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Thank you for standing by. This is the conference operator. Welcome to the first quarter 2021 results 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, Claudia. Good morning, everyone. We're pleased you could join us for our first quarter '21 conference call. With me today is Executive Vice President and Chief Financial Officer, Dennis DeChamplain. Dennis will begin today with some opening comments on our recent company developments and our financial results. Following 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 Dennis for his opening remarks.
Thanks, Myles, and good morning, everyone. Thank you all very much for joining us today on our first quarter 2021 conference call. Canadian Utilities achieved adjusted earnings of $191 million or $0.70 per share in the first quarter of 2021, which is $12 million or $0.04 per share, higher than the first quarter of 2020. The $12 million growth in first quarter earnings was in part as a result of cost efficiencies and continued growth in the regulated rate base in our Alberta utilities. Our Australian natural gas utility also had earnings growth this quarter from a higher inflation rate and a stronger Australian dollar compared to our Canadian currency. Economic activity in Western Australia has really improved over the last couple of quarters. Mining activity has been picking up due to increasing iron ore and copper prices. And the Australian economy appears to be improving. Hopefully, this trend continues through 2021. In Puerto Rico, we continued operations and maintenance transition work and are preparing to assume full operation of the electricity transmission and distribution system in June. In our energy infrastructure business, higher earnings were due to demand for natural gas storage services and recovered business development costs. Our resilient financial performance this quarter is a continuing testament to our business model as well as our people, who remain focused on delivering reliable service to our customers. On the regulatory front, we are seeing a return to prospectivity with a number of positive decisions received in March. We received a decision from the Alberta Utilities Commission, or AUC, approving our electricity transmission revenues until the end of 2022. We also received a decision from the AUC approving revenues for our natural gas transmission business until the end of 2023. In the distribution utilities, the AUC initiated a process to set customer rates for 2023. This process will also determine the regulatory framework for the distribution utilities after 2023. And last but certainly not least, the AUC was certainly busy this last quarter. They issued a 2022 generic cost of capital decision, extending the current return on equity of 8.5% and the equity thickness ratio of 37% for 2022. Having clarity into the future from these regulatory decisions helps us plan more effectively, creates a more stable business environment that encourages investment and creates certainty for our customers. We do recognize that the economic situation currently here in Alberta is presenting many hardships as a result of the pandemic, and it's been very challenging for our customers. In March, we filed a 2021 rate relief application for electricity distribution and natural gas distribution to postpone rate increases for all of 2021. We proposed to collect the deferred amounts commencing in 2023. While this application will impact Canadian Utilities' cash flow in the short term, it does align with our long-standing social practice of supporting the communities we have the privilege to serve. In terms of capital investments, we invested $220 million this quarter in our core utility businesses to generate stable earnings and reliable cash flows, and we continue to explore opportunities in renewable energy. A recent example of this is our newly announced agreement to acquire the rights to develop the 325-megawatt Central West Pumped Hydro Storage Project, which is located 175 kilometers west of Sydney, Australia. This acquisition marks our first renewable energy investment on Australia's East Coast. The project is close to significant renewable energy resources and would support the development of new renewable generation capacity in the state of New South Wales. A final investment decision on the project is not expected until 2023. All in all, Canadian Utilities had a solid first quarter of 2021. All of our businesses performed very well, and we received important regulatory decisions, which allow us to plan more effectively for the future. That concludes my prepared remarks, and I'll turn it back over to Myles.
Thank you, Dennis. [Operator Instructions] I'll turn it over to the conference coordinator now for questions.
[Operator Instructions] Our first question is from Mark Jarvi with CIBC Capital Markets.
First question, Dennis, is on LUMA, the joint venture. You alluded to the fact that you'll take over the 15-year O&M agreement without a transition phase. So just can you give us an update in terms of where you are on the incentive criteria? And also just PREPA coming out of bankruptcy, I think that was one of the criteria in terms of where you are in terms of that transition work.
Thanks for the question. Sorry, what's criteria? What was the first question?
The criteria, I think, there was some debate around what were some of the incentive metrics, which would determine your ability to earn a bit more under that contract.
And bankruptcy. Okay, got you. Yes, LUMA, our joint venture with Quanta Services, to run the Puerto Rico T&D systems, our CEO, Wayne Stensby, usually starts off most of the meetings with a safety moment and then reminds us how many days until the end of front-end transition. And we're 33 days out right now. Those incentive criteria that you're talking about, Mark, we have filed all of that with the Puerto Rico Energy Bureau, the PREB, the equivalent to the AUC as the regulator down there. And we filed that back in February. They have yet to make a final determination as to what those incentive criterion, the base amounts will be set out. So we don't know that yet. I was talking to the guys yesterday and over the weekend. And there is a line of sight to get those approvals from the PREB by June 1. So unfortunately, we don't know now. And we do expect to receive the ruling from the PREB before the end of the front-end transition. In terms of bankruptcy, the PREB is still -- PREPA, sorry, the Puerto Rico Power Authority, they're in bankruptcy. We anticipate that they will continue to be in bankruptcy. There are provisions in the agreement that we can exit the front-end transition and enter into operations under a supplemental agreement until PREPA does come out of bankruptcy. So we anticipate that in June, when we get the keys, they'll still be in bankruptcy. Views right now as to when they could come out of bankruptcy, we anticipate that sometime next year.
And then once they do come out of bankruptcy, can you explain in terms of how that move back and forth between the supplemental? Is it sort of immediate? Is it subsequent quarter? Just wondering if there's any sort of time lag in terms of how you transition between these 2 different types of structured contracts.
Yes. I'm not sure as to the exact date, but we will -- I'll say, immediately, I don't know if that's the following month. I don't think it's the quarter. But we -- when we come out of the supplemental agreement, we would enter contract year 1. And that contract year would run until -- it would say it's January 1 of next year. Contract year 1 would run from January until the end of June. And then we would get into contract year 2 of the agreement and go on that 12-month cycle from there.
So it wouldn't necessarily extend the full duration of the O&M agreement?
Well, it depends on how long we stay operating under the supplemental agreement for operating for a year under the supplemental agreement. And then we have 11 months of contract year 1. It could extend it, but you're only really talking about a year.
Got it. And then your comments about Australia and the results out of the international gas distribution utilities showed really strong year-over-year premium. You talked about the commodity market impacts. So the view would be that you've kind of hit a bit of an inflection and this is sustainable for that business. And then maybe beyond just your existing assets, your views in terms of willing to put more capital in Australia, whether on a regulated assets or contracted assets. Are you sort of more constructive on that market today than you would have been a few months ago -- or a few quarters ago?
With regards to Australia, I mean, that inflection point, I mean, because they are regulated based on a real return to convert the earnings into nominal, it's kind of dependent on the Australian CPI. And last year, I think the total CPI for the year was 0.3% and that's what we had recorded in Q1. And then the bottom came out when COVID hit. And there was no overall inflation for the remaining 3 quarters of 2021. For this first quarter, the inflation rate in Australia was 0.6% just for the first quarter. So that's the kind of like the uplift year-over-year. The big banks down there, they're forecasting about a 2% to 2.5% inflation rate for the year. We were kind of thinking that the inflation rate for Q1 would have been a little bit higher. There were some federal and state subsidies to keep the cost of new dwellings down year-over-year. So that may have -- well, that did mute the overall CPI for the first quarter. But given the -- as I mentioned in the opening remarks, the copper and iron ore prices down there, it's -- I'm not going to say it's booming. Our guys down there would say it's booming. It's getting berths for the ships to land pipe. And we're seeing increases in cost of pipe. They're all manageable increases. But just that real heightened activity gives us some tailwinds, I'm going to say, for Australia and the rest of this year, certainly. In terms of kind of redeploying capital in kind of the -- either the regulated or nonregulated space, I think we've been consistent, where we have been saying that we are looking to expand geographically. We're looking to expand into kind of more renewable power generation. The example of the Central West pumped hydro, and it's very early days on that project, FID isn't expected for a few years yet, just goes to show our willingness to deploy capital in that area. There's a lot of items on that particular project that we need to get comfortable with. But yes, we are comfortable in deploying capital in that zone, probably more in the non-reg area as opposed into the regulated, given the low rates of return that we have down there.
Our next question is from Linda Ezergailis with TD Securities.
Just to build on Mark's question about geographic expansion and opportunities, sometimes it's also interesting to hear what you're not commenting on in your prepared remarks. And I'm just wondering if you can also touch on some of the recent developments in Mexico and how that might change your outlook for either new investments or the merits of potentially exiting your presence there entirely.Also, one of your affiliates in ATCO, Structures & Logistics, as well as some other investments you have in South America through your affiliate -- or your affiliate has, I'm just wondering what the opportunities there might be long term for energy infrastructure in South America for Canadian Utilities? And then in the mix, closer to home, while short term in Western Canada, there are some challenges unfortunately related to the pandemic. We are seeing more than green shoots in the oil and gas industry and initiatives there to make transitions to lower-intensity energy sources long term as well. So can you comment on the relative scale of opportunities and how you see those having shifted recently?
Thanks, Linda. Yes, I don't know, I wouldn't put too much stock in the stuff that I don't say. But I will get to the Mexico. Yes, Mexico has been very tough for us. I mean, we still have an outstanding arbitration decision award on the two of the pipelines. We -- I kid our guys, keep getting updates and it's going to be this quarter and then it's going to be the following quarter and the following quarter. And they're taking their time getting to that ruling. And that was permitting delays. And in our MD&A this quarter, we've mutually agreed to cancel our agreement with Chemours due to permitting issues. So there's a little bit of a recurring theme. We got all of our money out from that Chemours investment, so we are covered there. But given those experiences, we are probably waiting to redeploy capital into Mexico. On the structures -- on the actual side of the structures, there isn't a concern with the Mexican environment. Our subsidiary down there is doing well and getting new orders and kind of expanding their line of business. So there isn't a concern on the structures side. In LatAm, we are continuing to explore other renewable energy projects down there. The announced Central West pumped hydro in Australia isn't the only, call it, iron in the fire that we have. We do have other projects that we are looking at in the region. But certainly, the -- we'll call it, those permitting issues, we are particularly attuned to as we look to further build out our businesses there. In terms of Western Canada and the green shoots of oil and gas or the movement to lower intensity, I mean, there's great opportunity here. We could be a major hub for blue hydrogen. We've been -- we've had hydrogen blending in Australia for a number of years for our clean energy innovation hub and now park. And we do have a blending project in Fort Saskatchewan, a small blending project with hydrogen. So when it comes to the renewable energy space with the decarbonization of our energy that we provide for our customers, it's certainly an area that we are looking at, and we think we could add a lot of value in -- especially in the Alberta marketplace, given our footprint that we have here.
Okay. And in terms of organic opportunities, clearly, those are -- have historically been a focus, and I expect would continue to be. But what are you thinking in terms of maybe portfolio management, just as a follow-up question to my prior one, portfolio management in terms of what might be a little bit less core versus where you might fill in some white space in your current core strategy and operations in terms of potentially some acquisition opportunities as they might arise opportunistically?
Yes. We like the cards that we're holding right now in the energy infrastructure space with regards to our storage facilities and processing facilities that we have here in Alberta. If we're looking for any kind of a white space, kind of small tuck-in acquisitions, we could be looking for, call it, late-stage solar wind developers in order to add to our renewable energy portfolio. So that -- in terms of portfolio management, those would be one of the areas that we would be looking at to round out our product offerings.
My second question relates to the Alberta regulatory environment, definitely positive to see it moving to more prospective decisions. And in fact, the fact that they are now contemplating what sort of regulatory framework might be appropriate for the distribution utilities in the province for 2023, I'm wondering, in a perfect world, what Canadian Utilities views to be -- if you can influence that decision or advocate for something, how do you see an appropriate regulatory framework evolving beyond 2023 in Alberta?
Are you referring to the distribution side of the house or the transmission side or...
I was referring to distribution, but if you want to expand your response to include transmission, I'd be interested as well.
Yes. It was -- we're very pleased with the progress that the AUC has made in their efforts and actions to reduce the red tape and to try to help expedite approvals to get back to prospectivity. Our natural gas transmission business has had kind of more success than on the electricity transmission side. All the bright lights were on electricity transmission as we went through the big bills. And I think there is a little bit of infrastructure that was built up weighing that regulatory process down. We're happy that we have 3-year test years for both of those businesses in order to help maintain that prospectivity. On the distribution side, again 2023 1-year cost of service application that the commission is looking to hear for all of the distribution utilities, and we've all put in our comments as to what we would like to see, whether it's a full-scale cost of service review, detailed line-by-line or more of an expedited hybrid between detail and leveraging some of the costs that we have incurred. The fact that the AUC has asked for a 1-year cost of service, in my mind, leads to a transition into PBR 3. If they didn't think there were merits in PBR, I suspect that would have gone back to a longer cost of service term for the distribution utilities. So while I don't want to handicap the outcome, I do believe that it will end up as a return to kind of a third-generation PBR and then it gets to the devil is in the detail. So going-in rates will be fundamental to whether we have an opportunity to earn a fair return on our capital, especially given the changes that we're seeing in the industry on the electricity side. There's a lot of modernization that needs to be done to their grid to allow for bidirectional flow of the electrons. On the gas side, additional investments to allow for the blending of the gas system with renewable energy to help lower emissions. So we would be looking to allow for those types of new investments and not be hamstrung with what has been done in the past. And the only other element that we would like to see on our wish list or which we think is imminently prudent is to allow us for the adjustment to our depreciation rates to allow for the mitigation of the prudent risk against prudent cost recovery to ensure that we don't get hit with any extraordinary retirements without legislative change. We're continuing to work with the Alberta government, Department of Energy and what have you, in order to get amendments to the legislation to allow for the recovery of our prudent costs. That's been a long-term goal, and we continue to work on that with the powers that be.
Our next question is from Matthew Weekes with IA Capital Markets.
I'll just ask a couple really quick here. I was just wondering with the postponement of rate increases to help customers out, you're saying that's kind of going to be a bit of a short-term impact on the cash flow. Does that impact the earnings profile at all in the short term?
It does not impact -- sorry, thank you for the question, Matthew. It does not impact our adjusted earnings. We'll continue to record the impact -- we'll continue to record the revenues for that rate increase on an adjusted earnings basis. For the IFRS statements, we don't record the revenue until it's built. So that would not be in the IFRS revenue -- IFRS earnings, but it will be in the adjusted earnings.
Okay. And just my second question was just about the natural gas transmission general rate application for '21 to '23. And it looks like there was a bit of an impact from sort of some cost savings being passed on to the rate payers now. Was that something that could be expected to continue through the rate period as you work through 2021 to 2023 and continue to impact the rate profile in the transmission there?
Yes. I mean, that's -- it will continue to impact it. We always see the savings flowing through to customers. And that's exactly how the regulatory compact is set up. Whenever we have a reset, there typically is the flowing of the benefits through during the test period through to customers. The challenge for us and our management is to restock the shelves for new savings. And that's what the management team and the gas transmission business has always done and is continuing to look at. So over the last 10 years, we've consistently, I'll say, outperformed the approved return on equity despite these rate resets, where we flowed the savings back through to customers. So while our 2021 to '23 earnings won't enjoy the benefit of the -- of those cost efficiencies that were identified in prior years, they are identifying new cost savings. Example of that is workforce asset management systems on the gas side and on the electricity side, covering T&D to allow for the, I'll call it, more effective management of the assets and more effective management of our people, who are maintaining those assets.
Our next question is from Andrew Kuske with Crédit Suisse.
Dennis, could you maybe just give us a bit of a discussion around how you think about carbon as it relates to future capital investments or acquisition potential? And I ask the question just in part because you've obviously gone through a really meaningful decarbonization effort with the sale of the coal plants a while back. And then how do you really line up just prospective investments? And I know you mentioned renewables, you have some focus on that, but looking at energy infrastructure or maybe more carbon-intensive utilities on an acquisition basis that have a path to become much cleaner. If you could just give us some color on that, that would be great.
Thanks, Andrew. Yes. If we got presented with an opportunity to buy a vertically integrated utility with a whole bunch of coal and a path to decarbonization, maybe a few years ago, we would have looked at that path. Right now, the leaning, I'll say, is more towards renewable energy. When coal was in the crosshairs to get those emissions out of the energy chain, many thought that natural gas would just be the next coal. And that appears to be the case for striving to meet kind of net zero targets or a 45% reduction in carbon emissions, to do it with more natural gas-fired generation may not achieve the results for long-lived assets. So for that reason, we're more focused on the renewable side as opposed to either greenfield or acquisitions of a carbon-intensive business on the energy infrastructure side.
Okay. That's very helpful. And then you did mention some comments around your shorter-duration projects or potential acquisitions on the renewable side. If you could maybe just give us a bit of color on the balancing act is. You clearly got the pump storage project into the future. You've had other long-dated projects in the past that didn't work out on the hydro side. But I'm just sort of curious, how do you think about the balancing act of -- clearly, the group always has had a long-duration view and has really played through cycles. But we see pockets of frenetic activity on shorter-duration renewables, but respectively, some really interesting opportunities on a longer-duration basis. How do you bridge that? Or how do you balance that from a capital allocation perspective?
Yes. I mean, in order to get into that renewable space, to be -- have projects and to be able to go market power purchase agreements with customers, you need some generation to go market. If we started to do the wind studies and solar studies now, it would take quite a bit of time before we've had an opportunity to redeploy that capital into the new areas. For that reason, we are looking at late-stage projects that are under development through acquisition. We'll say, similar to the group in Australia, where we just acquired some rights, we can, we'll say, bridge some of that gap and get the shorter projects that could start to deliver earnings within, say, a year's time frame that on projects that are almost shovel-ready or are shovel-ready compared to the, we'll call it, 5-, 6-year cycle that we are continuing to look at through some of the longer plays, like the Central West, the potential for Central West pumped hydro in Australia.
[Operator Instructions] Our next question is from Maurice Choy with RBC Capital Markets.
My first question is just along the lines of capital allocation as well. I recognize that all the commentary that you have about renewable energy and the market is quite attuned about where the returns are for some of those projects and also recognize that similar to Q4, you've repurchased some of your own shares in Q1. As you look at your capital allocation options, is the NCIB something that ranks well or high on your pecking order? Put differently, what should we expect in terms of NCIB for the rest of this year? Or is that activity aimed at managing the stake held by ATCO and CU?
Maurice, thanks for the question. Yes, we did start some buybacks last year and continuing into the first quarter this year. And at Canadian Utilities, we haven't really done any buybacks, let's say, in the last 15 years or so. The primary motivation on the buybacks is to offset the dilution from stock options. And those have been accumulating over that 1.5 decades. What this program is looking at is to right the ship and to offset the dilution that has eroded to our shareowners over the last 1.5 decades. A lot of -- I'll say a lot of things got in the way, as you know, the big build in transmission, primary one of them. We have purchased, I think, about 1.8 million shares in Q1. Under the NCIB, there's about another 1.7 million shares in potential that we could do until the NCIB runs out in June or July. Just as a matter of course, we're probably looking to renew that NCIB just as a matter of course. In terms of capital allocation, are we looking at -- are we considering taking a big hunk of the cash on the balance sheet and our capacity and plow it into buybacks? That's not really the case.
And just a follow-up on that, like recognizing you've got 1.7 million left that you're renewing the NCIB, how much more do you need to do in order to offset, I guess, 1.5 decades dilution?
We'll take a look at that as we go, Maurice. I suspect a fair chunk of it.
Okay. I'll follow up with that off the call. The second question is just to pick up on Puerto Rico again. And I recognize that Wayne presented at a government hearing recently. And there's been suggestions about the contract being amended, including the investment -- the incentive criteria you alluded to earlier. Could you help us understand how you now frame your earnings expectation versus when the agreement was signed? On one hand, it's likely that it's harder to achieve incentives. But on the other hand, if you do move into the supplemental agreement, I reckon that the fees possibly could be higher than what was designated for year 1.
Yes. I don't know if it's tougher to achieve those incentives or not because the bar hasn't been set. As I discussed with Mark out of the shoot, we'll see what the PREB kind of approves for going-in standards in order -- that we would need to achieve or exceed in order to earn those incentives. Under the supplemental agreement, there is no incentive potential because it's still in bankruptcy. We don't have all the means to improve performance. So in lieu of not being able to achieve to earn incentives under the supplemental agreement, the fixed fee is higher. I think all the contract details are out there and you want to double check with Myles as to the amounts. That potential is there. But in terms of the overall status of the contract, it's probably fair to say that it's been harder than we thought to go through the front-end transition. I think Mr. Stensby has done a phenomenal job with the hearings and with the people in Puerto Rico. We are committed and stay committed to improving the service for all Puerto Ricans. And that is the primary focus. The governor has come out and supported the agreement. And we are continuing on the path with the expectation that we will exit front-end transition in June. So while it's been harder, the end result is somewhat the same that -- in terms of our kind of the returns that we would expect from that investment.
Our next question is from Patrick Kenny with National Bank Financial.
Just a quick question here on -- given the strong power price environment we've seen year-to-date, if you're experiencing any tailwinds on your retail business. I know it's still a small contribution. But just in light of the rate freeze, do you see your retail businesses potentially offsetting some of your cash flow drag over the next couple of years?
Thank you for the question. We are seeing certainly some tailwinds in our retail business. We no longer have the benefit of having a natural hedge on the generation side to the extent that our retail business has -- we've locked in some fixed-price contracts, then the increase to the power prices doesn't really help the margins. The teams have been doing a great job in managing that risk. You're here in Calgary, you know how cold it got in February here when it was minus, I'll say, 15,000 degrees. And we weathered that February quite well because of the great work that the teams have done in matching up the cost of the electricity with the sales. That being said, the energy -- retail energy business is continuing to chip away at market share that is published every quarter. I think there, the market share on the non-reg side is over 10% now, #3 in the province and continuing to look to grow that business. Increased earnings in retail energy are included in the -- our corporate segment for Canadian Utilities. So it is definitely a bright spot -- another bright spot in our first quarter results.
Okay. Great. And yes, thanks for keeping the lights and the heat on during February, appreciate that. I just...
And it stayed on because it wasn't me. So it's a testament to our field people and our ops guys, they did a phenomenal job.
Pretty sure. And then maybe just to tie a bow on the net cash flow drag, if you will. But does that change any of the funding plan going forward? And maybe you can just update us on what we can expect on the debt issuance front through the back half 2021?
Yes. The impact from that rate freeze is between $110 million and $120 million in rate increases that we would forgo in 2021, looking to recover them in 2023 over a time period yet to be determined. We would look to finance that with short-term debt and cover it off that way. Our 5-year cost is hovering around, I think, 1.5%, 1.6%, give or take. The interest that we would earn from the commission, we'd be looking at around a 2% mark. So we'll call that cost of the financing would be covered by customers at a very low rate. So that's our proposal. And we expect a decision here imminently. Yesterday, I heard it could be within a week. So we'll get clarity on that. But we wouldn't look to impact CU Inc.'s long-term financing as a result of this short-term relief for our customers.
This concludes the question-and-answer session. I would like to turn the conference back over to Mr. Myles Dougan for any closing remarks.
Thank you, Claudia, and thank you all for participating in the call this morning. 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.