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Ladies and gentlemen, thank you for standing by. My name is Michelle, and I will be your conference operator today. Welcome to the Fortis Q2 2020 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, Michelle, and good morning, everyone. And welcome to Fortis' Second Quarter 2020 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. Actual results can differ materially from the forecast projections included in the forward-looking information presented today. All non-GAAP financial measures referenced in our prepared remarks are reconciled to the related U.S. GAAP financial measures in our second quarter 2020 MD&A. Also unless otherwise specified, all financial information references in Canadian dollars. With that, I will turn the call over to Barry.
Thank you, Stephanie, and good morning, everyone. When we spoke last quarter, we were just starting to understand the challenging impacts of the COVID-19 pandemic on North America and the world. Three months later, we continue to see the effects of the virus on our people and the communities we serve. At Fortis, we have lived with spikes in COVID-19 cases in some of our jurisdictions like New York and Michigan. Currently, the people of Arizona, our UNS employees and their families are facing the consequences of the spread of the disease. Our hearts go out to everyone affected. Our utilities remain vigilant during these uncertain times. We are focused on ensuring our employees, customers and communities are safe. Nothing is more important to us. We also know the responsibility we hold as an essential service provider. I am heartened to see the commitment of our employees at home and in the field as they keep the lights on and the natural gas flowing. Thank you to each and every one of you. From a financial perspective, the pandemic impacts have been manageable to date and relate primarily to reduced sales in the Caribbean as well as higher direct costs and credit losses. Together, these represented about $0.03 of EPS during the quarter. Last quarter, we disclosed that 82% of our annual revenues are either protected by regulatory mechanisms or are from residential sales, which were expected to increase during the pandemic. As expected, we did see higher residential sales and lower commercial and industrial sales. We recognize that the pandemic is ongoing, and we intend to continue to take the necessary measures to protect our employees, customers and communities, all while delivering safe, reliable and affordable service. Now I'd like to update you on the progress made on several fronts in our business in the second quarter. First, on the regulatory front, FERC issued an order on the MISO base ROE matter at ITC. In British Columbia, FortisBC received a final order on its multiyear rate plan for 2020 to 2024. And TEP continued to progress the rate case in Arizona. Jocelyn will walk through these developments in more detail in her remarks. During the quarter, we advanced our commitment to delivering cleaner energy to customers and creating a more sustainable future. In June, Tucson Electric Power filed its integrated resource plan with the Arizona Corporation Commission, outlining an ambitious target to reduce carbon emissions by 80% by 2035, compared to 2005 levels. More recently, we released our 2020 sustainability report and sign on to the Black North Initiative, which is committed to removal of systemic barriers negatively affecting the black community. Also, we invested $2 billion of capital into our systems during the first half of the year, supporting adjusted earnings per common share of $0.56 for the second quarter and $1.23 year-to-date. Overall, our team continues to maintain operational and financial performance amidst the pandemic. Turning to Slide 5. Here, we have provided an updated look at the year-over-year sales trends in our local jurisdictions during the second quarter. Generally speaking, our utilities continue to see an increase in residential sales and a decline in commercial and industrial sales as businesses continue to operate at a reduced level. As you might recall, last quarter, we identified UNS Energy and our other electric segment as having exposure to changes in sales. In fact, during the quarter, we saw total sales at those segments increased by 3%. Higher residential sales, mainly due to warmer weather in Arizona was the main driver, partially tempered by lower commercial sales due to travel restrictions, halting tourism in the Caribbean. Overall, retail sales in Arizona were up 9%, while other electric sales were down 3%. And excluding weather impacts in Arizona, sales at UNS Energy were up 2% over 2019 levels, mainly due to higher residential sales. Speaking of Arizona, we are very excited about TEP's new target to reduce carbon emissions 80% by 2035. To achieve this goal, TEP will require over 2,400 megawatts of new wind and solar power systems, including approximately 450 megawatts that will be coming online over the next year. In addition, TEP expects to add 1,400 megawatts of new energy storage systems. Once completed, TEP will have more than 70% of its power sourced from renewable generation. The integrated resource plan also calls for TEP to ramp down and ultimately retire 2 units at the coal-fired Springerville generating station in 2027 and 2032. Upon retirement of Unit 2 in 2032, Fortis expects to have a coal-free generation mix. These changes will result in TEP avoiding more than 50 million tons of CO2 emissions over the next 15 years, equivalent to taking approximately 700,000 passenger vehicles off the road on an annual basis. I want to congratulate Dave Hutchens and the team in Arizona for bringing forth this impressive plan, which continues our progress on a clean energy future for customers in Arizona. As we continue to focus on our core business of regulated energy delivery, sustainability is front and center in all that we do. Beyond TEP's new carbon emission targets, our newly released sustainability report highlights some of our other initiatives, including FortisBCs, 30 by 30 goal, which aims to reduce greenhouse gas emissions associated with customer energy use by 30% by 2030. This target at FortisBC, which is primarily a natural gas distribution company, is one of the most ambitious reduction targets among Canadian Utilities. The report also showcases our investments dedicated to asset resiliency, modernization and cleaner energy initiatives. In total, these investments represent about 70% of our $4.3 billion 2020 capital plan. In addition, the report highlights some of our recent disclosure enhancements, including our alignment with the recommendations of the task force on climate-related financial disclosures and expansion of various metrics. Report also emphasizes our new inclusion and diversity framework, which solidifies our commitment to take an active role on this front. Today, 40% of our Fortis Inc. directors, 3 of our 10 utility presidents and 60% of employees at our corporate head office are female. Lastly, the report outlines how our local leaders are supporting their communities. In 2019, more than $12 million in community investment was made by the Fortis Group of Companies. As mentioned, during the first half of 2020, we invested $2 billion in our energy systems or 47% of our annual capital plan and remain committed to our $4.3 billion capital expenditure plan in 2020. Major capital projects are progressing as planned. ITC received a key regulatory approval from the Iowa utilities Board to proceed with a multi-value project 5 with 345 kW transmission line will help expand system capacity and respond to consumer demands for more cost-effective renewable energy sources in the region. And in Northern Ontario, we recently raised the first tower in the 1,800 kilometer Wataynikaneyap Transmission Power Project, a milestone we are very proud of. Finally, the 250-megawatt Oso Grande Wind Project at TEP is progressing as planned. In fact, all 62 towers and turbines were installed during the first half of 2020, and TEP is in the process of installing the final remaining turbine blades. Turning to Slide 9. The 5-year capital plan of $18.8 billion remains unchanged. As you will recall, the capital plan is focused on our regulated businesses, and consists of a diverse mix of highly executable, low-risk projects needed to maintain and upgrade our existing infrastructure. In 2019, midyear rate base was $28 billion and is projected to grow to $34.5 billion by 2022 and $38.4 billion by 2024. This yields 3-year and 5-year compound annual growth rates of approximately 7%, which is consistent with our prior rate base growth guidance. For 46 consecutive years, we have increased our dividend. This track record positions us as a leader in dividend growth. Our low-risk energy delivery business gives us confidence to continue this record. I'll now turn the call over to Jocelyn for an update on our second quarter results.
Thank you, Barry, and good morning, everyone. Turning to Slide 12. Reported earnings for the second quarter of 2020 were $274 million or $0.59 per common share compared to earnings of $720 million or $1.66 per common share for the second quarter of 2019. On a year-to-date basis, reported earnings were $586 million or $1.26 per common share compared to earnings of approximately $1 billion or $2.39 per common share last year. Reported earnings for both the second quarter and year-to-date 2019 reflect a significant onetime net gain of $484 million from the sale of our 51% interest in the Waneta expansion. 2020 earnings also reflect the impact of FERC's ROE decision received in May, including a favorable earnings impact of $27 million at ITC related to the reversal of prior period accruals. And I'll get into that order in more detail in a couple of slides. On an adjusted basis, EPS for the quarter was $0.56, $0.02 higher compared to the previous year. During the second quarter, EPS was favorably impacted by strong rate base growth at our regulated utilities and higher retail sales at UNS Energy, primarily due to warmer weather. EPS was tempered by lower earnings at our Caribbean Utilities with the decline in tourism-related activities and incremental COVID-related costs, mainly at Central Hudson. A higher weighted average common share count also tempered EPS for the quarter. On a year-to-date basis, adjusted EPS was $1.23, $0.05 lower than the previous year. While year-to-date EPS was favorably impacted by similar items noted for the quarter, the overall decrease in year-to-date EPS was driven by lower earnings at UNS due to regulatory lag and a further impact of higher weighted average shares outstanding compared to last year. Slides 13 and 14 provide additional details on the EPS drivers for the quarter and year-to-date. First, on Slide 13, our U.S. electric and gas utilities contributed a $0.04 EPS increase for the quarter. Our Arizona business contributed $0.05, offset by $0.01 reduction from Central Hudson. Warmer weather in Arizona resulted in an approximate $0.03 EPS increase compared to last year. As you may recall, in 2019 Tucson experienced its coolest second quarter in the last 20 years. Additionally, in the second quarter, UNS realized partial recovery in the market value of certain assets that are held in trust to support retirement benefits. At Central Hudson, an increase in operating costs was driven by certain direct pandemic costs, including the sequestering of key operational staff. And as a reminder, Central Hudson's revenues are protected by regulatory mechanisms, however, the incremental operating costs are expensed as incurred. Central Hudson is tracking all COVID-19 related costs in conjunction with the generic proceeding initiated by the New York Public Service Commission. Although we cannot predict the timing and outcome of this proceeding, if regulatory recovery is achieved, this could add to earnings in a future period. Combined, our Western Canadian Regulated Utilities and ITC contributed a $0.03 EPS increase during the quarter. The increase was primarily attributable to rate base growth and lower business development costs at ITC. Lower operating expenses at our Western Canadian Utilities also contributed to the increase and that was mainly due to timing associated with the recent decision on FortisBC's multiyear rate plan. Next, a higher U.S. dollar to Canadian dollar foreign exchange rate favorably impacted quarterly results by $0.01. The $0.01 EPS decrease for our Other Electric segment was mainly attributable to lower commercial sales in the Caribbean due to the COVID-19 pandemic. As Barry discussed, sales in our Other Electric segment were down 3% in the quarter, driven by lower commercial sales in the Caribbean. Excluding Eastern Canadian sales, the Caribbean experienced a decrease in electric sales of approximately 9% during the quarter, mainly due to the impact of travel restrictions on tourism. In our Corporate and Other segment, the $0.01 negative EPS impact was mainly due to a gain on the repayment of debt recognized in the second quarter of 2019, partially offset by lower finance charges. And lastly, a higher number of shares contributed a $0.04 EPS decrease for the quarter. Turning to Slide 14. Adjusted year-to-date EPS decreased by $0.05 compared to the same period in 2019. Year-to-date EPS was impacted by many of the same drivers for the quarter. Rate base growth at our regulated utilities and warmer weather in Arizona favorably impacted EPS for the first half of 2020. The year-to-date EPS was tempered by higher cost at UNS energy associated with rate base growth not yet included in rates. If you will recall, TEP awaits the decision on its most recent rate case, which I'll discuss shortly. Earnings were also lower at UNS due to a reduction in the market value of certain assets that are held in a trust to support retirement benefits. This impact for the first 6 months was about $0.02 and was a result of the financial market volatility associated with COVID-19. In addition to these items, the impact of the FERC order at ITC tempered year-to-date earnings EPS by approximately $0.01. And lastly, a higher weighted average number of common shares lowered EPS by $0.09 for the first half of 2020 compared to the same period in 2019. As you can see on Slide 15, our utilities were active in the debt capital markets, issuing approximately $2 billion in debt since March 2020. More recently, FortisBC issued its inaugural green bond, the first green bond for a natural gas utility in Canada. The offering received strong investor demand and final pricing reflected the lowest long-dated Canadian corporate coupon on record. We have approximately $5 billion in total liquidity, leaving Fortis position near the top of our sector. Our conservative approach to running the business, including the equity issuance and sale of the Waneta Expansion in 2019 strongly positions us as we continue to work through the COVID-19 pandemic and execute on our capital plan. In May, we received an order from FERC regarding ITC's MISO base ROE. As you recall, in November 2019, FERC issued an order on the MISO base ROE, which resulted in an all-in ROE of 10.63%, including current incentive adders. The ROE was premised on a calculation using a discounted cash flow model and a capital asset pricing model. In the most recent order, FERC adjusted its ROE methodology to include a modified risk premium model in addition to the discounted cash flow and capital asset pricing model. Although FERC did not adopt the expected earnings model in the revised methodology, the commission noted that its use could be considered in future proceedings of certain conditions surrounding its use were addressed. FERC also denied the request for rehearing on complaint #2 and affirm that no refunds are due for the second complaint. In aggregate, the changes made by FERC result in a new MISO base ROE of 10.02%. With incentive adders, this implies an all-in go forward ROE of 10.77% compared to the 10.63% all-in ROE that ITC was previously collecting. The incremental 14 basis points is expected to increase annual EPS by $0.01 to $0.02 on a go-forward basis. The recalibration of prior period net accruals for ROE refunds resulted in a favorable EPS impact of $0.06 reflected in reported earnings for the second quarter. Now turning to updates on some of our additional regulatory proceedings. With regard to the 2 notice of inquiry issued in March 2019, FERC issued a notice of proposed rule-making or NOPR in March 2020 on the transmission incentive inquiry. The proposal could mean that ITC would be eligible for additional ROE adders, including project-specific incentives. Comments from stakeholders were provided to FERC through July -- on July 1. In Arizona, the TEP rate case remains outstanding. As you may recall, due to COVID-19, the Arizona Corporation Commission extended the procedural schedule, hearings concluded in June and post-hearing briefs are scheduled for July and August. We continue to expect a decision in late 2020. The New York Public Service Commission approved Central Hudson's request to delay the implementation of the previously approved July 1 electric and gas rate increase for 3 months to help customers through the financial challenges of COVID-19. The revenues will be deferred and collected over the remaining 9 months of the rate year from October 1 through June 30, 2021. Also in June, the New York Public Service Commission initiated a generic proceeding into the impacts of COVID-19 pandemic on the state's utilities, customers and commission adopted programs. Central Hudson, as part of the coalition of utilities, filed initial comments in July. We cannot predict the timing or outcome, but view this as a positive development. Shifting to our Western Canadian Utilities. In June, the British Columbia Utilities Commission issued a final order approving FortisBC's multiyear rate plan. The order sets the rate setting framework for 2020 through 2024. And as a reminder, the cost of capital was not a part of this proceeding, and the order was in line with management's expectations. During the quarter, FortisBC also received a final order on its COVID-19 customer recovery fund. The order established a rate base deferral account for bill credits, credit losses and payment deferrals up to June 30, 2020, associated with the pandemic. The recovery method will be determined through a future filing once the financial impacts of the pandemic are known. As discussed last quarter, the ongoing generic cost of capital proceeding for Alberta Utilities, including FortisAlberta, was suspended in March as a result of the pandemic. As part of the proceeding, the AUC offered the utility's 5 options for setting allowed ROEs and capital structures for 2021. In July, FortisAlberta notified the AUC that it had selected the third option, the extension of the currently approved cost of capital parameters on a final basis for 2021, one cool quarter at a time and continuing until the end of the quarter in which the commission makes a decision, which is expected sometime in 2021. The formal proceedings to set new cost of capital parameters prospectively in 2021 and for 2022 is expected to resume once the financial market effects of the COVID-19 pandemic stabilizes. FortisAlberta awaits a decision by the AUC in the review and variance and stay on implementation of the September 2019 order, which significantly changed the Alberta Electric System Operator's customer contribution policy related to transmission investment. FortisAlberta filed additional evidence in July and additional procedural steps are expected to conclude in September. A decision is expected in late 2020. And lastly, while not included on the slide, new rates went into effect at FortisTCI in July following the delayed rate increase originally scheduled for April. The new rates include the recovery of hurricane-related costs incurred in 2017. Overall, a busy yet constructive quarter on the regulatory front. This concludes my remarks, and I'll now turn the call back to Barry.
Thank you, Jocelyn. Our decentralized model where local teams have the authority to manage their businesses allows us to navigate through the pandemic with an acute focus on employee safety and reliable service. Lastly, with 93% of our assets dedicated to energy delivery, we have a light carbon footprint and a strong sustainability profile. And now with the ambitious emission reduction targets set at TEP and FortisBC, our teams have an opportunity to advance a low-carbon future for generations to come, all while supporting our growth strategy over the long run. This concludes my remarks. 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.
[Operator Instructions] Our first question comes from Robert Kwan from RBC Capital Markets.
The first question I've got is just asking as we head into the elections in the U.S. and recognizing it's going to be hard to be specific, but if you have any directional commentary on assuming under the current administration, status quo, but do you have any additional comments, that would be helpful. But if there is a change in administration, 2 things, I'd be interested in your comments, one, the impact or potential impact of retracing tax reform as well as initiatives to reduce carbon emissions further? And what you think that could mean for you for accelerated spending? And if you want to tie that to the TEP, IRP, that would be helpful as well.
Well thank you, Robert. And it is election season in America. So clearly, lots of chatter about that. And maybe we'll focus on, if there is a switch in the government, clearly, I think some of the things that we have been pursuing, whether it is in terms of the move to a cleaner energy future, I guess, in Arizona or ITC's focus on sort of renewable energy and hooking up the wind in the Midwest. I think all of that really is supported by the Democrats. And I do believe that, that will continue to be a positive backdrop for Fortis going forward. Clearly, a reversal of the tax reductions would see an increase in tax rates, and that's an increase in cost for delivery of our services to our customers. We would expect that our regulators would allow those costs to be passed on to our customers, like when we passed on the reduction in tax rates. I do believe that for holding companies like Fortis who have incurred some debt to acquire businesses in the U.S., it's sort of funny, but a higher tax rate actually is a positive from an EPS perspective because our interest costs are deductible at higher tax rates. So we did get a negative hit when tax rates got reduced, there would be a positive contribution to EPS if tax rates rose as well I think our cash flows as a business would improve as we're not really expected to be tax payable for a number of years. So increases in tax collections from customers would contribute to our annual cash flows and bolster our credit metrics on a go-forward basis. So I think we're in a good spot no matter what really happens with the upcoming elections.
And just as it relates to the impact of prior tax reform, I believe the last disclosure you gave was a roughly 3% negative impact to earnings and then cash flow, while you didn't specify a number. I think Moody's at that point was 150 to 250 basis point negative impact on the cash flow to debt metric, and you expect it to be well inside of that. Can you just talk about what actually unfolded, in terms of how you've seen that impact your business?
Robert, this is Jocelyn. Yes. So with U.S. tax reform, we did see a couple of pennies on our EPS with U.S. tax reform. And for cash, it was a little over 100 basis points, I would say, to our CFO to debt metrics. So Barry is right. We would expect everything else being equal, and if the legislation looks similar to the legislation of U.S. tax reform, then you really would think that it would just be simply a reversal of that.
Got it. If I can just finish with the question as it also relates somewhat to tax. You booked a reversal on the anti-hybrid in the quarter. My question actually though is more about I guess, tying it a little bit back to tax reform. When that was introduced as well as some of the BEPS pronouncements, I think the commentary from you was that none of that, you expect it to be material to your existing cross-border structures. I'm just wondering with the booking in this quarter, has your view changed on any of that with in terms of the existing structures of the ability to use structures on the cross-border side going forward?
No, Robert, I would say our view is still the same. It's not expected to be material to Fortis.
Your next question will come from Rob Hope from Scotiabank.
Just a question on the IRP in Tucson. When do you think you could see CapEx starting to ramp up there? And are you viewing that as potentially something you could add to your backlog at the upcoming Investor Day? And does this kind of backfill the rate base growth into the middle part of the decade?
So Rob, I'm going to let David Hutchens respond to that, but I will say, we're just in the early innings, really. We filed the IRP, and we've got to work through some processes with our regulator in Arizona on this and make sure that we have support for the plans. I think it's a little early, but David, maybe you can offer your thoughts.
Yes, Rob, good to hear from you this morning. You're spot on, Barry. What we're looking at now is trying to lay in all of the projects that we would need that 2,400 megawatts of renewables in the form of wind and solar and obviously, the battery storage as well. And all of these projects also come with transmission interconnections and other investments that we need to make on our side. So we're in the process of laying out a time line. I would note that a lot of these investments are back-end loaded sort of at years 5 through 15, but we do have some that we're trying to lay in, in the next 5 years. So you will definitely hear more about that in the future as we build up that capital plan for the next 5 years and then have a good look out for that following 10.
All right. And then a follow-up on Robert's question on tax reform. As you look forward to the kind of the next round of rate filings, could you see yourself potentially delay some of them just to ensure that you can capture the next phase of tax reform, if it does come to bear rather than wait to see a bit on the standalone proceeding?
I think, Rob, we don't really have many filings in front of us, when you think about in the next, say, 12 months. We just -- we're completing a case in Arizona. We just got a Canadian context, obviously, the case in BC done. Central Hudson is -- will be filing a case shortly. I don't think that's going to be delayed for the next 3 years. So I don't see that affecting any of those schedules really. And because I think we're really -- in fact, we're probably entering a period of somewhat regulatory stability here for a little while now. So that's a good place to be because it will give us some time to sort of figure out what this new tax plan is going to be, if there is a change in direction in the U.S. It's going to take some time. We're just -- just think about it, we're just now reporting on the final remnants of U.S. tax reform, and there's another presidential election underway, right? So it's taken us basically 3.5 years to get to this point right now. So these things take a while to figure out. And we're fortunate that we have, I think, a good runway now to digest this if it does come.
Our next question comes from Ryan Greenwald from Bank of America.
Can you just talk a little bit more about your confidence on getting the rate case done at UNS this year? And is the settlement definitely off the table at this point?
So David, this one's on you, man.
Yes. Yes, we are confident that we will get a decision by year-end. In fact, we're this week wrapping up the last bit of written testimony that goes in, which is our reply briefs, that's filed next week. Then the judge, the ALJ has the entire docket before her to be able to get a recommended opinion and order written up. And so we see ample time line to get a decision later this year. As far as the settlement, it's -- we're done with the process. So it would make sense to backtrack and try trading off different pieces at this point.
Got it. And then can you guys just provide a bit more color on load trends so far in July and given the evolving situation of the pandemic and what you're seeing in Arizona and the Caribbean specifically?
So I would say, Ryan, it's pretty similar to what we experienced in Q2. We have continued with some warm weather in Arizona. I think, David, it's like 108 there today. I think you mentioned. So and we're not really seeing any pickup in the Caribbean. They have started to open up the borders in the Caribbean and allowing tourists to come in. But in reality, there's not very many people traveling at this point in time. So I think we're going to be dealing with the slowdown in the Caribbean for -- probably for the rest of this year. We might get a gradual pickup as we head to the end of the year, but nothing that's significant, I don't think.
Next question comes from Mark Jarvi from CIBC Capital Markets.
Maybe just a few questions on the BCU decision so far, and I know it's not finalized yet, but maybe any commentary in terms of, I think there's some in the filings around revisiting 2023, 2024, CapEx and certain investments. Just maybe give us some context on what that is and if there's anything around the earnings sharing mechanism or going in on costs that you guys feel you need to sort of fight around.
Sorry, Mark, the first priority, what you said, we lost it. Was it related to FortisBC that you're describing?
Yes, that's correct. I think there were some comments on the decision around CapEx for 2023 and 2024. And I think you guys have to resubmit around that. I'm just wondering what that could mean for rate base growth in those utilities.
Roger, can you offer your thoughts on that?
Yes. Sure. Can you hear me okay, Mark?
Yes.
Yes. So the MRP decision on capital, unlike the previous PBR, where we are capital estimated on formula based off of the base here. We see a change here where we forecast what we call our base capital, which is all capital not requiring CPCN and instead of trying to forecast over 5 years, we've got approval for our base capital for the first 3 years and then come back and reforecast years 4 and 5. And that ensures that we're not going to have a situation where we're outside of forecast either above or below, which gives us a bit more clarity, I think, as we move through what we call our base capital. It doesn't impact the major out projects that require a CPCN though.
Okay. And anything around the sharing mechanism and in terms of the incentive rate making that surprised you or is it largely within the scope of you sharing the outcome.
No surprise on the earnings sharing mechanism. That's more or less consistent and that is the incentive to the extent that we share savings with our customers. I think a couple of surprises in the application. We had just come out of a performance-based rate making structure for both utilities. We've delivered significant savings out of those constructs. We had previously dealt with a 1% -- 1.03% on electric and 1.1% on gas might headed backwards, but basically 1% productivity improvement factor annually. So we were expecting no productivity improvement factor and said we got a 0.5%. Not insignificant, but something we can manage. But that was a bit of a surprise having come out with PBR, but no concerns with the mechanism itself. It's going to work as we expected, similar to the last PBR.
Okay. That's great. And then kind of going back to potentially change administration, you had talked about time lines, IRP and GDP. But maybe just anything incremental on ITC, whether it's continued support, whether it's faster permitting for transmission, if it's support for more renewables and the requirement for transmission. And just in terms of how quick you think that would take to roll out from positively impacting ITC's investment opportunities?
Well Mark, great question on ITC. And I will have to say ITC continues to perform very well for us. And when I think about our Fortis footprint of where we -- where our investments are, I'm so happy that we own the largest independent owner of transmission in the United States. That footprint that ITC owns is very, very valuable, and it's right in the sweet spot of everything that's happening in our sector as we push for more clean energy, a more resilient grid. So we're really looking forward to what ITC is going to be doing for Fortis over the next number of years. Linda, maybe you can offer some detailed comments on how you see sort of the change in -- possible change in government and ITC's evolution over the next few years.
Yes. Thanks, Barry. And I think you're spot on, Barry, but I would just say this, we have been very fortunate in this regardless of the -- sort of the administration and the controlling party. We consistently had particularly from FERC a strong views towards the need for continued investment in transmission. And obviously, times today and as we look out into the future in order to continue to facilitate the transition to more renewables, I think we feel pretty comfortable and confident that regardless of it's a Democratic or Republican administration, we see the we have continued to support and need for that. I would say, however, we have seen recently, just in terms of some of the current policy initiatives and in sort of draft legislation, circulating in Congress, whether it be the clean acts or the Moving Forward Act to find a select support. We're starting to see the incorporation of concepts around the need for regional or interregional transmission in order to realize sort of this future state of renewables. And so from a macro perspective, I think this is probably one of the first times we have seen where there is actually federal perspective. I think we should say it's probably at this point coming out of more of the Democrat side. But certainly, indications that in terms of any future environmental legislation that it definitely appears that they want some language included around high voltage transmission. And so from that perspective, I think that's constructive, certainly for us and our business, and as Barry said, where we're strategically located. And so we do see that as constructive and positive. But I don't think, regardless of Democrats or Republicans, I think we still -- will we see on both sides of the aisle, a strong interest in need recognition.
Okay. And then maybe a last question around Alberta and those transmission assets. Anything we can infer from the filings around things around the tax implications that point towards it going one way or the other that we'll be transferring those to AltaLink or that you guys still feel like you can put on those assets?
Well I think we're still -- I'm going to have Michael weigh in here, but we're still of the view that this should not happen. And the order did not -- wasn't based on the appropriate evidence, and we supplemented our filings with more evidence. Hopefully, the commission is interesting. I think all the 5 commissioners that were involved in the original decision, none of them are left at the commission at this point in time. So that may be a wrinkle as how this goes forward. But we'll -- we've done our filing, and we're hopeful that we've made our case. Michael, maybe you can add some color.
Spot on, Barry. The only other thing I would add is that the record in the proceeding schedule is now expected to close mid-September, setting up for a decision in late 2020. So just continue to file the additional tax evidence with respect to the contribution and awaiting commission action.
Okay. We'll keep an eye on that.
And your next question comes from Matthew Weekes from Industrial Alliance Securities.
Can you guys hear me okay?
Perfectly, Matthew.
Great. So I just have one question regarding the green bond issuance in FortisBC, and that was positive in terms of achieving a low cost of capital and reinforcing the investment plan for sustainable energy. Is this something that you're seeing more interest in, in the market going forward? And is this something you'll be looking at doing more of and possibly in other jurisdictions as well?
Yes. There's more interest. And yes, we'll do more of it. And I'm just so damn proud that Roger and his team could have issued the lowest price piece of long-dated corporate debt in Canadian history. Like can you imagine, that's just incredible. I think 30-year debt a bullet with 2.54% interest rate. Like that is just -- that's incredible. And so yes, we'll definitely look at doing more of this, not just in Canada, in the U.S. as well.
[Operator Instructions] Your next question comes from Linda Ezergailis from TD Securities.
I'm wondering if you can give us some more color around the FERC notice of proposed rule-making around transmission incentives. Can you maybe provide some more context around notable comments from the various stakeholders, including industry groups in Fortis? And how might we think of the timing of resolving this and the bookends of what might be possible as an outcome?
Okay. Linda, you want to -- Linda to Linda.
Sure. Thanks, Barry, and thanks, Linda, for the question. Yes, so I think people are probably familiar. And I think as Jocelyn mentioned, we did -- we as well as all the other stakeholder parties did file comments on the NOI -- or I'm sorry, on the NOPR back on July 1. We then subsequently filed some side comments on July 15. In terms of our primary comments, obviously, we offered comments supporting some of the proposals that the commission had identified when they issued NOPR. And so those were around obviously increasing the RTO participation incentive adder to 100 basis points. Obviously, we fully supported that and it's a strong case as to why. We also offered additional commentary around the need to create new incentives around driving economic viability benefits. So more project-specific incentives. We also encourage them to continue to redeem sort of what we call some of the non-ROE incentive. So that would be around quite rate base a plant, those types of things and then really made a strong push for creating incentives around the context of certain transmission technologies by room to security investments and those sorts of concepts or ideas. And so I think as most of you know, the commission in their NOPR indicated that they were willing to provide up to 250 basis points of additional incentives and essentially signaled that they were no -- at least they were no longer sort of, if you will, containing the incentives up to the upper end of the ROE net. So we really view the NOPR on incentives as a real opportunity to try to obtain additional incentives that are really going to drive benefits for customers. That was what I think was sort of the biggest shift in sort of how FERC is thinking about the NOI, and that is to sort of align the incentives with the actual benefits that are included from any type of investment or projects. So we're really encouraged by the commission's proposal. I would say it was a pretty active docket in pretty active case in terms of the parties that filed comments and those varied from state commissions, industrial user groups, consumer groups as well as a number of other industry and transmission owning entities. And so there was, I would say, a wide variance in the comments, but we remain hopeful that FERC will take action before the end of the year. We are encouraged. I think a quick action that commission took in terms of their time line for when they want to comment. And so we are hopeful that we may see some sort of decision prior to the end of the year. However, I would note, there is no time line or requirement for action. And so we are somewhat -- I guess, the question of FERC, I guess, can come to [indiscernible] perspective in issue an order, but we remain helpful.
Thank you for the context. On a slightly separate note, maybe from a natural gas distribution perspective, would it be possible to get an update on how you're evolving some of the initial initiatives on renewable natural gas and potentially, are you exploring opportunities related to green hydrogen? And anything on that front would be appreciated.
Thank you, Linda. I have to say there's so many exciting things going on in our British Columbia business. And this sort of push for more renewable gas is definitely one of those and exploring the hydrogen opportunity as well. So Roger, maybe you can give them -- Linda a little more details around some of the things that have been going on in the last little while.
Thank Barry. Thanks for the question, Linda. Short answer is yes. In BC, we've been advancing specifically renewable natural gas, the traditional landfill or agricultural waste renewal natural gas that we put into our system. We've just recently, over the last number of months, gotten approval for a number of new contracts for supply. We were successful in getting a couple of out of province contracts approved, which is a good sign. And we just started -- we just signed an agreement for our first bio -- woody biomass project in BC, which is significant because if we can get scale RNG woody biomass in the BC context, that's a very large supply basin. And so that one is we're watching carefully. We have another number of projects that are in the hopper that will increase RNG supply. On the hydrogen side, we are part of working teams with other natural gas utilities in the Canadian context, who are looking at both green and blue hydrogen. And we're looking at hydrogen in a couple of different avenues, one is in closed-loop systems for large industrial sites to displace natural gas use. We're also looking at blending of natural gas directly into the system, which is happening in other jurisdictions. So we see a significant role of what we're calling drop in fuels or renewable gases both traditional RNG as well as hydrogen over the next number of years.
Your next question comes from David Quezada from Raymond James.
Maybe a first question here. Just a follow-up on the IRP in Arizona. I think David mentioned that you'll need transmission, obviously, to complement the renewables that you intend to develop there. Are you able to just say -- give us some color around the magnitude of the transmission investment that may be required there as you move from kind of that centralized coal to wherever the renewables might be cited?
Well I probably would give you a number, but it'd be wrong. So David, David Hutchens. I know that it's not small, but I know it's probably not in the billions, but in the hundreds of millions over the plan. So David, any thoughts you could give.
Yes. David, this is David Hutchens. Yes, it's hard to estimate that now because right now, we're not obviously sure where we're going to put all the renewables, where they're going to come from, et cetera. We're going to try to use as much of our existing transmission system as possible to bring in wind and solar the lines where we're shutting down coal plants and maybe even focus on developing those renewable projects up there where we're shutting down coal plants in those communities. It's mostly -- I would say it's mostly interconnection dollars at this point. There is the ability to get more wind out of the Oso Grande Project, and so that would require some additional transmission investments that we've been talking about South line, mainly. So it's really too early to tell at this point, but you can bet we're going to be looking at that very carefully over the next -- balance of this year and then as we go forward.
And Dave, just a reminder that our transmission in Arizona is also regulated by FERC as well. So...
Great. That's good color. And then maybe just 1 more follow-up there. Just with all the storage capacity you're contemplating there, I'm wondering does that all make sense from a cost perspective with current technology? Or are you kind of baking in some kind of technological improvement as you roll it out?
We do have -- in our IRP process, we do have a technology curve baked in that reduces those prices over time, which is one of the main reasons you'll see storage a little bit more back-loaded, but that also has to do with when we're shutting down our coal plants as well. But it's not a really steep curve. It's not super aggressive. So we think we're right in that right kind of fair way of where the technology will actually go. And I think that's really important from our integrated resource plan perspective because this is all built on realistic time lines, prices, et cetera, and technology that we know today and is betting on some brand-new technology coming in and helping us out. So that's a big point there.
Your next question comes from Ryan Greenwald from Bank of America.
Appreciate the follow-up. Are you guys able to provide more granular color and break out specific impact for the quarter for commercial and then separately for industrial in Arizona?
I don't think so.
As there are no further questions in queue, I would like to turn the call back over to Stephanie Amaimo for closing remarks.
Thank you, Michelle. We have nothing further at this time. Thank you for participating in our second quarter 2020 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 now disconnect.