Canadian Utilities Ltd
TSX:CU
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Thank you for standing by. This is the conference operator. Welcome to the Canadian Utilities Limited First Quarter 2019 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, Claudia. Good morning, everyone. We are pleased, you could join us for our first quarter 2019 conference call. With me today are, Senior Vice President and Chief Financial Officer, Dennis DeChamplain; Senior Financial Officer and Controller, Derek Cook; and Vice President Finance and Risk, Katie Patrick. 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 our Senior Vice President and Chief Financial Officer, Dennis DeChamplain for his opening remarks.
Thanks, Myles, and good morning, everybody. Thank you for joining us today on our first quarter 2019 conference call. Canadian Utilities announced higher adjusted earnings in the first quarter of 2019 of $200 million or $0.73 per share compared to a $181 million or $0.67 per share in the first quarter of 2018. This $19 million growth in the first quarter earnings of 2018 was due to continued investment in our utilities, strong financial results from our Alberta electricity generation business and ongoing cost efficiencies achieved in electricity distribution and natural gas distribution utilities. Stronger power prices in Alberta drove higher earnings in our electricity generation business this quarter. The average Alberta power pool electricity price for the first quarter of 2019 was $69 per megawatt hour, or nearly $35 per megawatt hour higher compared to the first quarter of 2018. The increase was mainly due to two factors, the first factor was near record low temperatures in February, which increased electricity demand, the second factor was lower available electricity generation capacity due to coal-fired generation outages and low wind generation. In March, we completed the construction and energization of our Alberta PowerLine project. This tremendous achievement involve many people including communities and Indigenous peoples. The success of this 500-kilometer electricity transmission line construction project would not have been possible without their support. The earnings contribution from Alberta PowerLine or APL was lower this quarter than Q1 2018 due to the lower capital investment needed to complete the final stages of this project, but bringing the project in service a full three months early allowed us to record earnings for the remainder of the early energization incentives.Last quarter, we told you that we had commenced a strategic review of our 80% ownership in APL. As part of this process, Canadian Utilities is providing an opportunity for indigenous communities along the route to obtain an equity interest in APL. We intend to remain as the operator of APL over the 35 year concession arrangement. As you know in September of last year, we announced that we are exploring strategic alternatives for our Canadian electricity generation business. We are working through both of these strategic reviews now, while I had hoped to have an update for you this quarter. We're not quite at the decision stage and therefore have no update to report at this time. On the utility side of our company, we generated higher earnings this quarter, mainly due to ongoing rate base growth and cost efficiencies achieved, particularly in the natural gas distribution and electricity distribution utilities. Earnings from the utilities were up $7 million in the first quarter of 2019 compared to last year, but they could have been even higher than that. Our natural gas transmission and electricity transmission utilities are awaiting final rate decisions from the Alberta Utilities Commission or AUC. If the AUC approves all aspects of our two rate applications, the potential increase to first quarter 2019 adjusted earnings could have been approximately $8 million. We expect those two rate decisions in mid-2019 hopefully in time to record next quarter. We will report the impact on our earnings, when we receive the decisions. We also had in the inflation adjustment that brought down the Australia results this quarter. We think the way this inflation calculation works in the Australian regulatory model will not be a continuing issue as we move through 2019, but it did produce a reduction in earnings this quarter. On our last quarterly conference call at the end of February, I told you that the AUC had just released the decision on the first phase of the reopen our provision for the 2013 to 2017 PVR term. The AUC determined that the 2013 to 2017 PVR plan, will not be reopened. This decision agreed with our submission that the achievements of the utilities were not due to a flow on the PVR plan, but rather were the result of management decisions responding to the incentives, the PVR plan created. This process is now closed, and we're very pleased with the decision.In Australia, our natural gas distribution business continue to work on the next 5-year regulatory access arrangement. The regulator is expected to deliver a final decision in late third quarter of this year. There are still many aspects of the next access arrangement to resolve, so the total impact to earnings isn't known yet, but we will keep you apprised as the regulatory process develops. We have a few more regulatory updates in our MD&A, but they are all for proceedings underway with no major decisions impacting this past quarter. But we do expect decisions on a couple of them in the second quarter. If you have questions about those proceedings, I'll be happy to answer them in a moment.All in all, Canadian Utilities had a very good first quarter of 2019. We achieved strong earnings growth this quarter and completed the very large Alberta Power Line project on budget and ahead of schedule. That concludes my prepared remarks. I'll now turn the call back to Myles.
Thank you, Dennis. I'll turn the call over now to the conference coordinator for your questions.
[Operator Instructions] Our first question comes from Linda Ezergailis with TD Securities.
I have some questions about your ATCO Gas Australia access arrangement. Can you maybe help us understand a little bit the dynamics related to the adjustment in the quarter and how the balance of the year will look vis-à-vis, I guess, the prior quarter in the prior year or why this was just temporary onetime in nature?
Sure. Linda. Thanks. Just wanted to point out at the outset, the adjustments for our first quarter earnings for Gas Australia doesn't have anything to do with our next access arrangement. [ The ] AA5. So they are completely separate issues. In the first quarter of 2019, as you see there is a $6 million drop year-over-year from Gas Australia. And in Australia, the regulatory compact there is essentially covered on a real return basis. And we need to translate that to nominal dollars for our adjusted earnings and US GAAP purposes.Part of that translation involves adding an inflation amount to our rate of return calculations. In Q1, 2019, the Australian CPI was 0% whereas in Q1 2018, it was about 45 basis points. So the decrease of 45 basis points on a $1.2 billion rate base roughly accounts for that $6 million drop in the year-over-year earnings that you see. Going forward, we do not expect Australian CPI to be flat for the remainder of the year. Our business plans and forecast, we had baked in about a 1.8% increase in inflation and that is the amounts that we were expecting, we do expect CPI to be north of 0, in the future quarters. And that's why we're saying that, we don't expect that to continue.
Okay. And then just maybe with respect to the Draft 885 decision. Do you plan to submit a response and what is your kind of initial reaction and read on that decision?
Yes, we do plan on submitting our response. The process down under is different than what we experience here in Alberta for the rest of our utilities. In Alberta, as you know the AUC and interveners will ask there -- I call it 1,000 questions and we respond and then the -- at the end of the discovery process the AUC will come out with its final decision. In Australia, they've the regulatory authority there engages a consultant, they come in, they look at our application and the regulator comes out with a draft decision, which we received in April.We have 6 weeks to respond, so that's part of the -- I'll call it, the discovery process, down under that we don't have here in Alberta. We have 6 weeks to respond in the draft decisions. Some of the comments by the regulator there, invited us to comment further on the initial position the draft has outlined. The draft decision, it does take a significant cut in our growth capital and associated revenues, which we don't think is appropriate and we are kind of responding as such.There is some reductions in our operating costs, and again where we're using the 6-week time period to augment our evidence that we've put back to -- put back to the regulator. After we respond in early June, other parties will have -- I think it's about 4 weeks to respond to our filings on the draft decisions. And if there is, if we feel the need to kind of reply to what's been said by customers in their July period. Then we will have the opportunity to kind of reply or [indiscernible] our additional evidence. So that's the process that, that it goes through. Decision is going to schedule for September. So absent any process -- and we usually see process delays in our regulatory proceedings. We should be able to have the decision in the third quarter and we'll be able to update you at the end of the second quarter, as we get through this next call at 6 to 10 weeks in the process.
That's helpful. Context. And [indiscernible], maybe just moving back to Alberta. There's been a recent change in the provincial government. Can you comment on how this may change anything for your company, in terms of your approach to -- I guess your whole franchise there, but most specifically the outlook for the merchant power markets and what see you might be advocating on that front?
In terms of the terms of the outcome of the election, I guess we'll say that we're pleased with the outcome. The incoming government seems to have a grasp of the economic issues facing our province. And we look forward to working with them on the files. In specific regards to the generation and capacity market, I think the UCP in there [indiscernible] election platforms that they will have a -- I think it's a 90-day consultation period with industry. We intend to participate in that consultation period, and let our thoughts be known. We do think that energy only market has not serve the test of time very well, and if you look at all the other jurisdictions that implemented them and moved away from them. So we will be expressing our views with government and other industry participants, as the government works through their process.
Our next question is from Mark Jarvi with CIBC Capital Markets.
There are some commentary in the MD&A around filings for PVR 2 on a normal adjustments for going in rates. Can you provide a bit more context on that, what it could mean?
Sure, Mark. When the AUC came out with decision on the going-in rates for PBR two. They laid out a set of 5 criterion which was essentially impossible to qualify as an anomaly. Some of the other Companies are indeed that decision and AUC accepted that RMB and they're going through it. We launched, we became part of that RMB as well because the AUC noted that our costs that we're applying for recovery associated with our information technology would be a placeholder pending the outcome of our IT proceeding. And we don't believe that is legitimate under PBR framework with regards to we'll call it cherry picking for lack of a better word, adjusting some elements but not all. The approach on anomalies, they're going through to see, if those going in rates for 2018 and if you look at the operating cost that was based on the lowest of the first four years and for both of our distribution utilities that was 2016.So we'll be looking at what could be considered a one-off or anomalous factors in the results in 2016 and they might look at 2017 as well. I think the AUC said, maybe we should be looking at 2017 to see if there's any anomalies there that could qualify. So they're going through that process now and RMBs are generally harder to forecast the timing outcome of. The AUC tries to stick to kind of rendering a decision 90 days after all the evidence is filed at RMB process all the time. Time lines haven't been laid out, finalized yet, and then they don't AUC doesn't hold themselves bound by that 90 day decision internal rule. So we don't know when we would get a decision on that.
So based on initial discussions the discovery. Do you anticipate there being a retroactive sort of adjustment and directionally, which were way to go?
Yes, they do come back. There would be an impact to 2018 rate which would be a 100% retroactive impact. And also for the first couple of quarters for who knows how far going into 2019. And sorry Mark, I'm…
Just where do you guys think billing terms of where the discovery and where the initial discussions, which direction might headway in your favor?
Yes, it could be different for each of the utilities. The AUC seems to be trying to put all of the distribution utilities on the same footing. So depending on how those new or revised or even if there is any change to the criteria to qualify as an anomaly. It could impact the various distribution utilities. We could go up, somebody else could go down or vice versa. So we'll have to -- we really have to see how that plays out kind of on an industry-wide basis.
Okay. And then going back to Linda's question on the change in the ruling party, and with the strategic review of the power assets, how has the election or the change in government impacted that process or maybe it had no impact, any comments on that?
I think we've had that question before. I mean that the outcome of the election does not have very much of a bearing at all on our strategic reviews. We're continuing along our path with that.
[Operator Instructions] Our next question is from Robert Kwan with RBC Capital Markets.
Just with respect to the strategic reviews for those two assets. I'm just wondering, are you approaching it as in either or for those two reviews, or could it be both? And then, I guess in addressing last question around the Alberta Government, just to be clear. The capacity market framework review has no bearing on your decision on the Canadian power side. And then as it relates to power line, is the indigenous investment really the scope of what you're looking at from a strategic review or is there a potential kind of second or follow-on stuff?
Okay. Robert, I -- it's part A, B and C to your questions. I think Part A was our -- the Alberta power line and generation business. So they independent or combined we do one or both. And I guess the answer is, we are doing both strategic reviews, and then the outcomes of those strategic reviews could be zero transactions, one transaction or 2 transactions, as we work through them. We don't view it as a kind of an either or we're looking at each of those strategic reviews on its own merits. I don't have Part B of your question. So I got to flip to Part C with regards to the indigenous communities along the lines. I think we've said before we're going through that process and we are approaching it that we could sell kind of up to our entire 80% interest in Alberta PowerLine, so to the extent that it's available to the indigenous communities or independent third parties, we are looking at all of those options with a view to potentially completely exiting our ownership percentage of APL, bearing in mind that our electricity transmission division will continue to have the contract to operate that line over the 35-year concession arrangements.
Got it.
[indiscernible] The capacity market question?
Yes, just to confirm, when you were saying that the government change doesn't have a real bearing on the Canadian power sale, just as that extension, the timing isn't tied to seeing how this capacity market kind of plays out?
No, it's not.
Okay. If I can just finish with coming to regulatory, you've got the direct assigned transmission filing in -- recovery. Just want to be clear with the accounting treatment given you are under IFRS without the regulatory assets. So are you booking, you're booking this the returns into earnings under your adjusted earnings calculation, is that correct and really what you're looking at here is recovering the cash?
Yes. So those -- assets have been kind of essentially in service since 2012. So we have been including in our rate base and in our earnings, depreciation -- return on and return of capital since 2012 to the extent that there'd be, we'll call it a capital dis-allowance. What we do for accounting purposes is we reduce, we don't write off the value of those assets from our property, plant and equipment on our balance sheet. We reduce the rate base going forward that we charge to customers, thereby instead of earning an 8.5% return. It would be for 9% effective return on our entire assets. The impact of that -- of the [indiscernible] decision though, in Q2. We -- if there would be a capital disallowance which we don't think there is [indiscernible]. We would need to set up like a refund to customers for the amount of earnings and depreciation that we have recorded over those 6, 7 years, since those assets have been in service. So there could be a onetime yet to our results in Q2. Only because it goes back, so far and call it retrospective clawbacks from our rate base.
Okay. So just so I'm clear though, when you're talking about the onetime hit. Are you talking about the IFRS reporting. Are you talking about your adjusted earnings which are effectively U.S. GAAP equivalent?
The adjusted earnings component.
Okay. And so ultimately, if everything goes as planned, there really is no change to how you book adjusted earnings by it. Is this proceeding really down about, excuse me, how you recovering the cash?
Well, we have been recovering the cash associated with those assets, because they have been included in our rates on an interim basis, pending the results of this decision. And even after we get this decision, it may still be on an interim basis, pending the ADCs review the transmission inquiry, for the utilization of transmission assets, which they announced probably almost 2 years ago now, but has gone radio silent with regards to when and how they intended to proceed with that review. As then we thought out in [indiscernible] even on there, we'll call it a final direct assigned decision. The results were still interim pending the results of that transmission utilization proceeding. So I don't know if that would happen to us as well on [ Hana ]. I suspect we'll be afforded the same treatment.
Our next question is from Patrick Kenny with National Bank Financial.
Just first on the quarter. Was any of the financial performance driven by colder temperatures? And if so, how much of the earnings uplift could we back out, if we assumed more normalized weather?
Yes, the colder weather we didn't see it impacting our gas distribution utility too much. There are factors in there that kind of normalized for colder weather. I think on the gas distribution, we may see an earnings uptick, if it's cold and windy. And I know you're in Calgary, so that is essentially kind of baked into the normalization for our gas distribution. I mean the cold weather though did impact the power prices most notably in February, when it averaged about 20 below here in Alberta. So there is that uptick in the prices that we realized on our generation business and to the extent that I can bifurcated between colder temperature and lower generation capacity. And I don't have that information. I don't know as if you guys have some deep in the -- as to what percent would be temperature versus supply will...
That's all good. We'll take the extended ski season anyway. Back on the discussion around the [ UCP ] and thinking about their cutting the red tape mandate. Does this change the narrative at all, I see you from a capital allocation standpoint. Does this bring Alberta more in line with your other international jurisdictions, just from a competitive standpoint. And maybe you can comment on whether others anything in the [ UCP's ] platform that you can point to that might represent some upside potential to your CapEx budget, or rate base outlook?
Yes, that's the first item with regards to Red Tape and I could just feel my temperature rise will a bit as we even start to talk about it, especially in light of the previous conversation we had about -- and having a regulatory decision in Q2 of 2019, which can reach back to earnings that we booked in 2012. So you think about Red Tape, you look at our last deferral application that we filed that included -- I think the opening salvo was some 28,000 pages -- links proceeding it topped out at over 200,000 pages and multiyears worth of retrospective impact. We also talked earlier on the call about our 2018, going in rates for our PBR utilities, still not -- still aren't final, because we have this pending R&D. So to have that overhang and uncertainty facing us, is inordinate in my view. You put that beside the Australia access arrangement process, where it's a different process, but we will get final rates in advance of the test year. They -- we worked with a consultant, but there were 57 questions that we got asked on our application. And that's just a thorough of review, so when you think about Red Tape, and if you want some low hanging fruit. Let's go after these regulatory and permitting procedures.We still don't have a permit to commence construction on our Pembina-Keephills pipeline, which is a 100% backed by customers. It's ludicrous, the amount of hoops that we have to jump through, in order to conduct business in the province here. So we may have some things to say on the Red Tape file. Do we think that the UCP platform will help kind of our growth prospects and rate base going forward? Yes we do, is that going to materially impact this year's or next year's results.That'll be -- that would be tough as to some of the other permitting aside, we still need to go through adequate consultation and make sure the eyes are dotted and the T's are crossed. But it would be difficult to get kind of, I think, new investment applied for sanctioned and [indiscernible] ready where we would expect a material change in our kind of immediate near-term outlook for our CapEx here in Alberta.
This concludes the question-and-answer session. I would like to turn the conference back over to Mr. Myles Dougan for any closing remarks.
Thank you, Claudia, and thank you all for participating today. We really appreciate your interest in Canadian Utilities and we look forward to speaking with you again soon. Bye, bye.
This concludes today's conference call. You may disconnect your lines. Thank you for participating, and have a pleasant day.