Canadian Utilities Ltd
TSX:CU
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Thank you for standing by. This is the conference operator. Welcome to the Second Quarter 2020 Earnings Conference Call for Canadian Utilities Limited. [Operator Instructions] And the conference is being recorded. [Operator Instructions] I would now like to turn the conference over to Mr. Myles Dougan, Director, Investor Relations and External Disclosure. Please go ahead, Mr. Dougan.
Thank you, Anastasia, and good morning, everyone. We're pleased you could join us for our second quarter conference call. With me today is President and Chief Executive Officer, Siegfried Kiefer; and Executive Vice President and Chief Financial Officer, Dennis DeChamplain. Siegfried and Dennis will begin today with some opening comments on recent company developments and our financial results. Following their prepared remarks, we will take questions from the investment community.Please note that a replay of the conference call and a transcript will be available on our website at canadianutilities.com and can be found in the Investors section under the heading Events & Presentations. I'd like to remind you all that our remarks today will include forward-looking statements that are subject to important risks and uncertainties. For more information on these risks and uncertainties, please see the reports filed by Canadian Utilities with Canadian securities regulators.And finally, I'd also like to point out that during this presentation, we may refer to certain non-GAAP measures, such as adjusted earnings, adjusted earnings per share, funds generated by operations and capital investment. These measures do not have any standardized meaning under IFRS, and as a result, they may not be comparable to similar measures presented in other entities.And now I'll turn the call over to Siegfried for his opening remarks.
Thank you, Myles, and good morning, everyone. I thank all of you very much for joining us this morning on our second quarter 2020 conference call.I will ask Dennis to give you the second quarter financial highlights in just a minute, but I wanted to take a moment to begin by talking about a couple of our most recent business transactions. On June 22, we announced LUMA Energy. This limited liability corporation was selected by the Puerto Rico Public-Private Partnership Authority to modernize and operate Puerto Rico's electric transmission and distribution system over a term of 15 years. LUMA is a newly formed company, owned 50% by Canadian Utilities and 50% by Quanta Services.LUMA combines Canadian Utilities' world-class utility operations and customer service expertise with Quanta's superior utility services and project execution capabilities. This O&M contract is an innovative arrangement that sees that local jurisdiction continue to own the utility assets while benefiting from the expertise of a world-class operator. The opportunity fits with Canadian Utilities' growth strategy in the U.S. and Latin America, and allows us to bring our core competencies of operational excellence and exceptional customer service for the benefit of Puerto Rico.We won against some of North America's and the world's largest utility providers. And we look forward to complementing our world-class energy solutions with the experience of the employees of Puerto Rico's Electric Power Authority, or PREPA, as it's referred to. Together, we can provide Puerto Rico with a modern, resilient electric system that will support the broader economic development of the island. LUMA is headquartered in San Juan, Puerto Rico, and is in the process of relocating a team to the island. LUMA is being led by Canadian Utilities' former Managing Director of our Global Electricity Business Unit, Wayne Stensby. As LUMA's President and CEO, Wayne will, and his team, will oversee planning for the full transfer of the PREPA transmission and distribution operations to LUMA. This transition is expected to occur over the next 10 to 12 months. We provided contract information in our second quarter 2020 MD&A, and I recommend that information to you.Now I'd like to provide an update on Canadian Utilities' operations in relation to the COVID-19 pandemic and the slowing global economic activity. Now the pandemic can slow down an economic activity, did not have a material impact on Canadian Utilities' adjusted earnings in the first half of 2020. Canadian Utilities' pandemic response plan was activated in February 2020 by our Crisis Management Committee. And since then, our teams across the globe have been responding to the ever-changing situation to ensure a coordinated approach across our company. With the safety of our people, customers and communities we serve as our top priority.Now as a provider of utility and energy infrastructure services around the world, we remain focused on continuing to deliver reliable service to our customers. We implemented several enhanced health and hygiene protocols and alternative work options for employees where possible, such as working from home. I'm proud to share with you that our employees have stepped up in this challenging time and have performed in an exemplary fashion.As you are aware, our capital investment is targeted in our utilities and in our long-term contracted energy infrastructure. We continue to review our 2020 capital investment plan in order to incorporate any potential postponement of capital projects over the near-term due to customer project delays or changes to capital projects that are directly assigned to us by the ISO.We do have considerable resiliency given the regulatory and long-term contracted nature of our earnings. In 2019, 95% of Canadian Utilities' adjusted earnings came from the regulated utilities. This creates greater predictability in our earnings and cash flows. But the long-term impact on Canadian Utilities cannot be fully determined until the depth and length of the current economic slowdown is known. Earlier this month, we were awarded funding from the Emission Reductions Alberta, Natural Gas Challenge, to advance the first-of-its-kind hydrogen blending project in Fort Saskatchewan. Once complete, this project will allow us to inject up to 5% hydrogen into the residential gas distribution network, lowering the carbon intensity for our customers.Now in 2019, we also opened our Clean Energy Innovation Hub in Perth, Australia. This industry-leading test facility is a test bed for hybrid energy solutions and integrates natural gas, solar, battery storage and clean hydrogen production. Those are just 2 examples of our ongoing transformational journey to prepare our company for the future.And now I'll turn the call over to Dennis for his comments on our financial performance.
Thanks, Siegfried, and good morning, everybody. Canadian Utilities achieved adjusted earnings of $94 million in the second quarter of 2020, compared to $126 million in the second quarter of 2019. Lower earnings this quarter were mainly due to the sale of the Canadian electricity generation business in the third quarter of 2019 and the sale of Alberta PowerLine in the fourth quarter of 2019. These businesses contributed $17 million in adjusted earnings in the second quarter of last year. Lower earnings were also due to $15 million in prior-period adjusted earnings from electricity and natural gas transmission regulatory decisions that were received in the second quarter of 2019. Excluding the foregone earnings impact from the 2019 business sales and retroactive earnings impacts from the regulatory decisions received in the second quarter of 2019, Canadian Utilities' earnings in the second quarter of 2020 were comparable to last year's second quarter earnings.As Siegfried noted, the COVID-19 pandemic, oil price decline and slowing global economic activity did not have a material impact on Canadian Utilities' adjusted earnings in the first 6 months of 2020. Perhaps the largest single impact was felt in our natural gas distribution utility in Australia, where the financial results included the adverse impact of a lower inflation rate in the second quarter, which came hand-in-hand with the global pandemic. Overall, our businesses continue to perform well and generate strong earnings and cash flows.Regarding developments on the regulatory front. In March, the Alberta Utilities Commission, or AUC, suspended the 2021 generic cost of capital proceeding due to the COVID endemic. The main focus of the proceeding is to determine the return on equity, or ROE, for 2021 and 2022. The AUC acknowledged that the delayed proceeding creates uncertainty regarding the utility's ROE for 2021 and beyond. The AUC, therefore, provided utilities with a number of options for setting their return on equity for 2021.In order to create some level of certainty, we elected to have the ROE continued at the current 8.5%, with 37% equity thickness until an AUC decision is issued. Once the AUC issues its decision, the ROE and equity thickness will be implemented on a go-forward basis, and will be effective at the start of the quarter following the date of the AUC decision.Finally, I'm pleased to inform you that on July 20, DBRS affirmed its A(high) long-term corporate credit rating and stable outlook on Canadian Utilities' subsidiary, CU Inc. Credit ratings are important to our financing costs and ability to raise funds. We intend to maintain strong investment-grade credit ratings in order to provide efficient and cost-effective access to funds required for operations and growth.That concludes our prepared remarks, and I'll now turn the call back over to Myles.
Thank you, Dennis and Siegfried, and I'll turn the call over to the conference coordinator now for questions.
[Operator Instructions] The first question comes from Maurice Choy with RBC Capital Markets.
My first question is on capital deployment opportunities and the pipeline within those opportunities. Obviously, you now have the NCIB in your toolbox, and you're obviously reviewing your capital investment plan at least for 2020. Can you discuss those opportunities, how those pecking order now looks like? Has there been a shift away from deployment of capital part towards buybacks or keeping cash on your balance sheet?
Hi, Maurice, thanks very much for your question. This is Dennis. Yes, we did file an NCIB with the exchange. The primary purpose for that NCIB will be to offset dilution arising from stock options. At the moment, we don't see a compelling need to buy back many shares at all. Our focus right now is on maintaining liquidity and optionality in light of the current circumstances. I think everyone realizes we're not out of the woods yet on COVID. And I'm sorry, Maurice, you're breaking up on our end of the line here, and I couldn't quite hear your entire question. I apologize if I didn't hit everything.
I guess just a follow-up and clarification. So I guess, if you look at the next, say, 6 to 12 months, as the economy slowly emerges out of COVID-19, we should expect directionally that the cash will probably stay on the balance sheet for the time being?
Right now, those are our plans, Maurice. I mean we continue to look for other opportunities. I think as most of you or all of you are aware, the activity has slowed down greatly over the last 6 months. We continue to monitor the situation, and we'll respond accordingly.
Thank you. And the second question relates to Puerto Rico and the LUMA contract. Given the continuing news headlines on COVID cases in Puerto Rico, how does COVID-19, as the pandemic continues, play towards the transition from, say, the $60 million transition fee period into the $70 million to $90 million year 1, year 2 contract period. And specifically, if there's a delay in this transition due to COVID-19, thereby not allowing you to transition within 10- to 12-month period? How does this all get factored in?
Sure, Maurice, maybe I'll start, and then Siegfried can chime in if required. As part of the bid, we provided comprehensive plans going forward as to what we would be doing during this front-end transmission period. COVID is impacting operations, of course. I did speak with Wayne Stensby, the CEO from LUMA, this morning. We have about 60 people on island right now kind of implementing those plans that we developed. Those guys especially have become extremely proficient on Microsoft Teams or Zooms or whatever, in order to keep progressing. So we're on island. We do have the plans, and we're executing those plans as we speak. From my perspective, we're still looking good for achieving an exit from that front-end transition period, although it's early days. We've only been in it for a month. I don't know, Siegfried, if there's anything you'd like to add?
No. I think, Dennis, that's exactly right. We've got our team on the ground. We are supplementing it with work from afar. And at the moment, those teams are being able to access the PREPA employees, either directly on-site at their offices or through Teams. So at the moment, we're not seeing a slowdown in the work to advance the transition deliverables in order to be able to take over operations. I'll just remind everyone that the second key element of moving into full operations is the emergence of PREPA from bankruptcy. And as outlined in the agreement, there is a supplemental arrangement that would allow us to advance our work in the event that bankruptcy emergence isn't achieved and allow us to commence, albeit on a more limited basis, the operational element, but that would essentially just be for that interim period until they do emerge.
The next question comes from Linda Ezergailis with TD Securities.
Recognizing that you're still assessing your capital expenditures for this year, never mind beyond this year. I'm just wondering how your thinking has evolved since the first quarter call. In terms of your thoughts around what might be deferred, what might be delayed or shelved indefinitely and the bookends of potential outcome in terms of magnitude. On that front for the next few years.
Thanks, Linda. I'll focus my reply on 2020. We're pretty much in the same situation as we were in Q1. We're continuing to review our plans, and we're definitely not out of the woods yet on pandemic. If you take a look at our first half of 2020, the capital spend compared to last year, after you normalize for the businesses that were sold in 2019, we are pretty much bang-on on those levels. We're at about $450 million for the first half of this year versus last year of $440 million. And I'm going to say the only major project or the largest project that we've executed over the past 12 to 18 months is the Pembina to Keephills pipeline transmission line. In the first half of 2020, we've incurred expenditures of about $50 million, which is about double over that same time period last year. As you likely recall, that project really ramped up in the back half of 2019, where the majority of those expenditures were incurred. We continue to see good activity on the -- on our electricity distribution front, with customers continuing to apply for and get hooked up with service. So that is -- that hung in there, I'm going to say, over the second quarter. And we're very carefully monitoring that to see how that progresses over the next 6 months. That's about all I can tell you, Linda. And we're going through our plans for 2021 and beyond, and we'll be presenting those plans too to our Board in the fourth quarter here for approval, and we'll come out in 2,000 -- in our year-end MD&A. We'll be able to give you a better idea as to where we are going forward at that point in time.
That's helpful context. Maybe as my second question, I'm wondering, having seen the filing for the -- your natural gas transmission GRA in June for the period of 2021 to 2023. What do you view as being kind of the most important elements? And can you talk about the range of possible outcomes on that front? And how it might evolve versus your prior GRA.
When I'm asked about the range, my immediate reply is, well, they never approve more than what you file for. So at the top end, we would get absolutely everything in the application, and that, I'll say, rarely occurs. I hope the regulator isn't listening. In terms of the most important impact, the rates that were filed in that application are relatively flat. The biggest impact is from the, I'll say, the Pembina to Keephills increase in rate base. So as the prudence of those costs get tested, that will drive the majority of the impact, were knock on wood, we have not realized any material disallowance from any of the prudence and the execution of our capital programs to-date. There's always that possibility, but we're going in pretty confident with the execution of that project over the timelines.
Your next question comes from Mark Jarvis with CIBC Capital Markets.
Maybe I'll start with -- maybe eventually we'll get back to the GCOC. But just curious, in your mindset, as you think about that resuming sort of second phase of PBR now. And would you ever envisage moving to cost of service? And if that's something you think that might happen, how do you think that goes into the proceedings and the discussion around the allowed ROE going forward?
Good morning, Mark, thanks for the question. The generic cost of capital is looking at the returns for 2021 and 2022. And the end of that GCOC kind of time period also aligns with the end of PBR 2, that 5-year period ends in 2022. I think when we went into PBR and PBR 1, there wasn't any change in the returns or the capital structure. Moving from a cost-of-service regime to the PBR time set. So given that, I think, just moving from a PBR 2 into a PBR 3, if there is one, or moving from PPR 2 into a cost-of-service regime, as we sit right now, I wouldn't expect that to have a major impact on the business risk. The way Alberta has been adjusting for business risk is through the equity thickness. And then taking the market's view on the return on equity. So I don't really see that next stage of regulation for our distribution utilities here in Alberta to impact the next GCOC or whatever processes are raised at that time to determine returns and equity thickness.
That makes sense. And then, it sounds like you're a bit on hold on maybe deploying the capital, say, on the balance sheet. But as you think forward and maybe reengage, is there a preference for electric over gas infrastructure for you guys now? Or are you sort of agnostic and see sort of the best opportunity and the best returns? Or is it -- whether you've seen things like gas moratorium in the U.S. or electrification trends. Is that coming in your thinking at all right now in terms of where you would prioritize your efforts going forward?
Yes. We look at electricity, we'll say, versus gas. I mean, it comes down to energy. If you believe in the electrification of kind of the expanding electrification of our world, there would presumably be more of a demand on the electricity side. We are, say, relatively balanced rate right now. We've got a large investment in electricity transmission here in Alberta. We weighed those factors. We may not be going after more, call it, natural gas in a low-load environment, similar to what we have in Perth. In terms of heating content, it's pretty integral for cold-weather climates here in Alberta to have that natural gas as a fuel for energy in order to heat our homes and businesses. The cost to replace the gas system with an electrification of that would be enormous and kind of not in the near or medium term, in my view. So I think gas is still around for a while.
All right. I -- yes, go ahead.
I might just comment on that. I think the energy landscape is clearly evolving around the world, and there is a desire to move to nonhydrocarbon forms of energy. And so electricity, depending on how it's generated, is clearly a clean form of energy at the consumption point. The -- and as such, I think that would be something that we would certainly look at for future investment on a preferable basis to additional hydrocarbons. The challenge is that natural gas is a fuel, electricity is manufactured energy, and how you manufacture it is really a challenge around the world. And whilst we have some emerging forms of nonhydrocarbon electricity manufacturers, solar, wind, et cetera, the challenge will be how do you meet the needs of the energy demand on an exclusive basis if hydrocarbons are not a part of that. And I agree with Dennis, in colder climates the natural gas fuel is an integral part of meeting the energy demands here in Canada. But as we look across the world, clearly, emerging trends are to see more energy investments happening in the nonhydrocarbon space.
Okay. That makes sense. And then maybe last question, maybe for Dennis. Just digging into a little bit of the electric utility results and a little bit of a step-up in O&M this year versus last year. Any details in terms of whether or not that fell more with the distribution or the transmission and whether or not that's just timing related or if there is some incremental costs that have been coming in over the last couple of quarters.
I'm just looking at my handy dandy cheat sheet here, Mark. There isn't anything that jumps out on the O&M operating costs, our controllable costs. The businesses are continuing their focus on increasing the efficiencies, any bumps. There's always timings that we -- timing of costs that we see from quarter-to-quarter as we progress through the years. But the teams in the utilities really have their eyeballs on their efficient operations and are continuing to drive that total cost down as much as possible. Any blips in there would likely be timing.
The next question comes from Patrick Kenny with National Bank Financial.
Dennis, are you able to quantify the -- or what the demand destruction looks like in the quarter for your C&I customers, I guess, within electric distribution and what the financial impact was there? I agree with your statement that we're far out of the woods -- far from out of the woods. But with oil prices recovering somewhat, production levels as well, are you starting to see more normalized demand levels across the distribution utilities, at least over the past 30 days or so? I guess, how far off are we today from pre-COVID levels?
I'll give you the straight answer first and then tell a story. For the first 6 months, electricity distribution is down about $2 million after tax from commercial and industrial. Commercial and industrial customers. The ISO on their website, they show what the impact to the Alberta load has been like as a result of COVID. And up to the beginning of June, the load in the province dropped by about 8% versus their, kind of their normalized benchmark of February. The Fort McMurray area has dropped about 13%. So quite more of a drop. And in the Central East part of the province, where there's still heavy oil and a lot of services, that's dropped by 20%. And I haven't seen an update from the ISO as to where the loads have been coming back. But since May, they've said that the overall system load, not load from behind the fence for the major industrials, the system load has been a slight uptick since May. So if that continues, I would suspect that we would have the worst behind us. And to the impact on electricity distribution, it's not material. So when we say COVID is not material, there are impacts throughout all of our businesses. But on the electricity distribution side, it's $2 million for the first half of the year.
Okay. That's great. And then, on the residential front, I guess, with respect to the utility bill deferral program, it looks like there wasn't a material impact there as well on earnings through Q2. I was just wondering if you can confirm that you don't expect any lag, any impact on, say, Q3 or Q4 cash flows? And if so, how -- any shortfall there might be recovered in future rate filings?
Yes. When the province announced that utility bill deferral in mid-March, all of the details were not ironed out as they were flushed out. A lot of the backstop from those bills were taken on by other agencies and departments, whether it's the ISO or loans, what have you. The amount that did come back to the utilities related to the natural gas transmission component of our distribution charges. And I think the upward end of our estimate would have been in a potential impact to cash flows of about $30 million, and that would have delayed cash flows from that 1-month deferral over the following 12 months into recollection. Our estimate was, of the potential impact? Well, I'll say potential impact, the real impact was a fraction of that amount. So I'll say it's a very small component of an immaterial amount that our cash flows are being impacted. And that would all -- should all be trued up by the end of June next year. And no impact on adjusted earnings.
[Operator Instructions] Our next question comes from Andrew Kuske with Crédit Suisse.
I think the first question is for Dennis, and that's probably a bit more on the technical regulatory front. And it just relates to your PBR mechanism. And if we look at just broadly in the economy, there's clearly been several deflationary pressures, and it's not just Canada, it's really globally. And so if you think about the deflationary pressures and then the potential and the prospect for inflation in the future, at maybe an elevated rate, how do you think about those dynamics as far as your PBR goes?
Well, in terms of PBR 2, we're kind of locked in to their formula. They take a little bit of a trailing view. So the inflation factor for 2021 is actually the inflation that's experienced from July 1, 2019 to June 30, 2020. And that's the same -- a little bit of a lag on the inflation for PBR 2 that was taken for PBR 1. It is consistent between the 2 generations. The inflation index that we have in PBR here is a mix between kind of labor dollars through the average weekly earnings index in Alberta. That represents 55% of the overall inflation. And Alberta CPI is the remaining 45%. We haven't seen, let's say, a material disconnect between the inflation rate that's being used for PBR as what we're seeing in our operations. We have in the past seen disconnects where the cost of contractors during the big build far exceeded what the -- kind of like the headline inflation rates were in the province. So you can get large disconnects. One of the disconnects that we see right now in Australia and their CPI is that childcare during the pandemic is down 95%, and that's contributing to a very low CPI. Doesn't have a lot to do with the provision for safe, reliable gas delivery. So there can be those large disconnects. But as long as that index fairly reflects the ongoing impact to our operations, which it has, then I'll say we're okay with it. The minute it does get to be disconnected, then we would be looking to fine-tune that formula such that it better reflects the ongoing costs that we're experiencing in our companies.
Okay. That's very helpful. I appreciate that detail. And then, maybe just a broader question as a second question, and it really relates to, when you think about M&A, and you've clearly gone through a bunch of efforts of decarbonization in the core CU utilities portfolio and really pronounced in the last couple of years. So you think about that dynamic of decarbonization in sort of broader industry trends. If you were to see a rate-regulated utility asset that had coal generation attached to it within a rate base construct, is that something that's worth exploring? And is it really worth exploring at the first instance? Or is it exploring from a decarbonization prospect? I know it's all hypothetical, but I'm just curious as to how you think about that dynamic.
Thanks, Andrew. Hypothetically, then we would hypothetically look at it. One of the programs that we had with our Canadian generation business is we were well advanced in the coal-to-gas conversions. So hypothetically, if there was a coal-fired integrated utility -- or sorry, an integrated utility with coal-fired generation and there was an avenue to decarbonize it, we would take a look at it. Again, that's one factor out of many that would need to be considered in any kind of M&A targets that we would be looking at as we continue to look for geographic diversification out of Alberta. Siegfried alluded to earlier, the decarbonization into the renewable energy. So I'll say everything is on the table before it goes through our filters to see if it ticks all the boxes or not.
Our next question comes from Elias Foscolos with Industrial Alliance Securities.
I want to focus on the balance sheet because I see that as sort of the biggest optionality. In focusing in Puerto Rico, I see the current contract as sort of optionality to get into expanding sort of the power asset base. And the reason I'm focused on that, and please confirm it's true or not, is that I believe in the bid process. The LUMA joint venture was interested in providing some sort of debt financing. Would that be sort of a correct interpretation or incorrect interpretation?
Sorry, could you repeat or rephrase the question? LUMA is going in without any capital requirements. It's a 15-year O&M agreement, whereby there is no change in the ownership of the assets. There's no capital infusion required by the parents nor LUMA. They're in line for significant funding from FEMA in order to help rebuild and fund the modernization of their electricity system. So if I missed anything in the question, maybe you could come back with the supplemental?
Yes. I mean, I do believe in the bid process. There was a criteria that wasn't weighed on debt financing. So I'm asking, is the balance sheet potentially saved for that? Or is that completely not something to even look at?
That was considered early on in the process. It's been taken off the table. And as a result, there has been no requirement for capital infusion under the current deal.
Yes. I might just add, Dennis. I think part of the evaluation of the bidders was whether or not they knew how to structure a utility such that its debt financing would be seen attractive in the marketplace. And so I think it goes more to kind of rate setting, cost management and the go-forward positioning of the owner's balance sheet, if you will, to be able to be creditworthy.
Okay. Thanks for that clarification. And just again on the balance sheet and sort of the last question, as you talk about growth within the U.S. and Latin America, does this investment encompass both of those? Or just is it in the Latin America bucket as you look at it? In other words, should I keep my eyes out on the U.S.?
Yes. It's Latin America embedded in the U.S. So I mean, for us, I mean it really does check that diversification box as we're looking to get the earnings not as dependent on the Alberta resource-based economy, Alberta is making strides to diversify its economy. So as that progresses, that will help us. But as we look into diversifying into higher-growth markets, being the U.S. or LatAm, then Puerto Rico checks the box. Internally, we've had it in both camps, but not at the same time, so.
The next question comes from Mark Jarvi with CIBC Capital Markets.
Yes. I was going to get you at the end of the call, I just wanted to see if I could fit in that question on structures and logistics here, and pretty strong results this quarter. Just trying to understand, as you transition the LNG project from manufacturing to installation now, what happens through the earnings profile and the margins? And then sort of expectations for that business as you go through the back half of the year, whether or not there's sort of a lag as some of these COVID impacts flow through? And just maybe commentary again from that LNG contract.
Yes. Thanks, Mark. You're right, manufacturing kind of wound up in early Q2. We are continuing on with the lower-margin installation activities over the remainder of this year and spilling into 2021. We've shown the rental fleet stats in the MD&A, and you can see an increase in the global space rentals fleet. The utilization is hanging in there, which is great. And the margins are increasing slightly. Our workforce housing units, there's been a small contraction of those units, which helps with the cash flows as we continue to ensure that the fleet is right-sized for the markets that we operate in. And we've said in the past that absent any major announcement for kind of large camps, a large workforce housing is that we would recommend you looking at that kind of base business to see what kind of earnings and cash flows that that structures would contribute.
But just taking those comments, but really nothing where you're seeing a lot of negative pressure, undue competition on pricing, like it does feel like it's a pretty rational market right now. And in the transition from manufacturing to installation, not seeing a lot of downward pressure on margins?
Well, we've shown that our average rental rate for our space rentals units is up 32% kind of year-over-year for the 3 months ended June 30. And over the 6 months, it's up 5%. So it depends on the markets in which you're operating and the construction activity, largely that is driving those rates.
This concludes the question-and-answer session. I would like to turn the conference back over to Mr. Myles Dougan for any closing remarks.
Thanks, Anastasia, and thank you all for participating today. We appreciate your interest in Canadian Utilities. And we look forward to speaking with you again soon.
This concludes today's conference call. You may disconnect your lines. Thank you for participating, and have a pleasant day.