Earnings Transcript for TOLWF - Q3 Fiscal Year 2024

Operator: Good morning, ladies and gentlemen. Welcome to the Trican Well Service Third Quarter 2024 Earnings Results Conference Call and Webcast. As a reminder, this conference 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 Limited. Please go ahead, Mr. Fedora.

Brad Fedora: Good morning, everyone. Thank you for joining our Q3 call. First, instead of Scott Matson, who is traveling today, Desmond Ho, our Director of Corporate Finance, will give an overview of the quarterly results. And then, as usual, I will provide some comments with respect to the quarter, the current operating conditions and our outlook for the rest of this year and next year. And then we’ll open the call for questions. We have several members of our executive team in the room today and everybody will be available to answer questions, not only during this call, but for the remainder of the day. I’ll now turn the call over to Desmond.

Desmond Ho: Thanks, Brad. 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 MD&A for Q3 2024. 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 2023 Annual Information Form for the year ended December 31, 2023, for a more complete description of business risks and uncertainties facing Trican. This document is available both 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 Q3 2024 MD&A. Our quarterly results were released after close of market last night and are available both on SEDAR and our website. So with that, I’ll provide a brief summary of our quarter. My comments will draw comparisons mostly to the third quarter of last year and I will also provide some commentary about our quarterly activity and our expectations going forward. Trican’s results for the quarter compared to last year’s Q3 were solid but not quite as strong as last year as certain customers delayed portions of their capital programs. Programs were delayed for various reasons including water restrictions in some specific cases, well licensing requirements and customers generally managing their capital programs through the last half of the year in the face of challenging commodity price environments, particularly natural gas pricing. Revenue for the quarter was $221.6 million with adjusted EBITDA of $50.2 million or 23% of revenues. Not quite as strong as adjusted EBITDA of $65.7 million or 26% of revenues we generated in Q3 2023 but still solid. Adjusted EBITDAS for the quarter came in at $53.1 million or 24% of revenues. To arrive at EBITDAS we add back the effects of cash settled share-based compensation recognizing the quarter to more clearly show the results of our operations and remove some of the financial noise associated with changes in our share price as we mark-to-market these items. On a consolidated basis we continue to generate positive earnings producing $24.5 million in the quarter which translates to $0.12 per share on both a basic and fully diluted basis. Trican generated free cash flow of $32.4 million during the quarter. Our definition of free cash flow is essentially EBITDAS less non-discretionary cash expenditures which include maintenance capital, interest, current tax and cash settled stock based compensation. You can see more details on this in the non-GAAP measures section of our MD&A. CapEx for the quarter totaled $15.2 million split between maintenance capital of about $10.4 million and upgrade capital of $4.8 million. Our upgrade capital is dedicated mainly to the electrification of ancillary frac equipment and ongoing investments to maintain the productive capability of our active equipment. The balance sheet remains in great shape. We exited the quarter with positive working capital of approximately $136.5 million and expect to release a bit of working capital as we move through Q4 and exit the year in a similar strong position. With respect to our return on capital strategy we repurchased and canceled $7.5 million shares under our NCIB program in the quarter. Subsequent to Q3 2024 we purchased and canceled an additional 1 million shares and continue to be active with our buyback program. The 2023-2024 NCIB program was successfully completed on October 2, 2024, resulting in the purchase of 21 million common shares, the full 10% of our public float allowable under the program at a weighted average price of $4.51 per share. On October 2, 2024 we announced the renewal of our NCIB program which will allow us to purchase up to 19 million common shares, again 10% of our public float at renewal. The renewed program is scheduled to run from October 5, 2024 through October 4, 2025. As noted in our press release the Board of Directors approved a dividend of $0.045 per share reflecting approximately $8.5 million in aggregate to shareholders. The distribution is scheduled to be made on December 31, 2024 to shareholders of record as of close of business on December 13, 2024. I would like to note that the dividends are designated as eligible dividends for Canadian income tax purposes. With that, I’ll turn things back to Brad.

Brad Fedora: Thanks. My comments will include Q3 and what we’re seeing in the market today. Overall, even though we were happy with the quarter, it was softer than we expected. As you may recall, we talked about this in the summer that certain customers had moved Q3 work forward into Q2 to avoid potential water restriction and drought issues and forest fires, et cetera. So that took some of our July-August work and bumped it into Q2 and then we also had some customers move some work from September into Q4. And so, overall, the quarter was a little lower than we were hoping for. Considering where gas prices are today, we’re still really happy with the activity levels, and as a result of the work moving out of September into Q4, we are expecting a really good Q4. But generally, the rig count remained pretty resilient throughout Q3. Given where commodity prices or gas prices were, a lot of those rigs are focused on the oilier plays like the Clearwater and SAGB [ph], so they’re not very fracturing intensive or there’s no fracking work in those plays at all. As a result, our frac revenue was down 18% year-over-year and EBITDA in that division was down about 25% as well. On the flip side, in general, cost inflation basically had stopped for Q3. In fact, we actually experienced some cost reductions in certain areas, which helped mitigate the pricing pressure we experienced and we were able to maintain reasonable margins. We’re still running with seven frac crews. Nothing’s changed. We remain very disciplined in the market, which means we’re only operating about 70% or 60% of our total horsepower, operating seven of 12 frac crews. I think most of our competitors are basically operating at capacity, which means that we possess most, if not all, the spare capacity in this basin. We are going to continue our focus in the Montney, in the Duvernay, in the Deep Basin. Nothing’s changed there. On the cementing side, the cement division continues to operate at high utilization, generating great results in Q3. It’s an indication of the expertise in the market share that we experience in that service line. Our revenue was up 7%, and our EBITDA was up just over 1% in Q3. That’s just a result of the well designs in the areas that we work in, which is generally places like the Montney and the Deep Basin, where we enjoy almost a 50% market share. So we’re very happy with the performance of this division. We expect it to perform well. We do see that division trailing off as Q4 unfolds and everybody finishes their programs and we get into the Christmas slowdown. But, overall, we’re very happy with the performance of that division and expect it to perform well for the years ahead. On the coil tubing side, we’re still trying to build up that division, focused on growing our market share. We enjoy good field margins, but the scale of that division is still too low. It’s still too small. Revenue was down about 5% in Q3 year-over-year and the profitability although good in the field, is not great at the bottomline division level just due to its overall scale. So we’ll continue to focus on building that out. We’re very excited about our partnership with Atos, which is a specialized tool company. The oil plays throughout the Western Canadian Basin. We expect our coil division to grow its market share as that tool gets deployed in Canada. So we’re all up for Q4 in 2025. And as I said, as a result of work moving out of September into Q4, we actually expect Q4 to be quite busy as customers complete their programs for this year. We’re very happy with our results quarter-to-date, which is the end of October. We actually expect our Q4 to exceed expectations of the market and beat our Q3, which is not typical. It’s just based on the fact that we had work move out of September and into October and November. We are -- it’s fortunate that the gas strip for the rest of this year and into 2025 remain at very economic levels. So we are expecting -- that combined with the financial discipline of our customers, we’re expecting activity in 2025 to be basically near 2024. As always, any time you have periods of lower-than-expected activity, which we saw in Q3 and depending on who your customer list is in Q4, we are experiencing some pricing pressure just from our competitors. That’s to be expected. We’ll sort of -- generally sort of soldier through that. Everybody is still very focused in the Montney. I would say that Duvernay, which we’ve discussed in the past, is working out as good or better than expected. It’s very service-intensive for coil and cement as well. So we’re excited about that play as it builds momentum. Our corporate strategy, nothing’s changed. Our priorities are to build a resilient, sustainable and differentiated company. We’re currently modernizing our systems internally and just getting ready for the next five years to 10 years as this company evolves. I mean, as I’ve discussed before, Trican has been active in Western Canada for over 30 years and so we’re in the phase of the company where we’re having to upgrade all of our systems and make sure that we can take advantage of the technology and anything that may happen with AI going forward, making sure that our systems are prepared for that. We also want to invest in high-quality growth and upgrading opportunities to ensure a value-added product and service offering to our customers. That’s the bottomline with any service company, making sure that we’re providing value to our customers that our competitors cannot add. With that, that all should lead to a consistent return of capital to our shareholder in the form of dividends and share buybacks and share appreciation. And even though the market’s a little choppier these days, just given where gas prices are, we’re still very bullish on Canada over the next five years. We view Western Canada as an attractive place to grow our business. We’re still focused on being a Canada-only company at this stage and even though spot gas prices are lower than we would have hoped at this time of year, we expect as LNG comes on that that will correct itself. We’re actually looking forward to a fairly significant appreciation of gas prices next year. As a result, we -- 2025 activity levels should mirror 2024 with some upside potential in the second half of next year once LNG exports start flowing off the West Coast. We’re still seeing active drilling in Northeast BC, Northwest Alberta, which is all feedstock for the LNG facility. We do expect, based on what we’re hearing, an investment decision on Phase 2 of LNG Canada next year. We assume it would be a positive decision, which basically will double the capacity of that facility and then the other facilities along the West Coast continue to work through their various approval processes and FID processes. So we’re expecting that LNG off the West Coast of Canada will be a significant -- will have a significant impact on Canada in the next five years to 10 years, providing a great backdrop to grow this business. TMX is operational, as everybody knows, which has reduced the differentials there. So, the -- everything’s playing out quite nicely in Western Canada. Our customers, in the face of all this, are maintaining very disciplined capital programs. They’re only spending about 50% of their free cash flow on drilling and completions and their balance sheets are still in great shape. So the volatility of activity from year-to-year has been greatly reduced, which is great for a service company. It allows us to maintain staffing levels at more consistent levels and it provides more of a career opportunity for our employees. We’re finding now our voluntary turnover is down to about 4% in our staff, which is unprecedented in the services sector. We have good free cash flow, and importantly, a very clean balance sheet designed to allow us to execute on our plan and take advantage of any volatility or consolidation opportunities as they arise over the next few years. I’ve discussed sand logistics in the past and I’m just going to give a brief update on that. Everything’s sort of going as planned. We’ve seen sand volumes grow, particularly in the Montney and the Duvernay, on a per well basis. It wasn’t that long ago we were pumping 5 million tons to 6 million tons of sand in Canada. Now that number is well over 8 million tons. So we’re not expecting this trend to really change. We’re still seeing the length of horizontals grow, the amount of sand per stage grow, so we’re sort of positioning ourselves to make sure that we are operating efficiently with respect to moving ever-increasing volumes of sand, with a very keen focus on last-mile logistics to make sure that we are moving transporting sand profitably. Our partnership with Source is unfolding nicely. The facility will be ready in -- before Christmas with sand loading from rail to truck and this is a facility that we’re building in Taylor, B.C., which is Northeast BC in the heart of -- basically in the heart of the Montney. This partnership will benefit Trican from a strategic and cost perspective and the whole facility should be operational in Q1, which will give us storage facilities, as well as loading facilities to service our customers in Northeast BC. What this does is allows us to use our trucking fleet more effectively, ensure our customers that sand will be delivered to their location in an efficient manner as possible. It’s not uncommon for us to deliver 40 tons of sand every 12 minutes for days on end. In order to do that, you have to ensure that you have a trucking fleet that’s working efficiently and making sure that you have the sand volumes available to those trucks at the transload facility. So we’re continuing to work on our logistics and our last-mile logistics in particular, and we expect that that will be a revenue and profit source for this company going forward. On the technology side, we’ve kind of gone sideways here for the last year. We’ve been reviewing a few different pumping equipment technologies in our fracturing department with the ultimate goal that we want to have 100% natural gas-fueled operations on location in the future. We think this 100% natural gas-fueled operation is the cornerstone of any technology strategy here at Trican. As everybody knows, natural gas is very abundant in Canada, burns cleaner than diesel, and on an energy-equivalent basis is much less expensive than diesel and sort of the example that we use, which I think is easy for everybody, is $3 gas is essentially the equivalent of $0.15 diesel on an energy-equivalent basis. So it’s a huge cost-saving opportunity if you can get your equipment to run on natural gas. As you’ve seen some press releases recently, we’re also starting to think about, do our sand logistics trucks run on natural gas instead of diesel? I’m sure over the next few years we’ll see that evolve as well. There’s various pumping technologies available, each with their own pros and cons. We’ve deployed the Tier 4 DGB engines over the last couple of years very successfully. We’re also trialing an electric frac pump right now. We’ve deployed the electric ancillary fracturing equipment, which is things like the blender and the chem band and sand handling equipment, et cetera. That’s gone very well -- very well received by our customers. You’re seeing in the marketplace there’s also turbines, 100% natural gas engines. So we’re reviewing all of that and we have been now for several quarters. We are -- even though we’re actively deploying our Tier 4 DGB technology and our electric ancillary equipment, we’ll continue to evaluate the various technologies that are available and would make the most sense going forward with the goal of achieving 100% natural gas fuel operations. We expect that we’ll be in a position sometime in the next few quarters to pick a strategy going forward and it very well may be a continuation of our Tier 4. We’ll see. On the return of capital and just value for shareholders, as everybody knows, Trican continues to generate great free cash flow. We maintain a clean balance sheet. We do subscribe to a diversified return of capital strategy through a combination of our quarterly dividends and our NCIB when the NCIB represents a good investment for our shareholders in the context. Of the other growth opportunities and M&A opportunities that are in front of us, we’ll basically just rank our investment opportunities and pick the ones that are best for our shareholders over the long term. We’re not afraid to dip into our bank lines if we find something attractive or we feel like that our shares are way undervalued. So we maintain a fairly robust bank line of about $150 million and we won’t be afraid to use it when the right opportunity presents itself. I think as Desmond had mentioned, we did complete -- we did fully complete our 2023-2024 NCIB program in very early October. We bought the full 10%, which was just over 21 million shares at an average price of about $4.50 a share. I’m looking at Desmond.

Desmond Ho: Yeah.

Brad Fedora: He’s nodding, so that’s good. We did renew our NCIB program for another year and we’ve been active in that since we started it on October 5th. We are active in the market every day. Like, we purchased a 1 million shares or so over the last month and we continue to evaluate this and everything else, and we expect to deploy our capital accordingly. Our dividend program, we do renew it at the end of each year, which I guess is in Q1 of next year. And we -- as we’ve discussed previously, we will adjust our dividend to account for the number of shares that we bought in the prior year, holding that annual aggregate dividend payout in the $36 million range and so we’ll just make those adjustments based on the math. I think I’ll stop there and we’ll go to questions.

Operator: [Operator Instructions] The first question comes from Keith MacKey with RBC Capital Markets. Please go ahead.

Keith MacKey: Hey. Good morning. Just maybe wanted to start out on this 100% natural gas-fueled strategy. Just curious what you’d need to see in order to be comfortable picking a strategy and then maybe what you’d need to see in order to be comfortable putting some of that equipment into the field from a contract perspective. Certainly, the U.S. market’s been ahead of Canada and it seems to have come to a mix of DGB, electric and then natural gas reciprocating type engines. So, maybe Brad, can you just kind of walk us through a little bit of that, what you’re seeing so far and then ultimately what you’d need to see to be comfortable picking a strategy and putting some of that equipment into the field?

Brad Fedora: Yeah. Yeah. I mean, that’s the core of the issue, because the technology is available for 100%-fueled operations today, whether it’s electric or 100% natural gas engines. Now, they all have their issues from an operating perspective and from a footprint perspective. What is really great about the Tier 4 technology is it gets you to 80%, but there’s very little change in the overall layout of the equipment and the operation of that equipment, and it’s sort of foolproof, because if you have interruptions in gas supply, which is an issue, you can switch to diesel. So, when we look at the various technologies, we’re looking at how effective is it, how reliable is it, what’s the footprint on location, how robust is it with respect to operating in various qualities and pressures of gas supply, because it’s not as simple as sort of hooking up the garden hose from the wellhead into this equipment. They use a lot of natural gas and there are some sort of operating conditions that need to be met with respect to liquids content, temperature, pressure, et cetera. And then, assuming you can work through all of that, you, of course, have to make sure that you can operate the equipment, and most importantly, that you can eventually get a return on that equipment. Like what we’re seeing with the electric equipment is it’s great to operate. Like we have experience now with our ancillary fracturing equipment and the lack of hydraulic hoses, things like that is great, especially in the various, the constantly changing weather conditions and the cold that we experience every Q1. So, it’s great from an operational perspective, but is it reasonably priced and is it -- does it have a reasonable footprint, because there is a trend for these pads to stop growing and actually get a little bit smaller. And so, as an example, one of the challenges with electric equipment is, A, it’s very expensive. You basically double the cost of a fracturing spread when you buy all the electrical generation equipment and all that electrical generation equipment, which runs on natural gas. It has to go somewhere, right? And so operators, they’re not looking to build bigger pads to accommodate all of this. And so, I hope you could sort of sort through the list of things that, we have to think about when we pick a technology. The technology is there. It’s really just how practical is it in a Canadian setting and can you get it at a price that you can generate a return from? And there’s a lot of things, obviously, that go into the cost of ownership and we’re sort of sorting through that with our trialing of the electric pump, because there’s very little sort of off-the-shelf data for any of these technologies with respect to the sort of five-year cost of ownership. So it can be challenging at times to complete your return calculations, but that, of course, is essential, right? Somebody has to pay for this technology, and typically customers are never looking to pay more, right? And so you have to say, in the context of current pricing environments and what I would call fairly flexible contracts, can you generate a return on this equipment in the first five years, right? As we all know, with our cost of capital, the economic or financial returns in years six to 10 aren’t that impactful at our discount rates. And so we don’t really get the opportunity to say, well, hey, this all works out in year seven, eight, nine because you discount that back to today, it’s basically zero at where our cost of capital is, given the size of our company in the Canadian market. But so there’s a lot of things to think about. It’s not just does the technology work or not.

Keith MacKey: Yeah. Got it. Now, it seems like the U.S. model and maybe a little bit more of the drilling model as well has actually used somewhat of a take-or-pay contract to fund some of those upgrades. Is the market in Canada on the fracturing side amenable to that? Like, is that something you think you could actually do or is that how the model would look or would you have to take some of that to return risk on, do you think?

Brad Fedora: Yeah. I think both. There are contracts. I think five years ago I would have said, no, there’s no such thing as a contract and I’ve softened on that. It’s why we’ve softened on our views of debt as well. But there are contracts available. Take-or-pay is a strong term. And I think you’ve seen better contracts on the drilling side than you’ve seen on the fracturing side. And I can’t comment about the U.S. market. I don’t have any firsthand experience there. But there are contracts available here in Canada, and I would say, for the most part, the last few years they’ve been honored, which is new, frankly. But so you can make, I guess, less risky decisions. But at the end of the day, one customer really can’t drive a technological evolution in your company. I mean, you really have to evaluate how does it do -- how does -- where does it stand in the context of the market, where you don’t have surety of contracts. And is it going to be deployed? Are there operational advantages that it presents that it’s going to be employed quite broadly, because, of course, that’s, one spread of a particular technology? That’s sort of almost pointless to pursue something like that. So great to have the contract, but, it has to stand on its own 2-feet in a sort of competitive bidding situation as well.

Keith MacKey: Yeah. Understood. Okay. Well, that’s very helpful. Thanks very much.

Brad Fedora: Okay.

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

Waqar Syed: Thank you. Thanks for taking my question. Brad, as your new construction terminal in British Columbia comes up, how does that affect your operations and both operating efficiencies, logistics and then really how does it impact the bottomline?

Brad Fedora: I’m not going to give you that kind of granular information, but I will say this. We have about 85 trucks today in our sand fleet and they’re currently picking up sand in the Grand Prairie area and taking it to Northeast BC and that is sort of an 8-hour to 12-hour trip depending on where it ends up. And so, the trucks come back empty and that’s in the summer. And in the winter when there’s weather and car accidents and things like that, that length of time can grow very quickly, because it’s a single-lane highway in each direction or a double-lane highway from Grand Prairie to Northeast BC. So there’s lots of potential for interruptions there. By putting a sand terminal in Taylor, we basically cut that trucking time in half. And remember, typical frac companies, the third-party trucking rates. So when you can’t use your own trucks, you have to go into the third-party. There’s no markup on that and so it’s a path -- straight path through versus when we run our own trucks, we make a bit of margin on running, on delivering sand when we use our own trucks. So it’s not -- and I understand you’re trying to figure out how does this impact the model going forward. I mean, it’s not a huge difference percentage-wise, but it’s -- every little bit helps, right? And as the sand volumes grow in the basin and customers are moving towards supplying their own sand, thus removing that area of profit for us. We have to figure out how we’re going to make money in those conditions and I think the best way to do that going forward is through logistics. And then, we’re at the point now where, we think we have enough logistics expertise and trucking expertise that, maybe we can grow this logistics business outside of fracturing and into other parts of the economy. So, we’re very sort of focused on logistics and where we fit into the whole value chain.

Waqar Syed: And where is the Canadian pumping market now with respect to using local sands? Is it still going to be sand imported from the U.S. or customers increasingly shifting towards locally sourced sand?

Brad Fedora: I don’t know if you can hear us whispering in the background. We’re debating whether it’s 50-50 or 60-40. But it depends on the quarter, but in general, if you wanted to apply this to the basin, I would say, 60% U.S., 40% domestic.

Waqar Syed: And is that ratio changing?

Brad Fedora: No. It’s been pretty constant at that for a while now. Sometimes you’ll see it go up to 70% U.S. It just kind of depends on what’s happening. Customers change their minds. Like they try different sand to see if it has an impact on production because, of course, domestic sand is less expensive than U.S. sand given the shorter distances that it has to travel. But there is a crush quality difference as well. But so you do see customers sort of experiment and look for different ways to do things and get the best economics. So, we would say generally it’s 60-40 going forward, but we wouldn’t at all be surprised if that changes.

Waqar Syed: Sure. And then just one last question from me. Could you maybe talk about the overall supply of fleets in Canada today or active fleets and what proportion of that, the fleet count is Tier 4 DGB or next-generation fleets?

Brad Fedora: Okay. So we have about 31 fleets in Canada. Say 22 of those would be sort of Deep Basin to Montney focused. Out of those 22, say, sort of big Montney fleets, there would be seven or eight Tier 4 fleets. We would have five of them.

Waqar Syed: Yeah.

Brad Fedora: And maybe as high as 10 Tier 4 fleets now. It depends. There’s a lot of on-the-come equipment. But I would say, we’re 50% to 70% of the Tier 4 equipment in Canada. And all Tier 4s are not created equal either, what we’re seeing with cars. Tier 4 engines combined with old pumps and transmissions have a high failure rate. We ensure that when we did the Tier 4 upgrades, that we had very robust transmissions and pumps upgraded or we had upgraded transmissions and pumps to make sure that the whole system is very robust. So, we still think, even within the Tier 4 world, we still think we’re leading from a non-productive time by quite a margin.

Waqar Syed: So -- and just one question, if I may, more. You mentioned that, your fuel substitution is close to 90%. That’s pretty impressive. Now, is that an average number and do you know what the average is in the Canadian market, because in the U.S., we hear about 60%, 65% and that may have to do with the temperature and weather and all that. But 90% seems high if that’s the average?

Brad Fedora: Yeah. I mean, it’s -- I think max is 85%, I would say, with the ancillary equipment. So we would have the highest because we have the electric equipment, as well as the Tier 4s. And we have the most experience with the Tier 4 equipment. And so, people like Kath would tell us that we have the highest substitution rates in North America. So I would think the Canadian average is similar. But well-to-well, pump-to-pump, so many things can change. The higher the pressures you get, so you might see lower substitution rates in the Duvernay as you have high pressure where the engines will switch to diesel, trying to get that higher on the torque curve. So it’s hard to sort of, Canada is always challenging because you have such differing well conditions, 100 kilometers apart.

Waqar Syed: Yeah. yeah. Well, thank you very much. Appreciate the color.

Brad Fedora: Okay. Thanks.

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

Brad Fedora: Thanks for joining, everyone. We appreciate your time. If there’s any more questions, the management team here at Trican is available for the next few days and hope you have a good day.

Operator: This brings to a close today’s conference call. You may disconnect your lines. Thank you for participating and have a pleasant day.