Canadian Utilities Limited

Thank you, Sachi, and good morning, everyone. We're pleased you could join us for our third 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 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 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 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.

Now, I'll turn the call over to Dennis for his opening remarks.

Thanks, Myles, and good morning, everyone. I hope you and your families are well and staying safe.

Canadian Utilities achieved adjusted earnings of $76 million in the third quarter of 2020, compared to $106 million in the third 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 $37 million in adjusted earnings in the third quarter of 2019. Excluding the forgone earnings from the businesses that were sold, Canadian Utilities earnings in the third quarter of 2020 were $7 million higher compared to the third quarter last year.

Higher earnings were mainly due to Storage and Industrial Water earnings, higher earnings in Electricity Generation from cost efficiencies, as well as higher earnings from our Alberta retail energy business. The COVID-19 pandemic, oil price decline and slowing global economic activity did not have a significant impact on Canadian Utilities' operations and financial performance in the first nine months of 2020.

While we are experiencing a softening in our capital investments, overall, our businesses continue to generate strong earnings and cash flows. On September 30th, we entered into an agreement to acquire the 130-kilometre Pioneer Pipeline for a purchase price of $255 million.

This agreement replaces the previously announced purchase and sale agreement, whereby NOVA Gas Transmission Limited, or NGTL, was to have purchased the pipeline under substantially similar terms. Canadian Utilities and NGTL agreed that we will transfer to NGTL a 30-kilometre segment that is located within their service territory.

We will retain ownership and continue to operate the 100-kilometre portion of the Pioneer Pipeline that is in our service territory. The transaction is subject to regulatory approvals by the AUC and the Alberta Energy Regulator, which are expected by the second quarter of 2021.

If approved by the regulators, this Pioneer transaction would add a net $200 million to Natural Gas Transmissions' current rate base of about $2 billion. Continuing with regulatory developments; on October 13, we received an AUC decision on the 2021generic cost of capital proceeding.

The Commission approved the extension of the current return on equity of 8.5% at an equity thickness ratio of 37%, both on a final basis for 2021. Our total capital investment in the first nine months of 2020 was $659 million, or $193 million lower than the same period in 2019.

Lower capital spending was mainly due to the completion of construction on Alberta PowerLine in 2019, as well as delayed capital investment in the Utilities. As a result of the COVID-19 pandemic and the oil price collapse, we do not expect to invest the previously disclosed $1.2 billion in capital in 2020.Our current estimate for the full year is approximately $900 million in regulated and long-term contracted capital investment in 2020.

We continue to review our three-year capital investment plan to account for changing customer needs and changes to capital projects that are directly assigned to us from the Alberta Electric System Operator. Finally, I'm pleased to inform you that, in August, Dominion Bond Rating Service affirmed it's A, long-term corporate credit rating and stable outlook on Canadian Utilities, and it's A, low rating on ATCO, our parent company.

In September, S&P affirmed it's A minus credit rating on Canadian Utilities and ATCO. S&P's outlook for both companies was revised from stable to negative.

S&P also affirmed CU Inc.' s A minus credit rating and maintained a stable outlook, reflecting S&P's decision to insulate the CU Inc.

credit rating from the ATCO Group credit rating. CU Inc.

has been our main debt issuer in recent years, so we think this decision by S&P to change from a single group rating approach to a separate rating approach for CU Inc. is entirely appropriate and has been welcomed by our CU Inc.

bond investors. That concludes my prepared remarks, and I will turn the call back over to Myles.

Thank you, Dennis. And we'll turn the call over now to our conference coordinator for questions.

Thank you. And good morning, everyone.

My first question is just picking up on the CapEx plan. Dennis, you mentioned, there's this softening in spend, and that has led to a $900 million spend this year down from $1.2 billion.

Can you share if you've had more recent discussions with your regulators, with regards to the direction of utility spend moving forward? Specifically, I suppose if you look at the effects of the pandemic, surely you are now able to revisit some of the types of spending.

Should we expect more towards electric side and perhaps away from gas, given GHG emission reasons, or are there any early indications of incorporating your findings from hydrogen blending?

Thanks, Maurice. We've not had direct discussions with the regulators on the CapEx.

As you know, our Distribution Utilities in Alberta and in Australia are covered by a five-year PBR or Access Arrangement deal, so that's relatively light-handed regulation for those companies. In terms of our Cost of Service companies, Electric Transmission is in the midst of its general tariff application.

It's, I'll call it, the long-running electric GTA. And we're also in the midst of our gas transmission.

So while there haven't been any direct discussions, the Electricity Transmission capital, to the extent that it's direct assigned by the ISO, there has been deferral account treatment to that capital. so any reductions or changes to that capital get trued up and the impacts flowed through the impactful through back customers and the company, accordingly.

What we see is really our Q3 results of capital where we spent about $200 million. We see that as kind of reflective of the run rate, or what we would expect to see in Q4, at a very high level.

That's kind of how we get to that approximately $900 million in capital investment for 2020. Once you factor in depreciation and other adjustments, that equates to about a 1% growth in rate base.

With regards to the ongoing knock-on effect to the three-year forecast, I think as everyone's aware, we're in an extremely fluid environment. We are reviewing our 2020 delays and deferrals and how much of that goes into the 2021 to 2023 timeframe, and then the domino or knock-on effect from the pandemic and oil price collapse, how much of that capital in that period would slide out.

So we're going through that, and we'll re-arrive at our net number and communicate that to you in our fourth quarter MD&A which will be out at the end of February; don't know the exact date. But there's no significant spend, I'm going to say, in hydrogen for this year, and again, we'll be reviewing that 2021 to 2023 forecast as we go through the final couple of months of this year.

And just a quick follow-up on that, is the process one where it's an internal review and/or is it one where you're waiting for regulators to come back with your feedback and finalize this capital plan review?

It's our internal view. We're not waiting on the regulator to form our investment plans.

Great. and the second and final question is in regard to Puerto Rico.

You would've seen some recent comments from some of the leading candidates for governor position, in regard to the O&M contract. Can you share any early thoughts as to how you think this contract will progress, if you've had any early discussions with any of the parties?

Thank you.

Sure, thanks, Maurice. At this time, LUMA doesn't believe that there's been a change in the assessment of the risk of termination of the agreement.

I think some of the - or at least one of the gubernatorial candidates has expressed such a sentiment, but despite the public statements, there haven't been any third-party actions that have been made that would undermine the legal enforceability of the agreement. And we are as committed as ever to work through the front-end transition period, and we're focused on improving electricity service to the people of Puerto Rico.

So no change in our view at present.

Hey, good morning, everyone. I wanted to talk about the GCOC, given the fact that they essentially pushed out and stopped the 2021 proceedings given they couldn't get a decision probably done and implemented in the next year.

So I think in the MD&A you guys think that they'll restart again in 2021 for 2022. How does that match up given the fact that PBR 2.0 is kind of will wrap up at the end of 2022?

How do you see the outlook here in terms of setting new regulatory ROE and equity thickness, and having that match up with where you are in the current performance-based mechanism?

Yes, good morning, Mark. Thanks for the question.

With our four Alberta-based Utilities, it really hasn't been possible in the past to have all of the components of our revenue requirement to be determined as final, final for the entire test periods that they're in. We do have a good balance between our Cost of Service and PBR companies.

It's about 60/40, 60% cost of service and 40% PBR companies, when you look at the rate base. Having staggered test periods, it really helps to lessen the overall impact of any rate resets in a given year.

Given that the GCOC impacts all four Utilities and all $13-ish billion of our rate base, it's extremely important that we have prospectivity for the GCOC. And I guess, beyond GCOC, what we want and quite frankly expect is that all material components of our revenues, whether GCOC, IT costs, what have you, are finalized in advance of the test periods, so that we and customers get the full benefits of prospectivity going into the terms.

You're right, it doesn't line up exactly anymore with the end of PBR 2.0, but it helps to align it, maybe on the gas transmission or electricity side, and we'll march forward; but again, having prospectivity for such an important matter like GCOC is paramount. So we are glad that the AUC has determined those rates on a prospective basis.

We're not happy that it's still among the lowest returns in North America, which we're continuing to strive to get that reflective of the risk, given the times. That's where we're at with GCOC.

When you re-enter, I guess next year, and you talk about the prospective outlook, what would you be advocating for in terms of a timeline for how long the new ROEs would be set for, or are you guys still gathering those thoughts right now?

Yes, we're still gathering our thoughts. From the last proceeding, I was going to say there weren't many fans, but I don't think there were any fans of returning to a formula.

I don't think much has changed to get parties to change their positions on that. So how long are we able to forecast out for final returns and equity thicknesses, given the current times?

Nobody wants to do this every year. We're probably looking at a two to three-year time period, but again, gathering our thoughts, and we'll see how that plays out when the AUC announces their timeline for that proceeding.

Okay. Then you made the comment about S&P and the fact that CU Inc.

preserved their stable outlook which is probably the most key to your funding and debt issuance. I'm just maybe wondering what the implications are for the negative outlook at ATCO and Canadian Utilities in terms of capital redeployment.

Again, maybe given the uncertainty with, secondly, the pandemic, how you guys are thinking about liquidity, balance sheet metrics in light of that revised outlook?

Yes, I'd put on negative outlook, not as you would expect, not loudly happy about that. They still have, essentially, a floor, FFO to debt, of about 15%.

We're looking at our plans and seeing what we can do to convince S&P that those are attainable, and the best way to do that is to deliver the goods for it. Having cash on the balance sheet is a credit metric positive for us, it goes to offset the amount for net debt.

In that regard, our strength of our balance sheet goes to help on those FFO to debt metrics. We'll soldier on and do what we can on our operations and work with S&P to help hopefully remove that negative outlook and get it back to stable.

Just a quick follow-up on that. I mean, at one point with the asset sales, particularly the power asset sales, I think your view was the business risk profile had improved and therefore, there might be an argument to be made to change your FFO to debt thresholds or benchmarks.

How have those conversations gone, and how do the debt agencies, credit rating agencies, think of the LUMA cash flows in terms of their business risk and quality - relative to a regulated earnings stream?

I'll deal with the LUMA part first. S&P views that not to be in the same class as utility earnings.

To move to the low volatility table where CU Inc. is at and having an FFO to debt floor of about 10%, they count that in, we'll call it the non-regulated bucket.

When you take a look at ATCO Group on an overall basis, with the, I'll call it the strengthening of our structure's earnings, and layer in LUMA and our other non-regulated businesses, they're of the view that the ATCO Group really should be judged on the medial volatility table, and therefore getting it to that 15%. So they haven't insulated Canadian Utilities Limited, but as that reg to non-reg mix in Canadian Utilities Limited is, we'll call it at least 90/10 right now, we do believe that if that negative outlook were to come to pass, resulting in a downgrade for the ATCO Group, that Canadian Utilities Limited should be insulated, similar to how CU Inc.

was insulated. But again, talking in hypotheticals, the best way to avoid it is to deliver that 15% FFO to debt, so we don't even need to go there.

Great, that's very helpful. Thanks, Dennis.

Thanks, Mark.

Thank you. Good morning.

Could you maybe give us just an outlook for your Energy Infrastructure business? I ask the question in part because you do have a fairly large land position and opportunity set in an area where there's not necessarily a lot of land available for development.

And given your asset base, you do function a little bit like Switzerland with the neutrality kind of view on things. How do you think about that business and just growing that business to a greater degree?

Thanks, Andrew. Great question on the energy infrastructure.

We do have our presence in the Industrial Heartland. We've got sufficient land to build substantially more salt caverns.

I think we're putting in number five right now for a customer, and room to put dozens more in. When you talk about our land position, we think Canadian Utilities Limited is ideally situated with the footprint in order to do that.

We do have other land holdings in ATCO, with our ATCO Land and Development company. So some of the lands in the Heartland area are owned by ATCO, but our Energy Infrastructure company is ideally poised, situated and we are actively looking at - we've got the hydrogen blend project in that area, and we're continuing to look to build out that Energy Infrastructure business unit in Alberta and abroad as we look at renewable energy, in terms of hydro, solar, in our other target markets as well.

Thank you for that. Maybe just on that latter point and maybe more focused on just the energy infrastructure side, when you see certain companies that have either engaged in outright asset sales of energy infrastructure or butterfly off assets, or planning to.

How do you think about that proposition from a Canadian Utilities perspective? There's a duality to it, that would you go down that path, or conversely, are there opportunities with just the pricing of those assets in the marketplace right now, where there's just opportunities for capital allocation outside of Alberta in that realm?

Yes. We continually look at our structure, and we'll call it corporate vehicle options.

Right now, we're happy with our Energy Infrastructure assets located within Canadian Utilities. It fits right in our wheelhouse in terms of our operational excellence, energy expertise.

So there are no immediate plans to do anything structurally with that company here and especially in the holdings here in Alberta.

Then growth opportunities elsewhere?

Yes, growth opportunities are, you know, Mexico is challenging, Chile, who is a large focus for us right now, as is Australia in terms of the developments, especially in those latter two geographic areas for development.

Okay, that's great. Thank you.

Good morning. I just had a clarification question.

First, I just wanted to make sure you said that you'd lowered the expected CapEx for 2020 to $900 million amounts from $1.2 billion. Is that correct?

That's correct, Matthew.

Okay, thank you. Second question; focusing on the Australian Gas Distribution business, it looks like, quarter-on-quarter, there was a little bit of a pickup there, and I know there has been some headwinds due to a lower forecasted inflation rate.

Are you seeing that reverse a little bit as economic conditions improve, and is that rebasing what drove the improvement in earnings in the Australian gas business?

Yes, Australia is down, I think, Gas Australia, about $8 million kind of year-over-year. As we look at it, the AA5 decision has taken about a $7 million reduction from Q3 2019 to Q3 2020.

You're right, CPI has been very challenging for Australia. That's contributing about a $4 million decrease in year-over-year.

The inflation rate that we use, we used the CPI, the forecast going into just a couple days ago, we're at about a 1.1% inflation rate increase. The actuals that came out were about 1.6%, so higher than what they were forecasting for the quarter.

We haven't seen an updated full year forecast for them just yet; maybe they've got it down under, but it hasn't made its way to my desk. So we are - it looks like there is some upward pressure on their overall CPI inflation rate, which the previous forecast had at 0.3%, and just for reference, I mean, that compares to a 1.8% inflation from last year.

So upwards pressure, we'll see how it goes in Q4.

Okay, thanks. Then a question in terms of the regulatory update provided in your presentation, saying you expect decisions on the electric and gas transmission general tariff and general rate applications.

I was wondering if you'd be able to help me understand what the impact of those decisions would be in 2021, and if we could quantify that?

Yes, the timing for the electricity GTA decision, if they hold to their current schedule, which has been problematic for them, we're looking like a decision in, we'll call it late Q1. Don't know what the impact will be.

That tariff application is for 2020 to 2023, so we probably won't receive it in time to record for our 2020 earnings. So there would be a retroactive impact for that decision, which we would need to book when we receive that decision.

I've said before; they rarely, if ever, give you more than what you ask for, so I can't forecast what that impact will be. On the gas transmission side, their GRA is for the years 2021 to 2023.

That process is going much better in terms of getting some prospectivity. We will get rates in 2021 for that test year, and again, the same comments; can't hazard a forecast as to what that impact is going to be.

Okay, thank you. Looking at the Pioneer Pipeline acquisition, I just want to make sure I've kind of got this right.

So essentially, it's $255 million, but then NGTL is going to end up paying, I think it was about $63 million to you guys for their portion, and then when you net out the $255 million minus that 60 something, is that how you get to your $200 million, approximately, added in the rate base?

Yes, exactly. There's a little bit of extra work that we need to do to tie everything in.

There's a little bit of investment on the gas transmission side, and it brings it to around $200 million.

Oh, okay, so it's about 190 something million and then there's a bit of investment after that, and that brings it to that figure there. But your net investment is going to be closer to that $190-something million after NGTL buys their portion?

Correct.

Okay, thank you. That's it for me.

I appreciate the colour on that. I'll turn the call back.

Thanks, Matthew.

Hi guys, I was just wondering if you'd be able to help me out with one thing here, if you're able to quantify, say, the demand recovery in the quarter for your C&I customers, just in terms of, say, percentage impact of load and then the financial impact there, and where we're at right now compared to pre-COVID levels?

Yes. What we're seeing on - are you talking electricity distribution?

That's right.

Yes. What we're seeing overall for electricity is about a 5% reduction in sales.

The industrials and commercial, C&I, is about a 7% reduction year-over-year. And we're seeing about a 4% increase in our residential load.

We're closely monitoring to see if this will qualify for, under PBR, a Z Factor application to recover lost earnings from exogenous events. The materiality factor for filing those Z Factor applications is about $3.5 million for electricity distribution.

While C&I will have a 7% load decrease, it's protected by ratchets, contracts, fixed charges, to the extent that - we are, I'll say, right on the cusp of whether we even meet that materiality threshold in order to recover from customers the lost earnings from the impact of COVID. So we're taking a look at it; we don't know yet whether it will trigger that $3.5 million earnings impact.

We'll see how Q4 goes as COVID has reared its ugly head here in Alberta of late.

Okay, that's very helpful. I appreciate the colour.

That's the only question for me.

Thanks, Paul.

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