast majority of our EBITDA converts into free cash flow. And I'll just wrap up with some comments on our NCIB program. As Scott said, we continue to view the NCIB as a very attractive investment. Year-to-date, we've purchased just over 8.5 million shares or 3.5% of our outstanding shares. We intend to increase our participation in the NCIB in the second half. We remain committed to this as an investment, and we have both a consistent monthly budget and an allocation funds for one-off purchases if the market disconnects from how we view the future of our basin. So we continue to be active in that, and we look forward to reducing our share count. I think I'll stop there, and I'll hand over the call to the operator.

[Operator Instructions] The first question is from Keith MacKey with RBC.

Just to start out on the 8 fleet, I think Brad said it's going to be incremental and in the field by later this quarter. Can you just give us a little more context around the staffing of that fleet? Is it fully staffed and now a matter of training? How many of the personnel for that fleet have been recruited from outside of the province? Just a little more color on that. And I guess it will also affect what happens with the 9 fleet when you get your third Tier 4 DGB later this year. So maybe just a little commentary on staffing these 8 and 9 fleets and will they be incremental or will we see some replacement of existing diesel fleets for -- as the new equipment comes in.

Yes. Just from a recruitment perspective, we're actively recruiting throughout Canada. I mean it's not relevant as to where people are coming from with respect to what equipment they work on. But it does take time a lot longer now than it used to. It used to be the recruiting cycle, could be 3 months long. You could wait until the last minute basically to try to recruit incremental equipment that's going to crew incremental equipment that would be going into the field. Now the lead time on people, I would say is 6 months. It may be more. And we're drawing from a pool of people that haven't worked more so now. We're drawing from people that haven't worked in the oil patch. And so there's more training that may be required on whether it's just getting familiar with the equipment or driving, getting a Class 1 license, et cetera. So the recruiting and retention of people into our industry is more important now than it has ever been. They're very great paying jobs. We think it will be a stable career for the next few years at least. So we're trying to sell those attributes of our industry. But as we all know, like unemployment is low throughout Canada and COVID has restricted travel from Eastern Canada into the oil patch. Of course, people are not interested in coming to work here unless they know they can go home for their days off. And as the restrictions are lifting, we're getting more interest. So when you think about adding incremental fleet into the field, it takes a long time. And typically, what's going to happen with fleet 8 and 9 as the equipment is going to come into the field, it's going to displace either diesel equipment or dual fuel equipment. Our new Tier 4 equipment is much more efficient, much more desirable by the customers, provides lower emissions, the higher, more reliable pumps. So there's definitely -- that's our first -- that's our customers choice of equipment if they have the option. So we'll bring the equipment into the field. we'll displace older gear. And then as we're happy with our crews, it will become incremental spreads. But the exact timing, we just -- we can't make that prediction.

And you mentioned some LNG drilling has started up. Just curious if you started to see some of the RFPs on the frac side for that drilling. And if you can just talk a little bit more about what you've seen there, if anything, and when you expect to see more RFPs to follow up some of this drilling that's occurring?

Yes. We have seen RFPs on the completion side for one of the participants of LNG Canada, when we're going to see more, I don't know. But from what we understand, just from the information that's publicly available. LNG Canada is 0.7 of a Bcf a day short on their commitments. And of course, they can always buy the gas from other companies operating in the basin. So be careful not to imply too much from that information. But generally, what that tells you is there's going to be activity in the basin. That's LNG-based. LNG, obviously, is a very, very long-term project. And so there's just a layer of consistent Montney drilling that is going to get -- it's going to be in place that we've never had before. So we're not only excited for Canada to participate in the global LNG market. And as we all know, the world needs more Canadian oil and gas. But it's very -- it's just nice to have some reliable, consistent projects that are occurring.

The next question is from Aaron MacNeil with TD Securities.

A couple of questions on the new DGB engines. Now that you've got more data, can you give us a sense of what the actual fuel savings are in percentage terms on a metric ton basis, whatever you think really, I guess, it doesn't really matter, just whatever you think on as you compare to the fuel cost of a Tier 2 engine or a biofuel engine?

I mean there's so many -- I mean I understand what you're asking and why you're asking me. Unfortunately, there's just so many operating conditions that greatly influence the fuel consumption. So it's hard to say. But it's not unusual for there to be $70,000 a day savings on a large frac spread on fuel or on a per well basis, sorry. So it's significant. The price of natural gas, even at these prices is a lot less than $2 a liter for diesel.

And then as the follow-up, I assume that those savings are somewhat shared between you and the customer with higher pricing offset by lower costs. But I guess the question is, are you delivering a lower all-in completions cost to your customer, even though you might be charging more for the fleet?

Generally, yes. because there's so much that goes into completions costs like -- just things like time and location, right. This equipment is so efficient that we're just -- we're getting wells done quicker than ever when you compare it to our other equipment.

[Operator Instructions] The next question is from Waqar Syed with ATB Capital Markets.

Brad, what's the cost of a Tier 4 upgrade these days?

Well, I hate to say this, but it depends. I mean part of -- because as you know, we're retrofitting equipment. And so it really depends on the state of the equipment that you're retrofitting, whether it needs a rebuilt pump or brand new pump. It is very fair to say that our costs, as we continue to go into our park fleet of equipment, the costs are climbing. And I've made these comments before, I mean, Trican, like every other competitor in the basin has equipment parked and the age of the typical frac fleet in Canada is not young. It can easily be 10 years old, 10 years-plus old. So if you're going into an old 2,500 horsepower pump that was built in 2011 that pump may need to be replaced by now, may not be worth upgrading. And so I mean, when we started down this road, we were about CAD 20 million in retrofit costs that has climbed to CAD 30 million. And it's a combination of both inflation from cat on the price of these engines and just the requirements for new pumps and transmissions versus rebuilt pumps and transmissions.

And if you were to do it like a completely new fleet, what would the cost be there?

Like a brand new frac fleet with Tier 4 pumps would be $50 million-ish.

And that will be like a 30,000 horsepower or 35,000?

No. That would be...

40,000.

40,000.

40,000? Yes. Okay.

Or 14 times 3,000 or like 14 pumps at 3,000 horsepower.

Okay. Makes sense. Now in terms of -- as you talk to your customers, what are you hearing from them about the typical seasonality that you see in Q4? What's your early thoughts? How would that look like?

I don't think anything's changed. I mean in the past, I would say there's more sort of focus on budget exhaustion versus seasonality. I mean, there's always weather interruptions. It doesn't matter what quarter of the year in Canada. We work in the north. It's remote. We have 4 seasons. And every time you have a change of seasons, there's issues, right? So there's always weather delays in Q4. And then, of course, we have the Christmas slowdown in Canada, Christmas is a much bigger event than Thanksgiving. But obviously, based on its adjacency to New Year's, the Christmas slowdown can be a couple of weeks. So there's always those issues. I don't think budget exhaustion is going to be as big an issue this year as it has in prior years.

Okay. All right. And then so far in first half, your -- the EBITDA margins have kind of lagged last year's first half. Do you see a substantial pickup in second half versus second half of last year?

Yes. Sorry, you're asking second half of this year versus second half of last year?

Yes, that's correct. Yes.

Yes. Yes, we expect the margins to be higher.

Yes. Just the other point I'd add, Waqar, is just to remember to normalize last year's operating results and margins for the amount of wage subsidy programs that came in there, right? So...

Fair enough. Fair enough. And Brad, in terms of -- you mentioned about sand shortages and chemical shortages and certainly those issues. But could you maybe talk to the magnitude of that? Do you think that industry activity is going to get disrupted? We've not been able to get things done overall in the industry. Or is it more kind of a nuisance that's going to be handled and there's going to be some price inflation, and that's about it?

Yes. I think I do actually expect there will be short-term shortages. And by short-term, I mean sort of a day or 2. So it is going to be -- I would say it's going to be, though, a more consistent nuisance. And will we get it done? Yes. But when we look long-term, we're always looking a few years down the road. And so are we thinking about sort of sand supply and chemical supply in the volumes because the volumes have grown on a per well basis and as the well count grows, you can have some fairly steep increases in the total tons of sand being pumped. So yes, we are thinking about -- we are working with our suppliers on making sure that their operations are matching what we're seeing.

Yes. And just one final question. Any early reads on CapEx for next year?

No. We're very happy with the Tier 4 performance. And so yes, I think it's a fair assumption that we are going to continue to retrofit our equipment with what we view to be the best technology at the time. And right now that's the Tier 4 DGB engines. If something better comes along, we're completely agnostic to technology. And so we'll put the best technology into the field.

So would it be fair to say that at minimum CapEx could be relatively flat, at least flat 2023 versus 2022?

Yes. I think that's reasonable.

Yes. And just one last -- sorry, I get one more in maintenance CapEx per fleet, what is that running?

I don't think like in fleet terms 3%-ish, like maintenance capital, you can roughly predict is around 4% of revenue.

[Operator Instructions] The next question is from John Gibson with BMO Capital Markets.

I just had one quick one here. You spoke about some debt pricing increase hitting your fleet. Just wondering if you could give a sense of what proportion should benefit from the higher net pricing starting in July? And then how will that sort of change at the back half of the year progresses?

I'm not following you, John. What proportion...

I'm just wondering what percentage of your fleet will actually benefit from higher net pricing increase as the year goes on?

Generally, all of it.

The next question is from Cole Pereira with Stifel.

Just wanted to quickly build on John's question. I mean, maybe it's a bit tough to answer because it's going to vary between customers. But I mean, you're willing to sort of add any details on what that net pricing increase might be, say, on average compared to Q1?

No. I have made public comments before that we were targeting a net price increases of 10%. And we've been very open with our customers that it's frustrating for them because we've just had -- we've had very significant price increases that they've obviously taken on, and it's frustrating for us because almost none of those price increases went into our pockets. And so we're fortunate our customers understand we need to make money. And so we've been more vocal about the need for Trican to gain from these price increases. And generally, it's gone pretty smoothly. And it's not -- we're not talking big numbers. We're targeting what I've already mentioned, which...

And coming back to the incremental Tier 4s. I mean, you kind of mentioned earlier, you think the frac market is sort of at capacity and you're adding a fleet here in Q3 and another in Q4. I mean, is it a function of just your current program? You have line of sight that that shouldn't oversupply the market? Or is it more a function of pricing is getting high enough to justify the activation? And I mean, with the fleet coming in Q4, do you think Q4 is actually going to be stronger than Q3 or how should we think about that?

Yes, I'll just maybe address. I don't think -- I think very rarely Q4 will ever be stronger than Q3 just due to the onset of winter and the Christmas break. It's very hard for Q4 to be in excess of Q3. And just with respect to the equipment additions, you have to remember this isn't just generic equipment that's going into the field, right? So it's very targeted additions with respect to customer demand for Tier 4 technology. And we don't -- this is priced at a premium, and we're prepared to park it if we don't get the right price for it.

And some commentary in the industry just about bottlenecks in the event that you touched on. Can you just comment on how pricing specifically for that service line should be in the second half and as well maybe on the cost inflation front?

Yes. Cement has probably experienced some of the most significant cost inflation starting back in Q4 of 2021. And so we really had to be on our toes to keep up with price inflation or our cost inflation. So -- but in general, we're fairly consistent across our service lines with respect to price increases.

And you mentioned you plan to increase your share buybacks. Can you just give somewhat of a quantum of that whether in percentage or dollar terms?

Yes, I'd say we've been buying back roughly $3 million of shares each month over the last 6 months. So I would expect that will be our baseline. We'll probably pick that up a little bit. And then as Brad mentioned, we've got some opportunistic funds set aside as well. So you could expect that that regular cadence that you saw in the first 6 months will be a bit higher in the back half, plus we'll be able to take advantage of some of the price disconnects that we're seeing.

Yes. Just for modeling purposes, I'd use $4 million a month. But there is -- depending on where the share prices go, that can influence that. But at these levels, I would say $4 million a month, it should be pretty close $4 million worth per month.

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

Okay. Thank you, everyone. We appreciate your interest in our company. And Scott and I and the rest of the management team will be available for any follow-up questions that anyone may have throughout the day. So please call us directly if there's any more questions. Thank you.

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