Canadian Utilities Ltd
TSX:CU
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Welcome to the Canadian Utilities Limited Third Quarter 2018 Results Conference Call and Webcast. [Operator Instructions] I would now like to turn the conference over to Mr. Myles Dougan, Senior Manager Investor Relations. Please go ahead, Mr. Dougan.
Thank you. Good morning, everyone. We're pleased you could join us for our third quarter 2018 conference call. With me today are Senior Vice President and Chief Financial Officer, Dennis DeChamplain; Vice President and Controller, Anthony Maher; and Vice President, Finance and Risk, Katie Patrick. Dennis will begin today with some opening comments in 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 & 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 reports filed by Canadian Utilities with the 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. Thanks very much for joining us today for our third quarter 2018 conference call. Canadian Utilities recorded third quarter 2018 adjusted earnings of $132 million or $0.49 per share, which is $38 million or $0.14 per share higher than the third quarter of 2017. Higher earnings this quarter were mainly due to stronger performance in our Electricity Global Business Unit. As you may remember, earlier this year, the Alberta Balancing Pool gave notice that it would terminate the Battle River unit 5 Power Purchase Arrangement or PPA. In order to do that, the Balancing Pool was required to take Canadian Utilities the remaining net book value of the PPA. We've received that onetime payment from the Balancing Pool this quarter and the net amount was included on our income statement, but was excluded from the calculation of our adjusted earnings. In addition, the Battle River PPA included causes for Canadian Utilities to earn incentive payments if we maintain plant availability above certain thresholds. We also book a profit margin on the O&M services that we provide at Battle River. The combined amount of $42 million for these profit margins and incentive payments was included in our income statement this quarter. We recognize these kind of payments in the normal course of business, and therefore, we have included them in our adjusted earnings this quarter. We also had higher earnings mainly due to improved Alberta power market pricing. The average power price in the third quarter of 2018 was about $55 per megawatt hour, or nearly $31 dollars higher than the third quarter of 2017. This was mainly due to an increase in carbon prices, which is being included in the market power price. There was also some improvement in the supply-demand balance with some other power producers retiring and mothballing some other of their coal-fired generation in Alberta. We also had a nice warm summer with warmer-than-average temperatures in July and August here in Alberta. On the business development side in electricity, we have been busy developing plans for the conversion of our coal plants to run on natural gas. Earlier this year, we successfully completed a project to co-fire natural gas at Battle River unit 4, enabling the use of natural gas for 50% of the unit's 150-megawatt total generating capacity. In the next phase of this coal-to-gas initiative, a conversion project will allow co-firing of natural gas on Battle River unit 5 for 100% of its 385-megawatt capacity. We expect to complete this BR unit 5 conversion project in late 2019. A full conversion of Battle River unit 4 and Battle River unit 3 is under analysis. We're also committed to the conversion of our Sheerness plant to run on natural gas. Sheerness is under a PPA with the Alberta Balancing Pool until the end of 2020. After that, it'll be returned to us to operate as merchant power plant. We are planning a full conversion of Sheerness from coal to natural gas. The conversion project is expected to be complete in advance of firm natural gas supply, which has been secured for the second quarter of 2022. In Australia, we completed negotiations on a 5-year extension to the Power Purchase Agreement for the 180-megawatt Osborne Power facility, located near Adelaide. The original agreement for 180 megawatts of contracted capacity was scheduled to expire at the end of this year and has now been extended to the end of 2023. So our electricity business had a pretty good third quarter this year with strong earnings in the power business and good progress on the business development front. In the pipelines and liquids business, we are proceeding with plans to build the Pembina-Keephills pipeline. This project will be a 59-kilometer natural gas pipeline to support coal-to-gas conversion for power producers in the Genesee and surrounding area about 80 kilometers southwest of Edmonton, Alberta. The pipeline will supply natural gas to the Genesee generating station and has the capacity to support the forecast demands of other power producers in the area that may be looking at coal-to-gas conversions. On the earnings side, over the first 9 months of 2018, our natural gas distribution business has reported comparatively lower adjusted earnings in the same period in 2017. This was mainly due to the impact of rate rebasing in the second generation of Performance Based Regulation or PBR. We're seeing a similar earnings impact on our electric distribution utility. In 2018, we are driving to achieve financial returns on equity that are well above the 8.5% regulated rate. All our 2018 year-to-date financial results in these PBR utilities are comparatively lower than 2017 and has more to do with just how strong our financial returns were in 2017. These utilities continue to perform very well in 2018 and we're confident in our strategy to create long-term shareowner value, as we always have, with these businesses. Regarding our financial strength, in August, Dominion Bond Rating Service affirmed its A rating and stable outlook for Canadian Utilities. In September, S&P affirmed its A- rating and stable outlook for Canadian Utilities. Credit ratings are important to our financing costs and our ability to raise funds. We intend to maintain strong investment credit ratings to provide efficient and cost-effective access to funds required for our operations and for growth. That does conclude my prepared remarks. And I'll turn the call back over to Myles.
Thank you, Dennis. We'll turn it over now to the conference coordinator for questions.
[Operator Instructions] Our first question comes from Linda Ezergailis from TD Securities.
I have some questions about your PBR reopener. Can you just give us an update on how you're thinking this might unfold in terms of timing to resolve Phase 1, and perhaps what that might mean for timing of Phase 2? And an update perhaps on the bookend of outcomes with maybe any sort of read-through potentially to PBR 2.0?
Sure. Before we get to Phase 2, we have to see if the AUC allows it to move forward to -- past the Phase 1. We did file our submissions on the first phase, indicating that our higher earnings in 2017 were a direct result of our responses to the incentives that were baked into the plan and for us to implement efficiency improvements, which is exactly what we did. We're still in, I'm going to say a holding pattern for Phase 1. I think the process that the AUC ran has come to its conclusion a couple of weeks ago, and we're expecting further comment from the AUC, I'll say, imminently. Intervenors have requested a right for argument and reply argument on Phase 1. So if that does go ahead, that will likely play out until the end of this year. And then, if it does go to Phase 2, it would likely get kicked off in 2019. In terms of the bookends that you're talking about, the -- I guess the biggest area would be around the going-in rates for O&M services. And under the existing going-in rates, they've chosen -- the framework was for all of the Alberta utilities to pick their lowest of the first 4 years for ATCO Electric Distribution. That was 2016. They were kind of reopened further as a result of their 2017 performance. And their 2017 operating costs were similar to 2016, so if the AUC were to kind of reopen into -- reopen the going-in rates for PBR 2, we don't think that there would be much of an impact for electric distribution on the gas distribution side. Their returns in 2017 were considerably higher than experienced in 2016, so if they were to move to I call it retroactive ratemaking, where they change the results of the PBR going-in rates, there would be, I'll call it there's maybe about $40 million in lower cost that we incurred in 2017 compared to 2016 that there -- we may get arguments for that to be flowed through to PBR 2. But I've always contended that there's been no evidence that the going-in rates for PBR 2 are not kind of just and reasonable. That would manifest itself through our utility returns in 2018. So let's see where we end up for our results in 2018. And if we reopen it on that case, then there would be time to revisit the going-in rates.
But you're optimistic that it won't get past Phase 1?
We're the only utility that tripped the reopener. So for me, that indicates that that's -- there's no structural defect in the Performance Based Regulation 1.0 plans. So we are confident that, in our position, that the regulatory principles will be upheld and we'll move on to the opening rates for PBR 2 as previously approved.
That's helpful context. And just as my follow-up, I'm wondering if you can give us some parameters around how your strategic review with your Alberta power business is unfolding in terms of -- I'm assuming you've made progress since your Investor Day. And can you give us a sense of the bookends of timing of when it might result and what the main factors might -- are that might inform your decision-making, including potentially the merits of using proceeds to finance other initiatives?
Sure. In regards to timing, we would hope to kind of resolve this strategic review in I'll call it first quarter of 2019. The factors that would influence our decision would be kind of what price we may be offered for the assets. And in terms of what we would do with the proceeds, there's been no decision made yet. Canadian Utilities invests in regulated and long-term contracted assets, including the electricity sector. So we would be looking at continuing on our strategy for that. And we've also talked in the past about diversification away from Alberta. Right now, we've got Canadian Utilities, $21 billion in balance sheet; $20 billion is in Alberta, so 95%. So if a transaction were to occur, we would also consider that geographic diversification in our plans to what we may do with the cash if there was a transaction. So no assurance that a transaction will result from this process.
And would a special dividend be possible if there was no use of proceeds?
We would look at all of the financing options, whether it's dividends and other financing arrangements, definitely.
Our next question comes from Jeff Zippel of BMO Capital Markets.
So just in the package, you note that the general tariff application for transmissions got pushed back from -- you thought it was in Q1 originally in 2019; now, it's Q2. You also mentioned an additional $13 million that would be related to 2018. So just want to confirm that, that is a retroactive impact for only 2018. Or does that include what the expected impact for Q1 2019 would be as well?
That would be the retroactive impact for 2018 that would be recorded in 2019. And in 2019, there will be a delay from the Q1 2019 rates into subsequent quarters within 2019 if we -- I think we can reasonably expect a decision on that file in Q2 or Q3, depending on how the rest of the process plays out. So the $13 million amount related to 2018 will be recorded in 2019. And there may be a little bit of noise in Q1, Q2 2019 as those rates get finaled sometime in 2019.
Okay, perfect. And then I guess just also on the strategic review, so I was wondering just kind of what we're seeing right now, is the focus because of the current like premium valuations you're seeing? And just to get your thoughts on -- really, we're seeing a lot of that geared towards renewable assets. Do you think you'd still be able to get those like premium valuations if you take your gas and coal-fired power assets to the market?
I don't think it's necessarily the valuations. I mean, if we go back to our strategy, we built our power generation business off of the long-term contracted assets. We built the plants that were backed with long-term PPAs. Over the years as those long-term contracts and PPAs have rolled off, the percent of long-term contracted has gone down, and right now in our portfolio, we're about 50-50 merchant versus contracted. Alberta is a fairly mature market. Capacity markets coming in, good for incumbent generators. And we're just taking a look at those factors and decided it would be prudent for us to take a look on the options available, cycling cash on our balance sheet just like every other good corporate does.
Our next question comes from Patrick Kenny of National Bank Financial.
Just on Battle River 5, I know power prices have been fairly strong so far in October, but I'm wondering if you can confirm for us what the utilization rate has been so far in the first 25 days or so running the plant as merchant. And perhaps maybe give us a sense as to what power price you need to see going forward just to keep the plant online prior to gas conversion.
I don't have the detailed stats on BR 5 in front of me. You can follow-up with Myles afterwards. But with Q4 pricing, the forward curve, if it stays in that -- the $50 range, our marginal cost is lower than that, so we can economically dispatch that plant. So depending on the forwards and all of the other markets -- sorry, not the forwards, depending on all the other market factors that drive the pricing, will obviously indicate whether that plant's economical or not. But right now, we've been seeing it in the money.
Okay, that's great. And then just on Battle River 3, I know you mentioned the life extension for the overall generating facility. But can you confirm for Battle River 3 the potential life extension of that plant under gas conversion?
Yes. We haven't made any decisions on whether converting -- whether we do convert BR 3 to gas or not. If we don't convert, then we need to retire that unit at the end of 2019. So we'll take a look at the factors, the costs to convert it. If we can get below the emission intensity standards and make a call, hopefully, kind of early 2019.
Our next question comes from Mark Jarvi of CIBC Capital Markets.
I wanted to go back to the prepared remarks. You had talked about, I'll say year-over-year reduction with the distribution utilities and how 2017 was sort of a high watermark for those businesses. What do you think in terms of now that you've had a few more quarters under your belt under PBR 2.0, the timelines to realize efficiencies and maybe not get back to 2017 levels, but get back to 2016 earning levels, and whether or not you have more confidence in the sort of earnings trajectory for the electric or the natural gas distribution utilities?
Yes. We won't be returning to those 2017 levels. I think gas distribution outperformed by some 700 basis points, and electricity in the 400s, I think 400 to 450. I hope -- we do have plans in place. They are manifesting themselves in higher returns this year. We would look to -- probably not to the 700 basis points given that that took 5 years to accumulate in natural gas, but we would look to, in the 2- to 3-year time period, to be able to push up to some of those reopener thresholds. And again, the reopener threshold is 2 years in a row at over 300 basis points, or 1 year at over 500 basis points if we exceed those amounts.
Okay. And then in terms of how you're seeing both utilities setup right now, the electric and natural gas, which one do you feel you guys are making the best progress in terms of driving towards overearnings?
I think I've said before, there's no such thing as overearnings. But both companies are making fantastic strides. On the gas side, we've done a integration between our transmission and distribution operations, so we've been able to streamline the costs in that business. On the electricity side, they've made changes to the work processes to aggregate work and to better and more efficiently and economically mobilize crews. We're seeing great success from that initiative as well. I think the tie would likely go to the gas distribution business in terms of being able to exceed the approved return by a larger amount.
Okay, helpful. And then just quickly, in terms of the business and maybe regulatory environment in Australia, I'm just wondering how you guys forms your views about potentially deploying more capital in that country. Obviously, you talked about maybe wanting to diversify the cash flows in different regions.
Yes. We're going through our next access arrangement in Australia, which is similar to a 5-year PBR deal here in Alberta. Continuing downward pressures on the returns on equity in that market. So we would view that. But it wouldn't -- may not necessarily just be regulated assets that we would look at in Australia; a combination of regulated and nonregulated assets. But as you're aware, and we've been on record saying that Australia is one of our target markets, along with Mexico, South America, in order to expand. So when we talk about geographic diversification, we're definitely looking at opportunities in Australia.
[Operator Instructions] Our next question comes from Robert Kwan of RBC Capital Markets.
Maybe just starting with the quarter, can you just on merchant power side, do you have an estimate as to what the hedging drag was in the quarter? Is it as simple as that 358 megawatts and the difference between the spot spark spread and your realized? And I guess just looking forward, do you have what the hedge book profile looks like for Q4 and into 2019?
Yes. I think -- yes, for Q3, I mean I could say that's a drag, but it's kind of like the 2020 hindsight from when we did place the hedges back. They were in the money compared to where the market settled in 2013. Given the small market, we're not prepared to outline what our hedge book is in the next couple of quarters. We're kind of undergoing our strategic review right now and we'll let those factors play out.
Okay. And I guess maybe if I can just clean up on the other part of the strategic review, you're looking at the sale of the Barking land in the U.K. Can you just confirm that you do, with the consolidation previously, that you hold 100% of this? And can you just talk about what it's zoned for? Has it been rezoned to residential?
No, it hasn't been rezoned to residential. And yes, we do own a 100% of it. We didn't go in owning 100% of Barking. It was around 25%. But in 2015 and 2016, we consolidated the ownership of Barking Power Limited, so now, we're 100% owner of that land.
And how far into the remediation are you on that and how much is left to go?
We haven't remediated any of that site.
Our next question comes from Andrew Kuske of Credit Suisse.
Just on Battle River 5, and just a little bit of clarity on the $25 million of OM&A margin that was brought into the earnings in the quarter, was that exclusively for the quarter, or was that also partly for prior quarters?
That includes prior quarters. It was a true-up. When we converted to IFRS 15, the new revenue standard, at the beginning of this year, we split that contract into the capital component and O&M component because we're obligated -- our performance obligations were to provide O&M services. And that was revalued at that point in time back to the beginning of the contract compared to the cash that was received. The cash that we did receive was, I'm going to say front-end-loaded, as the capacity payments reduced with the reduction in net book value. So the -- that $25 million associated with the O&M is the contracted [ AHF ] on that portion of the PPA compensation.
Is there a rough breakdown of what would be applicable to Q3 versus the prior periods?
The vast majority in prior periods.
Okay. And then just on Barking, when you think about the monetization process there and surfacing value from the parcel of land, is there any kind of guidance on timeline? And then, ultimately, on a disposition, how do you ask tax-efficiently repatriate the capital?
In terms of timeline, we are, I would say relatively short-fused on that one. We hope to conclude that this year. But it may trip into next year because the timelines are tight, and we are looking at tax strategies in order to minimize any leakage on repatriation of those funds.
[Operator Instructions] Our next question is a follow-up from Patrick Kenny.
Just back on the Pembina-Keephills pipeline, just wanted to confirm the commercial arrangement there. Is this a long-term take-or-pay contract, or is it the capital just simply rolling into rate base? And also, is the initial capacity of 550 PJs a day, is that also the maximum capacity of the pipe? Or can you ramp that up based on incremental demand from customers in the area?
The investment is part of ATCO pipeline's regulated rate base. So that will go into the transmission -- gas transmission rate base. In terms of capacity and amping it up, Myles, do you have detail on that?
I think that 550, Pat, includes additional capacity for expansion beyond the deliveries for Genesee generating station. So there's some expansion capacity there already in that system.
Okay, got it. And then just lastly, wondering if there's any update on the Pemex Cogen plant in Mexico?
No change in the status on that. We continue to work with Pemex to see if anything can be done. I think they're still proceeding with that refinery expansion. I've said before that it's an economic project, and we've gone through a number of times rejustifying it with Pemex, the various leadership changes. So we continue to work with them, but no real change in the status on that.
Our next question comes from Jeremy Rosenfield of Industrial Alliance Securities.
I have a couple of questions. Just in terms of growth opportunities or utilization of capital going forward, do you think it makes more sense to be investing in additional regulated utility infrastructure assets, maybe in new geographies? Or are -- is the risk-return profile more attractive in more contracted power? And I'm thinking here both outside of Alberta, not in Alberta.
Well, it's a risk and return question. The regulated utility's stable, reliable, shouldn't be too volatile, although we are seeing volatility in PBR utilities. Long-term contracted is, I'll say, fantastic for us. If we can get a long-term contracted asset with a little bit of merchant exposure similar to how we built the power generation business back in the day, I think those are ideal for maybe a mix of regulated and nonregulated operations in any sort of target that we may be exploring. So on the pure regulated, we look at it, but we do look for the market upside where we can extract additional value from the investments.
Okay. And does the U.S. market attract any attention at this point? Are there any pockets where you see value where it could be interesting to make investments there?
In the U.S., I think for -- ATCO was looking in the U.S. for -- with its investments on the Canadian Utilities side for energy infrastructures. It's tough given the valuations and multiples down there now. So for strategic reasons, we have and we will continue to look at kind of maybe some of the smaller transactions. But we've said before that unlikely that CU would go in to take on the size of an ITC or something like that.
Okay. And maybe if I could just have one cleanup question. With regards to the items related to the Battle River 5 termination, the O&M margin and the availability incentives, how much of the amount -- I think it was highlighted at about $42 million altogether, so $25 million, $10 million and a $7 million -- how much of that was actually cash or flowing through the cash flow statements in Q3?
Well, the -- I think there's a couple of things here. That $42 million is the cash that came in through the onetime payment. Okay, sorry. It's $25 million for the O&M, $10 million for the availability incentive, and the remaining $7 million...
Was for the availability this quarter...
This quarter's availability. Okay. So the cash for all of that would have come in over the life of the contract. That $7 million was, I'll say, this quarter's impact.
This concludes the question-and-answer session. I'd like to turn the conference back over to Mr. Myles Dougan for any closing remarks.
Thanks and just one follow-up answer to a question there. Battle River 5 dispatched about 50% of its capacity since the turn back here as a merchant unit. So we just had one outstanding question there. Thank you. Thank you all for participating today. We appreciate your interest in Canadian Utilities and we look forward to speaking with you again soon. Thanks so much. Bye for now.
This concludes today's conference call. You may disconnect your lines. Thank you for participating and have a pleasant day.