Thank you for standing by. This is the conference operator. Welcome to the Canadian Utilities Limited Third Quarter 2019 Results Conference Call and Webcast. As a reminder, all participants are in listen only mode and the conference is being recorded. After the presentation, there will be an opportunity to ask questions.
I would now like to turn the conference over to Mr. Myles Dougan, Director, Investor Relations. Please go ahead, Mr. Dougan.
Thank you, Savvis, and good morning, everyone. We're pleased you could join us for our Q3 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.
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 Q3 2019 conference call. Canadian Utilities announced adjusted earnings of $106,000,000 in the Q3 of 2019, which is $26,000,000 lower compared to the $132,000,000 we recorded in the Q3 of 2018. You may recall, we recorded $42,000,000 in adjusted earnings in the Q3 of 2018 associated with the balancing pools 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 1st 9 months of 2019 are $432,000,000 or $12,000,000 higher than the 1st 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. 1st, thanks to all of our people involved in our regulatory filings, we produced positive earnings impacts from the Electricity Transmission 2018 2019 General Tariff Application Decision and the Natural Gas Pipeline 2019 2020 general rate application decision.
2nd, we continue to achieve rate based growth across most of our utilities, in no small part due to the focus of our capital teams. Through their great work, we continue 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 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 $821,000,000 of aggregate proceeds. We also recognized a gain on sale of $139,000,000 which is after tax, and that has been excluded from adjusted earnings. These sale transactions remove 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 a 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 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. Percent of bondholders providing their approval during the initial written consent solicitation process.
The sale of APL is expected to close in the Q4 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 discipline 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 3rd quarter.
In July August, Dominion Bond Rating Service released a series of reports affirming our A range corporate credit rating and stable outlook for ATCO, Canadian Utilities and CU Inc. Earlier this month, S and P Global Ratings affirmed their A- credit rating and stable outlook for our companies as well. We do intend to maintain these 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 Miles. Thank you, Dennis.
I'll turn the call over now to our conference coordinator for your questions.
Thank you. We will now begin the question and answer session. In the interest of time, we ask you to limit yourself to 2 questions. If you have additional questions, you are welcome to rejoin the queue. Near the top of the webcast frame and type their question.
The Canadian Utilities Investor Relations team will follow-up with you by e mail after the call. Our first question comes from Maurice Choi with RBC Capital Markets. Please go ahead.
Thank you and good morning. So my first question, I guess, just a follow-up on the capital deployment. It sounds like the commentary has been unchanged. I wonder whether if is it a case where we're still casting a wider net or there have been targets, be it markets or type of assets that you've further refined since we last had it at the Investor Day?
Maurice, good morning. No, there's been no significant change in our capital investment prospects. We're still forecasting our 3 years, and we're continuing our pursuits for redeploying our proceeds that we've garnered on the sale of our generation business.
And I guess since you brought the $3,500,000,000 I noticed that the electric transmission GTA, obviously, you've asked for 2020 to 2022, but also established an escalator for 20 232024. 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?
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 2024 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 4th 5th 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.
Thanks. And just finally on Australia. So I guess other than getting better clarity on the LOE, and I believe your commentary on cost rebasing is largely unchanged. Has there been anything that may have changed your view of your Q2
results in the $15,000,000 about a $15,000,000 per annum drop. That results in the $15,000,000 about a $15,000,000 per annum drop in regulated earnings coming out of Aqua Gas Australia. There has been a little bit of work in the Q3 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.
Thank you very much.
Thanks, Maurice.
Our next question comes from Andrew Kuske with Credit Suisse. Please go ahead.
Thank you. Good morning. 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 toward the end of their life versus really new growth capital?
Good morning, Andrew. Over the over our planned period, we're still looking at $400,000,000 to $500,000,000 worth of rate base growth per annum. 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 kind of a rough order of magnitude, I'll call it about 2 thirds system maintenance and reinforcement capital and about 1 third 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 and getting the backbone of our grid up to the oil producing areas. That really led to the, I'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 huge rate base growth in our electric transmission company as a result of hydrocarbons 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 how that drives our customers' investment decisions for future major plant.
Okay. Very helpful. Thank you.
Thanks, Andrew.
Our next question comes from Mark Jarvi with CIBC Capital Markets. Please go ahead.
Thanks. Good morning. I just wanted to come back to the your comments on the credit rating agencies. Were there any more discussions with them around shifting you down to a lower volatility, the business risk given the sale of the power assets?
Good morning, Mark. 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 grounds 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 kind of safe reliable service. As I mentioned earlier, about 2 thirds maintenance and 1 third growth capital, Projects like our urban pipelines renewals 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 in the 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 discussion with the rating agencies, how confident would you guys be redeploying 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.
Okay.
Thanks, Dennis. Thank you.
Our next question comes from Patrick Kenny with National Bank Financial. Please go ahead.
Yes, good morning guys. 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 2 40 kilobytes 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, 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 those customers really pay for the interconnection costs.
So if it costs, call it, dollars 50,000,000 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 material rate based growth as a result.
Okay. Thanks for that.
I'm curious your
thoughts on Mexico as a 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 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 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, number 1 United States, number 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 might be positioned here to capitalize on the next wave of petrochemical growth in that area?
Thanks for that 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 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 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. Please go ahead.
Yes, thanks. Good morning. Just a quick question on the some of the Keyfields 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. Yes, when we initially disclosed it, it was at $230,000,000 and then there was a time where we moved it down to $230,000,000 Since then, we've been consistent with our regulatory applications that's in there at $230,000,000 The project is in flight right now. We do expect those costs to come through between the $200,000,000 $230,000,000 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 Q4, early Q1, and we'll be able to give an updated number at that point in time. But we're right in there at that $200,000,000 to $230,000,000 range.
Okay. And then just in terms of the regulatory approval process for the pipeline project specifically, can you just remind us as to where you are with that?
We received approval for that Pembinaeke pills 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. And thanks for following up because that's been lost a little bit, but that's was one of the great successes in the Q3 is that we were able to get that approval from the AUC and will still be able to meet our customers' required in service date of Q2 of next year.
Okay. That's great. And then just as a little cleanup question. There was a note in the MD and A around changes in the recording of depreciation expense, I believe, in the Q3 and 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 and A on that.
Yes. And those I think my colleagues are signaling to me about $20,000,000 per year.
Correct.
$20,000,000 per year lower depreciation expense as a result of our depreciation study, extended lives. Our revenue comes down by the $20,000,000 Our depreciation expense will come down by the $20,000,000 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 a flat across the year, just out of curiosity?
The depreciation expense is flat across the year. Okay. Much appreciated. That's all for me. Unlike those distribution revenues.
Right. I understand. Thank you.
Yes. Thanks, Jeremy.
Our next question comes from Ben Pham with BMO. Please go ahead. Mr. Pham, your line is live.
Perhaps you're on mute, Ben. Are you there?
Yes, I'm here. Sorry about that. Can you hear me okay now?
Yes, we can. Go ahead.
Good morning, Ben. Good morning. Sorry, I was just calling from my cell phone. First question on Australia. ROE going down to 5%.
I know you've been able to over earn 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 rebates 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, let's 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 number 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 the last 3 years or 5 years or so. And then second one, the Australia sorry, Australia, the Alberta that factor decision that you quoted. I'm just curious, I know you 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 that's been going on for some time?
That's a good question. Where are they? In the Fed Factor decision, there wasn't, call it, a dissenting comments, but there were comments from the commission pointing out the oddities that the same fire can have an extraordinary retirement in one 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 distribution.
Our distribution sorry, our depreciation study at the time used our experience up until 2,008. 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 Stor's block and their singular interpretation that Storrs Block means extraordinary gains or sorry, extraordinary losses goes to the account of our share owners. 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 legislature's legislative side as well.
So it sounds like AUC has opined to some extent and now it's really you think it's more Alberta government's 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?
Well, that last one, that, call it, failed Bill 13 that they implemented. I mean, they, the amendments gave the AUC unfettered discretion in order to determine whether or sorry, how those proceeds or how those asset 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.
Okay. Okay, I got it. Okay. Thanks a lot, Dennis.
Thanks, Ben.
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, Savvis, and 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.