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Thank you for standing by. This is the conference operator. Welcome to the Canadian Utilities Limited Third Quarter 2019 Results Conference Call and Webcast. [Operator Instructions] I would now like to turn the conference over to Mr. Myles Dougan, Director, Investor Relations. Please go ahead, Mr. Dougan.
Thank you, Savis, and good morning, everyone. We're pleased you could join us for our third 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 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. Thank you all very much for joining us today on our third quarter 2019 Conference Call. Canadian Utilities announced adjusted earnings of $106 million in the third quarter of 2019, which is $26 million lower compared to the $132 million we recorded in the third quarter of 2018. You may recall, we recorded $42 million in adjusted earnings in the third quarter of 2018, associated with the balancing pool's termination of the Battle River Unit 5 PPA and the completion of performance obligations and availability incentives. While that was a good financial result last year, it also set us up for quite a challenge this year to close that earnings gap. And close that earnings gap is exactly what we've done. Our adjusted earnings in the first 9 months of 2019 are $432 million or $12 million higher than the first 9 months of 2018. Our pipelines and liquids and electricity businesses have both done well so far in 2019. Their positive earnings results have come from a number of areas. First, thanks to all of our people involved in our regulatory filings, we produced positive earnings impacts from the electricity transmission 2018 and 2019 general tariff application decision and the natural gas pipeline 2019 and 2020 general rate application decision. Second, we continue to achieve rate base growth across most of our utilities, in no small part due to the focus of our capital teams. Through their great work, we continued to deliver more energy safely and reliably for our customers. And third, our operating teams across the company have maintained a keen eye on cost containment and the implementation of cost efficiencies. Our customers benefit when we provide the best services in the most cost-effective way, and our shareowners benefit as we respond to the operating efficiency incentives inherent in our regulatory construct and generate premium returns on equity. Due to the great work of all of our people, we have been able to achieve some remarkable financial results. Continuing with that theme, during the quarter, we completed the sale of our entire 2,100-megawatt Canadian fossil fuel-based electricity generation portfolio in 3 separate transactions. Canadian Utilities received $821 million of aggregate proceeds. We also recognized a gain on sale of $139 million, which is after tax, and that has been excluded from adjusted earnings. These sale transactions removed coal-fired electricity generation assets from Canadian Utilities' asset portfolio and have the added benefit of significantly reducing our overall greenhouse gas emissions as of October 1, 2019. We also continue working on the sale of Alberta PowerLine. In September, we confirmed that 7 indigenous communities entered into definitive agreements to purchase the combined 40% ownership in APL. The remaining 60% of APL will be owned by an investment consortium. Canadian Utilities will remain as the operator of APL over its 35-year contract with the Alberta Electric System Operator. We are pleased to announce that late yesterday, October 30, we achieved another milestone towards the closing of Alberta PowerLine Limited Partnership sale. Bondholder consent was achieved with more than 95% of bondholders providing their approval during the initial written consent solicitation process. The sale of APL is expected to close in the fourth quarter of 2019. Going forward, we will focus on opportunities that globally diversify our portfolio of utility and energy infrastructure assets and leverage the breadth of our energy expertise. Our success as a financially secure and stable energy infrastructure company is a result of our disciplined and prudent capital investment in utility and utility-like assets with regulated or long-term contracted earnings. We will continue to look for similar investment opportunities outside of Alberta, in North America, Latin America and Australia. I'm also pleased to report that we received updates from our rating agencies on our financial strength in the third quarter. In July and August, Dominion Bond Rating Service released a series of reports, affirming our A range corporate credit rating and stable outlook for ATCO, Canadian Utilities & CU Inc. Earlier this month, S&P Global Ratings affirmed their A-minus credit rating and stable outlook for our companies as well. We do intend to maintain the strong investment-grade credit ratings in order to provide efficient and cost-effective access to funds required for our operations and growth. That concludes my opening prepared remarks, and I'll pass the call back over to Myles.
Thank you, Dennis. I'll turn the call over now to our conference coordinator for your questions.
[Operator Instructions] Our first question comes from Maurice Choy with RBC Capital Markets.
My first question, I guess, just a follow-up on the capital deployment. It sounds like the commentary has been unchanged. I wonder whether it's a -- is it a case where we're still casting a wider net? Or has there been targets, be it markets or type of assets that you've further refined since we last chatted at the Investor Day?
Maurice, no, there's been no significant change in our capital investment prospects. We're still forecasting our $3.5 billion of investment over the next 3 years. And we're continuing our pursuits for redeploying our proceeds that we garnered on the sale of our generation business.
And I guess, since you brought the $3.5 billion, I noticed that the electric transmission GTA, obviously, you've asked for 2020 to 2022 but also established an escalator for 2023 and 2024. Notwithstanding that AUC still has to review this extension bit of it, but can you speak a little bit about how this escalator may relate to your capital project opportunities or rate base growth for this business?
The -- our transmission business is different. The regulatory requirements for transmission is a little bit different than natural gas. Our rates on the electricity transmission side are date certain. So that means at the end of our test period we must file for new rates, whereas in our gas businesses, we can stay out on existing rates. What we've done is put in an option at our request to escalate the approved 2022 rates into 2023 and '24 at our option. So when we approach that time period, we'll be assessing whether the escalated rates for the, we'll call it the fourth and fifth years, will adequately recover our costs, including an opportunity to earn a fair return. And we'll take a look at what those growth prospects are in the transmission business at that point in time before we, if approved by the AUC, pull the trigger on that escalator or not.
And just finally on Australia. So I guess, other than getting better clarity on the ROE and I believe your commentary on cost rebasing is largely unchanged, has there been anything that may have changed your view of your achievable ROE from, say, Q2 or at the September Investor Day?
No. Not really, Maurice. I mean, the return on equity, as we've disclosed, has dropped from 7.21% to 5.02%. That results in the $15 million -- about a $15 million per annum drop in regulated earnings coming out of ATCO Gas, Australia. There has been a little bit of work in the third quarter by the regulator, taking a look at the load forecast. And there's been some puts and takes or toing and froing, I'll call it, with the regulator and submissions on that. But we're right now in a holding pattern until we receive the decision in November as currently anticipated.
[Operator Instructions] Our next question comes from Andrew Kuske with Crédit Suisse.
Maybe the first question is just on the outlook for rate base growth in Alberta, and maybe we could just discuss a little bit of the mix of replenishment capital that is effectively driven by assets that are sort of towards the end of their life versus really new growth capital.
Over the -- over our plan period, we're still looking at $400 million to $500 million worth of rate base growth per annum. That results in about a 4% growth per year. With the growth prospects and what we've seen over the past couple of years in Alberta, we've really gone to more maintenance capital as opposed to growth capital. Maintenance capital is absolutely required for safe, reliable service. Examples of that are our urban pipeline replacement program that we have in our gas transmission and a lot of the CapEx and electricity transmission. So on a, kind of a rough order of magnitude, I'll call it about 2/3 system maintenance and reinforcement capital and about 1/3 on growth capital.
Okay, that's great. And then maybe just a follow-up, when we see the policy coming out from the Alberta government today on just the rail over the production quotas, how do you think about just longer-term expectations for hydrocarbon production out of the province? And how does that impact the longer-term growth rates for CU?
Well, the hydrocarbon producers have been a great driver for the Alberta and federal economies as our customers required additional transmission facilities, powering the north in getting the backbone of our grid up to the oil-producing areas. That really led to the, we'll call it the big build in the northern part of our province. In the southern part of our province we had, and along with AltaLink as well, we had significant investments to rebuild our backbone to enable the interconnection of renewable generation. That backbone is largely built now for the major oil sands up north and the renewables down south. So we don't expect to see a huge rate base growth in our electric transmission company as a result of hydrocarbon growth. Our distribution company, as more wells are drilled and explored, as we interconnect the fields up in the Montney-Duvernay area that really does help our electricity distribution business. Again, it's a long-term play. We'll see what -- we'll see how that drives our customers' investment decisions for future major plant.
Our next question comes from Mark Jarvi with CIBC Capital Markets.
Dennis, I want to come back to your comments on the credit rating agencies. Were there any more discussions with them around shifting you down to a lower volatility for the business risk, given the sale of the power assets?
No, we haven't had any further discussions with the credit rating agencies regarding the improved quality of our earnings. We are looking to meet up with them soon. And when our paths connect, we will be continuing to advocate that, but we haven't made any further ground since we've last chatted.
Okay. And then, obviously, there's a little bit of uncertainty, and it's a bit hard to predict. But with the general cost of capital review coming up next year in Alberta, does that impact at all on how you guys think about redeploying the capital so much as maybe holding back a little bit, depending if they do lower ROEs just to help you guys from -- preserve balance sheet strength? Or is there any thought around holding back a little bit to see how that plays out?
Not so much. I mean, a lot of our utility capital is required for that in a safe, reliable service. As I mentioned earlier, about 2/3 maintenance and 1/3 growth capital. Projects like our urban pipelines renewal is continuing. We have reinforcement programs that are risk-based. And while those risks and timing of our actions change, our commitment to safe and reliable service does not. So we'll continue to deploy our capital as required in our regulated utilities in order to meet our obligations to serve requirements. If the generic cost of capital outcome results in lower ROEs, then that would be consistent with a kind of overall environment for all companies and lower for longer scenario. We'll take a look at as we redeploy our capital. If returns and utilities come down, returns and other targets may come down as well. So we'll take a look at that as we progress.
So just maybe as you stand today, given the proceeds that have come in here now where the balance sheet is and your discussions with the rating agencies, how confident would you guys be if redeployment isn't like the bulk of the proceeds now? Any concerns, any reservations about spending that money right now? Or sort of -- yes, any commentary around that?
We're not spending the money right now. I mean, we are sitting on the cash, and that helps our net debt for our FFO to debt calculations. As we've discussed at our Investor Day and continually, we will continue our prudent, disciplined approach to redeploying that capital. We're looking at our target markets outside of Alberta, Rest of Canada. United States, LatAm and Australia as well.
[Operator Instructions] Our next question comes from Patrick Kenny with National Bank Financial.
Dennis, there's been several new wind and solar projects announced in Alberta over the past few months. Wondering if this trend continues, if tying all these projects into the grid might represent a bit of upside to your electric rate base growth outlook?
I mentioned a little bit earlier our -- the big build for transmission, we upgraded our network, the backbone ourselves in AltaLink to 240 kV, our Hanna project and the AltaLink projects, I think. We initially energized 1 circuit. We built those towers for the ability to carry 2 circuits. And I'll say the major capital has already been invested. It's the lowest overall cost to be able to build a tower where you can hang 2 circuits on it. Right now on some of those lines, we've only hung 1 circuit. As the growth materializes, we have the ability to go in and, I'll call it, double the capacity of those lines. If there's future major wind projects that need to be interconnected, that backbone has been built in order to accommodate it. I think a lot of the economic projects for the wind and solar, the closer you are to hook up the better it is for those projects. And most customers really pay for the interconnection costs. So if the costs, we'll call it, $50 million to interconnect your solar project to the distribution system, customers typically would fund that while we would get the capital that would be offset with customer contribution. And as a result, there wouldn't be a material rate base growth as a result.
Okay. And I'm curious your thoughts on Mexico as a target market these days, given we saw some resolve over the summer on some of the gas pipeline contracts in the country. Maybe perhaps we could just get a refresh on your geographical pecking order for redeploying the sale proceeds between Canada, U.S., South America, Australia and Mexico?
As we look to redeploy the capital, our, call it -- or our target is for regulated or long-term contracted earnings in utility or utility-like. So if you think of a regulated utility is up there in the pecking order, those aren't really available in Mexico. So to redeploy those proceeds, we would be looking at other jurisdictions -- to redeploy in a regulated utility, we would be looking at other jurisdictions besides Mexico. We're still looking in Mexico for the long-term contracted earnings. We do have a few projects down there now, where we do have heavily contracted earnings, such as our Veracruz Hydro plant. And we continue to work with potential customers down there, options for utility-scale solar that we can -- can be built if we have the offtake and we're considering those types of projects down in Mexico as well. Yes. I can't give you Rest of Canada #1, United States #2, Mexico 3, Australia 4, South America 5 type of a pecking order. We evaluate each of those projects as it comes. But definitely, geographic diversity is a major consideration for when we review our potential projects and redeployment of our cash.
Fair enough. Yes, got it. And then lastly, it looks like there's going to be another round of petrochemical diversification subsidies here in the province. Can you just maybe remind us how your Heartland water assets and footprint, you might be positioned here to capitalize on the next wave of petrochemical growth in that area?
Thanks for that. A water question. We have our small kind of water company right now. We do have a contract to supply water to IPL's new facility that will be coming online in, I think, in 2020 or 2021, maybe 2021 time range. So we do have that water license. We're continuing -- we're able to interconnect IPL through our, we'll call it our little water backbone that we have there. So we are continuing to work with customers in the Heartland to help them with their needs.
Our next question comes from Jeremy Rosenfield with Industrial Alliance Securities.
Just a quick question on the Pembina-Keephills pipeline. It looks like the capital cost estimate has creeped up a little bit here quarter-over-quarter. Can you just sort of walk us through what changes have been made, if any, to the project? Or what's really causing the capital costs to move around here?
Thanks, Jeremy. When we initially disclosed it, it was at $230 million. And then there is a time where we moved it down to $230 million. Since then, we've been consistent with our regulatory applications. That's in there at $230 million. We -- the project is in-flight right now. And we do expect those costs to come through between the $200 million, $230 million mark. There are some contingencies associated with that project. Most notably, some of the river crossings with directional drills that we need to traverse a couple of water bodies here, and that will be the, I think, one of the key elements of whether all the contingency is required or not. We won't be passing through those events until later on this fourth quarter, early first quarter, and we'll be able to give an updated number at that point in time. But we're right in there at that $200 million to $230 million range.
Okay. And then -- and just in terms of the regulatory approval process for the pipeline product, specifically, can you just remind us as to where you are with that?
We received approval for that -- Pembina-Keephills in August of 2019, which was -- and it was approved as filed, which was about a full year after we filed that application with the AUC. So it put us behind the 8-ball a little bit. Thanks for following up because that's been lost a little bit, but that was one of the great successes in the third quarter is that we were able to get that approval from the AUC, and we'll still be able to meet our customers' required in-service date of second quarter of next year.
Okay, that's great. And then just a little cleanup question. There was a note in the MD&A around changes in the recording of depreciation expense, I believe, in the third quarter in the Electric Distribution segment, if I'm not mistaken. Can you just sort of explain what's going on in terms of depreciation rate changes and depreciation expenses? And if this is going to be something material that we should just be aware of for -- within that segment specifically going forward?
On the electricity distribution side?
Yes, I believe there's just a note in the MD&A on that.
And those -- I think my colleagues are signaling to me about $20 million per year?
Correct.
$20 million per year lower depreciation expense as a result of our depreciation study, extends the lives. Our revenue comes down by the $20 million. Our depreciation expense will come down by the $20 million, leaving no impact to earnings, a very small impact to the cash flows.
Do you know if there's a seasonality associated with that? Or if it's flat across the year, just out of curiosity?
The depreciation expense is flat across the year, unlike those distribution revenues.
Our next question comes from Ben Pham with BMO.
Perhaps you're on you mute, Ben, are you there?
Yes, I'm here. Sorry about that. Can you hear me okay now?
Yes, we can, go ahead.
First question on Australia. Are we going down to 5%. I know you've been able to overearn that historically. But are you -- is there options for you guys in the industry to look at maybe changing how that ROE would be calculated going forward rather than just having it rebased by monetary policy every 5 years?
We're looking at that with the legislators down there. We don't believe that the 5% is representative of the returns that we should be receiving on the systems. It gets set based on a 20-day observation period. So under the same rules, if you had your 20-day observation period back in January, your return on equity would be, I'll call it, materially higher than it is for 20 days in September. Unfortunately, it's a national regulation, the binding rate of returns, but we're continuing to advocate over the -- our access arrangement #5 in the next 5 years from 2020 to 2024, and we'll see how we progress over the term in order to get that turned around.
I agree with you -- okay. Yes, I know. It's just kind of usually have 1 month versus, say using average of the last 3 years or 5 years or so. And then second one, Australia -- sorry, not Australia, the Alberta Z factor decision that you quoted. I'm just curious, I know you've got a pretty large portion of proof, but what are you thinking about the remaining 10%? And how the regulators think about stranded asset risk? And maybe just an update on where is the regulator and maybe the government with the utility asset disposition conversation has been going on for some time?
That's a good question. Where are they? In the Z factor decision, the kind of -- there wasn't, I'll call it, a dissenting comment, but there were comments from the commission pointing out the oddities that the same fire can have an extraordinary retirement in 1 utility and an ordinary retirement in 2 others. We were able to recover our -- the book value of our assets in our gas distribution business and in our electric transmission business. But the fact that our distribution company didn't reflect the fires in our most recent depreciation study, which was just going into PBR, and that was the 2011, 2012 general tariff application for our distribution. Our distribution -- or sorry, our depreciation study at the time used our experience up until 2008. So we weren't able to reflect the Slave Lake Fire, even though we accounted for it in our usual way, recovered our costs. It was clearly known, anticipated. We filed evidence to say that even if the book value of those costs were included in our depreciation study, it wouldn't make one iota difference on our depreciation expense. The commission pointed that out with a view to spark conversation and move away from the -- I don't know, if the rhetoric is the right word, but help the AUC get over their interpretation of Stores Block and their singular interpretation that Stores Block means extraordinary gains -- sorry, extraordinary losses that goes to the account of our shareowners. So we're continuing to advocate on the regulated front, on the legislative front. We've been pretty clear that once our view is that once assets go in the ground based on an approved need and our costs are determined to be prudent that our utility is entitled to recover those costs irrespective of any future retirement event, whether ordinary or extraordinary. So that's what we are advocating with the legislatures -- legislative side as well.
It sounds like AUC has opined to some extent and announced, really, do you think it's more Alberta Government. I think the last one that proposed a bill it's something along the lines of that. Do you think that will provide a bit more clarity?
Yes, well, that last one, we'll call it, failed bill 13 that they implemented. I mean, they -- that amendment gave the AUC unfettered discretion in order to determine whether -- or sorry, how those proceeds -- or how those asset -- the loss on the destruction of assets should be attributed to shareholders or customers, given that discretion to the AUC. We'd be advocating no discretion to the AUC as opposed to 100% discretion to the AUC.
This concludes the question-and-answer session. I would like to turn the conference back over to Mr. Myles Dougan for any closing remarks.
Thanks, Savis, and thank you all for participating this morning. We really appreciate your interest in Canadian Utilities. And we look forward to speaking with you again soon. That's it for now. Thanks.
This concludes today's conference call. You may disconnect your lines. Thank you for participating, and have a pleasant day.