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. During the call, all participants will be in a listen-only mode. There will be a question-and-answer session following the presentation. [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 enhance 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 five years. In Arizona, Tucson Electric Power, or TEP, filed a rate case on April 1st 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 expansion of its 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…

Thank you, Barry, and good morning, everyone. For the first quarter, reported EPS of $0.72 was $0.05 lower than last year. This was largely due to a one-time 30 million positive U.S. tax adjustment in 2018 related to our filing of a consolidated state income 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 plans 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, 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 cost 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 base growth partially offset by the reduced ROE independent incentive adder. Our Canadian and Caribbean utilities increased EPS by $0.01 driven mainly by rate base 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 non-regulated energy infrastructure businesses. Realized margins were lower at Aitken Creek and…

Thank you, Jocelyn. Fortis consist 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 was strong with over 7% rate base growth expected over the next three years and 6% rate base growth over the next five years. This supports our 6% average annual dividend growth guidance through 2023. We continue to focus on growing our utility businesses. To summarize, to 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 Waneta proceeds to pay down corporate debt, including the US$400 million repurchase of notes due in 2026. Advanced the Wataynikaneyap Power project by obtaining the leave-to-construct from the OEB; progressed our commitment to reduce our environmental footprint with the announcement of the Oso Grande Wind Project and the FortisBC energy conservation efficiency program, filed rate cases at TEP and FortisBC and delivered strong EPS growth in the quarter. I’ll now 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. Please go ahead.

Good morning.

Good morning, Robert.

Good morning.

Maybe just to start with some of the opportunities that are potentially in front of you in BC and 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?

Thank you Robert for you question. We continue to work with Woodfibre. They obviously have asked us to build the pipeline to sell them – to get them some gas for their facility. They’re providing us some funds to do permitting, procurement, design of the pipeline so we continue to work with them on that. And frankly I’m probably anxious for them to make a final investment decision, but that’s not yet been done. So we’re hopeful that will come soon. And in terms of sort of the resilience and reliability of the gas network, Roger Dall’Antonia is here, our CEO of FortisBC. 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. Roger Dall’Antonia: 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.

Okay. I guess just with that, I’m also wondering if Woodfibre went ahead, are there any discussions kind of with the province or the BCUC? And really upside I guess with strengthening whether that’s actually getting something done additionally at Tilbury or something around Southern Crossing? Roger Dall’Antonia: We’re looking at both opportunities. It’s too early to discuss those plans in front of the BCUC and the government in the next little while as we look at both options.

Got it. And if I can just finish with financing. With the Waneta divestiture really kind of squaring up the funding plan, I’m 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 as there 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 weigh 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 Waneta transaction 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 on that and 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 are committed to our investment grade credit ratings. We would do nothing that would harm those ratings.

Got it. So that stands that ATM is really the first option here?

That’s correct.

Okay, that’s great. Thank you.

Your next question comes from the line of Ben Pham from BMO. Please go ahead.

Okay. Thanks. Good morning. Just going back to the Waneta sale and even what divestiture is, does your Holdco debt outlook that you highlighted at Investor Day, does that – are you well ahead of that slide that you presented or is it more of a gradual reduction?

Yes. So, Ben, this is Jocelyn. So at Investor Day we actually had Waneta included in our projections for Holdco debt. So I think we showed at Investor Day at Holdco was going from 38% down to around 33%, 32%. So we’re on track with that plan with the close of Waneta sale.

Okay. 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 – okay, all right. Just wanted to check on that. And then on the – just going back to some of the questions on future growth prospects. Just on the transmission stuff in Ontario, there is a press release mentioning Ontario capacity markets could drive your transmission initiatives. And could you comment a bit on that and on why that couldn’t 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 more economic sense and we felt 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 long-term contract for it to go ahead and we are 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. This is Linda Apsey. Yes, as Barry mentioned certainly with sort of the energy market, capacity market and PJM as well as obviously directional capacity interest in Ontario obviously from a DP 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 differentials that occurs in terms of capacity pricing in both those different markets. So from our perspective, capacity market was not something that Ontario has obviously a lot of experience in. And so bringing more attention to the benefits of a capacity market and the value of projects like the Lake Erie Connector brings, we’re just really obviously trying to highlight that and continue to sort of be part of the conversation and continue to advance that project in highlighting the benefits and the need for the project and continue to drive value for Ontario customers.

Okay, that’s great. And maybe to finish off, so some of the CapEx changes on Oso Grande Wind farm in Arizona, I’m just more curious. Is the reiteration of the rate base at UNS, is that just because tax equity is going to pick 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 of rate base growth since the last historical test year in Arizona?

I was thinking more just with the higher megawatts on the Oso Grande Wind farm, like it’s going up by 200 million from previous disclosures and so that’s 0.2 billion in CapEx. And I’m nitpicking on all 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, Ben. We just obviously – we weren’t ready to update our overall program for the year. A lot of the projects in the 17.3 billion. So I would say stay tuned for that. But this is definitely an increased amount of capital but we haven’t yet updated our overall program.

Okay, got it. Thanks everybody.

Your next question comes from the line of Nicholas Campanella from Bank of America Merrill Lynch. Please go ahead.

Hi. Congrats on the quarter. Good morning.

Thank you.

Just looking at the regulatory items, I was just curious if you can provide a timeframe 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 prospective. You’re the closest to it.

Good morning, Nic. Yes, certainly our view is particularly on the pending ROE base complaints. 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 they proceed all of the various comments and refi comments. I think that’s less 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 see a decision yet this year on the MISO base ROE complaint. I think we’ll have to just wait and see based on the comments the FERC and the composition of FERC what they might do on those NOIs.

Thanks. I guess just shifting to Arizona, we all saw the Hudbay mine and it 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, Nic, 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, 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 are 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 I don’t really have a firm estimate of what that top line revenue impact would be, but you can probably calculate it 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 – 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 our longer-term forecast. Now it’s moved around quite a bit over the last two years, but that’s the timeline that we currently have.

I appreciate it. That’s it for me. Thanks again.

Thanks, Nic.

Your next question comes from the line of Robert Catellier from CIBC Capital. Please go ahead.

Hi. Good morning. 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 portfolios 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 of purchase power agreements that also come in next year will bring our portfolio to over 1,000 megawatts. So we’ve got – we’re doing all the plans for integrating not only that 1,000 megawatts but making room for a little more. So we don’t have a firm number for additional renewable resources that we’ll build over that near term. But just keep your eye out for our preliminary integrated resource plan that we’re going to be filing here in the next couple of weeks. We’ll show you what those resources look like now and then we’re going to go through about a year long stakeholder process, get input from our commission, other stakeholders and develop a final integrated resource plan that will lay that out in a little bit more detail. That won’t be finished until about a year from now but it will 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 the vast majority other than this big wind project has been PPAs. So that’s kind of how you could look at it.

Okay. 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, the ROEs 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 we filed does not include cost of capital. So cost to capital in BC it’s a separate process, Rob. So obviously once we get to that we will 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. But we have to make a case why it’s good for our customers to fix it and 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 was any other items in there that help make it more balanced on the risk adjusted basis that might not meet the eye, because they’re not capital items.

Roger is here to make a comment. Roger Dall’Antonia: Good morning, Robert. Just on the application itself, traditionally in BC going back to the '90s cost of capital has been checked separately. That’s rate of return as well as equity thickness from rate applications. So it’s not unusual that our multiyear 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 followed just multiyear rate application. As this allocation rolls forward, we’ll make another decision on when we think the right time is to bring it forward a new cost of capital application. As far as the application itself, it’s really an extension of the existing PBR. They have a different focus. The current PBR was really rooted in productivity efficiency on both O&M and capital. This program maintains – this application maintains many of the same elements but it is more of a focus on targeted incentives around low-carbon energy on demand side management and innovation. So it’s not directly changing. And our view is more of an extension of our current regulatory construct, not a large departure. So we don’t see it having any impact right now by our view of cost to capital.

Okay. Thank you very much.

Thank you, Rob.

Your next question comes from the line of Robert Hope from Scotiabank. Please go ahead.

Good morning, everyone. 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 I appreciate David’s comment 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?

So, Rob, you’re peeling – you want to peel the onion.

Just a little bit.

I guess I was a little too vague and purposely so because they still aren’t developing their mining plan. As far as the construction goes, we should have that line built by the end of next year. It’s only a 13 mile route. So 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 really say much more about the expected load there.

All right. So let’s do a broader question then. So, Barry, when you looked at the overall market and the very strong valuations we’re seeing on energy infrastructure items either majority or minority interest, how do you weigh further strengthening the balance sheet versus your existing asset suite?

Well, first of all, Robert, I’d 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. What 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 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 zero investment in order to serve Rosemont. So that’s a really nice asset to have join in our company with a customer that size, zero additional infrastructure needed and obviously a big customer. So that might provide a little bit color for that later period cash topic.

Thank you.

Your next question comes from the line of David Quezada from Raymond James. Please go ahead.

Thanks. Good morning, everyone. My first question here just on Wataynikaneyap, 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 of years and we’ve met all the requirements in the permitting process. The file now is on front of the minister to make a decision. We just think it’s a little bit more time required for him to digest the information we have 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.

Okay, that’s good color. Thank you. And then maybe just one other one. I realize this is a longer-term opportunity but just on Big Chino if you’ve had any early consultations with stakeholders there and how that process has been going?

Well, Big Chino is an interesting project. Obviously it’s – 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 on to the grid, solar and wind. That being said, it will a big project that would take seven, eight years to complete. So we’re evaluating our involvement in that project at this point in time and continuing to do certain initiatives there. But I would say that it’s a project we won’t be making a decision on this year whether we continue to put development dollars into it going forward.

Okay, fair enough. Thank you for that. That’s all I have from me.

Your next question comes from the line of Linda Ezergailis from TD Securities. Please go ahead.

Thank you. I’m wondering if you could help us understand whether your current funding plan addresses or should eliminate the negative outlook at 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. I would not expect any immediate actions from them. Jocelyn, you want to add.

Yes. Linda, I would say that the negative outlook stem from obviously post-U.S. tax reform and U.S. tax reform was as expected for us and we do expect to get back to metrics similar to pre-U.S. tax reform in a few years. So I suspect that that will create even better dialogue with S&P.

And, Linda, to be clear I’d like the BBB+ unsecured debt rating with S&P.

Okay. Thank you. 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 here to-date kind of what you’re seeing both from a volume and margin perspective? And beyond just help in deleveraging their 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 prospective with your rating agencies or some other strategic benefit?

I would say in a perfect world, Linda, Roger is sitting right next to me here, so I would like to see that asset in regulated operations. It is a critical asset for the management of the gas network in Western Canada and our utility FortisBC 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 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 we had a sort of light quarter. Roger Dall’Antonia: Yes. Thanks, Barry. Good morning, Linda. I think the main driver is Q1 2018. There was 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 to Northwest and we sort of experienced winter more in February into March than the previous year. So we had a greater demand for gas outer storage Q1 2018. We also had some maintenance constraints where gas prices are generally higher, so there was significant amount of gas pulled out of the ground. In 2018 we were closing off deals and realizing the value of the market at the time. 2019 partly because of 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 a potential expansion in the timing, what factors need to be in place to expand that asset? Roger Dall’Antonia: We were just connecting to the north [indiscernible] 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 determinant on market factors in the next two to three years, so more to come on that one.

But fairly small in terms of capital, Roger. Roger Dall’Antonia: Yes, may be $100 million.

And what factors would need to be in place to move it to rate base?

Just LNG development, natural gas expansion Pacific Northwest, ongoing increased demand for natural gas which we think is positive but those things will develop over time.

Okay. Thank you. 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 add to non-regulated 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 has 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 overly interested in non-regulated assets other than I would say things like LNG tolling or the contracted transmission that 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. A fair amount of investment going into our pipeline network. We added 22,000 customers in British Columbia last year, 2% plus customer growth which is probably one of the strongest growing natural gas franchises in all of North America, so we’re very positive on that business and we’re aligning with – reducing carbon intensity of our product there, focusing on renewable natural gas, gas with transportation, all of these things that are obviously consistent with government policy. In Alberta, across the border we have an electric franchise distribution only. Alberta still grows our business there by 5%, 6% a year. It’s a strong business and we’re working obviously through the regulatory regime in Alberta. It has the thinnest equity in all of Canada, 37%. That’s a significant issue and 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 it will be the case with this government. And I think that’s the benefit of what you get with Fortis. We have these local teams who are running the businesses with their 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.

Thank you.

Thanks, Linda.

Your next question comes from the line of Andrew Kuske from Credit Suisse. Please go ahead.

Good morning. I guess a question starts off with Barry and it’s just on energy conversation and the efforts behind that. How do you think about returns on that business activity? 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.

Andrew, I will just say that we need to keep doing the things that reduce 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 and run into some trouble and I will use Arizona as the poster child for the way to do it. 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 there the jurisdiction I think that people should look to. So I would say regulators that are progressive enough to think that their utilities can play a major role in improving the portfolio of supply, become 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 when we interact with our regulators, we’re looking for those opportunities. And I would 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 four years. It does go into rate base, but it accelerates these programs very quickly and we will see results from that.

Okay, I appreciate 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 and sort of directly if you can do rate base renewable? And then anything outside of rate base if it’s in a contractual framework.

Where we can do renewables within our utilities, we will 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, expect for Arizona and David and his team there working with the Corporations Commission have done a really good job of improving their portfolio of supply and we’ll continue to do so. I think in America obviously renewables have become very attractive in terms of price. In the 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 of 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 – look, we can try and we will try here and there, but competing against the big renewables businesses that are non-regulated 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.

Okay, that’s great. Thank you.

Thank you.

[Operator Instructions]. Your next question comes from the line of Patrick Kenny from National Bank. Please go ahead.

Hi. Good morning. Just a follow up on the question around credit ratings. Now with the Waneta proceeds in the door, I’m wondering if you could update us on any discussions you might be having with Moody’s and if there’s any visibility or a roadmap to get off the AA industry rating?

Yes, Patrick, this is Jocelyn. 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 in this past quarter. So we’re having good discussions with them and they’ll go through their normal ratings process. But we are looking to improve this rating over the planning period, yes.

And I’ll sound defensive on this, but I want to remind everyone on the call that we’re BBB+ with DBRS. We’re BBB+ with S&P. And we – yes, we’re Baa3 with Moody’s. But a lot of folks forget the other two agencies who rate us very attractively.

Thanks. And, Jocelyn, can you just remind us what the target Holdco debt to total debt ratio would be for Moody’s?

So Moody’s doesn’t actually provide a target. I expect it’s 30% or lower.

Okay, great. 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, I’m wondering if you think this represents upside or downside to the 8.5%.

I can only hope that it represents upside since I can’t imagine we can go much lower than where we are. But that – clearly, Patrick, we’ll be in that process making sure that we put good evidence forward to make sure that those – any outcome that would suggest it should be lower than that would 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.

Okay, that’s great. Thanks, Barry. Thanks, Jocelyn.

Thank you. 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. You may disconnect.