Canadian Utilities Limited

Thank you, Anastasia, and good morning, everyone. We’re pleased you could join us for our fourth quarter 2020 conference call.

With me today is Executive Vice President and Chief Financial Officer, Dennis DeChamplain. Dennis will begin today with some opening comments on his -- on recent company developments and our financial results.

Following his 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 securities -- 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 fourth quarter 2020 conference call.

I’d like to begin by talking about our performance in 2020; then our capital investment outlook; and lastly, our sustainable growth direction for the future. As most of you are aware, our investments are largely focused on regulated utilities and long-term contracted businesses with strong counterparties.

Over the years, we’ve created a resilient investment portfolio able to withstand turbulent economic conditions, and 2020 sure had its share of turbulence. Our Australian natural gas utility entered a regulatory reset year with a much lower approved return on equity and severe financial headwinds as a result of the slowing economy due to the COVID-19 pandemic.

We also lowered our 2020 capital investments in the year by $300 million as a response to the slowing economic activity. While we experienced a softening in our capital investments this year and slowing activity in some of our businesses, overall, Canadian Utilities continued to generate strong earnings and cash flows.

Overall, the slowing global economic activity did not have a significant impact on our operations and financial performance. On a normalized basis, excluding the foregone earnings from the businesses we sold in 2019, Canadian Utilities earnings in 2020 were $535 million or $14 million higher compared to 2019.

Our resilient financial performance is a testament to our business model as well as our people who remain focused on continuing to deliver reliable service to our customers. They face considerable operational challenges of working in these new pandemic conditions with courage and dedication, and performed in an exemplary fashion.

Our 2020 earnings were buoyed by initial earnings from the Puerto Rico contract that I’ll talk about more in a minute as well as continued excellent performance from our distribution utilities operating in their third year of PBR 2’s 5-year plan. Their performance, along with continued improvements in our cost structure across all of our businesses, were able to overcome the headwinds experienced in Australia and electricity transmission, which transitioned from capital to operating activities on Alberta PowerLine.

Our focus on operational excellence has been a key driver in creating a more innovative culture that has empowered our people to find new and more meaningful ways to meet the needs of our customers. In doing so, we have continued to improve our overall cost structure, thereby providing premium returns on equity for our investors and long-term benefits for our customers.

That commitment was a key factor in our successful 2020 bid for a 15-year contract to operate Puerto Rico’s electricity transmission and distribution utility. This 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. Going forward in our Australia and our Alberta utilities, we expect to invest $3.2 billion in capital growth projects over the next 3 years.

This capital investment is expected to generate growth in our utility asset base of approximately 2% per year, which is a leading indicator of the growth trend of our utilities. Our regulated utility operations are our largest contributor to earnings and will remain so for many years to come.

Regarding developments on the regulatory front, in October, the Alberta Utilities Commission issued a decision on the generic cost of capital, or GCOC, approving the current 8.5% return on equity and a capital structure of 30% equity on a final basis for 2021. The AUC commenced a new GCOC process in early 2021 to address the ROE and equity thickness for 2022 and beyond.

Our hope and, quite frankly, expectation is that this will be resolved this year, so we maintain prospectivity and avoid regulatory lag heading into 2022. We are waiting on 2 regulatory decisions addressing our electricity transmission and natural gas transmission general rate applications.

We expect decisions on both proceedings later in this first quarter of 2021. Natural gas transmission also entered into an agreement in September to acquire 100 kilometers of the Pioneer Pipeline here in Alberta for a net purchase price of $200 million.

The transaction is subject to regulatory approvals by the AUC and the Alberta Energy Regulator, which are expected in the second quarter of 2021. While we continue to invest in our core utility businesses to generate stable earnings and reliable cash flows, we recognize that a collaborative and long-term approach to minimizing our environmental footprint is vital.

We continue to explore new and more efficient ways to generate, distribute and conserve energy. Most notably, in 2019, we divested our entire Canadian fossil-fuel-based electricity generation business to eliminate coal-fired electricity from our from our portfolio and significantly reduced our greenhouse gas emissions by almost 90% from 2019 to 2020.

We see a shift to cleaner energy, and we are well positioned to participate in the development of clean fuels such as hydrogen and renewable energy infrastructure investments. In Australia, we’re focused on the shift to renewables.

We also believe that we can have a meaningful role in the transmission and interconnection of renewable energy to the grid as Australia expands its renewable generation capacity. In Latin America, we’re focused on energy infrastructure, particularly renewable generation.

We also continue to pursue various other business development opportunities with long-term potential here in our home market of Alberta as well as in our other target markets. To achieve this growth strategy, we’re focused on 3 aspects.

First, we will continue investing in our rate-regulated business to generate stable, reliable cash flow and adapt to changing utility customer preferences. Second, we will drive forward renewables and clean fuels as clean growth priorities to supplement our base regulated business.

And third, we may use smaller scale acquisitions to accelerate growth opportunistically, but we do not intend to invest in transformational M&A in the near term. That concludes my prepared remarks, and I’ll turn the call back over to Myles.

Well, thanks very much, Dennis. And now we’ll turn the call over to the conference coordinator for investor questions.

Thank you. Congratulations for navigating a challenging year very successfully.

I’m wondering if you can help us understand the decision-making behind the master services agreement with IBM, the onetime charge to terminate your prior agreement with your prior -- your current vendor and how that might translate into innovative new efficiencies, process changes and when and where we might see that in your operations.

Thank you, Linda. The decision to terminate the contract with Wipro was definitely not done lightly.

We really do believe that this new arrangement with IBM gives -- is the right path to meet the needs of our business moving forward. We really do require an IT solution that provides a platform for growth and innovation, increasing our use of cloud, artificial intelligence as well as automation.

So that’s the strategic rationale behind the switch. Onetime charge you see in the accounts backed out for adjusted earnings.

In terms of your, of the innovation question and the time frame, there is a 6-month transition from Wipro over to IBM that commenced February 1. So IBM, in essence, will get the keys to the operating systems in August of this year.

That’s the plan. And when do we expect to see performance from that change in vendor?

We really do believe that, that acceleration to cloud will result in tangible benefits. It will be hard to see them in 2021, but they should start to appear in 2022.

That’s helpful context. And maybe switching over to your utility distribution businesses.

Can you talk about, now that you’ve seen a full year, how the industrial and commercial customer base volumes were impacted by the pandemic and whether or not that might trigger some sort of mitigation through filing for a Z factor event?

Yes. We do have, thanks, great question, Linda.

I mean we do have the, both volumes in the AIF. I don’t have them at my fingertips.

We’ve been saying all along and there’s really no change on gas distribution, we don’t expect Z factor on the electricity side. We are kind of bumping our heads right up to that.

It’s about a $3.5 million trigger for Z factor. But where we stand right now, it doesn’t look like we’ll be filing a Z factor.

There’s no recovery in 2020 associated with that. But I’m going to say it’s doubtful that we’ll be recovering or we’ll be applying for any Z factor for electricity distribution.

They haven’t completed the final analysis yet. But in any event, it would be relatively small dollars.

So those volumes really, really hung in there on the electricity distribution side. We not, maybe not surprising, but we did think that the capital would come off more than what it did but we continue to see customers come to us looking for hookup to the electricity system.

So it, we really did weather that COVID, I’ll say, waves 1 and 2 extremely well.

And just as another follow-up question, looking at the next couple of years. I see that your incentive fees kind of escalate over your LUMA contract, energy contract.

I’m wondering what the what the performance hurdles are to get to the maximum amount. And what is the performance hurdle to get any amount, I guess, the bookends of when you might realize an incentive and when you might book it?

Yes. These performance metrics, they’re all outlined in the contract.

The parameters, however, have not been finalized yet. We just launched our filings.

We’ll call them the big 3 filings with the Puerto Rico Electricity Bureau or the PREB there. One of them is initial budgets.

We’re applying for no rate increase. The next one is on a system remediation plan that we have for the island’s electricity system.

And the third one is on those performance metrics, where we’ve submitted those amounts that we believe where the bar should be set. That’s going to go through approximately a 90-day process, and then we’ll be in a better position to be able to answer the question as to the quantum and timing for any incentive fees coming out of that contract.

The regulatory decision from the PREB, and they’re on their kind of a 90-day clock now, is a condition precedent for coming out of the transition timeline and moving into the contract years.

Great. I wanted to talk about Australia.

Maybe, Dennis, you can comment a little bit about that pumped hydro project that you seem to be involved in now and maybe just dovetail that with your comments around looking at opportunities around electric transmission in Australia in terms of what that size, scope, style, the economic framework for transmission opportunities might be.

Thanks, Mark. Yes.

That’s, I’m going to say it’s very, very early days on that pumped hydro project. It’s, there are clear signals forming in the market that this type of product is going to be required as renewables penetrate and escalate their share of generation as their coal comes off.

We were, I’m going to say, a couple of years out for making a final investment decision and that we’re anticipating early 2023 and commercial operations pending FID would be a few years after that. So we’re looking at 2026 as to when that could deliver earnings.

It’s a 325 megawatts, approximately $500 million development. So we believe that’s kind of in our wheelhouse, as we move, sorry, as we, after we’ve disposed of our Canadian fossil fuel and moving into the renewable electricity generation.

You also mentioned the transmission, and that is firmly in our expertise coming off of successful projects like the West Fort McMurray Transmission Development, EdL and before that, the Hanna Region Transmission Development. So we’ve, I think we’ve really honed our craft with respect to that long transmission, long linear projects and to help get that renewable energy to market in Eastern Australia.

Now we’ve been, we’ve got our critical mass, we’ll say, in Western Australia with our gas business in Perth, but we do have our structures business on, kind of on the East Coast with manufacturing facilities in Brisbane, so, and operations down in the Sydney area as well. So looking to expand that utilities and energy infrastructure portion out from the West into the Eastern Australia.

So we’re very excited about the project, and it’s very early days with a long ways to go. But we’re working on it.

And just a follow-up in terms of -- you need, obviously, some sort of long-term offtake for pumped hydro to move forward. And then on the transmission, would it be more like concession-type projects or actual ownership of some permanent regulated utility assets?

Yes. On the offtake for the pumped hydro, our business development and sales teams will be looking to contract for a significant portion of that asset as we move forward to making FID.

On the transmission side, it’s looking more like an ownership model that we would charge a kind of -- get a capacity charge based on a regulated rate.

Okay. And then one question in terms of the results in the quarter.

The natural gas distribution utility performed quite well, really strong year-over-year. There’s some commentary about some timing of cost.

Can you just maybe outline what drove the strong year-over-year performance? And if the timing of cost is because you already incurred them in prior quarters?

Or you deferred this quarter and you’ll have to incur those in subsequent quarters?

A lot of the boost to the earnings in our natural gas distribution business, it’s -- I’ll say, it’s a combination of operating and capital efficiencies. If you can recall, the PBR 2, the revenue makes in a notional $300 million per year in capital.

And while we’re operating safely and reliably as a lower CapEx, those savings compound and are really starting to deliver, I’ll call it, kind of material in-year savings. Of course, when we go to rebase coming out of PBR 2 into PBR 3 or the next version of regulatory, that lower rate base will result in lower charges, which flow through to customers.

So there’s a lot of the upsides associated with capital improvements and then also on the operating end of it. I’m going to say there’s numerous small initiatives that are amounting to those costs -- cost savings.

The timing element, we’re really catching up. Hang on a second.

Where am I going here? Sorry, I’ve blanked out here on you, Mark, for the timing of the operating costs.

That’s all right. We can follow up with anyone there, Dennis, or you can come back to there on the call.

Those are the questions I had for now.

Sure. That’d be great.

Thanks, Mark.

You had some comments on how you expect to achieve growth, and one of your comments was not looking to transformational M&A. I’m just curious, is that just really a reflection of where your stock is trading today?

It’s hard to do M&A in a big way, or is it more you feel confident in those other 2 pillars that, that 2% rate base growth will start to gain some traction as your core businesses in Alberta, in particular, are going to ramp up next couple of years ahead?

Yes. Thanks, Ben.

If you’re looking at the stock price, maybe it’s kind of like our price relative to the price that utilities are going for. They’re going for up to 2x rate base.

It’s really kind of -- in absolute and relative terms, they’re pretty expensive right now. So we’re not looking to go that way.

The regulated pillars, as you referred to them, with that 2% rate base growth, while not at the levels we saw during the transmission big build that was -- that drove a lot of that increase. We really see that growth as kind of our anchor tenant in order to help drive growth in the energy infrastructure, renewables, nonregulated side of the business.

And there’s very little. I don’t think it makes the rounding on the $3.2 billion of CapEx for the next 3 years.

It’s pretty much entirely on the utility side. We haven’t put anything in that capital commitment for things like Australia pumped hydro or other capital associated with some of our other irons in the fire that we have given that we’re not -- we haven’t announced those projects.

Okay. And maybe when we think of the small-scale acquisitions, I’m thinking that, that’s more Pioneer and maybe it includes the pumped hydro one you did just more development.

Can you share the really thought process around -- is that -- the most of it just in your core geographies here, you’re looking at -- you need it to be accretive in the first year? Maybe context on size, what’s your definition of small scale?

Well, the Pioneer is, we’ll say that’s just like a natural extension to our utility assets. And while that’s kind of an acquisition, it’s -- I don’t want to say it’s a no-brainer, I mean, because we are looking to diversify geographically.

This is a gas asset in Alberta. It comes with a 0 premium.

And we just fold that into our existing operating footprint. So the 100 kilometers is in our operating footprint.

So we believe that, that’s -- rightfully falls to the gas -- our gas transmission based on the integration agreement that we have with Nova. So that’s -- whether it’s a small acquisition or just an extension of our utility growth.

In terms of opportunistic M&A, we’re not necessarily looking for kind of that in-year accretive. We’re looking to build for the long term.

We acquired the pumped hydro rights for a small undisclosed amount of money. And that has the potential to drive earnings, as I mentioned earlier, in the back half of this decade.

So, we’re really focused on the long-term growth being driven from the renewables side of the host. Sorry, Ben.

The other element is LUMA. We have a half year worth of earnings in 2021.

And the contract amounts are included in the MD&A. And as we ramp up to full operations, that will help to support the increased growth in earnings.

Yes, there’s that base -- 2% rate base, and then you got these other [Indiscernible] drivers. And maybe just to close off the loop on M&A, would you compute the Aqua Gas Australia acquisition as large scale back then, 10 years ago?

I mean is that -- would you characterize that as large scale for you?

Yes, $1 billion 10 years ago would have been large scale for us.

Good morning guys. I was just curious what you’re hoping to see come out of the Alberta hydrogen roadmap this spring, what near-term opportunities you might be looking to sanction within the energy infrastructure segment as well as potentially any upside to the capital outlook for the distribution business.

And I guess related to that is, curious if you think it makes sense to build the blue hydrogen production facilities effectively on-site of the power plant, so I guess, at the end of the natural gas pipeline, such as your Pembina-Keephills line. Or do you think over time, it makes more sense to build more of a production hub closer to the storage caverns in Fort Saskatchewan and then build dedicated hydrogen pipelines to the power plants and other end users?

Yes. Thanks, Pat.

And good morning. I think in terms of what kind of would make more sense would probably be that the latter scenario that you referred to in Fort Saskatchewan, where with hydrogen production there, we’d be the -- we’d like to think that we’re the natural storage and transmission provider of that blue hydrogen.

We’ve got 4 caverns operational, one under construction and room for dozens more. So we are exploring that hydrogen development here in Alberta very seriously.

So we really do see that as not -- great potential, not only for hydrogen blending into the distribution system to lower the greenhouse gases, which we do have that pilot project that we’re doing right now in that Fort Sask area, but also to a greater extent throughout natural gasses footprint.

Okay. That’s great color.

And then maybe switching over to LUMA. Outside of your counterparty’s debt restructuring there, can you just clarify how your contract might be backstopped by the emergency funding that was approved by the previous U.S.

administration last fall? And just if you have any insights into -- if that funding has been reaffirmed by the new administration.

Yes. I don’t think it’s been reaffirmed by the Biden administration.

I do know that FEMA has never backed down on its committed funding, even with changes in the presidency. That roughly $10 billion from FEMA goes to reconstruction of the Puerto Rican electric system that was damaged by the hurricanes that, that money necessarily hasn’t kind of backstopped our agreement.

But one of the conditions for that to receive that money is that a private operator needs to be in the chair. The Federal Oversight Management Board, FOMB, are very supportive of us and of having that private operator go in to really remediate that system and get it to approaching world-class.

And that’s going to take a number of years given the state of disrepair that, that system is in right now.

Dennis, I think you mentioned earlier on in the call that you spent many years really honing your craft of long linear infrastructure. And I guess if we look back over the last, we can pick any time frame, 10, 20, 30 years, all the heavy lifting you did in Alberta to really keep up with the pace of growth in the province.

And now you’re at this juncture where growth looks like it’s flattening out. And I guess there’s a bit of a duality of the question.

Are you seeing any signs of green shoots in Alberta? And then maybe the other aspect of this question is, given what you did in Alberta over all those years, is that a great calling card for you to execute in certain projects and RFPs like you did with Puerto Rico?

Yes. Great question, Andrew.

And you can see in the MD&A over the next few years, we are forecasting our transmission from the big build of just over $5 billion in assets. It’s built, and with the depreciation burn, it’s pretty much offsetting the CapEx.

So you see that flat over the next few years. So while there’s green shoots in Alberta, we don’t really see too much of that impacting the, our electricity transmission business, which, at 5 out of 13 for our utility rate base here in Alberta, that’s a big anchor.

It’s spinning off great cash flows right now, but we don’t anticipate a meaningful transmission development over, for the next 10 years because the grid’s been built to accommodate the interconnection of renewables and so on. We do see some pickup on our customer requests coming from our gas business.

On the distribution side, it really seems to track with GDP. So as the Alberta GDP goes, that’s what we would expect to see our electricity and gas business growing by, all else being equal, not including hydrogen for our gas or kind of like the grid modernization and strategic improvements that we need to do to the electricity grid to enable distributed systems, smart energy networks and what have you.

So we’ve got the GDP, but we also have some, we’ll call them, strategic investments that we need to do on the distribution side. And that goes to our calling card and you’re bang on.

Our performance over the last number of decades where we continually improve on our operations, our efficiencies, that was great for the resume that we think helps put us over the top on the Puerto Rico contract. So we’re digesting that right now, and it’s a lot of heavy lifting to get through the transition agreement and then would, sorry, the transition time frame.

And then we can look to apply those operatorship-type skills to other potential opportunities, whether they exist now or whether we can go out and create them.

That’s very helpful. And then maybe just following up on the operatorship side of things.

With what we’ve seen in Alberta year-to-date with cold weather, the market transition into different kind of market versus the PPA, the legacy PPA system, can you maybe talk a little bit about just the resiliency of the system and how things held up? And were there any surprises with just the new market construct and the opening up this market again?

On the electricity side? Is that what you’re talking about?

Yes.

Everything held in, held up really, really well. I was reading on the ISO website the other day.

There is a kind of an outage on one of the tie lines coming in from BC, and they said, don’t worry, it’s not like Texas. So if you compare us, I mean, we’re built for the cold weather.

The system held up. Pool prices obviously went up, but it held up very well.

Our distribution system, electricity transmission, there wasn’t a hitch. And given that we’re built for it, it’s kind of in our DNA on the gas distribution side as well where our people performed fantastically.

They’re, a lot of pride and admiration for our folks on the tools in order to keep the compression up. All of the system planning and response that we have kind of really shown through under the radar, I’m going to say, because it’s come to be expected that the, our homes will be heated, and that’s exactly what we continue to deliver.

A bit of a rah, rah, call it, shout out for our gas distribution guys. They, I’m glad I wasn’t out there in the minus 40.

My first question, just coming back to the capital deployment bit. If you look back at last year, there was obviously a benefit of maintaining financial flexibility in midst of pandemic.

Do you see yourself tilting more now to its deployment? Or is there still quite a considerable benefit keeping this flexibility?

And then that is, indeed, more towards deployment, is it fair to say that many of your initiatives are more towards sowing the seed for future deployment, like the pump hydro, like the hydrogen, rather than investing in operational assets today?

Thanks, Maurice. Yes, I don’t know, if anyone’s ever out of the woods from COVID.

We do still have the -- and the global economic turmoil that left in its wake. I love the financial flexibility.

It helps us on the credit metric sides. You’re correct in noting the kind of the longer-term project view.

We have a long track record of our greenfield developments. We built up our international power generation business, most of it disposed of in 2019 there.

But we still have that greenfield development -- sorry, recognition that the greenfield development will lead to higher long-term value for our shareowners, we’re not turning our back on kind of operating assets where we can use that to accelerate market entry into a region. Acquiring late-stage development projects that have been somewhat derisked but not all the way through can help, we’ll call that, middle ground where we can have some nearer-term earnings, maybe not instant accretive operational earnings but would come with a much shorter development timeline that we talked about earlier with the Australian pumped hydro example.

Great. And if I could just switch gears to Puerto Rico.

I recognize all the comments and all the questions earlier about the contract. But could you share any thoughts on what perhaps the steering committee formed by the Governor -- the new Governor to review the O&M contract could lead to.

Have you engaged discussions with them?

Yes. I mean Governor issued an executive order in January, and that supports the contract and did establish that steering committee to help shepherd LUMA into commencement.

So looking at things like ensuring some -- a couple of fundamental principles like stable utility rates, and I mentioned earlier in the call that we filed our application with the PREB that didn’t have any increase in the utility rates, along with the system remediation plan, that will help to drive down costs long term for customers. So that was one fundamental principle, stable rates.

And the second one was continued employment of the utility workers. We are in the process of -- on our recruitment drive as employees would move from PREPA into LUMA, the affected employees that choose or are not offered an opportunity with LUMA, do have, by law, employment with the government of Puerto Rico.

So we think that continued employment is a check as well. And given all of the, I don’t know, the legal, political charts that -- chartered waters that we need to go through, the steering committee, we really view as an ally to help get us to our targeted June 1 commencement.

Just two questions. You applied to defer the rate increases in Alberta.

While I realize that’s not going to have an earnings impact, it will have a cash flow or funds flow impact, can you, I guess, confirm that this is really not going to be that material that it would impact our credit metrics?

Thanks, Elias, for the question. I mean we didn’t take it lightly.

Our customers and Alberta right now are hurting as a result of COVID. Given the rate increases that we’re facing, our electricity and gas distribution utilities, we believe that it was the right thing to do for our customers, long term.

You’re right that it will not affect earnings, but it does affect cash flow. We will be filing our application next week outlining the quantums and potential recovery periods for that cash deferral.

It is not overly material. If you look at our cash flow from operations and foresee $1.6 billion, $1.7 billion range, so it’s less than -- materiality, in my mind, the hurdle is 10%.

It will be less than 10%, I suspect, of our overall cash flows. But we’ve -- in discussions with the rating agencies, it is -- it would be a timing issue purely.

So we don’t think that we’d be unduly penalized in one year for something where we have the remaining balance sheet strength in order to back up the kind of a range credit metrics where we’re at right now.

I appreciate it. And yes, I agree.

It’s just a 1-year thing with a clear line of sight to catch up. The last question and focusing a bit on Mark’s question earlier about natural gas distribution, I’ll just try to simplify it a bit because it caught me off guard.

We can expect to see a tailwind from the efficiencies into 2021 with that likely dissipating by 2022. Would that be a good way to view it?

Yes. I think those -- that if you’re talking about tailwinds and timings to Mark’s questions, I mean, some of those costs planned programs that we had in 2020, some of those got deferred.

So we’re not -- I don’t want to say kicking costs down the road, but there’s some elements of our O&M programs that we weren’t able to get to in 2020, which we would see coming through in 2021. So a little bit of headwinds for gas distribution in 2021 compared to where they were in 2020.

Well, thank you, 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.