Canadian Utilities Limited

Thank you, Anastasia, and good morning, everyone. We’re pleased you could join us for our fourth quarter 2019 conference call.

With me today is Executive Vice President and Chief Financial Officer, Dennis DeChamplain, Senior Vice President and Controller, Derek Cook, and Vice President, Finance Treasury, and Risk, Colin Jackson. Dennis will begin today with some opening comments on our financial results and recent Company developments.

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 Investor section under the heading Events and 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 the Canadian Securities Regulators.

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.

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 2019 conference call.

Canadian Utilities achieved adjusted earnings of $608 million in 2019 compared to $607 million in 2018. Our strong performance in 2019 was mainly the result of continued cost improvements across the Company, ongoing capital investment and utility rate base growth, and positive regulatory decisions.

Two additional hydrocarbon storage caverns became operational in the second quarter of 2018 and provided a full year of earnings in 2019. Additional earnings also resulted from regulatory rate decisions in both the Electricity Transmission and the Natural Gas Transmission businesses.

Maintaining stable year-over-year earnings was quite an achievement considering that 2018’s adjusted earnings included $35 million in earnings associated with the Alberta Balancing Pool’s termination of the Battle River unit 5 PPA. We also recorded $12 million in earnings in 2018 due to an early energization incentive for completing construction ahead of schedule on Alberta PowerLine.

While all those were good financial outcomes in 2018, they also set us up for quite a challenge in 2019 to close that earnings gap. Due to the great work of our people in 2019, not only did we close that earnings gap, we recorded ever so slightly higher earnings in 2019 compared to last year.

We also completed two notable asset dispositions in 2019. In September, we sold or Canadian fossil fuel-based Electricity Generation business, and in December we completed the sale of our 80% interest in Alberta PowerLine.

We made the decision to sell the Generation business and our ownership interest in Alberta PowerLine in 2019 for different business reasons, but the overall strategic rationale is the same; we are increasingly focused on global prospects for growth. As we seek strategic opportunities to expand our global portfolio of utility and energy infrastructure investments and services, we continuously review our holdings to look for opportunities to monetize assets and increase our capacity for growth.

These 2019 sale transactions significantly improve our overall financial strength. Our many years of success as a financially secure and stable utility and energy infrastructure company is the result of our disciplined and prudent capital investment in utility and utility-like assets with long-term contracted earnings.

We will continue to look for opportunities for similar investments and complementary services outside of Alberta, with a particular focus on North America, Latin America, and Australia. Maintaining our patient approach to long-term shareowner value creation has been Canadian Utilities’ hallmark for many years.

We’ll look for the right investment, with the right strategic fit, and at the right price. In the meantime, we continued to build our portfolio of utility and long-term contracted energy infrastructure assets.

Our 2020 capital plans, including investing more than $1 billion in our five regulated Utilities and in long-term contracted capital assets, we are already busy on several of those projects in 2020. We commenced construction on the Pembina-Keephills natural gas transmission pipeline in the fourth quarter of 2019.

The 59-kilometre, high-pressure natural gas pipelines supports the coal-to-gas conversion of power producers in the Genesee and surrounding areas of Alberta. The estimated cost to construct this natural gas pipeline is approximate $230 million and is expected to be complete in mid-2020.

We secured long-term contracts and commenced construction for a fifth salt cavern hydrocarbon storage facility. Construction began in the fourth quarter of 2019 with full operation targeted for late 2021.

We also entered into a partnership with a Chilean developer to build and operate an 18-megawatt solar project located in Southern Chile. The total investment in this project is approximately $24 million with an expected completion in 2021.

With these projects and others, our plans for continued utility and energy infrastructure investments are already well underway in 2020. In January, we declared a first quarter 2020 dividend with a 3% increase over the dividends paid in 2019.

Canadian Utilities has increased its dividend per share for 48 consecutive years, the longest track record of annual dividend increases of any publicly-traded Canadian company. We are very proud of our track record of dividend increases.

It was a prudent choice to adjust the size of our dividend increase to be in line with our sustainable earnings growth, which is linked to growth from our regulated and long-term contracted investments. Over the next three years, our expected rate base growth is about 3% per year.

Going forward, Canadian Utilities’ strong, stable foundation of regulated utility and long-term contracted energy infrastructure investments and services will provide the platform to continue our long track record of exceptional returns for our shareowners. That concludes my prepared remarks, and I’ll now turn the call back over to Myles.

Thank you, Dennis. We’ll turn the call over to the conference coordinator now for your questions.

Thank you. I’m wondering if you could maybe give us some more context about how you’re thinking of the probability and timing of putting your sale proceeds to use.

What are you seeing in terms of the current environment, relative attractiveness of various geographies, types of investments; and at what point would you consider alternative use of the proceeds, including potentially share buybacks or special dividends?

Thanks. Good morning, Linda.

Good morning.

In terms of our strategy for redeploying the capital, we are staying the course with what we have communicated in the past. Our core strength is really managing operating regulated utility assets, so we’ve achieved, as you know, top-tier results under all different regulatory regimes to bring value to our shareowners.

I’m going to say there’s nothing imminent right now on redeploying that cash. I mentioned that we are looking for the right asset, in the right geography, at the right price.

In terms of alternate uses, right now our cash on the balance sheet does help our credit metrics as our FFO-to-debt is a net debt after you subtract the cash, so that does help us on the credit metrics side and gives us optionality. While we are focused on growing the business within Canadian Utilities, and we diligently pursue those, there’s, never say never, down the road we could look at a special dividend.

We did one in the mid-2000s and buybacks as well. But right now the focus is on growing the Company, so that is, in essence, our plans.

Thank you.

I think I’ve addressed your four bullets.

I’m sorry. I guess my follow-up question might have a few bullets as well, if you want to call it that.

On the flip side, you’re focusing on growth, but you also have been disciplined stewards of capital. What would be the criteria for considering on the edges partial or full asset sales; would it be if you found a supersized opportunity to raise proceeds; would it be maybe because it could serve as value and clearly these assets would be valued more highly with maybe private money or some other strategic operator; or maybe would ESG considerations influence as well how you look at optimizing your portfolio of assets and businesses?

I mean, we continue to look at our portfolio in terms of value to us versus value to others, and how it’s performing, and if it’s a long-term fit into our strategic plans. We, like many businesses, continue to review that.

Further asset sales, I guess, could be a potential. In terms of looking for super-sizing a deal, I mean, we have partnered and are willing to work with other partners in order to, I’ll say, increase the check size or increase the target size.

It’s the same check size for us in terms of potential targets. You mentioned ES&G considerations.

With the disposition of our Generation business our carbon dioxide emissions are down pretty much to nothing, I’m going to say, through our Generation. We’re at the point now where our Oldman River hydro dam that we retained from the disposition generates enough electricity to power all of our operative businesses.

In terms of ES&G bonuses and pluses, that is a factor that we look at, although that was not the primary reason for the Generation sales. We look for longer-term contracted earnings and the earnings for Generation were becoming increasingly merchant.

Probably. We would probably prefer electricity over gas.

That’s not to say that gas isn’t viable in the long term. We are innovating with hydrogen down in Australia.

We have opened our Clean Energy Innovation hub at our operations in Perth whereby we are creating green hydrogen, running a fuel cell off of that hydrogen, injecting some of the hydrogen into our gas lines to further kind of promote the usefulness of natural gas as a fuel in the future. Electricity, with the electrification of everything, we believe that there’s a great future there.

Maybe not the electricity that we’ve seen in the previous few decades, as more distributed systems come online. The next dollar, as you put it, we will look at electricity and gas.

All else being equal, which they never are, we would probably lean to electricity.

Thanks. Then the second question is more about this quarter or this year in particular.

As you look across the utilities in Alberta, can you speak to the achieved ROEs that you’ve seen this year and whether or not you believe some of the outperformances will continue moving forward?

On the PBR companies, we view those earnings as entirely sustainable. We are in 2019, finished year two of the five-year term of the second-generation of PBR.

So, we are well underway lowering the run rate of our costs so that we will be able to achieve the returns for the share owner over the PBR term. Just like when we came off of PBR 1 into PBR 2, that benefited our customers by having a great rate decrease as we reset from PBR 1 into PBR 2.

All the while during this PBR period, our customers are experiencing, I’d say, rate increases at lower than inflation. I’ll say that the PBR model is continuing to deliver the intended results for both our customers and for our shareowners.

On the cost of service utilities, they’ve been steady in their outperformance of the approved returns. That being said, there are just kind of more variability in those transmission cost of service companies as they go in and out of shorter two or three-year terms for their rates.

On the PBR companies, we view those earnings as entirely sustainable. We are in 2019, finished year two of the five-year term of the second-generation of PBR.

So, we are well underway lowering the run rate of our costs so that we will be able to achieve the returns for the share owner over the PBR term. Just like when we came off of PBR 1 into PBR 2, that benefited our customers by having a great rate decrease as we reset from PBR 1 into PBR 2.

All the while during this PBR period, our customers are experiencing, I’d say, rate increases at lower than inflation. I’ll say that the PBR model is continuing to deliver the intended results for both our customers and for our shareowners.

On the cost of service utilities, they’ve been steady in their outperformance of the approved returns. That being said, there are just kind of more variability in those transmission cost of service companies as they go in and out of shorter two or three-year terms for their rates.

Maybe just want to start on there was some commentary in the MD&A about reassessment of anomaly adjustments. I’m just wondering what that could mean for the PBR-regulated utilities in Alberta.

Hey.

The AUC kind of went back and reviewed what they had previously identified as their five criterion for identifying as an anomaly by which rates would be adjusted moving from PBR 1 into PBR 2. They essentially scrapped that criterion and have put it up for kind of an ad hoc, you make an application if you believe that an anomaly has been hit.

That being said, they have come out to say the past performance, the overall performance of the utility companies, they don’t believe would make it as an anomaly. AUC doesn’t expect there to be many anomalies, and it is on the utilities and the customer groups to apply for anomalies.

This would be going back and reaching back adjusting rates back to January 1, 2018, so there would be a cumulative impact should any anomalies be approved. We’ve applied for an anomaly to increase the rates due to the inflation factor.

We know of one customer group that has indicated that they will be applying for an anomaly. We don’t know what that application will be, but that process is intended to rollout over the remainder of this year, so I sure as heck hope we have got final rates for 2018 by the end of this year.

That’s the largest kind of potential retrospective reach that we have hanging out on our companies.

Could you quantify it at all, Dennis, in terms of what the impact could be on retroactive and even on the go-forward?

I think that I’ll have to follow up. Maybe you can follow up offline with Myles because I don’t want to give you a wrong number, Mark.

Okay. Fair enough.

It is in the millions.

Okay. I wanted to maybe pick up on the comment you made about cash being on the balance sheet and being credit positive.

Just curious, and obviously you’ve seen Hydro One come to market this week with really low rates and the markets are right now. What do you guys think about the debt financing markets, and where you are with the balance sheet?

Do the current rates you’re seeing out there change when you come to market and maybe lock in at this lower rate for longer?

Yes. I mean, looking at the rates the other day with long Canada is at, whatever, 1.3%, and if you roll in our spread right now, it could be between 130 and 140 basis points; would make for, I’ll say, an even lower than our 2.96% issuance that we had from last year.

We generally have been issuing later on in the year once we get kind of a firmer bead on our capital programs. With the current environment right now, we continually monitor it.

I don’t think that there’s going to be a large uptick in the near future, but we continue to monitor it. As you know, we’ve been a traditional third or fourth quarter issuer.

But, yes, those rates are appealing, and they caught my eye.

Good morning, guys. Dennis, just on the 3% dividend increase versus ATCO with 7.5%, I guess, you mentioned the 3% rate base growth profile, but I was just curious what opportunities you might be pursuing to augment CU’s dividend growth rates so that it converges closer to ATCO’s over the coming years.

It makes sense. Then on the flip side, I guess, with the AUC considering a return to a formula-based generic cost to capital approach, how much downside to the 8.5% base ROE do you think you can absorb without impacting that 3% dividend growth rate?

That’s my pitch for returns to go up, not down. At 37% equity, every 100 basis points change from that impacts Canadian Utilities by between $40 million and $45 million per year, so that’s in earnings and cash.

If you look at $600 without generation and Alberta PowerLine, in future earnings, and you back that out, you’re in, call it, the $500 to $550 range, so that $40 million is a good hunk of growth.

That’s my pitch for returns to go up, not down. At 37% equity, every 100 basis points change from that impacts Canadian Utilities by between $40 million and $45 million per year, so that’s in earnings and cash.

If you look at $600 without generation and Alberta PowerLine, in future earnings, and you back that out, you’re in, call it, the $500 to $550 range, so that $40 million is a good hunk of growth.

That’s my pitch for returns to go up, not down. At 37% equity, every 100 basis points change from that impacts Canadian Utilities by between $40 million and $45 million per year, so that’s in earnings and cash.

If you look at $600 without generation and Alberta PowerLine, in future earnings, and you back that out, you’re in, call it, the $500 to $550 range, so that $40 million is a good hunk of growth.

That’s great. Very helpful.

Those are our considerations and what the impact of that GCOC would be. Again, that’s not effective until 2021.

Right. Got it.

Okay. Then just last one for me here, given the current selloff in commodities, you mentioned ESG considerations weighing in on your capital redeployment strategy.

Any chance you could clarify which geographies, industries, or even counterparties are now off the table given your strategy around ESG?

I mentioned ESG. The primary component for our generation was the, kind of, long term versus merchant earnings that was driving our Generation portfolio sale.

ES&G was a factor, but it wasn’t the driving factor in the decision. If you take a look at geographies, or targets with a heavy ESG component, we would think hard about investing in coal.

We could do coal, if there was a path, like we were on with our former Generation business, to convert it to cleaner fired natural gas. That being said, given where sentiment is and the investors, we would consider that in our targets, I don’t think anything is completely off the table right now.

Like I say, we could do coal and convert, but that’s about it.

Just one question for me. Wondering if you can talk about your Chilean investment in solar, and if there are any potential follow-on investments with that partner, the same region or in South America.

Thanks. That’s helpful.

Just wondering if you can add a bit more colour on what the scope of the scale of those additional investments could look like.

Well, it’ll depend on the opportunity. I mean, we recently completed north of $100 million deal for a 35-megawatt hydro plant in Mexico.

That gives you a little bit of an idea as to, in the tens of millions not the hundreds of millions. There are other opportunities out there that could be significantly larger than that, and our Development teams are looking at all of those elements.

As we continue to invest in our existing utilities, we’re continuing to look for M&A activity for other utilities and greenfield developments for probably more on the renewable side. We’re looking at all of those aspects given where we are with our current financial strength.

Well, thanks, Anastasia, and thank you all for participating this morning. We appreciate your interest in Canadian Utilities, and we look forward to speaking with you again soon.

Bye for now.