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Ladies and gentlemen, thank you for standing by. My name is Jessa, and I will be your conference operator today. Welcome to the Fortis First Quarter 2019 Conference Call and Webcast. [Operator Instructions]At this time, I would like to turn the conference over to Stephanie Amaimo. Please go ahead, Ms. Amaimo.
Thanks, Jessa, and good morning, everyone, and welcome to Fortis' First Quarter Results Conference Call. I'm joined by Barry Perry, President and CEO; and Jocelyn Perry, Executive VP and CFO; other members of the Senior Management Team as well as CEOs from certain subsidiaries.Before we begin today's call, I want to remind you that the discussion will include forward-looking information, which is subject to the cautionary statement contained in the supporting slide show. All non-GAAP financial measures referenced in our prepared remarks are reconciled to the related U.S. GAAP financial measures in our 2019 first quarter MD&A. Also unless otherwise specified, all financial information referenced is in Canadian dollars. With that, I will turn the call over to Barry.
Thank you, Stephanie, and good morning, everyone. Before getting into the quarterly results, I wanted to take a moment to thank ITC's team for quickly and safely restoring power after blizzard conditions brought heavy snowfall, ice and high winds to the Midwest. The storm damaged over 400 poles in Southern Minnesota and Northern Iowa last month. Fortunately, ITC was able to restore service to its customers within a few days. 2019 is off to a strong start. We continue to see strong growth in our regulated utility businesses. Financially and operationally, we've made strides positioning us well to execute on our goals for the year. Financially, adjusted EPS was $0.74 for the quarter, and was up $0.04 compared to the previous year, reflecting 5.7% EPS growth. Operationally, in the quarter, we invested $740 million at our utilities. These investments enhanced the service we provide to our customers with an eye on delivering cleaner energy in a safe, reliable and affordable manner. We remain on track to invest $3.7 billion in 2019 and approximately $17 billion over the next 5 years. In Arizona, Tucson Electric Power, or TEP, filed a rate case on April 1, using a 2018 historical test year. TEP is seeking to recover its investments made since its last rate case supporting customers in the transition to a cleaner energy future, including expansions of wind, solar and natural gas generation resources. Earlier this year, we announced that we had entered into an agreement with Columbia Power Corporation and Columbia Basin Trust to sell our 51% interest in the Waneta expansion for approximately $1 billion. During the quarter, we progressed through the sale process, and we successfully closed the transaction on April 16. Lastly, in conjunction with the Waneta expansion sale, we successfully settled a tender offer to repurchase USD 400 million of the corporation's outstanding notes due 2026. At Fortis, we are committed to reducing our environmental footprint. During the quarter, 3 significant milestones were achieved to support this commitment. In March, TEP finalized its plans for construction of the USD 370 million Oso Grande Wind Project. Construction of the 247-megawatt wind farm is expected to commence later this year and be online by the end of next year. Once completed, it will become TEP's largest renewable energy resource and generate enough power to supply nearly 100,000 homes. This project is expected to increase TEP's renewable energy production to approximately 28% in 2021. Well ahead of existing state renewable goal of 15% by 2025 and bringing the utility close to a 30% goal planned to be achieved by 2030. Although we expect to meet our target well ahead of 2030, we are not stopping there. We'll continue to pursue new initiatives to support the shift to a lower carbon economy for our customers, and we expect to be able to grow beyond the 30% previously targeted for 2030. Turning to British Columbia. Fortis BC announced a significant increase in its energy conservation and efficiency program over the next 4 years. The nearly $370 million program will be focused on customer initiatives to lower energy use, emissions and reduced energy bills. These expenditures will increase quarter species rate base over the 4 years. These conservation and efficiency enhancements are expected to decrease carbon dioxide emissions by 50,000 tonnes annually, which equates to taking close to 11,000 gasoline-powered cars off the road. A significant milestone was achieved in the Wataynikaneyap power project last month when the lead to construct was obtained from the Ontario Energy Board. Remaining milestones include finalization of environmental approvals, which are expected to be received later this year. The project is targeted to be completed in 2023 and will reduce greenhouse gas emissions associated with the diesel generation currently used by the communities. We are confident in our ability to deliver on our $17.3 billion capital plan for the period 2019 through 2023. 99% of our planned capital investments are in our regulated businesses. The plan consists of a diverse mix of highly executable low-risk projects needed to maintain and upgrade our existing infrastructure. This capital plan supports our 6% to 7% average annual rate base growth and translates to over $35 billion in rate base in 2023. We remain optimistic in our ability to grow our portfolio of utility businesses. Our 45 years of dividend increases makes us a leader in dividend growth. Our strong growth profile, coupled with our highly-regulated businesses, gives us confidence that we'll continue this record and grow the dividend at an average annual growth rate of 6% through 2023. I'll now turn the call over to Jocelyn for an update on our first quarter results.
Thank you, Barry, and good morning, everyone.For the first quarter, reported EPS of $0.72 was $0.05 lower than last year. This is largely due to a one-time 30 million positive U.S. tax adjustment in 2018 related to our filing of a consolidated state income tax return. Excluding one-time items, adjusted EPS of $0.74 for the quarter was up $0.04 compared to the previous year, reflecting a 5.7% EPS increase. Our utilities continue to execute on their capital plan with $740 million invested during the first quarter. Now turning to Slide 10. I'll take a look at the EPS growth on a segmented basis. First, a strong performance at UNS and Central Hudson resulted in a $0.03 EPS increase during the quarter. Higher sales at UNS Energy as a result of colder temperatures and the new rate order at Central Hudson were the key drivers of this increase. Central Hudson's results were also positively impacted by timing differences associated with the rate order and operating costs. These increases were partially offset by planned outage costs at UNS. A higher U.S. dollar to Canadian dollar foreign exchange rate favorably impacted the quarter. The average rate was $1.33 this quarter compared to $1.26 in the first quarter last year. This increase resulted in a $0.02 EPS increase. ITC contributed a $0.01 increase to EPS during the quarter. This was driven by rate-based growth, partially offset by the reduced ROE independent incentive adder. Our Canadian and Caribbean utilities increased EPS by $0.01, driven mainly by rate-based growth and higher electricity sales at Turks and Caicos. Sales at Turks and Caicos last year were impacted by Hurricane Irma. Offsetting growth at our regulated utilities was a $0.02 EPS decrease associated with our nonregulated energy infrastructure businesses. Realized margins were lower at Aitken Creek and lower rainfall decreased production in Belize. Lastly, there was a $0.01 EPS decrease during the quarter due to a higher number of weighted average common shares as a result of our dividend reinvestment plan. The funding plan outlined at Investor Day this past fall remains intact. The majority of the funding required to execute the 5-year capital plan will come from cash flow -- our operating cash flows, drip proceeds and debt financing as a regulated utility. The ATM program remains available to provide additional financing flexibility. As Barry discussed, our recent sale of the Waneta Hydro Plant for approximately $1 billion completed the asset sale component of our current capital funding plan. Net proceeds were used to pay down corporate short-term borrowing as well as repurchase a portion of the corporation's outstanding 3.055% notes due in 2026. The repayment of holding company debt strengthens our balance sheet, improves our credit metrics and further support our investment-grade credit ratings. Overall, we are pleased with the Waneta sale. We estimate our gain to be approximately $415 million, and this gain is expected to be recognized in the second quarter. Turning to our 2019 regulatory outlook. There was a fair amount of regulatory activity during the first quarter. In March, FERC issued 2 notices of inquiry, which seek comment on its policies for determining the ROE, used in setting rates, and how to improve its transmission incentive policies to appropriately encourage the development of needed infrastructure to the benefit of our customers. ITC views this process as an opportunity to demonstrate the value of the independent transmission model as well as advocate for the appropriate incentives to drive needed investment. With respect to the ROE inquiry, FERC is providing an opportunity for all stakeholders beyond those currently involved in New England or MISO transmission ROE litigation to comment on the new ROE methodology. We don't expect this will materially impact the MISO-based ROE complaint process, and we anticipate that FERC will issue an order later this year. Fortis BC filed its multi-year rate plan in March as the current term expires at the end of this year. The proposed plan seeks approval for a rate setting framework for 2020 through to 2024. Cost of capital is not included in filing, and we anticipate a decision in 2020. As Barry mentioned, Tucson Electric Power filed its rate case April 1. And turning to Slide 13, we wanted to spend some time on this filing. Current rates at TEP are based on a mid-2015 test year and do not include approximately USD 700 million of rate-based investment at the utility since rates were last set. These investments were made to deliver safe and reliable service to our customers, meet increasing demand and improve the sustainability of our generation portfolio, including the integration of over 1,000 megawatts of renewable resources scheduled to be on TEP's system by the end of 2020. Additional request include an ROE increase of 60 basis points to 10.35%, and an equity thickness increase to 53%. This equates to a nonfuel revenue increase of USD 115 million or USD 76 million net revenue increase after considering a reduction in fuel cost. The reduction in fuel cost is driven by our migration to a cleaner and more balanced resource portfolio. TEP's proposals translates into an average residential customer bill increase of approximately USD 7.61 per month. Over the past 10 years, TEP has seen its rate base grow from USD 1 billion to USD 2.7 billion while keeping average customer rate increases consistently below inflation each year. We await a procedural schedule from the Arizona Corporations Commission to determine the timing of proceeding. This concludes my remarks. I will now turn the call back to Barry.
Thank you, Jocelyn. Fortis consists of well run utilities. We are now 99% regulated, and we are one of the most diversified utility businesses in North America. Looking ahead, our growth profile is strong with over 7% rate base growth expected over the next 3 years and 6% rate based growth over the next 5 years. This supports our 6% average annual dividend growth guidance to 2023. We continue to focus on growing our utility businesses. To summarize, through the first quarter, the following accomplishments positions us well for the remainder of 2019: we closed the Waneta expansion sale for approximately $1 billion; improved our credit metric outlook by using the Waneta [ proceeds ] to pay down corporate debt, including the 400 million U.S. repurchase of notes due in 2026; advanced the Wataynikaneyap Power Project by obtaining the lead to construct from the OEB; progressed our commitment to reduce our environmental footprint with the announcement of the Oso Grande Wind Project and the Fortis BC Energy Conservation Efficiency Program; filed rate cases at TEP and Fortis BC; and delivered strong EPS growth in the quarter. Now I'll turn the call back over to Stephanie.
Thank you, Barry. This concludes the presentation. At this time, we'd like to open the call to address questions from the investment community.
Thank you. Ladies and gentlemen, we will now conduct a question-and-answer period. [Operator Instructions] Your first question comes from the line of Robert Kwan from RBC Capital Markets.
Maybe just to start with some of the opportunities that are potentially in front of you in BC. I'm just wondering if there's an update on Woodfibre LNG. And I guess generally, just thoughts given the gas supply issues we had this past winter.
Robert, we continue to work with Woodfibre. They, obviously, have asked us to build the pipeline but sell them to get them some gas for their facility. They have been providing us some funds to do permitting, procurement, design of the pipeline. So we continue to work with them on that. And frankly, probably anxious that for them to make a final investment decision, but that's not yet been done. So we're hopeful that will come soon. And there's a sort of resilience and reliability of the gas network. Roger Dall'Antonia is here, our CEO of Fortis BC. He was the fellow that sort of handled that crisis as a result of the Enbridge pipeline rupture late last year. He did a great job for us. So he's here for our Annual Meeting tomorrow, and I'll let Roger comment on that.
Thanks, Barry. Good morning, Robert. As far as Woodfibre and the Enbridge situation, Woodfibre holds their capacity, and they haven't raised any issues with that. So we don't see that as a concern, and we are working with Enbridge just generally on how we're addressing resiliency going forward.
I guess just with that I'm also wondering if Woodfibre went ahead, are there any discussions kind of with the problem for the BCUC? And really upside, I guess, with strengthening, whether that's actually getting something done, additionally at Tilbury, or something around Southern Crossing?
We're looking at both opportunities. It's too early to discuss those plans. They'll be in front of the BCUC and the government and the actual law as we look at both options.
I'm can just finish with financing with the Waneta divestiture, really kind of squaring up the funding plan. Just wondering what you might be thinking about past that, whether that's funding and making room for new assets or future step up in capital projects because it seems like there's a lot of things kind of in front of you right now? Or even just streamlining the asset base?
Robert, maybe I'll wade in, and Jocelyn can follow-up here. But we've been pretty clear that the $17 billion program required us to raise certain proceeds from asset sales, and we now said that we wanted to get a transaction that completes that. We've also been clear if our capital does go up that we have our ATM program, which is $500 million currently approved at, that we would turn that on. And that would be -- that is our plan, basically. Clearly, if CapEx went well beyond levels that one could think about, we would have to consider other opportunities to raise capital. To be clear, we're committed to our investment-grade credit ratings, we would do nothing that would harm those ratings.
So that stands that ATM is really the first option here?
That's correct.
Your next question comes from the line of Ben Pham from BMO.
Just going back to the Waneta sale and do you think what divestitures -- does your holdco debt outlook that you highlighted at Investor Day, does that -- are you well ahead of that slide that you presented or was it more of a gradual reduction?
Yes, Ben. This is Jocelyn. So at Investor Day, we actually had Waneta included in our projections for holdco debt. So I think we showed on Investor Day that holdco was going from 38% down to around 33%, 32%. So we're on track with that plan with the close of the Waneta sale.
So the graphs are still in terms of the timing of Waneta, it's still more of a gradual reduction than you're bringing forward the [ holdco ]. Just wanted to check on that.And then the -- on the -- just coming back to some of the questions on future growth prospects, there's a -- [ on lake ] just some of the transmission stuff in Ontario, there's a press release mentioning Ontario capacity markets could drive your transmission initiatives. And can you comment a bit on that and why that can increase the probability of Erie happening?
Linda Apsey is here with us from ITC. I would just comment, obviously, Ben, that we saw that developments in Ontario were positive towards making projects like Erie connector make a more economic sense. And we felt that it would make some sense for us to come out in support of the initiatives that were occurring there. The project still, obviously, does require a sort of a contract -- a long-term contract for it to go ahead. And we're not there on that at this point in time. But overall, the backdrop to -- some of the changes that are occurring in Ontario are positive for the project.
Yes, absolutely. Good morning, Ben. It's Linda Apsey. Yes. As Barry mentioned, certainly with sort of the energy market, capacity market in PJM, as well as obviously, directional capacity interest in Ontario, obviously, from -- a DC-type project, obviously, we're trying to bring more attention to the benefits that can be sort of created, if you will, both in terms of Ontario through that transmission line just in the differential that occurs in terms of capacity pricing in both those different markets so, from our perspective, capacity market is not something that Ontario has, I would say, a lot of experience in. And so bringing more attention to the benefits of a capacity market and the value of the project like the Lake Erie connector we bring, we're just really actually trying to highlight that to continue to sort of be part of the conversation and to continue to advance that project and highlighting the benefits and the need for the project and continue to drive value for Ontario customers.
That's great. And maybe to finish off, some of the CapEx changes on the Oso Grande Wind Farm in Arizona and just more curious, is the reiteration of the rate base at UNS, is that just because tax equity is going to take up a greater share of that increase in CapEx that your rate base isn't changing?
I don't know if I understand your question, Ben. I don't think that's part of it. Are you referring to the $700 million rate base growth since the last historical test year in Arizona?
I was thinking more this was the higher megawatts on the Oso Grande Wind Farm, like it's going up by $200 million from previous disclosures? And so it says $0.2 billion in CapEx and I'm nitpicking on a little bit of the numbers, but is that -- you've opted not to raise or change your rate base with that change. So is it because the $200 million, a big portion of this tax equity doesn't go to your rate base. Is that...
No. That's not it. We just, obviously, we weren't ready to update our overall program for the year, a lot of projects in the $17.3 billion. So I would say stay tuned for that, but this is definitely a increased amount of capital, but we haven't yet updated our overall program.
Your next question comes from the line of Nicholas Campanella from Bank of America Merrill Lynch.
Congrats on the quarter. Just looking at the regulatory items, I was just curious if you could provide a time frame, if you haven't already, on when you think we'll have a resolution for the ITC complaints as well as the notice of inquiry.
Linda, you want to provide your perspective? You're the closest to it.
Yes. I mean, certainly, our view is particularly on the ROE, the pending ROE-based complaint, we still believe we will see a decision on that yet this year. In terms of the notice of inquiry, I think those are a little less certain in terms of what FERC will do. Once the -- they've received all of the various comments and [ provide ] comments, I think that's left clear as to what their next steps might be or what their timeline might be. But I think, clearly, we feel as though we will continue to get a decision yet this year on the MISO-based ROE complaints. I think we'll just have to wait and see based on the comments and the FERC and the composition of FERC what they might do on the NOIs.
I guess just shifting to Arizona, we all saw the Hudbay mine and sounds like that's going to be your largest customer in the jurisdiction. Is there any way to kind of quantify how meaningful that is to your top line sales. And then if you could just kind of remind us how that reconciles with your longer term forecast. And then perhaps we can kind of talk about incremental opportunities in Arizona as well.
Well, Nick, all I can say is that Arizona is a pretty big business, and we're bringing on a new customer that's going to be our largest customer. That's got to be positive, right? So David's here. David, do you want to add some other color?
Yes. So our current largest customer is 80 megawatts. So it's going to be north of that. They're still trying to figure out what equipment they're going to have in their mine design. We're working with them through that process over the balance of this year, so don't really have a firm estimate of what that top line revenue impact would be but you could probably calculate pretty close yourself if you're looking at that kind of above 80 megawatt-type load and a typical capacity factor of a mine so you could probably get pretty close. So yes, we're expecting -- our -- well, we're expecting them to start building early next year. The transmission line that will serve them, we expect that to start later this year and as Hudbay has put out for this mine, they're expecting that full production to be in by the end of 2022 so that is in our longer term forecast. Now it's moved around quite a bit over the last few years, but that's the time line that we currently have.
Your next question comes from the line of Robert Catellier from CIBC Capital.
I was wondering if you could characterize what type of run rate you have to increase renewables at TEP and UNS given that you're bumping up against some of the renewable portfolio standards there.
David?
So, obviously, putting in the 250-megawatt Oso Grande Project is going to be a big one for us. That's the one that we currently have on our time horizon. We expect that to be done by the end of next year. That, with a couple purchase power agreements that also come in next year will bring our portfolio of over 1,000 megawatts so we've got -- we're doing all the plans for integrating not only that thousand megawatts but making room for a little more. So we don't have a firm number for additional renewable resources that we will build over that near term but just to keep your eye out for our preliminary integrated resource plan that we're going to be filing here in the next couple weeks. We'll show you what those resources look like now. And then we're going to go through about a yearlong stakeholder process, get input from our commission, other stakeholders and develop a final integrated resource plan and we'll lay that out in a little bit more detail. That won't be finished until about 1 year from now, but it'll give you a pretty good heads up. We plan on -- our current plan is owning any additional renewable energy that we put in the ground for our customers on a going forward basis because of the vast majority other than this big wind project has been PPAs. So that's kind of how you could look at it.
And then, Barry, I wanted you to help me with the rate cases in BC. You've been an advocate for Canadian regulators to improve the competitiveness of the cost of capital and the ROE and the equity [ thicknesses ] basically. I wondered if you could tell us how the rate applications in BC address that and help make the returns more competitive.
This case that's been filed, it does not include cost of capital, so cost of capital in BC is a separate process, Rob. So, obviously, once we get to that, we'll be incorporating our thoughts in that filing. I will just be clear to say that the Canadian regulatory landscape is inferior to the U.S. landscape. Our equity thickness is a full 10 points lower than our American businesses and that, over the long term, is a major competitive issue for Canadian companies and it has to be fixed. So we -- but we have to make a case of why it's good for our customers to fix that. We'll be doing that and that is a challenge that Fortis is taking on, and we're going to work transparently with respect with our regulators in Canada to try to improve that situation.
Barry, the question was actually in the context of the fact that this rate case doesn't address cost of capital. I was wondering if there's any other items in there that help make it more balanced on the risk-reward -- risk-adjusted basis that, that might not be [indiscernible] because they're not capital items.
Roger is here to make a comment.
Just on the application itself. Traditionally in BC, going back to the '90s, cost of capital has been set separately. That's rate of return as well as equity thickness from rate application so it's not unusual that our multi-year rate plan does not include a specific filing for cost of capital. Our last decision on cost of capital was 2016 so we do look time to time at the financial situation to determine whether we'll be bringing forth a new cost of capital allocation. We've just filed this multi-year rate application. As this application rolls forward, we'll make another decision on what we think the right time is to bring forth a new cost of capital application. As far as the application itself, it's really an extension of the existing PBR, a bit of a different focus. The current PBR was really rooted in productivity efficiency of both O&M and capital. This program maintains -- this application maintains many of the same elements, but it's more of a focus on targeted senses around low-carbon energy on a demand side management and innovation. So it's not directly changing. In our view, it's more of an extension of our current regulatory construct, not a large departure, so we don't see it having an impact right now on our view of cost of capital.
Your next question comes from the line of Rob Hope from Scotiabank.
I want to circle back with Rosemont. Just want to get a sense of when the kind of relatively short transmission line to the mine would be completed as well as appreciate David's comments on load. But just want to get a sense of how much load do you think you're going to get out of that project during the construction of it?
You want to peel the onion.
A little bit.
I guess I was a little too vague. And purposely so because they still are developing their mining plan. As far as the construction goes, we should have that line built by the end of next year. It's not a -- it's only a 13-mile route. The engineering is mostly done. We have been doing prep work for that for years. So it's all permitted and ready to go. We just need to get it in time for them to start their operations. But yes. I can't -- I really can't say much more about the expected load there.
Right. So let's do a broader question then. So Barry, when you look at the overall market and very strong valuations we're seeing on energy infrastructure items, either majority or minority interests. How do you weigh further strengthening the balance sheet versus your existing asset suite?
First of all, Robert, I take you back to the fact that we laid out a strong funding plan for the existing capital program, and we're executing well on that plan. And that does see our credit metrics improve over time. So we'll start there. But I would say, frankly, any offers we would receive on assets that would be similar to or better than what we got for Waneta, everything is for sale at those levels. Any CEO of a large public company would have to entertain those kinds of offers. And I don't see those showing up, but if they did appear for certain of our assets, we would have to look at them.
Barry, I could add a little color related to Rosemont. Because one of the things that you're talking about the transmission line, I think it's important to point out that we don't pay for that transmission line. Rosemont is paying the $30 million it will take to construct that. So when you look at from a customer perspective and kind of that cash flow versus investment, we have to make absolutely 0 investment in order to serve Rosemont. So that's a really nice asset to have joining our company with the customer that size. 0 additional infrastructure needed, and obviously, a big customer. So that might provide a little bit color for that later period cash topic.
Your next question comes from the line of David Quezada from Raymond James.
My first question here just on Wataynikaneyap. I'm just curious if there's any color you can provide on the permitting process? And just if you could comment at all on whether or not that's going as expected?
It's going very well, and Gary Smith who heads up that project for us is here. Gary, you want to give an update?
Yes. We've been at the permitting process, for sure, pretty hard now for a couple years, and we've met all the requirements in the permitting process. The file now is in front of the minister to make a decision. We just think there's a little bit more time required for him to digest the information we provided, but we don't see any critical hurdles in our way to stop the project from moving forward. So we do expect to get a decision soon. But again, exactly when that will be later this year is undetermined.
That's good color. And then maybe just one other one. I realize this is a longer term opportunity, but just on Big Chino, if you had any early consultations with stakeholders there? And how that process has been going?
Well, Big Chino is an interesting project, obviously. Theoretically, it's a great project for the region to have long durations of pump storage. It would greatly enhance the ability of the region, southwest region, to bring more renewables onto the grid, solar, wind. That being said, it is a big project that would take 7, 8 years to complete. So we're evaluating our involvement in that project at this point in time and continue to do certain initiatives there, but I would say that it's a project we'll be making a decision on this year whether we continue to put development dollars into it going forward.
Your next question comes from the line of Linda Ezergailis from TD Securities.
I'm wondering if you could help us understand whether your current funding plan addresses or should eliminate the negative outlook that S&P has. Or how you feel about kind of defending your S&P rating versus potentially a downgrade?
Well, I would hope that they would remove it, related to our strong execution and investing in our regulated businesses, Linda. We're continuing to have good dialogue with S&P. We would not expect any immediate actions from them. Jocelyn, you want to add?
Yes. I would say that the negative outlook stems from, obviously, a post-U.S. tax reform. And so U.S. tax reform was as expected for us, and we do expect to get back to a metric similar to pre-U.S. tax reform in a few years. So I suspect that will create even better dialogue with S&P.
And Linda, to be clear, I like the BBB+ unsecured debt rating with S&P.
That's helpful. And maybe we can move on to Aitken Creek. I realize that it's hard to predict that earnings stream, but maybe you can help us see year-to-date kind of what you're seeing both from a volume and margin perspective and beyond just helping deleveraging your funding. Would maybe moving that asset to rate base or, for the right price, exiting kind of help your, I guess, risk profile from a business risk perspective with the rating agencies or some other strategic benefit.
I would say, in a perfect world, Linda, Roger's sitting right next to me here. So I would like to see that asset in regulated operations, that it is a critical asset for the management of the gas network in Western Canada. And our utility Fortis BC uses a lot of the capacity of the plant. That's something we'll be thinking about in the future. In terms of performance in the quarter and longer-term performance, I think since we bought it, the asset has done very well, it's actually, I would say outperformed our expectations. There's some potential, though, to also expand the asset a little bit. So Roger, maybe you can add some color on where we are in the quarter and some of the reasons why that we had sort of a light quarter?
Yes. Thanks, Barry. Linda, I think the main driver is Q1 2018, there were a couple of things happening that were not prevalent in 2019 so. We had a colder regional winter Q4 '17, Q1 '18 relative to what we experienced in 2019. We had a very mild winter in the region Pacific Northwest, and we sort of experienced winter more in February into March than the previous years. So we had a greater demand for gas -- outer storage Q1 2018. We also had some maintenance constraints. So gas prices are generally higher so there is significant amount of gaps pulled over the ground in 2018. We are closing off deals and realizing the value of the market at the time, 2019, partly because the weather and the Enbridge situation there was lower prices. So we were injecting more than withdrawing in the quarter, and that's really the driver. We feel that Q1 2019 was a good quarter, but not as strong as '18 because of those factors.
And can you comment on the scale of the potential expansion and the timing, what factors need to be in place to expand that asset?
We were just connecting to the North Montney, which is a small expansion of the system. We are looking at development of the north Aitken field. That would be a few years away. We don't have specific capital estimates yet. It's really going to be determined on market factors in the next 2 to 3 years. So more to come on that one.
But it's fairly small in terms of the capital, Roger.
Yes. Less, like maybe $100 million.
And what factors would need to be in place to move it to rate base?
Just LNG development, natural gas expansion in Pacific Northwest, ongoing increased demand for natural gas, which we think is positive, but those things will develop over time.
And maybe just a final high-level strategic question. I guess for Barry, given some of the recent changes in provincial governments, how has that affected your strategic lens and outlook on those geographies? And does that increase the urgency to address some of your cost of capital issues you have with Canada? Or might there be some opportunities to potentially to nonregulated assets in those geographies? Can you comment on, I guess, Alberta, and to a lesser extent, Ontario and anywhere else, specifically, that you think there's been a change in policy that might help or affect your business?
That's a big question, Linda. I'll try to address it. We're not only interested in nonregulated assets other than, I would say, things like LNG tolling or the contracted transmission that the Erie connector would be involved in, so things that look and feel like regulated, I would say. In terms of the region, we have a very positive relationship with the government in British Columbia. Our natural gas business is doing well there. Fair amount of investment going into our pipeline network. We added 22,000 customers in British Columbia last year, 2-plus percent customer growth with probably one of the strongest growing natural gas franchises in all of North America. And so we're very positive on that business, and we are aligning with reducing carbon intensity of our product there, focusing on renewable natural gas, gas for transportation, all of these things that are obviously consistent with government policy. In [ Britain ] -- in Alberta, across the border, we have an electric franchise distribution only. Alberta still grows by -- our business there by 5%, 6% a year. It's a strong business. And we're working, obviously, through the regulatory regime. And Alberta -- it has the thinnest equity in all of Canada, 37%. That's a significant issue. We need to see some improvement there, but the distribution network that's comprised of over 1 million poles, is a very strong franchise, and we continue to have good relationship with the previous government. And I expect that will be the case with this government, and I think that's the benefits of what you get with Fortis. We have these local teams who are running the businesses with a local independent board, dealing with the matters that they face within their territories. And it's been a pretty successful model for our company, and I would expect that, that will continue going forward.
Your next question comes from the line of Andrew Kuske from Crédit Suisse.
I guess the question starts off with Barry and it's just on energy conservation and the efforts behind that. How do you think about returns on that business activity? This -- sort of the quirky thing with regulated utilities? It's probably the only industry in the world where you're effectively trying to incent people to use less of your product and service?
Well, Andrew, I would just say that we need to keep doing the things that we do for the company's environmental footprint. Our customers are demanding cleaner energy be delivered. Obviously, always with an eye on affordability. I think jurisdictions that go too far too quick have run into some trouble and I would use Arizona at the poster child for the for the way to do it. They they've gotten greener incrementally every year for the last number of years, but yet have kept rates very economic and affordable in that jurisdiction. So they're the jurisdiction I think that people should look to. So I would say regulators that are progressive enough to think that the utilities can play a major role in improving the portfolio of supply becoming more energy efficient are very progressive because utilities know how to do this. And Fortis knows how to do it and we can get it done quickly. So I think that, clearly, we are looking for that and we interact with our regulators. We are looking for those opportunities, and I would commend the BCUC for being very progressive in terms of this new program that we have in place in British Columbia that we get to invest $370 million, I think, over the next 4 years. It does go into rate base, but it accelerates these programs very quickly, and we will see results from that.
And then just maybe an extension on some of the activities you've got going on in the portfolio and to the first question. Do you see any broader need to pivot into renewables to a greater degree? Then sort of, directly, if you can do rate base renewables and then anything outside of rate base if it's in a contractual framework.
Where we can do renewables within our utilities, we would definitely pursue those, but I always remind folks that most of our business is just wires and gas pipes. So we're not that involved in the generation side of the business except for Arizona and David and his team. They are working with the corporations commission, have done a really good job of improving their portfolio of supply and will continue to do so. I think in America, obviously, renewables have become very attractive in terms of price. It was Oso Grande Wind [ regime ], David, I think we're at, like, 45% capacity factor, I think, something like that. So these are 4.5 megawatt turbines. These are great assets, and so where we can do more, that we will, but you have to remember Fortis is more of a T&D business without that generation. I don't see us, frankly -- we can try and we will try here and there but competing against the big renewables businesses that are nonregulated, that's a tough spot to go to and it's hard to make money in that area. So really, our core focus will be investing in our grid, our energy networks as well as improving our portfolio supply in Arizona.
[Operator Instructions] Your next question comes from the line of Patrick Kenny from National Bank.
Yes. Just a follow-up on the question around credit ratings. Now with the Waneta proceeds in the door, wondering if you could update us on any discussions you might be having with Moody's? And if there's any visibility or road map to get off the Baa3 rating?
Yes, Patrick. This is Jocelyn. Yes. I think I can echo Barry on this one that we're not happy with the Baa3 rating and we do work with Moody's to understand it better and we work to improve it. But we're having normal discussions with Moody's. And certainly, we shared with them our funding plan out of the fall and we updated them even with in this past quarter. So we're having good discussions with them, and they'll go through the normal ratings process. But we are looking to improve this rating over the planning period.
And I'll sound defensive on this, but I want to remind everyone on the call that we're BBB-plus with DBRS. We're BBB-plus with S&P, and yes, we're Baa3 with Moody's. But a lot of folks forget the other 2 agencies who rate us very attractively.
And Jocelyn, can you just remind us what the target Holdco debt to total debt ratio would be from Moody's?
The Moody's doesn't actually provide a target. I expect it's 30% or lower.
And then just back to Alberta and the regulatory outlook there. How should we be thinking about the AUC potentially moving to a formula based ROE by 2022? I know it's still a ways off but I guess based on the shape of the interest rate curve today, wondering if you think this represents upside or downside to the 8.5%?
I can only hope that it represent upside. Since I can't imagine we could go much lower than where we are but that -- clearly we, Patrick, will be in that process, making sure that we put good evidence forward to make sure that any outcome that would suggest that should be lower than that would not be not be appropriate. Clearly, regulators will do what they do, but I would hope that we could put forward strong evidence to suggest that any outcome that would generate an ROE even where we are today is not appropriate.
There are no further questions. I would now like to turn the call back over to Ms. Amaimo for closing remarks.
Thank you, Jessa. We have nothing further at this time. Thank you, everyone, for participating in our first quarter 2019 results call. Please contact Investor Relations should you need anything further. Thank you for your time and have a great day.
Thank you for participating, ladies and gentlemen. This concludes today's conference call. You may disconnect.