Fortis Inc
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Fortis Inc
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Ladies and gentlemen, thank you for standing by. My name is April, and I will be your conference operator today. Welcome to the Fortis Fourth Quarter and Annual 2021 Results Conference Call and Webcast. [Operator Instructions] At this time, I would like to turn the conference over to Stephanie Amaimo. Please go ahead, Miss Amaimo.
Thanks, April, and good morning, everyone, and welcome to Fortis' Fourth Quarter and Annual 2021 Results 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 annual 2021 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. In 2021, we delivered steady growth while progressing our cleaner energy goals. During the year, we invested $3.6 billion of capital to support the continued delivery of reliable electricity and natural gas to our customers, despite the ongoing challenges of the COVID-19 pandemic. On the ESG front, we advanced many of our priorities, including becoming a supporter of the Task Force on Climate-related Financial Disclosures, improving the diversity of our Board and enhancing our sustainability disclosures, all while continuing to reduce our greenhouse gas emissions. Financially, absent foreign exchange differences, we grew adjusted earnings per share by approximately 5%, supporting our 6% dividend growth and strong shareholder returns in 2021. 2021 was another year of extreme weather across North America and a few of our service territories were impacted. British Columbia saw fires and record heat in the summer and a devastating flood in the fall, while ITC system experienced the derecho windstorm for the second year in a row. With our operating model, our utilities were able to respond to those events and restore service quickly and safely using their local system knowledge and the support of best practices and expertise shared from across the Fortis group. A strong reliability and safety culture continues to be the foundation of our utility operations as evidenced by another year of outperformance relative to industry averages. I would like to thank all of our employees and our utilities whose dedication day in and day out allows us to provide exemplary service to our customers.Our long history of achieving strong shareholder returns continued in 2021, with a 1-year total shareholder return of 21.8%. Looking back over a 20-year time frame, Fortis has delivered average annual total shareholder returns of approximately 13% or 975% in total. Also as shown on Slide 6, this far exceeds the returns generated by the benchmark indices. Since 2019, we have reduced Scope 1 emissions by 20%. This demonstrates significant progress towards reaching our target to reduce these emissions 75% by 2035. At UNS, closure of the coal-fired Navajo Generating Station in late 2019 as well as the recent additions of the 250-megawatt Oso Grande Wind Project, the 100-megawatt Wilmot Solar Project and the 99-megawatt Borderlands Wind Project have driven our carbon emissions reduction to date. With a full year of these renewable generation projects and the planned closure of San Juan generating station scheduled for midyear, we expect further reductions in carbon emissions in 2022 and remain on track to achieve our 75% reduction target. In 2021, our utilities deployed $3.6 billion of capital, focused on resiliency, modernization and sustainable energy, including $600 million for cleaner energy projects. These investments supported rate base growth of approximately 6% over 2020. Capital investments for the year were broadly in line with plan. However, a lower U.S. to Canadian dollar exchange rate and pandemic-related timing delays for both the Wataynikaneyap transmission project and planned spending at Caribbean Utilities modestly tempered investments during the year. This was partially offset by higher capital spending at ITC, including restoration costs following the December derecho storm. While the pandemic has not had a material impact on our overall capital plan to date, we are continuing to monitor the supply chain in order to identify and mitigate issues promptly. For 2022, capital expenditures remain on track and are not expected to be significantly impacted. In the fourth quarter, we rolled out our $20 billion 5-year capital plan through 2026, reflecting approximately $4 billion of annual investment in our utilities. The plan consists of virtually all regulated investments and a diverse mix of highly executable, low-risk projects supporting rate base growth across our utilities. With investments spanning the entire energy delivery chain, $3.8 billion of the 5-year capital plan is allocated to cleaner energy investments, aimed at improving our already low carbon footprint. The plan is expected to increase rate base by over $10 billion from approximately $31 billion in 2021 to nearly $42 billion in 2026, supporting average annual rate base growth of approximately 6%. Above and beyond our base plan, we remain optimistic about incremental opportunities to enhance our growth strategy. Specifically, as it relates to our transmission business, we continue to see a supportive policy environment. At the state level, the Transmission Infrastructure Planning Act in Michigan was signed into law in December. With this legislation enacted, ITC now has a right of first refusal in Iowa, Michigan and Minnesota, providing ITC the first right to build and own regional projects located within its service territory.At the federal level, the White House released a fact sheet last month, outlining various administrative actions that will take in 2022 to implement its clean energy goals and climate agenda, including a new initiative from the Department of Energy, building a better grid. This initiative is expected to support the nationwide development of new and upgraded transmission lines, enhance resiliency and provide additional access to clean energy. In addition to these positive policy advancements, ITC's geographic footprint puts them in a strong position to take advantage of the MISO long-range transmission plan. MISO is identifying regional transmission required to support the evolving needs of the system as it transitions to cleaner energy. Visibility on the initial tranche of projects is expected in the second quarter following the approval of the proposed cost allocation methodology that was filed earlier this month with FERC by MISO and a majority of its transmission owners. On the Lake Erie Connector project, the fully permitted shovel-ready project continues to progress. Last month, the Ontario Minister of Energy issued a letter to the province's Independent Electric System Operator, or IESO, acknowledging the many benefits of the project. In the letter, the Ontario government requested IESO continued discussions with ITC to advance contract negotiations on a transmission service agreement and requested a report back from IESO in late March. Should ITC reach a finalized agreement with IESO, construction of the project would take approximately 4 years. Our current 5-year plan does not include investments associated with these projects. As these or other opportunities that we've highlighted in the past come to fruition, they would either be additive to our existing plan or extend growth beyond 2026.In 2021, we increased our dividends paid per common share to $2.05, an approximately 6% increase compared to 2020, marking 48 years of dividend increases. Looking ahead, we remain committed to building on this record through the execution of our growth strategy and a targeted 6% average annual dividend growth in 2025. Now I will turn the call over to Jocelyn for an update on our fourth quarter and annual financial results.
Thank you, David, and good morning, everyone. Turning to Slide 13 and looking first at our fourth quarter results. While we continue to see rate base growth across our utilities, we successfully concluded the Central Hudson rate case and advanced the TEP rate settlement in the fourth quarter. There were a number of key drivers lowering EPS quarter-over-quarter. Reported earnings per common share was $0.69, $0.02 lower than the fourth quarter of 2020, and adjusted earnings per common share was $0.63, $0.06 lower than the fourth quarter of 2020. Unfavorable weather impacts in Arizona and Belize impacted EPS by $0.04 alone. In Arizona, retail sales were down 6% in the quarter, driven mainly by milder weather, and production in Belize was down 87% because of lower rainfall. Central Hudson also experienced a number of weather-related service interruptions that contributed to the company not meeting its performance targets, and Fortis' share price increased approximately 9% in the quarter, which resulted in higher stock-based compensation expense, and together, this decreased EPS by $0.03. UNS also experienced lower gains on its retirement investments during the quarter, and this was a $0.01 impact. And as expected, timing of tax deductions at FortisAlberta lowered EPS by $0.02 and a lower foreign exchange and a higher weighted average shares outstanding each decreased EPS by $0.01. Looking at the annual results. Reported earnings per common share was $2.61, $0.01 higher than 2020, and adjusted earnings per common share for the year was $2.59, $0.02 higher than 2020. This increase in EPS year-over-year was achieved despite a lower foreign exchange rate, which decreased EPS by $0.10. Excluding foreign exchange impacts, adjusted EPS grew by $0.12 or approximately 5% in 2021.The waterfall table on Slide 15 breaks down the annual EPS drivers, as well as the earnings growth at our regulated utilities, excluding the impacts of foreign exchange. In 2021, our regulated utilities increased EPS by $0.18 over 2020. Our largest utility, ITC, increased EPS by $0.07, reflecting 9% year-over-year earnings growth at utilities. Strong rate base growth coupled with a favorable adjustment related to interest rate swaps was partially offset by higher nonrecoverable stock-based compensation costs. UNS Energy increased EPS by $0.02, growing its earnings by approximately 4%. I'll speak to you in more detail on the next slide. Central Hudson contributed a $0.02 EPS increase, growing its earnings by approximately 7%, reflecting rate base growth and the conclusion of its rate case. Our Western Canadian Utilities contributed a $0.05 EPS increase, driven mainly by rate base growth. Higher earnings at FortisAlberta were also driven by favorable weather. In total, earnings in Western Canada grew 6% year-over-year. At our Other Electric segment, higher sales in the Caribbean due to the continued recovery of the tourism industry and rate base growth contributed to a $0.02 increase in EPS or 7% segmented earnings growth compared to 2020. At our Energy Infrastructure segment, EPS decreased $0.03, mainly driven by lower hydroelectric production in Belize and realized losses on natural gas contracts at Aitken Creek. With the lower rainfall in Belize, production in 2021 was 147 gigawatt hours compared to 229 gigawatt hours in 2020. This reflects a 35% decrease year-over-year. And the realized losses at Aitken Creek as we discussed in the third quarter reflect contracts settled in consideration of market conditions and favorable forward curve. As expected with our dividend reinvestment program, EPS decreased $0.03 due to higher weighted average shares outstanding, and lastly, the average U.S. dollar to Canadian dollar exchange rate was 1.25 for 2021 compared to 1.34 for 2020, which lowered EPS by $0.10. As I mentioned on the previous slide, UNS grew -- earnings grew by 4% compared to 2020. UNS benefited from higher net margin in 2021, driven largely by new retail rates at TEP, the FERC settlement and higher wholesale margins. This increased EPS by approximately $0.10. UNS did, however, report higher planned maintenance cost at TEP's generating facilities, which lowered EPS by $0.03. And lastly, weather impacts in 2021 lowered EPS by $0.05. As you recall, Tucson experienced its hottest summer on record in 2020. Looking ahead to 2022, we expect to reasonably manage regulatory lag as we expect lower planned generation maintenance costs coupled with customer growth and formula-based transmission rate. Additionally, while no decision has been made, we are in the process of evaluating the timing of the next rate case filing at TEP.As you can see on Slide 17, we were active in the debt capital markets again in 2021 with over $1 billion in long-term debt raised at attractive rates, highlighted by ITC's inaugural green notes. Debt issued at Fortis Inc. mainly refinanced maturing debt, while our regulated utilities issued debt in support of their capital programs. With the backdrop of a rising interest rate environment, several of our utilities accelerated long-term debt issuances in 2021, locking in attractive rates. In addition, ITC entered into interest rate swaps to mitigate refinancing risk. We continue to monitor the capital markets and any impacts on our future financing requirements. With our recent debt issuance, coupled with over $3 billion available on our credit facilities, we continue to maintain a strong liquidity position, supporting our $20 billion 5-year capital plan. Our capital plan is expected to be primarily funded with cash from operations, debt issued at our regulated utilities and our equity dividend reinvestment plan, while maintaining a relatively steady capital structure through 2026. This funding plan, coupled with Fortis' low business risk profile, provides financial flexibility and positions us comfortably within our existing investment-grade credit ratings. Turning to recent regulatory updates. First, ITC continues to await a final rule from FERC in relation to the supplemental notice of proposed rule making on transmission incentives, which proposes to eliminate the 50 basis point RTO, return on equity, incentive matter. In November, ITC filed comments in response to the events notice of proposed rule making, or ANOPR on regional transmission planning, cost allocation and generator interconnection processes. In its response, ITC recommended for direct the RTOs to conduct regular holistic transmission planning and highlighted some of the impediments of Order 1000 competition. While FERC has indicated its plans to move the ANOPR through the regulatory process as fast as possible, it remains unclear whether aspects of the ANOPR will be broken out into multiple NOPRs. At TEP, you may recall FERC issued an order in 2019, accepting formula transmission rates as filed subject to refund and settlement procedures. A settlement in principle was filed with FERC in December 2021. The settlement includes an allowed ROE of 9.79% and a single roll-in rate design. The FERC rate design settlement is positive as over 20% of UNS Energy's 5-year capital plan is allocated to transmission investments, which will receive timely recovery in rates. In November 2021, Central Hudson received an order from the New York Public Service Commission approving a 3-year rate plan retroactive to July 2021. The commission approved the joint proposal, which includes an ROE of 9% and an equity layer of 50%, declining by 1% annually to 48% in the third rate year. In British Columbia, the generic cost of capital proceeding is expected to continue into 2022 and the effective date of any change in the cost of capital remains unknown. FortisAlberta filed its 2023 cost of service application in November in conjunction with the return to a third performance-based rate-making term beginning in 2024. A decision from the AUC is expected in the third quarter. And lastly, in January 2022, the AUC initiated a generic cost of capital proceeding to consider whether the current cost of capital parameters should be extended for 2023. A decision is expected as early as March. The AUC also confirmed it will begin a separate process for cost of capital for 2024 and beyond later this year. That concludes my remarks. I'll now turn the call back to David.
Thank you, Jocelyn. At Fortis, we have the right people, values and plan to advance our growth strategy and deliver a cleaner energy future. With our local operating model, geographic and regulatory diversity and operational expertise, our stakeholders stand to benefit from the long-term value of Fortis that we will deliver in 2022 and beyond. 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] And your first question is from Linda Ezergailis with TD Securities.
I'm wondering if you could help us understand a normalized weather year on a consolidated basis, what that might look like in terms of EPS? It was really helpful to get the year-over-year $0.05 impact, recognizing that 2020 had record hot weather. But I'm wondering what the sensitivity would be to normal weather, if you could provide it, in 2021.
Yes. That's -- Linda, I'm glad you can make the call. The weather sensitivity is quite a bit of a combination of art and science, and it is very difficult to get kind of some really good thumb rules from a year-over-year basis, particularly coming out of the pandemic because we saw very different customer behavior back in 2020 than we did in 2021. With everyone working from home, we saw a very different use per customer profile. So that compounded by the fact that we tend to get a little bit warmer every year these days other than 2021 where we saw kind of slip back. It is pretty tough to get that sensitivity. So I know that it's a nonresponsive answer, but we're trying to work on how we can see that really from a -- it mostly is impacted by the weather in Arizona because most of the other utilities that we have, have very limited weather flow through to the bottom line. So I would say, when you look at 2021 versus 2020, obviously, 2021 was a much more normal weather year. So that would be more of a normal than I would think of on a going-forward basis.
And in terms of different customer behavior, again, I know it's an art, not a science. But maybe just as a follow-up, are your teams putting thought towards what's the new normal? And how much of that shift in customer behavior might be not permanent, but systemic and continue versus what might revert back to historical patterns potentially going forward?
Sure. So in Arizona, we're actually seeing it kind of revert back to normal, back to the pre-2020 timeframe when you look at it from a use per customer perspective as well as the more normal -- for the most part, residential and commercial load shapes. Because in Arizona, I think a lot of folks did return to work in 2021. Business has opened up quite a bit more, obviously, than in 2020. So we have seen in 2021, probably what I would call pretty darn close to the new normal from a load perspective and from a customer usage and demand profile perspective. Not to say that doesn't change on a going-forward basis. When you look at some of the other new technologies, DSM energy efficiency, et cetera, that can be deployed across our utilities. But for the most part, we're kind of back to what the pre-2020 or pre-pandemic behavior.
That's helpful. And recognizing that Q1 is only half finished at this point and a lot can happen still in the quarter. I'm wondering if anyone on the team would be able to provide a sense of what the weather and believes water levels have them so far that we've been seeing in Q1 and even any sort of natural gas storage, if I may be so bold.
Yes. I mean it is just tracking rainfall in Belize, and it's better than Q4. That's -- we have -- we are starting to see production tick back up, but it's hard to say where we'll end up at for the quarter. It is frankly a pretty variable based on that rainfall and believes that production is obviously directly correlated with that. Q4 was a very, very low quarter for us when you compare it '21 to '20. So we do see it coming back somewhat.
Your next question is from Maurice Choy with RBC Capital Markets.
My first question is on MISO, LRTP. Dave, you mentioned in your prepared remarks that you see supportive policy from premium to federal and state levels. As you approach the announcement of the first tranche of projects in Q2, how should we view your market share, if I could call it that way? And how does this market share do you change for the Michigan decision in December?
Yes. So I don't really have it broken down by jurisdiction, and maybe Linda could provide a little color on this, but we have talked in the past about just our overall footprint in the MISO region, and that's 23-ish percent, 22%, 23% of the MISO footprint. That's our assets. And we also kind of use -- and I don't know how indicative it is and probably not that indicative for -- on a forward-looking basis because the MISO trends, these new long-range transmission projects, we don't know exactly where they're going to land, where they're going to come in, in the tranches. And frankly, this isn't a great indication, obviously, looking backwards. But when we did the MVP projects, I guess almost a decade ago, we did get about that same level, 22%, 23% of the MVP projects came our way at ITC. So it's hard to necessarily project any of that on a going-forward basis, especially when you can just wait a few months, and we'll hopefully be able to see you and have a really good view on it. And then once we see that tranche, we see the -- where our ROFRs land related to those projects, we'll get a really good view of what we think from projects -- which projects are ours on a going-forward basis and then start the fun part, which is figuring out how to plan and build them. Linda, do you have any color to add on that?
No, Dave, I think you captured it all. Nothing additive for me.
Got it. And maybe a second question is on Arizona. Jocelyn, I may have missed it and apologies if I did, but I think you mentioned that Fortis' evaluating the timing of the next rate case filing in -- for TEP. As the current rates were approved just over a year ago, what are the changes to your business that you'd be highlighting to the ACC to justify new rates? And as a follow-up, how do you see the ACC's recent regulatory decisions relating to peers in the state being factored into your view about this rate application?
Maurice, before I throw it to David because I'm sure David will talk about the Arizona environment there, but with respect to the rate case, it's not uncommon for TEP to be thinking about a rate case. The last rate case was filed with the year-end December 31, 2018. So it's been several years since we've last set rates. So we've invested, as you know, we keep investing in Arizona. So we do have, what I would say, suggests that we would highlight to the regulator that we're continuing to invest, and we need to revisit what we've invested over the last couple of years and get that into rates. TEP has done a great job, right? It's done -- keep moving forward with its clean energy plans. It's managing its cost. It's doing the right things. So this is just very typical for a utility to file the rate case every couple of years. And so nothing out of the ordinary from TEP's perspective. I'll let David speak to what's happening with the peers there.
Yes, I'd just add that you're right on, Jocelyn, because it really is -- 3 years is a lot of lag for a utility like ours in Arizona. And we have obviously not just invested in the past 3 years, but are looking to invest quite a bit on a going-forward basis to go down the path of our clean energy transition in Arizona. So we want to make sure that we're getting in front of our regulators telling that story, looking for mechanisms that we need to make sure that we get adequate and timely cost recovery related to those investments as we go forward. And then the regulatory environment in the Arizona, I know this has been a bit of a hot topic for the past few months, but I think, one, a lot of that conversation and the results of another company's rate case in Arizona don't necessarily reflect on expectations -- don't reflect at all expectations on an outcome for us. I think those are very utility-specific. We've got a different utility, a different relationship with the commission, different resource plan, all of that stuff is different. So from my perspective, there's not a -- there's definitely not a read-through to TEP from that. And frankly, there's been some very good and positive -- very recent positive outcomes in Arizona regulatory environment. Just this week, the Arizona Corporation Commission acknowledged the integrated resource plans that we filed for Tucson Electric Power and our smaller electric utility, UNS Electric, which supports that 2020 integrated resource plan that supports our 80% greenhouse gas reduction at TEP that of course, supports 75% greenhouse gas reduction that we have Fortis wide. So those are all good signals that the commission is moving in the right direction, providing the right signals and allowing us to do what we have to do, which is plan our system, its needs for our customers for the reliability and affordability through an integrated resource planning process, and they're actually spending a good amount of time to get those integrated resource plan rules right so that we can look at a broad array of different opportunities from a lease cost portfolio to the most aggressive renewable portfolio and make sure that we pick the one that our stakeholders and our customers and our regulators all agree on. That's what we did in 2020. So nothing new for us. We're looking forward to getting that next integrated resource plan, which actually is now not due until August of next year. So a lot of work to be done between now and then.
Great. And just a quick follow-up. Could you help us focus a little more on timing of this filing? Are you talking about in the next few months or by the end of this year, roughly that would be great.
Yes. It's really hard to put a pin in it at this point, but we're looking at it. There's -- one of these things that you always evaluate is capital plan timing and when is the right test year to pick. And so we're still working through all of those bits and pieces.
Your next question is from Rob Hope with Scotiabank.
Just a follow-up question on the Midwest transmission projects. I assume that there's not a ton of capital in your existing capital plan related to the next tranche that will be coming out. But when you take a look at just kind of the selection schedules, the project timing, when do you think you could start to see capital being layered into the capital plan on a more meaningful basis? Is this more of a 2024, 2025 start to put steel in the ground.
Yes, Rob, thanks for that question. Just to clarify, yes, there is no money in our existing capital plan related to those MISO projects. We don't put something on top of our current existing plan in there. So the question around timing is a good one because it's really hard to tell. There's -- who knows which projects are going to come out first in this first tranche. There might be some that are upgrades. There might be some that are maybe a little bit easier like transmission interconnection. That's a different process that FERC is going through, but that can fall in the next several years because those are a little bit easier to do than some of the long-term transmission projects that are obviously going to be a big chunk of this tranche and the next tranches. So I would say, the majority of that expenditure is going to be late in this 5-year plan to mostly, I would say, past the 2026 timeframe that's in our 5-year plan. So with a little luck, we get the easy ones on the front end here, and we can lay that in to boost up the current capital plan. But I would say, the biggest impact is going to be on the later years of the 5-year plan and the extension from year 6 on.
All right. That's helpful. And then just pivoting over to another large transmission project, Lake Erie Connector, it looks like it's getting through some of the gates here in Ontario. Where are you in discussions with the government? Is kind of the key terms been broadly discovered? Or can you maybe just give us an update on the process there?
Yes. It's broad terms, term sheets. The principals have been laid out. It's now getting to the details and finalizing all of those pieces. So that was part of the update that the IESO gave. The government in December, they came back and said, this all looks reasonable now, finish the negotiations and work towards that TSA and bring us back another update in the end of March. And so these are all positive step-by-step movements that we're making on getting to a final agreement. And then of course, once we get to that final agreement, we get it -- we agree with the IESO. The IESO brings it to the Ontario government. Everybody signs it, and then we start the process or continue the process of designing, getting the EPC contractor and start construction. So it's feeling, obviously, the best we've ever felt on this project and just a couple of steps, a couple of signatures away from really getting this thing moving, which is a real testament to the time that our team at ITC has put in on this project to make it a go. This one has been talked about for a while, and we know it's difficult. Well, it's a cross-border project. It's got 2 IESOs on each end that you got to connect between PJM and Ontario. So lots of details, but the harder the project size, the more fun in there when you actually get to put them into service. And we're looking forward to getting those last couple of steps done as quickly as we can.
Your next question is from Mark Jarvi with CIBC Capital Markets.
A couple of questions on Alberta. One would be around the potential move to a formula if you guys could comment on that in terms of want to see your openness to that. And then second on the cost of service rebasing. Just expectations in terms of what the parameters are in terms of maybe like ability to keep earnings flat to up because I remember last time around, sometimes we saw flat or down earnings after that rebasing, can you give some color on both those items.
Sure. I'll talk about the first one and then turn the cost of service rebasing over to Janine to get some direct insight. Janine Sullivan is the CEO of FortisAlberta. On the potential formula, this is one of those things where it all depends, right? It all depends on how the formula is set, whether it takes in to account the right risks and that are specific to your utility. If it's flexible enough to adapt to the changing energy environment that we're all going to see over the next few years and obviously, extending further than that. So we're going to work hard if it is a formula type rate. We want to make sure that it works for us. It's like any regulatory mechanism. It all depends on the details in the end. So I think we could be supportive of either way as long as it provided the right ability for us to get the return on the investments that we make and for the growth opportunities that we see and the participation, frankly, that we want to have in that clean energy transition in Alberta. Janine, I'll turn it over to you to talk about the cost of service rebasing.
Sure. So the cost of service rebasing is ongoing. We are in the midst of it. It is an important opportunity for FortisAlberta in terms of rebasing our revenues and costs after almost a decade of PBR-based regulation. So we are optimistic that the process will provide visibility of the current costs that FortisAlberta is incurring and what we foresee happening into the future. And as Dave indicated, some of the newer projects that need to be addressed as part of a clean energy future and having those address as part of the revenue requirement, which would then provide a strong starting point for going into a third term of PBR. And of course, that will be determined over the next 12 months as to what that third term will look like in terms of specific mechanisms. With respect to cost of capital, there is a desire to become prospective or more prospective at least in Alberta around such matters. And so it's very early days with respect to setting cost of capital for 2024 with the formula. So the focus right now is really on determining what should happen in 2023. There is early indications that it likely hold the current parameters just given that desirable prospectivity and a difficulty in terms of readdressing it in the short term for anything new for 2023, but then really setting the foundation for more deliberate conversation around what it should look like in 2024 and beyond and the possibility of a formula, but still very, very early days.
And just coming back to the rebasing. When you look at sort of where you are and what your stance is now in terms of your submissions, it is the thought that your sort of achievable ROE can be held flat through that process?
We are optimistic that this rebasing will provide a solid starting point for 2023 in terms of a full realignment of our revenues and our costs. I mean there are some concerns in the province around affordability and that dynamic between investing for the future and clean energy programs and how we do so in a thoughtful and affordable way is certainly for us to demonstrate. But we believe we have a very good plan going forward that does both, and I think that we'll be in a good position starting in 2023.
Okay. Jocelyn, a question for you. Just in terms of the DRIP and just updated thoughts on the discount in terms of usage of the DRIP now or a pivot back to the ATM where you have a bit more control on sort of when shares are issued, sort of updated thoughts on that?
Yes. So Mark, we actually put the DRIP in a couple of years. We turned it off and then we put the discount back on. And it's a pretty effective way of getting the equity we need and so it does provide us with some flexibility. The uptake is back up to over 35% again. So pretty healthy participation. We evaluate it every year. Right now, it's working for us. It has given us the equity that we need. We don't need any discrete equity. The ATM program, in my opinion, worked as well. It's just a different way of getting it, but I think the DRIP is an easy, effective, cost-effective way of getting the equity that we need because we understand our growth profile should, with all the opportunities that Dave is talking about change our capital program in any meaningful way, we'll revisit funding on every level. So -- but for right now, the group is working for us.
Your next question is from David Quezada with Raymond James.
My first question here just on BC relates to the Tilbury site and any -- or the planned expansions there as well. Just curious how you're thinking today about the infrastructure in that region and the floods that we saw over the past year? I understand that the regulator is undergoing some kind of review process. Just any color you can provide there.
Yes. I'll turn it over to Roger here to get all the details, particularly around the tank that we're proposing because I think that's a real important project for the BCUC to consider from a resiliency perspective. As we have now seen in the past several years, some hiccups. I'll call on Enbridge's system, one back in, I guess, it was winter 2018 and then of course, the one recently with the flood. It makes us -- makes it more important for us to look for resiliency projects down in the lower mainland in the Vancouver area. And one of those projects, as you know, is the big new LNG tank that we have a big 3 BCF tank that we have proposed. That's going to be really important to providing that resiliency in that back up. I'll turn it to Roger to tell you where we're at from the application perspective with the BCUC and the EA process.
So yes, on the Tilbury tank, there's 2 processes underway. One is with the BCUC. We're mid process on that CPCN, answering information requests from intervenors. That process will continue for the better part of the year before we get to conclusion. In addition, because of the size of the tank, we have to file and obtain environmental assessment certificate from both BC and Canada. We're on track with that process. We filed the detailed project description last year. We received a readiness decision and expect to go to public comment Q1 of this year. The Impact Assessment Agency of Canada did agree to write a substitution so the BC, EA will lead the process, and that will continue for the better part of 2022 before we figure out what the next steps are in that environmental assessment.
Okay. Great. And Roger, maybe a follow-up for you. It feels as though with news headlines lately, there's been some increased momentum for the use of RNG in marine bunkering. And I know you guys have made really good progress on procurement of RNG in the BC -- at FortisBC. Just curious if you think you could ultimately, depending on the extent of RNG for usage in the marine end market, could you potentially get to more than a 15% mix in BC on the RNG side?
Yes. I think there are 2 distinct questions there. The marine market, I think RNG eventually will end up there. We did have that pilot project with Seaspan, where we ran low carbon [Audio Gap] for their barge ferries. I think there is a similar pilot down in Florida last year as well. So I think the marine market is looking at LNG, and if it can come from renewable gases, all the better. It's already got a significant advantage over marine fuels like diesel. So I think that will be an added benefit. So we see that as an additive support for increasing LNG in marine market. I think, generally, our RNG development, we received approval from the BC government last year to go to 15% of our resource or gas supply coming from RNG, including hydrogen. We just recently signed 8 petajoules deal, still needs regulatory approval, but we expect to get that this year. We're about 18 petajoules, which is just over halfway to our 2030 target of 15%. So we believe we can go beyond that for sure over time, and that doesn't include the adoption of hydrogen. So we see a growing amount of renewable gases in our system going forward.
Your next question is from Matthew Weekes with IA Capital Markets.
I think they've mostly been answered at this point, but I think I'll just ask on the macro and rate cases. In terms of rate cases that are ongoing right now or that you're planning on doing in the near future, how do you expect the outlook for rising interest rates to impact those proceedings? And are you pursuing any creative measures to maybe address the rising rates over the couple of years or anything like that?
Yes, Matthew, a great question because the rising rates can help or hurt. Obviously, from an inflation perspective and cost of doing business, that's going to put some upward pressure on the cost that we incur. And depending on which jurisdiction we're talking about across our footprint, some of those have very direct pass-through mechanisms to customers like ITC and now TEP's transmission down in Arizona has that same pass-through mechanism. So there isn't really an impact because it's on a forward basis and then trued up as well. Other jurisdictions like Alberta and BC have inflation in part of their calculations for cost escalation. And then the one bigger jurisdiction that doesn't have it is TEP's non-FERC assets or their retail rates, which would be subject to some regulatory lag between, obviously, when you see that inflation and when you actually get those costs and that inflation reflected in rates. So it's a bit of a mishmash across the utility, but no huge impact from a company perspective. Now of course, this all has impacts to our customers raising their costs across the board, whether it's things from normal inflation in products and services to natural gas prices, et cetera. So we are very laser-focused on making sure that we are doing everything we can from a cost perspective throughout the rest of the utility to reduce the impact on our customers. Now on the other side of things, ROEs are obviously -- track that rising rate, and it's obviously not a direct correlation. Sometimes it lags down, sometimes it lags up. But the general hypothesis here is in rising rate environment ROEs rise. And so we would expect to see that over time, increase the return that we would get on our equity. And of course, that's why these proceedings on generic cost of capital, et cetera, and rate cases are important to get that reset and reflected.
Your next question is from Patrick Kenny with National Bank.
Just a follow-up on your 100% RNG initiative in BC. And I was just curious if you see any opportunities to implement this newbuild renewable energy source offering across some of your electric utility platforms? And how that might be able to accelerate your overall 75% reduction target by 2035?
Yes. First off, what a great program that FortisBC that team came up with. It's making -- it's getting everyone to recognize the role that natural gas companies and their infrastructure can play in delivering the cleaner energy future. We talk about it a lot on how you can green up electrons on the transmission and distribution side, but we need to be talking more about how you can green up and clean up the molecules that you send through your pipe, whether it's through renewable natural gas and gas, hydrogen, whatever it is, that shows that we're part of that solution. So that's a great solution for FortisBC. It could be in our other -- we have small gas companies in Arizona and New York that could also look at programs like that. And utilities like Arizona, where we have a vertically integrated utility, we do offer some green power programs for our customers already. So those things can -- and of course, you got to be looking at more and more opportunities to do that to create the customers' option to go a little bit faster than perhaps we were going from a portfolio-wide perspective. Of course, our goal is to -- if you -- if we execute on our integrated resource plan in Arizona, our customers -- in 2035, 70%, actually about right around 2032, about 70% of the energy that we provide will be renewable energy. So people forget how much we're really doing behind the scenes and increase in that volume. But still, there's customers who want to have, like me myself at my home in Arizona have 100% renewable energy tariff where my energy comes 100% from renewables, and we have that, obviously, for across the board in Arizona.
Excellent. And then maybe just a high-level question, David, on the portfolio in general in light of the rising rate environment and the potential here to add some additional larger-scale growth within your larger core utilities. I know you've always seen the benefits of diversification, but it's now the time to weigh the option of perhaps divesting of 1 or 2 of your smaller utilities simply to beef up liquidity ahead of some of these larger-scale projects.
Yes, not really a priority for us. I mean I think the utilities that we have, we don't -- we're not blind to market drivers and value and opportunities, et cetera. But I think that we run every single one of our utilities within our model, the best they can be run. And we will continue to improve each one of those utilities on a going-forward basis and improve the growth of each. So I don't -- someone would have to see some weird outsized value because to create value in one of our subsidiaries or one of our pieces of our portfolio above and beyond what we can, I think that's a -- it's a high hurdle, but we'll pay attention, but definitely not something that we're looking at in the near term.
[Operator Instructions] Your next question is from Dariusz Lozny with Bank of America.
Just wanted to hopefully get a quick update on the Cardinal-Hickory Creek project. I realize it's not a significant part of your long-term CapEx plan, but there have been some hurdles there. And I was just curious if you could provide an update and potential timeframe for next steps. And the part 2 of that question would be, given the experience of bringing that project along thus far, does that inform your approach at all to potentially further down the line additional projects in the MISO footprint?
Yes. Thanks, Dariusz, for that question. You get full points for getting into the details because that's in the details. And I'm going to pass that -- that's so far in the detail. I'm going to pass it to obviously our expert on this, Linda Apsey from ITC.
Great. Thanks, Dave, and thanks, Dariusz, for the question. Yes, I think to keep in mind -- I mean no doubt, certainly, there's multiple legal proceedings around Cardinal-Hickory Creek, but I think just to kind of put it in perspective, the litigation all revolves around essentially what is 1.5 miles, basically 150-mile project. And that litigation so far has not ceased construction on the project. We continue to construct the projects, both in Iowa and in Wisconsin with our partners on the project who are about a 45% owner of that project, and so it's a partnership project with both American Transmission Company and Dairyland Power. So despite, I would say, some headlines, complexity of sort of the litigation and multiple lawsuits, it really is a minimal portion of the project, the concession, and we continue to pursue our construction activities. And quite frankly, I think we feel pretty confident that we'll continue to realize that project given the need for the project. This is a project that was identified over 10 years ago with an MVP project through MISO, and certainly, the need, the benefits for customers just have continued to grow. So I think we feel pretty confident that the project will be realized, and it has not stopped our construction activities at all. And then I think in regards to the -- sorry, I know you had the second question just in terms of does it alter how we think about the future LRTP projects? No. Look, I mean I think -- generally, I think just from a broad perspective, certainly, litigation, environmental opposition to energy projects in general is certainly growing. But I think when we step back, when you look at the primary drivers of all of these LRTP or regional transmission projects, the primary driver is to interconnect and deliver green energy to customers. And ultimately, when you -- I think you layer on the additional benefits of any transmission project, economic benefits, reliability benefits. When you look at the analysis and study process that the RTO goes through when they assess these projects, there is no doubt. I mean all of these projects have to pass cost benefit calculations, and there is an immense amount of detail around the benefits of any of these projects. So I think we feel pretty comfortable and confident that ultimately, when you have a need-based project, typically, the projects prevail, but certainly, depending on the location of a project, maybe the sensitivity of certain geographies, all of those things need to be considered and particularly considered and how we think about the timing of construction approval and obviously, putting those projects into operation. But I don't think we see this as any type of sign of the future that's different than what we've been dealing with. I think, at ITC, we have a great track record of citing transmission projects. And we work very, very closely with all of our local communities, our states, our landowners. We take all of those things into consideration on the front end. And so I think we feel pretty confident in our ability to continue to realize transmission projects that come out of the LRTP effort.
I appreciate the detail in that response. If I could just ask one more quickly. This is pivoting over to the Q4 adjusted drivers. I noticed as part of the Central Hudson $0.03 drag related to nonrecoverable costs, you referenced performance targets. Is there any way you could elaborate on that just in brief what those targets were? And perhaps, was isolated to Q4 or something you'd see maybe potentially being ongoing?
Yes. Let me send that over to Charlie. He's got the color on that. Charlie Freni, who's the CEO of Central Hudson.
Thanks, Dave. So we have within all of our rate agreements performance metrics, which we need to meet, and those performance metrics, if they aren't met, do result in penalties associated with missing those. And so 2 targets that were related to reliability that we missed were frequency of outages and duration of outages. And those are all outages that are nonstorm-related outages. So it's kind of on a day-to-day basis. I mean those provisions have been in our rate cases for many years, and they are -- continue to be part of our rate structure going forward. I certainly believe that last year was an unusual year, and I wouldn't expect that we would exceed those targets going forward.
As there are no further questions, I would like to turn the call back to Miss Amaimo.
Thank you, April. We have nothing further at this time. Thank you, everyone, for participating in our fourth quarter and annual 2021 results conference 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.