Canadian Utilities Ltd
TSX:CU
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Thank you for standing by. This is the conference operator. Welcome to the Third Quarter 2020 Earnings Conference Call for Canadian Utilities Limited. [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, 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.And 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. Our 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 foregone 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 and 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 9 months of 2020. While we are experiencing a softening in our capital investment. Overall, our businesses continue to generate strong earnings and cash flows.On September 30, we entered into an agreement to acquire the 130-kilometer 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, [indiscernible] have purchased pipeline under substantially similar terms. Canadian Utilities and NGTL agreed that we will transfer to NGTL, a 30-kilometer segment that is located within their service territory. We will retain ownership and continue to operate the 100-kilometer portion of the Pioneer pipeline that is in our service territory.The transaction is subject to regulatory approvals by ABC, 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 AUC decision on the 2021 generic cost of capital proceeding. The Commission approved the extension of the current return on equity of 8.5% and an equity thickness ratio of 37%, both on a final basis for 2021.Our total capital investments in the first 9 months of 2020 with $659 million for $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 3-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 its A long-term corporate credit rating and stable outlook on Canadian Utilities and its A low rating on ATCO, our parent company. In September S&P affirmed its A- 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- 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'll turn the call back over to Myles.
Thank you, Dennis. And we will turn the call over now to the conference coordinator for questions.
[Operator Instructions] The first question is from Maurice Choy of RBC Capital Markets.
My first question is just picking up on the CapEx plan, then, as you mentioned, as a softening and spend and that has led to a $900 million spend this year, down from $1.2 billion. Can you share if you've had any recent discussions with your regulators with regards to the direction that you can spend moving forward? Specifically, I suppose, if you look at the effects of the pandemic, surely you are now able to leave that some of the types of spending. Should we expect more towards electric side and perhaps away from gas given the GHG emission reasons? Or is there any early indications of incorporating your findings from hydrogen blending?
Thanks, Maurice. We have 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 5-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, I'll call it, long on running Electric GTA. And we're also in the midst of our gas transmission. So while there hasn't been any direct discussions the electricity transmission capital to the extent that it's direct signed by the ISO. There has been deferral account treatment to that capital. So any reductions or changes to that capital get trued up and flowed through-- the impact flowed through back to 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 and in Q4, at a very high level. And 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 one percent growth in rate base.With regards to the ongoing, the knock on effect to the 3-year forecast because as everyone's aware, we are in a extremely fluid environment. We are reviewing our 2020 delays and deferrals and how much of that goes into the 2021 to 2023 time frame. And then the dominant or knock on effect from the pandemic and oil price collapse, how much of that capital in that period with slide out. So we're going through that and we'll arrive at our net number and communicate that to you on our fourth quarter MD&A, which is will be out at the end of February. Don't know the exact date, but there is 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, a couple of months of this year.
And just a quick follow-up, and that is the process, one where it's an internal review. And/or is it one that you're waiting for regulators to come back with your feedback, finalized this capital [ review ]?
It's our internal view. We are not waiting on the regulator to form our investment plans.
And the second and final question is regards to Puerto Rico. You would have seen some recent comments from some of the leading candidates for the governor position regards to the O&M contract. Can you share any thoughts as to how you think this contract with progress if you've had any further discussions with any of the parties? Thank you.
I'm sure, thanks. Thanks, Maurice. At this time, LUMA doesn't believe that there has been a change in the assessment of the risk of termination of the agreement. I think some of the, or one 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 legal enforceability of the agreement, and we are as committed as ever to work through the front entrance transition period and focus on improving electricity service to the people of Puerto Rico. So no change in our view at present.
The next question is from Mark Jarvi of CIBC Capital Markets.
Wanted to talk about the GCOC given the fact that they essentially pushed out and start the 20% -21% given they couldn't get a decision probably done implemented in next year. So I think in the MD&A you guys think the restart again in 2021 for our 2022, but how does that match up with given the fact that PBR 2.0 is kind of will wrap up within the 2022. So how do you guys see the look here in terms of setting new regulatory ROE and I think thickness and having in that much with where you are in the current performance-based mechanism.
Thanks for the question. With our -- for 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 going, 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 and with 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 4 Utilities and all 14-ish billion dollars 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 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 can get the -- so that we and customers get the full benefits of prospectivity going into the terms. So right, it doesn't line up exactly anymore, with the end of PBR 2, but it helps to align that may be on the gas transmission or electricity side and will march forward. Again having prospectivity for such an important matter like GCOC is paramount. So we are glad that the agency has determined those rates on a prospective basis. We're not happy that it's still among the lost returns in North America, which we continue to strive to get that reflective of the risk given the time. So that's where we're at with GCOC.
And when we enter I guess next year, can you talk about the perspective of what would you be advocating for in terms of a time line for, how long is the new ROEs to be set for or are you still gathering those structure now?
We're still gathering the gathering our thoughts. I mean we're-- from the last proceeding there weren't, I was going to say there aren't many fans, but I don't think there were any fans of returning to Formula. I don't think much has changed to get parties to change their positions on that. So how long can we able to forecast out for final returns and equity thicknesses given the current times. Nobody wants to do this every year. So probably looking at a 2 to 3 year time period. But again, gathering our thoughts and we'll see how that plays out when AUC announces their time line for that proceeding.
Okay. And then, you made the comment about S&P and the fact that CU Inc. preserve their similar look which is probably more senior funding in debt issuance. I'm just wondering what the implications are for the negative outlook at ATCO and key utilities in terms of capital redeployment again made and just given the uncertainty. Secondly, pandemic, how you guys are thinking about maybe liquidity balance sheet metrics and in light of that revised outlook.
Yes, put on negative outlook. Not as you would expect, not while we're 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 credit metric positive for us. It offsets the amount for debt. So in that regards, it is our strength of our balance sheet goes to help on those FFO to debt metrics. So 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 at the power asset sales, I think your view was the business risk profile has improved in Formula, there might be an argument made to change FFO, the debt thresholds for benchmarks. How those conversation gone? And how do you debt agencies, [ rating ] agencies, think of the LUMA cash flows in terms of their business risk and quality? Well, that's a regulated earnings stream.
Deal with the Loom apart first. S&P views that not to be in the same class as utility earnings, so to move to the low volatility table where the -- where CU Inc. is at and having a FFO to debt floor of about 10%, they count that and we'll call it, the non-regulated bucket. So when you take a look at ATCO group on an overall basis with the, I'll call it the strengthening of our structures earnings and later in LUMA and our other non-regulated businesses, they are of the view that the ATCO group is 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 at least 90 10 right now. We do believe that if that negative outlook quarter to come to pass resulting in a gallon grade for the ATCO group, that Canadian Utilities Limited should be insulated similar to how CU Inc. was insulated. Again talking and hypotheticals but best way to avoid it is to deliver that 15% FFO to debt. So we don't even need to go there.
The next question is from Andrew Kuske at Crédit Suisse.
Could you maybe give us just an outlook for your energy infrastructure? But that's and I asked the question part is, you do have a fairly large land position and opportunity set in an area where there not necessarily a lot of land available for development and given your asset base, you do a little bit like switch a one word neutrality kind of view on things. And so how do you think about that business is just growing that business to a greater degree.
Thanks, Andrew. Great question on the energy infrastructure. I mean 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 5 right now for customer and room to put it dozens more in. So when you talk about kind of our land position within Canadian Utilities Limited, we do have ideally situated the footprint in order to do that. We do have other our land holdings and 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 in 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.
And 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 an outright asset sales of infrastructure, energy infrastructure or butterfly off assets we're planning to. How do you think about that proposition from a Canadian Utilities perspective, then there is a duality at that, would you go down that path or the converts their opportunities with just the pricing of those assets in the marketplace right now where it's just opportunities for capital allocation outside of Alberta in that realm.
Yes. Yes, we continually look at of our structure and we call it corporate vehicle options. Right now, we are happy with our energy infrastructure assets located within Canadian Utilities. 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 with the holdings here in Alberta.
Number of opportunities elsewhere?
Yes, growth opportunities. Mexico is challenging Chile, who is a large focus for us right now, as is Australia, in terms of the developments in those, especially in those latter 2 geographic areas for development.
The next question is from Matthew Weekes of Industrial Alliance Securities.
I just had a clarification question. First, I just wanted to make sure, you said that you lowered the expected CapEx required $20 million to #900 million, but that was from $1.2 billion, is that correct?
That's correct, Matthew.
Okay. Second question. Focusing on the Australian gas distribution business and looks like quarter on quarter, their wallets, I'm looking at, bit of a pickup there and I know there has been some headwinds due to a lower forecast inflation rate. I kind of see that reverse a little bit sort of economic conditions improve and is not really sort of rebasing. Is that what you will be improvement in earnings in the Australian gas business?
Yes. Australia is down. Okay. Gas Australia about $8 million kind of year-over-year. As we look at it, the A5 precision has taken about $7 million in our reduction from Q3 2019 to Q3 2020. You're right. CPI has been a very challenging for Australia. It's contributing about a $4 million decrease in year-over-year. The inflation rate that we use with their CPI, the forecast going into just a couple of 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 had, what they were forecasting for the quarter, they haven't, we haven't seen an updated full year forecast for them just yet. Maybe they've got it down under 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 on how that 0.3% and that just for reference, I mean, that compares to a 1.8% inflation from last year. So output pressure, we'll see how it goes in Q4.
Okay. And then sort of a question in terms of the regulatory update provided in your presentation. Not saying you expect decision soon on the electric and gas transmission general tariff in general rate application. I was wondering if you'd be able to help me sort of 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 for a decision in, we'll call it late Q1. Don't know what the impact will be and that's for tariff applications 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. Don't know, I've said before they rarely if ever give you more than what you asked for. So I can't forecast what that impact will be. On the gas transmission side, the GRA's for the years 2021 to 2023, that process is going much better in terms of getting some cost activity. So we will get rates in 2021 for that test year and again same comments can't have a forecast as to what that impact is going to be.
Okay. Looking at the Pioneer pipeline acquisition, I just want to make sure I've kind of got this right. So essentially, it's $265 million but then NGTL can end up paying. Yes, I think it was about $63 million you guys for their portion. And then when you net out the $255 million minus that $60 million something. Is that how you get to your $200 million approximately added in the rate base?
Yes, exactly. There is a little bit of extra work that we need to do to tie everything in. So there is a little bit of investment on the gas transmission side and it brings it to a rounded $200 million.
Okay, so you take about $190 million something and then there is a bit of investment after that, that brings you to -- so that take you there. But your in that investment is going to be closer to that $190 million something after NGTL buys their portion?
Correct.
[Operator Instructions]. The next question is from Paul Dhaliwal of BMO Capital Markets.
I was just wondering if you'd be able to help me with one thing here. You're able to quantify stated demand recovery in the quarter for your C&I customers, just in terms of say like impact to load and financial impact there, just how well around right now compares to pre-target levels?
Yes, what we're seeing on, are you talking of electricity distribution?
That's right.
Yes, what we're seeing for overall for electricity, it's 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. What we're closely monitoring to see if this will qualify for under PBR said factor application to recover kind of lost earnings from exogenous events. That materiality factor for filing those that factor applications is about $3.5 million for electricity distribution and 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 kind of right on the cusp of whether we even meet that materiality threshold in order to recover from some 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. Let's see how Q4 goes. COVID has reared its ugly head here in Alberta of late.
This concludes the question-and-answer session. I would like to turn the conference back over to Mr. Myles Dougan for any closing remarks.
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.
This concludes today's conference call. You may disconnect your lines. Thank you for participating and have a pleasant day.