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Good morning, ladies and gentlemen. Thank you for standing by. My name is Michelle, and I will be your conference operator today. Welcome to the Fortis Q3 2022 Earnings and 5-year Capital Outlook 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' Third Quarter 2022 Results and 5-Year Capital Outlook Conference Call. I'm joined by David Hutchens, President and CEO; 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 third quarter 2022 MD&A. Also, unless otherwise specified, all financial information referenced is in Canadian dollars. With that, I will turn the call over to David.
Thank you, and good morning, everyone. Before we get to the financial highlights, I would like to take a minute to discuss the severe weather events experienced in the quarter. In late September, 3 of our communities were affected by Hurricane Fiona. In the Caribbean, it hit Turks and Caicos as a Category 3 storm, impacting several of the islands. However, we were able to restore service quickly following the storm due in large part to the prior investments made to strengthen the grid after Hurricane Irma in 2017. In Atlantic Canada, Fiona was one of the worst storms in its history. The small community of Port aux Basques on the southwest coast of Newfoundland and Labrador took a direct and devastating blow from the hurricane as it swept several homes into the sea and severely damaged many others. On Prince Edward Island, tidal surges and high winds resulted in extensive damage across the island that left nearly all 86,000 customers without power immediately after the storm and, unfortunately, some of our customers for an extended period of time. In the wake of an historic storm like Fiona, it is important to recognize the breadth of partners that come together to offer aid to our customers, communities and employees during such a difficult time. On behalf of Fortis, I would like to give our sincerest thanks to the Canadian government, the governments of Prince Edward Island, Newfoundland and Labrador, Turks and Caicos and our industry partners and all the local people on the ground who pitched in to help across these jurisdictions. And a special thank you to our customers for their assistance and patience during the restorations. Lastly, I would like to thank the dedicated people from our utilities in the U.S. and Canada who assisted in the restoration efforts. Their commitment to the safety of our customers, communities and each other is unmatched. Now to touch on the third quarter highlights. Financially, third quarter adjusted EPS was $0.71, increasing $0.07 compared to the third quarter last year. On a year-to-date basis, adjusted EPS was $2.06, representing 5% growth over last year. Jocelyn will provide more details on this later. Through September, our utilities invested $2.9 billion in our systems, keeping us on track with our 2022 capital budget plan of $4 billion. And today, we are pleased to unveil our $22.3 billion 5-year capital plan, our largest to date. During the quarter, our Board of Directors increased the fourth quarter dividend by 5.6%. And today, we are announcing 4% to 6% annual dividend growth guidance and extending it 2 years through 2027. Turning to Slide 5, the new 5-year capital plan reflects a $2.3 billion increase compared to the prior plan, driven by growth at our utilities and a higher foreign exchange rate. Key drivers of the growth include the addition of MISO long-range transmission plan projects at ITC that I will speak to shortly, new renewable generation and energy storage investments at UNS Energy to support its exit from coal and investments in distribution reliability and additional capacity to support customer growth across our utilities. Consolidated rate base is expected to increase by $12 billion, from approximately $34 billion in 2022 to over $46 billion in 2027, supporting average annual [Audio Gap] through 2027. Customer affordability remained a top priority as we developed this plan. We prioritized capital investments that provide offsetting cost savings that flow through to our customers. Examples of such investments include renewable energy in Arizona, which translates into fuel and operating cost savings as coal plants are shut down, or investments in field technology like advanced metering and grid sensors that reduce operating costs while also improving reliability and customer service. Our utilities are also continuing to manage operating costs by finding efficiencies through innovation and process improvements. And lastly, as we have seen higher prices in the natural gas and electricity markets, we have increased our outreach on energy efficiency and assistance programs to help our customers manage their bills. We are highly confident that we can execute this capital plan. 83% of the expenditures are relatively small, routine projects. The remaining 17% that we categorize as large, which is over $200 million, are also straightforward infrastructure projects. From a geographic perspective, we expect 55% to be invested in the United States, 41% in Canada and the remaining 4% in the Caribbean. Similar to previous capital plans, the vast majority of investments are concentrated at our 3 largest utilities, ITC, FortisBC and UNS Energy, representing 68% of the total plan. With $5.8 billion planned at ITC, investments are focused on transmission infrastructure that ensures reliability, resiliency and grid security. It includes approximately USD 700 million associated with MISO's long-range transmission plan. As you will recall, 6 of the 18 projects in Tranche 1 are located in ITC service territory, including Michigan and Iowa, where rights of first refusal provisions exist for incumbent transmission owners. In total, ITC estimates investments of approximately USD 1.4 billion to USD 1.8 billion through 2030 under Tranche 1. FortisBC plans to invest $4.6 billion in reliability and integrity projects, liquefied natural gas infrastructure, advanced metering and renewable gas projects. At UNS Energy, investments of $4.6 billion are planned over the next 5 years, including $1.2 billion for renewable generation and storage to support Tucson Electric Power's integrated resource plan. Other investments include transmission and distribution investments to modernize the grid and ensure resiliency. Turning to Slide 8, the plan includes $5.9 billion for investments that directly support cleaner energy. This includes $2.7 billion for investments which deliver renewables to the grid, primarily at ITC, and $1.8 billion mainly related to renewable generation and storage investments in Arizona and the Caribbean. Additionally, $1.4 billion is planned for liquefied natural gas infrastructure in British Columbia as well as cleaner fuel solutions such as renewable natural gas and hydrogen. These investments keep us on track to achieve our target to reduce Scope 1 emissions, greenhouse gas emissions, 75% by 2035. It also supports our 2050 net zero target focused on decarbonizing our already low emissions profile over the long run while preserving customer reliability and affordability. Beyond the base plan, our teams are focused on incremental opportunities on several fronts. First, it is important to note we have not included any incremental investments related to the recently passed Inflation Reduction Act. With incentives and tax credits encouraging investments in clean energy, storage, electric vehicles and manufacturing, the Inflation Reduction Act will be a catalyst for a faster, more affordable transition to a cleaner energy future. We expect it will drive additional investments under the MISO long-range transmission plan. MISO will begin studying the next phase of the long-range transmission plan, which is Tranche 2, with the aim of identifying new projects in late 2023. The Inflation Reduction Act could also accelerate TEP's clean energy transition by reducing the cost of new renewables and providing funding to aid the communities impacted by the exit from fossil fuels. In aggregate, we estimate additional investments of approximately USD 2 billion to USD 4 billion through 2035 will be required to implement TEP's integrated resource plan. Furthermore, with more extreme weather events expected similar to the recent hurricanes, we have heightened our focus on climate adaptation. Our Fortis operating group is evaluating grid resiliency and storm-hardening requirements under various climate scenarios and geographies to enhance the readiness of our systems. Lastly, our team in British Columbia is developing renewable fuel solutions to support the province's CleanBC road map aimed at lowering emissions 40% by 2030, while also working to provide the international community with Canadian LNG as a more secure and cleaner fuel option. As I mentioned, last month our Board of Directors declared a fourth quarter dividend of $0.565, representing a 5.6% increase. This brings our dividend track record to 49 consecutive years of increases, a record of which we are very proud. With our strong dividend track record and regulated growth strategy, we are announcing 4% to 6% annual dividend growth guidance through 2027. With our low-risk rate base growth fundamentals, this guidance extends visibility on dividend increases through 2027, provides flexibility to fund more capital internally and is expected to reduce our dividend payout ratio to more historic norms over time. Overall, we expect to deliver stable and compelling returns to our shareholders over the long term. Now I will turn the call over to Jocelyn for an update on our third quarter financial results.
Thank you, David, and good morning, everyone. Turning to Slide 12, reported earnings for the third quarter of 2022 were $326 million, or $0.68 per common share, $0.05 higher than the third quarter of 2021. On a year-to-date basis, reported earnings were $960 million, or $2.01 per common share, $0.09 higher than last year. Reported earnings include timing difference related to mark-to-market accounting of natural gas derivatives at Aitken Creek, onetime costs associated with the suspension of the Lake Erie Connector project and the revaluation of deferred income taxes related to a change in the Iowa state corporate tax rate. The following discussion on our financial results for the quarter excludes these items. We delivered adjusted net earnings of $341 million, or $0.71 per common share, in the third quarter. This is $0.07 higher than the third quarter of 2021. We continue to see rate base growth across our utilities, supported by capital investments of nearly $3 billion year-to-date. Higher earnings in Arizona and New York, lower stock-based compensation and increased production in Belize were also key drivers of the quarter-over-quarter increase. Year-to-date September, we delivered adjusted net earnings of $982 million, or $2.06 per common share, $0.10 higher than the same period in 2021, representing 5% growth. The waterfall chart on Slide 14 highlights the EPS drivers for the quarter by segment. At our U.S. electric and gas utilities, EPS increased by $0.08 for the quarter, with UNS contributing $0.05 and Central Hudson contributing $0.03. In Arizona, warmer weather and higher transmission revenue were partially offset by higher costs associated with rate base growth not yet included in customer rates due to the historical test year. And as expected, third quarter earnings in Arizona were favorably impacted by the recognition of production tax credits related to the Oso Grande Wind generating facility. Central Hudson's EPS contribution was mainly driven by rate base growth as well as the timing of operating cost and implementation of new rates in 2021. New rates did not become effective until the fourth quarter of last year, favorably impacting quarter-over-quarter EPS by $0.01. Our Energy Infrastructure segment contributed a $0.02 EPS increase for the quarter, driven by higher hydroelectric production in Belize, which was up 60% from last year, and higher earnings at Aitkin Creek. At ITC, EPS increased by $0.01 for the quarter. Rate base growth and lower stock-based compensation costs were partially offset by a favorable adjustment related to interest rate swaps recognized in the third quarter of 2021. A higher U.S. dollar to Canadian dollar foreign exchange rate favorably impacted the translation of our U.S.-denominated earnings, which increased quarterly EPS by approximately $0.02. And next, there were a number of items in the corporate segment, driven by broader market volatility, that unfavorably impacted this segment by $0.03. First, mark-to-market losses on total return swaps less stock-based compensation expense contributed to a $0.01 decrease in EPS. I would note that this was more than offset by lower stock-based compensation in other segments, particularly ITC that I mentioned earlier. And in corporate, we also had mark-to-market losses on foreign exchange contracts, which impacted the segment by $0.02 for the quarter. The remaining decrease in EPS at corporate is largely driven by higher finance charges. And lastly, as expected with our Dividend Reinvestment Plan, EPS decreased by $0.01 due to higher weighted-average shares outstanding. Year-to-date, EPS was impacted by many of the same drivers as the quarter. In addition, rate base growth at our Western Canadian utilities and higher wholesale sales at UNS favorably contributed to the results. However, losses on retirement assets at UNS and ITC reduced year-to-date EPS by approximately $0.05, and higher costs associated with the implementation of a new customer information system at Central Hudson also unfavorably impacted year-to-date results. I would note that Central Hudson did not incur any significant additional direct costs beyond the $0.03 EPS impact recorded through to the end of June. Turning now to our funding plan for our new 5-year capital plan. As you can see from the pie chart, the bulk of our new 5-year capital plan is expected to be funded from cash from operations and net debt primarily issued at our regulated utilities, with the remaining funding coming from our Dividend Reinvestment Plan. Overall, our funding plan is largely consistent with last year's plan and does not require any discrete equity funding through 2027. Or capital structure is expected to remain steady over the planning period. And additionally, our dividend growth guidance range provides incremental funding flexibility. We continue to take a conservative approach to running our business and our funding plan. Coupled with Fortis' low business risk profile, our funding plan positions us comfortably within our existing investment-grade credit ratings as we execute on our capital plan and pursue incremental growth opportunities. In particular, our Moody's CFO-to-debt and S&P FFO-to-debt metrics are each expected to average approximately 12% through 2027. While we continue to await final regulations, the alternative minimum tax, or AMT, is not expected to have a significant impact on our credit metrics over the planning period, with limited near-term impacts of less than 20 basis points on our CFO-to-debt metrics. Turning to our regulatory update. At ITC, in August, the D.C. Circuit Court of Appeals issued a decision vacating and remanding FERC's most recent MISO-based ROE methodology. You might recall, in May 2020, FERC issued an order establishing a MISO base ROE of 10.02%, which resulted in an ROE for ITC of 10.77%, including incentive adders. The D.C. Circuit Court concluded that FERC failed to offer an explanation for its decision to reintroduce the risk premium model that resulted in a 14-basis points increase in the MISO base ROE reflected in the 10.77% all-in ROE that ITC continues to use today. Although we cannot predict the timing and nature of any FERC action, for every 10 basis points change in ROE at ITC impacts Fortis' annual EPS by approximately $0.01. While no change in the quarter for ITC, we also await a final rule from FERC on the supplemental NOPR on transmission incentives and action on the ITC Midwest capital structure complaint. The timing and outcome of both proceedings remain unknown. In July, the Alberta Utilities Commission issued a decision on FortisAlberta's 2023 Cost of Service rebasing application. In the decision, which is expected to form the basis for going-in rates for the third PBR term starting in 2024, the AUC largely accepted the forecast methodology and O&M forecast submitted. FortisAlberta refiled its 2023 revenue requirement last month, reflecting a 5% increase. A final decision on the filing is expected later this year. And lastly, we have a number of ongoing regulatory proceedings which we expect to conclude over the next 24 months; particularly, the TEP rate case and generic cost of capital proceeding in British Columbia. Given some of the broader market volatility we've experienced this year, I wanted to touch on some of the potential implications for Fortis, starting with the strengthening of the U.S. dollar. Approximately 2/3 of our earnings and capital investments are in U.S. dollars. With the release of our new capital plan, we have updated our assumed foreign exchange rate using $1.3. As you may recall, every $0.05 change in the U.S. dollar to Canadian dollar exchange rate impacts annual EPS by approximately $0.06, on average, and would result in an approximate $500 million change in our 5-year capital plan. As most of our regulated utilities have regulatory mechanisms protecting against fluctuations in interest rates as well as periodic rebasing of rates, our primary exposure to rising rates pertains to nonregulated debt issuances and credit facility borrowings at Fortis Inc. and ITC Holdings. Earlier this year, Fortis Inc. refinanced $500 million in debt due in 2023, and ITC entered into notional USD 450 million of interest rate swaps that mitigated refinancing risk associated with debt that was due in November. From a near-term refinancing perspective, we have approximately USD 400 million in nonregulated debt maturing on average annually through 2025 at a weighted-average rate of about 4%. On inflation, our 5-year capital plan assumes inflation levels return to historical averages starting in 2025. While it's not easy to quantify the impact of inflation plan-over-plan, given scope changes, timing of projects and contract negotiations, we estimate inflation impacted the current plan by approximately $300 million over the 5-year period. And lastly, given the ongoing regulatory proceedings, we have also included a sensitivity on this slide for changes in allowed returns and equity ratios at our largest utilities. That concludes my remarks. I will now turn the call back to David.
Thank you, Jocelyn. At our core, we are a diversified North American utility company with strong fundamentals and a straightforward growth strategy. We are leveraging our regulated energy delivery portfolio, operating expertise, strong governance and talented people to deliver the results that make us a premium utility to our stakeholders. For our customers, we are focused on delivering a cleaner energy future with safety, reliability, resiliency and affordability top of mind. And for our shareholders, we have a low-risk, compelling return outlook supported by our capital plan and dividend growth guidance through 2027. I will now turn the call back over to Stephanie.
Thank you, David. This concludes the presentation. At this time, we'd like to open the call to address questions from the investment community.
[Operator Instructions] Your first question comes from Maurice Choy of RBC.
Thank you for all the new disclosures that you've put out. In trying times like this, I really appreciate the macro assumptions that you have. So thank you for that. I wanted to start with the dividend policy. Would you please elaborate how you landed at the 4% and 6% levels as your lower and upper bounds? I assume the 6% simply matched the previous policy. So what scenarios, be that a payout ratio, otherwise, which would drive a decision to be 4% over the next, say, 1 or 2 years?
Thanks, Maurice, and good to hear from you this morning. So the range is basically developed by us as we look forward at our forecast and looking at the things that we want to address from both an earnings growth perspective and a dividend payout ratio perspective. When you look at our very strong rate base growth that we have, as laid out by this capital plan, we see the ability for us to manage this dividend payout ratio of 4% to 6% and bring our payout ratio down over time. And so that's really what we were shooting for, is to have that flexibility within that range. As you know, the markets are absolutely volatile these days, and having that flexibility for funding gives us that additional room in that 2%. Obviously, having a single point is very difficult to manage around, as you may guess, and we think a range is very appropriate.
And maybe just to follow on to that, like, I guess, if you look at your peers here in Canada, some of the payout ratios are north of 70%, whereas the U.S. peers are below that. How do you see where you kind of want the payout ratio to be over the long term? Or is it somewhere in the middle between the 2, is the sweet spot?
I knew that would be your follow-up, Maurice. We do want to decrease our payout ratio. That's clear. We haven't really put out a target. If you look at our more historical levels over the past even 5 to 10 years, we've ranged everywhere from mid-60s to upper 70s. And we just think it's right and prudent for us to look at bringing that payout ratio down to give more headroom over time. And so we don't have a definite goal in mind. This is something that we talk with our board about every year. So we have the dividend growth range that we put out, but we have yet to give an official payout ratio band that we want to be in. But again, discussed every year. And if we get more clarity on that next year when we have these conversations, we'll surely [Audio Gap], just the assumption of us trying to push that down over time is the goal. And I would say, you did mention payout ratios. And yes, the Canadian utilities and our peers have a higher payout ratio, some of them higher than ours, and the U.S. is lower. We recognize that, but we have to do what we think is right and best for our own company, which is basically half Canadian, half U.S.
Understood. And my second question, I'm sure you've heard about what happened in Nova Scotia, and a nonfuel rate increase cap there. Maybe your thoughts about what you think happened in the province from a utility standpoint and how that may or may not relate to the various regulatory matters and government relations that you have both north and south of the border?
So I obviously don't know details of those regulatory relationships or the history there. But know that there is a lot of history in every jurisdiction. And every jurisdiction, obviously, is different. And there's different structures, there's different regulatory structures, there's different regulators and, obviously, governments and how they interact and how the utility fits into that relationship and how they interact with each one of those. I can't comment on why that's happening in Nova Scotia. I don't see similar things like that happening across our jurisdictions, whether they be in Canada or the U.S. Some of our jurisdictions have obviously very different setups. Like ITC, obviously, has -- their main regulator is FERC. So that's a very different setup there. And then in Arizona, we actually have regulators who are elected and not appointed and are a fourth branch of government. So there's a lot of variations across jurisdictions. I can't imagine seeing any read-through from what's going on in Nova Scotia other than being a Nova Scotia-specific issue.
Your next question comes from Rob Hope of Scotiabank.
First question is on the capital plan. So we've seen an increase in the capital plan, including a step-up in 2023. There's also some other factors going on, including kind of fuel recoveries. How did you get to keeping the financing outlook unchanged? And how are you thinking about your near-term credit metrics? Could they soften a little bit here and improve through the term? And what other options did you look at?
Thank you for the question, Rob. When we looked at the financing -- there is a bit of a tick up in the capital plan-over-plan in 2023, but after that, it's really more weighted towards the tail end of the 5-year capital plan, which we had room built in the prior plan around that. So the DRIP could easily handle how the new capital plan was coming in annually. So felt really comfortable over that. You're right, there were some near-term credit metric deterioration, I guess, and a lot of that was timing of recovery of regulatory assets. And we do see some short-term fluctuations in our credit metrics, depending on settlements that we have with regulators on how we're going to collect things, like the [ PPAC ] account in UNS Energy, which we extended from 12 months to 18 months. Those things just tend to put some pressure on metrics. But over the 5 years, we're feeling good with respect to our credit metrics. I have shared this plan with Moody's and S&P. And I would say no surprises coming out of those discussions and particularly around the funding plan.
All right. Appreciate the clarity. And then maybe more conceptually, with the rise in interest rates, how are you thinking about kind of cost of capital as well as allowed ROEs? You have the ability to go in -- the transmission owners have the ability to go in at any time at FERC, and you have 2 cost of capital process undergoing in Western Canada.
Rob, as you know, a good strong basis for those ROE conversations and calculations relate to interest rates. And as interest rates go up, we expect ROEs to follow them up as well. Now the direct correlation and time and lag and all that stuff is up for debate. But even very recently, we just saw Ontario increasing their ROEs there. So you'll see that kind of conversation across the board. So as we have general Cost of Capitals pending in both BC and Alberta as well as a rate case in Arizona, et cetera, there's definitely room for ROEs to go up. Again, timing, amounts, very hard to tell at this point.
Your next question comes from Linda Ezergailis of TD Securities.
I'm always curious to see what's not in your press releases. And specifically, I'm looking at your funding plan, and I'm just wondering if you can walk us through how asset sales or partial interest in some of your franchise sales or maybe JV partnerships over time were considered, or not, and at what point might you reconsider those when you look at your funding plan, especially given any sort of amplification of volatility in the capital markets potentially over the next 5 years and/or an increase to your capital plan for whatever reason.
Thanks, Linda. Yes, always looking, always paying attention, always evaluating. That's what we do when we develop any kind of capital plan. But none of that's in this one. So we'll continue to be looking going forward, but there's nothing like that is needed to fund this existing capital plan. And as we always talk about, if we have a big slug that's needed because we have a nice big project that comes in or advancing rate base growth, that's a great problem to have. That's where we then look and find the best way to fund capital at that time. So it's always a very current conversation.
And just as a follow-up to policy and regulatory considerations and how they evolve over time, customer affordability probably will become an increasing consideration, and it's always considered, I would say, in the jurisdictions in which you operate. And recognizing that you have a history, in my view, of innovative thinking on the regulatory front, how are you evolving your thoughts around accommodating any sort of increase in ROE, inflationary pressures on your capital plan, energy transition costs? What levers do you think could be used to manage customer affordability without compromising any of the other tenets of the regulatory compact, especially fair return?
That's a great question. I'm actually really glad you asked that, because that's really what we are focused on across all of our jurisdictions. Because as you know, this capital plan is a big capital plan, but that doesn't necessarily mean rates go up a lot, and I'll explain that here in a second. But obviously, there's been a lot of pressure on customers' bills related to electricity and natural gas commodity markets. We have very different business models across our subsidiaries, but in the end, all of them have some sort of piece of that, that goes through to their bills. And so we really focus on cost management and cost control, looking for efficiencies, looking for innovative ways to keep our OpEx down. But I think also, as importantly or perhaps more importantly is how we prioritize the capital in our planning cycles. We want to make sure that we prioritize capital that has either a low rate impact or might even offset some rate impact of other things. A prime example. As we shut down some coal plants, this is a great -- there's a great exhibit in our slide deck in the back that shows TEP's rate case. And when you look at how we are shutting down coal and removing a huge chunk of OpEx and fuel, that more than pays for the investments in renewables like wind and solar, and even accelerated depreciation that we have in that case. So it's those kind of capital plans that we have to look at. There's other things that we do that reduces OpEx as well. So not all of the -- a big capital plan doesn't read through as big rate increases, just is a big kind of caveat related to capital plan sizes. But also you have to look at it from a total bill perspective. That's what our customers see. And obviously, we don't necessarily control the commodity; we don't control the commodity in most cases across our subsidiaries. So we have to figure out how to mitigate the impacts of increases to our customers. And we do that over time through hedging. Several of our utilities of hedging programs. In Arizona, Tucson Electric Power and its other small utility are participants in the Energy Imbalance Market in California that helps us dispatch our resources more cost effectively, and those savings go right back to customers. We push energy efficiency and conservation messaging and programs to our customers. And as was mentioned in one of the prior answers, we also look at ways to help smooth out the impacts on our customers' bills by spreading out some of the recoveries of blips in electricity and natural gas markets and what they cause on our bills. And then, of course, lastly, we look for ways to get our customers federal dollars, et cetera, from a bill assistance perspective, it could be federal, state, provincial dollars, to make sure that they're getting all the help that they can and all the help that's out there and available. And then on top of that, the good news of the Inflation Reduction Act is that some of these investments that we're making are not going to be as expensive to our customers because of things like production tax credits, et cetera, that will then get passed through to our customers. So all of that is to say that we've got a very multi-pronged approach to make sure that we're growing our rate base, we're growing our earnings, we're growing our dividend. We're doing all those things, but we're trying to keep our rates as flat as possible as we do it.
Your next question comes from Ben Pham of BMO.
On your 5-year CapEx plan, you've mentioned focusing on investments that contain costs, and I noticed that your percent of clean energy investments have gone up as well. I was wondering, when you compiled this plan this year, how was it different than, say, last year's plan? Was the process different? Was there much more variables that you were dealing with? Was there a hint of more conservatism in a number? And any additional context would be helpful.
We didn't change the basics. We still -- we have always prioritized capital plans, like I mentioned. Just it wasn't something that was out there being discussed basically in the context of bills and rate increases, et cetera. That's always been part of our subsidiaries' roles. These are plans that are rolled up on a subsidiary-by-subsidiary perspective that then rolls into an overall capital plan. So we have many discussions with those subsidiaries, with the individual utilities looking at those capital plans. Their own boards review them. So there's nothing that's changed, other than every year looking at new projects, looking at the timing, looking at costs related to projects, re-estimating them, et cetera. But there's nothing, quote-unquote, like really new here.
Okay. Got it. And was there any change in the RNG component? I know it's generally quite small in the past. Was it -- did it move up a bit?
Research and development?
Renewable natural gas.
Oh, RNG. Sorry. I thought you said R&D. And I was, like, where did you get that line item? And I was looking quickly at Jocelyn. So renewable natural gas, yes, that's still a very small component of BC's capital plan.
Okay. Got it. And maybe one for Jocelyn. I know you mentioned the 12%, and you've gotten there. And it looks like you hit your HoldCo debt percentages. I'm wondering, though, in this environment we're in, doesn't it make more sense to be maybe more under levered in this cycle of rising interest rates and a bit bump up in your CapEx?
Ben, we're certainly looking at it, right? We have, as I've mentioned a couple of times, we've done a lot to improve our balance sheet, and we've actually delevered our balance sheet quite a bit over the last number of years. We're in a decent spot right now with respect to that. And we're watching the rising interest rate environment, which is why we've done a number of things at corporate to pull forward debt at the holding company. We did some interest rate swaps at ITC. So we're doing all the right things to manage our costs, going forward, but it's certainly something that we're looking at constantly, and it's evolving. But we're doing the right things to manage the costs that we have.
Your next question comes from Mark Jarvi of CIBC Capital Markets.
Maybe sticking with the last topic, Jocelyn, you mentioned that with the minimum tax, you think it would be less than 20 basis points. I think you said in the near term. Are you implying do you think that will go up over time and just that cash taxes will creep up through the 5-year plan? Maybe you can clarify that comment.
Mark, it is expected to be lower in the earlier years, down around as low as 10%, and could go up to 30 basis points in the latter part of the plan. Again, I will qualify AMT. We are still waiting for final regulations as well. But based on what we see today, near term, 10 to 20, and it could increase closer to 30 at the tail end.
Okay. And then turning to the comment about it's already in the plan an incremental $1.2 billion of renewables and storage at TEP and it's part of the IRP, I assume you're implying then that you hope to put that in a rate base. I'm just wondering of confidence on that versus outsourcing the PPA. So just maybe, I don't know, David, if you want to take that in terms of whether or not that all comes to fruition or if that's just a plan right now.
That's our current projection of the portion that we expect to be in rate base. Now we're in the process of going through RFP for both renewables and capacity down there in Arizona for our 2 utilities and in the middle of that. We were in the middle of it and then the Inflation Reduction Act came out. And so obviously, we pushed the bids back to make sure that we had all of those things built in there. One of the best things about the IRA, well, there's a lot of good stuff in there, but making sure that there's the credits and the tax credits are transferable really leveled the playing field vis-a-vis utilities to do it regulated versus IPPs and other folks who are a little more adept at finding the tax equity that would have been needed. So I would expect from last call to this call that on a going-forward basis I would expect us to see more utility-owned portion of that capital spend for renewables and storage than we would have prior to the Inflation Reduction Act.
Your next question comes from Andrew Kuske of Credit Suisse.
If you could maybe just give us a snapshot on how you think about economic growth on a jurisdiction-by-jurisdiction basis where you've got exposure. And maybe to follow up on that is really how that translates into CapEx for the economic growth that can also avoid bill pressure because the growth essentially solves a lot of problems associated with bill pressure on a volume basis. So any kind of color would be appreciated.
Boy, that's a wide-ranging question with 10 jurisdictions. So I'll hit maybe a couple of highlights. Obviously, the underlying growth in our biggest footprint, which is ITC's, is going to be driven -- well, let me back up and say there's going to be, there's 2 kinds of growth. There's customer growth and then there's use per customer growth. And a lot of that use per customer growth is going to be driven by the incentives in the Inflation Reduction Act, by driving demand for electricity, whether it be electrification, electric vehicles, the manufacturing focus. All those things are going to be driving economic development no matter what region you're in, what jurisdiction you're in, in the U.S. That will be a big shot in the arm. And that's on the use per customer side and, frankly, on the customer side, too, as you see economic growth for manufacturing in terms of economic development, which turns into jobs, which turns into people in those jurisdictions. And obviously, the Midwest and the vehicle manufacturing arena is very ripe for that. So we see good growth there, a lot of strong economic development opportunities. Arizona has always got the underlying weather fundamentals, but we're also seeing manufacturing really tick up; again, some related to electric vehicle manufacturing and other economic development opportunities that we're seeing in the state. I mean, Arizona is one of the fastest growing states. And depending on the year, sometimes the fastest growing state. And so we'll be keeping an eye on that. That can give you both of those benefits, both the customer growth and the use per customer growth. So those are probably the 2 ones worth mentioning the most. Other than, I know this is really a bit in the weeds and it's a very small part of our portfolio, the Caribbean and seeing those sales bounce back post-COVID have been quite impressive as well.
Okay. That is helpful. And I know it was a big broad question. And then maybe just coming back to that, could you have a situation where you have it all, where you effectively get economic growth in the jurisdiction so other people are investing capital, you have net migration, you're investing capital on the power side, bill rates are going down, but then given the competition for capital within a jurisdiction, does that actually help you with rates biasing upwards on your allowed ROEs?
Boy, I think from a jurisdictional perspective I think you can see a lot of those positive benefits. I don't see the negative at the tail end of your question there. If we get economic growth, customer growth, use per customer growth, that keeps bill pressure down. I think you were implying maybe is that going to be an issue from an ROE perspective, will the return match the growth. Look, in our world, the return is always going to be at a right level, right? I mean, we obviously see ebbs and flows related to ROEs, and we've seen them come down over years. And we're going to see as interest rates tick up, we're going to see them go up over the next few years. So I think that's a bit of a behind-the-scenes piece. It doesn't impact necessarily the underlying growth opportunities that we see in that laundry list I gave you.
You next question comes from David Quezada of Raymond James.
My first question, just on the capital plan and at UNS, specifically. I guess since the 5-year period now kind of coincides with the retirement of Springerville Unit 1, does the planned renewable CapEx at ITC over 5 years, does that get you all the power you need, I guess, to offset that retirement? Or would there be upside related to that?
Let me -- I'm going to turn that over to Susan Gray, who's the CEO down there and is in the midst of looking at those RFPs that we have out there, and let her answer that one. Susan?
All right. Thanks, David. Thanks for the question. So we are in the middle of an all-source RFP and evaluating those bids for potential projects. I would say what we have in the capital plan right now reflects what we think based on our 2020 IRP is required to offset the capacity that we'll be losing with the closure of Unit 1 at Springerville. However, we are publishing a new IRP next year. And so we're -- this is a continual process, always looking at current resources, current technologies, the market in the Southwest and what's available here. So it's always going to be adjusted as we go through the IRP process. And again, looking at the projects that are available through the all-source RFP may change our timing and an opportunity to accelerate investment, but I would say the current plan reflects what we think we need for that capacity.
Okay. Great. Maybe just one more for me on the MISO long-range transmission plan. I think that it's 2 of the 6 projects that you expect to be involved in are ones where you have right of first refusal. So I'm just curious, among those remaining 4 projects, which I guess will go to competitive bidding process, any color around how you expect that competitive process to play out? And what assumptions are you making there in terms of which projects you win, I guess, as it relates to the $1.4 billion to $1.8 billion that you've indicated you could build up to 2030?
David, that's actually incorrect, but I'll let Linda, our CEO at ITC, answer that, because those 6 projects are all ROFR projects. So go ahead, Linda.
Sure. Great. David, as Dave Hutchens just mentioned, all 6 of the projects that ITC has within the current Tranche 1 LRTP are indeed all covered by ROFRs. All 6 of the projects are either in Iowa or in Michigan, and both states have active rights of first refusals that were put in place through legislation in those respective states. Those projects are all ours, and we do not -- we will not have any competitive bidding for those projects. And in fact, we have already notified our respective state utility commissions that we are indeed pursuing those projects that are identified within our footprints. And so we have made the appropriate notifications as required. And so we will -- we're already well in tow in terms of continuing to plan and make the appropriate regulatory filings to pursue those projects.
Your next question comes from Patrick Kenny of National Bank.
Just on FortisBC here as we head into the peak demand season, can you just remind us if we do see some wild natural gas price volatility this winter how you plan to recover these higher fuel costs, going forward? Assuming you'll want to, of course, avoid a material adjustment in near-term customer rates in light of the political focus on affordability right now. And I guess, to that end, whether or not the rating agencies are fine with the potential drag on cash flow metrics at both FortisBC and on a consolidated basis?
Patrick, I'm going to kick that over to Roger Dal Antonio, who's the CEO of FortisBC, to cover that and what we currently are doing as well as answering your question there on going forward. And then I'll bounce it back to Jocelyn to cover the consolidated view on the cash flows. Roger?
Thanks, David. Thanks, Patrick, for the question. So on the first part of the question regarding the natural gas prices, we do have the commodity cost recovery account. Our mechanism is a quarterly recovery. So we're always trying to track fairly closely gas price changes so we avoid a large buildup and then requiring a very large passthrough at one point in the year. So, so far, we've had some increases this year. But what we're seeing for the next 4 to 6 months, we're not expecting much volatility in the BC context. But if we do, the mechanism is we pass through the rate increase, but we forecast over a 12- to 24-month period to smooth out the recovery of any increases to mitigate bill pressure. As far as the rating agencies go, so far, no indications is concerned. We've never had any issues with the commodity cost recovery accounts in the past. And it's about 35% to 40% of our overall bill.
The only thing I would add to that is rating agencies tend to look through timing or short-term volatility in collections of flow-through costs. So we've been always having those changes in cash flows because of the timing. But particularly, it's of interest now given the increase in recoveries. So it's always a balance to work with regulators and to smooth out recovery with customers and managing the cash flows of the utilities. So folks are doing a great job balancing that, but it's something that we're keeping our eye on and we're keeping the rating agencies updated on as well.
Okay. That's great color. Much appreciated. And then I guess, just being a FortisAlberta customer myself, I've got to ask, on the recent refiling of your 2023 revenue requirement it looks like it includes a 5% rate increase. Just curious what your read is on Premier Smith's comments to reduce electricity costs for Albertans over the near term and, I guess, even if you do receive regulatory approval for this 5% increase, whether you see a risk in capping electricity rates here in Alberta becoming a hot political topic ahead of the provincial election next spring.
So I'll provide you -- this is why we have the business model that we have, because we need those ears on the ground in every jurisdiction to decipher some of this information. And so I'll turn that one over to Janine Sullivan, who's the CEO of FortisAlberta, right in your neck of the woods, to answer that.
Thanks for the question. So just as a reminder, the Cost of Service application that we filed for 2023 was a reset of our revenue requirement after almost a decade of PBR regulation. So there was a lot that went into that application, and we fared very favorably in terms of things that we brought forward to establish that new revenue requirement, because it will be used as a stepping stone for the third generation of PBR, starting in 2024. So there was a lot of appetite for the things that we brought forward, and it was a very balanced application, I'll say, in terms of resetting our costs to align with revenues, but also bringing some new items on the table that needed to be addressed after a decade, as I said, of previous PBR. So affordability is a key topic in Alberta, as it is in most jurisdictions, as you've referred or heard referred to here this morning. Danielle Smith has created a new Ministry of Affordability in Utilities. So we do know that it is an important topic for Albertans as well as for this government, particularly as they prepare for an election. We're spending a lot of time with customers and with the regulator outlining what we're doing to address the affordability question and how our plans do consider it. We're quite cognizant of the fact that any growth in Alberta will have to be done very thoughtfully and very mindfully of the impact to customers. And so in this application, we brought forward some ideas that were tested with the regulator around things like DSM and how we can help customers manage their electricity bills, along with the investments required to support electrification. And it's easy to see that both the regulator and government are still contemplating what that means in a fossil fuel-based economy. But certainly, there's a lot of conversation going on, and we're staying very close to both the regulator, government and customers as to how we respond to that question. But you're right, it is a hot topic, and it will be, I think, for the foreseeable future, particularly as Danielle Smith goes into an election next spring.
Your next question comes from Dariusz Lozny of Bank of America.
Just wanted to follow up on the UNS renewables CapEx that you guys added to the plan. Obviously, you've got some tailwinds from the IRA legislation. Curious if, I know it's pending still, but if you were to get a positive outcome on your proposed clean energy rider in Arizona, how that might affect that renewable spend over whether it's this plan or the next iteration of the plan.
It gives us -- if we do get that resource transition mechanism, which is a tracker to get the recovery on those investments in the clean energy transition that we make between rate cases, it would definitely allow us to create maybe a quicker and maybe even a less lumpy type of resource plan and allow us quite a bit more flexibility in the timing when we make some of these investments. So that's probably the main thing. And it's the combination of that resource transition mechanism, that tracker and the IRA and the tax credit benefits that would, in essence, get passed through to our customers sets us up pretty good for additional conversations on that tracker in the rate case.
Okay. Great. One more, if I can, and this is shifting to your ITC capital plan, you laid out a fairly steady cadence through '27. And just doing the arithmetic, it seems like maybe half or just under half of your MISO Tranche 1 capital is in there. As we think about the latter half of the decade and, I guess, the years that are not in this current 5-year plan, should we expect a step-up possibly in capital as you deploy the rest of that CapEx for MISO, but then also any other spending that needs to be done?
So it's hard to go past the current -- it was hard enough to get to 5 years, Dariusz, and you're asking for the next 3. But as we state in our materials, we do expect the rest of that MISO long-range transmission plan Tranche 1 to be filled in post this 5-year period. And obviously, then we start on MISO long-range transmission plan Tranche 2, which we expect to be a pretty good sizable tranche and, obviously, looking for a good chunk of those investments as well. So it's all of these pieces that lay in. It's one of these things that you have to look at it from a long-term project perspective. Some are getting completed. Long-range transmission plans are coming in on top of that. Those go out for several years, and then Tranche 2 comes on top of that, they could both start in a few years at the soonest, and lay it on top of that. So it's just this layering effect. So it's really hard to say whether or not -- when the big step-ups will be, until we get a little bit more visibility on that Tranche 2. Because Tranche 2 will take some time to get those projects, one, through the planning process, but then, 2, obviously, for our team at ITC to then lay them out in their capital plan. But that's kind of all the different pieces that need to come together.
Your next question comes from Matthew Weekes of iA Capital Markets.
Just following up on that last one and looking longer term at opportunities at ITC, if you think about some of the regulatory matters that are pending from the FERC and, hypothetically, if there were to be some sort of downside impacts, maybe reduce the returns a little bit, longer term, would you sort of think about your appetite in terms of how much you want to pursue long-range transmission projects beyond Tranche 1 and, in general, long term, what your capital allocation would be to the region?
No. That would be probably the simplest answer I could give today, is no. I mean, there's obviously a lot of gyrations going on, on incentive adders, base ROE, et cetera. But longer term, the FERC jurisdiction that ITC operates in, in my view, will always have the right return levels to incentivize transmission. Remember, the whole United States government is focused on accelerating the clean energy transition, and I hardly think that it will get bogged up by not enough incentives or drive to get transmission done that's the critical link to making all this happen.
As there are no further questions at this time, I would like to turn the conference back to Ms. Amaimo for any closing remarks.
Thank you, Michelle. We have nothing further at this time. Thank you for participating in our third quarter 2020 results and 5-year capital outlook conference call. Please contact IR should you need anything further. Thank you for your time, and have a great day.
Ladies and gentlemen, this does conclude your conference call for this morning. We would like to thank everyone for participating, and you may now disconnect your lines.