Fortis Inc

TSX:FTS

Earnings Call Transcript 2022-Q1

[Operator]

Ladies and gentlemen, thank you for standing by. My name is Ruel, and I will be your conference operator today. Welcome to the Fortis' First Quarter Conference Call and Webcast.

[Operator Instructions]

At this time, I would like to turn the conference over to Ms. Stephanie Amaimo.

Please go ahead, Ms. Amaimo.

[Stephanie Amaimo, executive]

Thanks, Ruel, and good morning, everyone, and welcome to Fortis' First Quarter 2022 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 slideshow. 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 first 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.

[David Hutchens, executive]

Thank you, and good morning, everyone. Our first quarter not only demonstrated the financial strength and stability of our business, but also our commitment to delivering a cleaner energy future for our stakeholders. During the first quarter, we successfully executed on our capital plan by investing nearly $1 billion in our energy systems supporting our adjusted EPS of $0.78. There were also advancements made on the FortisBC Eagle Mountain-Woodfibre Gas Line Project as well as the MISO long-range transmission plan and Lake Erie Connector project at ITC. Today, we are pleased to announce a 2050 net-zero target to build on our 2035 75% Greenhouse Gas Reduction target. This announcement follows our inaugural TCFD climate assessment report issued in March.

Today, the importance of reliable, affordable and secure energy service to our customers is more obvious than any time in recent memory. And at Fortis, we are ensuring that these remain core principles as we take actions to both mitigate and respond to the impacts of climate change. While our reliability metrics continue to outperform industry averages, we must continue to make responsible investments in our energy systems to withstand the increasing frequency and severity of weather events.

With the backdrop of inflation reaching 40-year highs, we are laser-focused on managing rising energy and material costs to limit customer bill impacts. As shown on Slide 5, our utilities have historically managed annual increases in controllable operating cost per customer to 1% to 2%. As operators of critical energy infrastructure, cybersecurity is a key component of our risk management program. With recent geopolitical tensions in Eastern Europe increasing cyber threats, our utilities continue to enhance security protection including working with critical industry and government partners. As I mentioned, we made significant progress on our commitment as a TCFD supporter with the release of our first Climate Assessment Report.

The report looked at 4 climate-related scenarios at our 5 largest utilities identifying risks and opportunities. The report highlights our strong governance and oversight around climate matters and explains how risks are incorporated into existing risk management, long-term strategy and financial planning processes. It is no surprise that policy and regulatory advancements, innovation, customer affordability and reliability are imperative to facilitate the rapid transformation that is required to address climate change.

Overall, Fortis is well positioned to mitigate these risks and realize opportunities under various scenarios. Today, we are extending our commitment to a clean energy future with a 2050 net-zero target. This next step in our ESG journey builds off our 2035, 75% Greenhouse Gas emissions reduction target. Having reduced our direct Greenhouse Gas Emissions 20% since 2019 and with plans to fully exit coal by 2032, we are committed to a net-zero target by eliminating the last 25% of direct emissions by 2050.

Through technology advancements, the appropriate use of low or no carbon fuels and carbon offsets, we believe we can achieve our net-zero target while preserving customer reliability and affordability.

Turning now to Slide 8. Last year, we announced our $20 billion 5-year capital plan through 2026. For 2022, we remain on track to invest $4 billion in our systems with nearly $1 billion invested through March. We do not expect 2022 capital expenditures to be significantly impacted by supply chain constraints as our teams have taken proactive steps to promptly identify and mitigate supply chain issues.

Major capital projects, which represent 15% of the 5-year plan, continue to progress. In April, Woodfibre LNG issued a notice to proceed to its prime contractor for the proposed Liquefied Natural Gas site in Squamish, British Columbia. This announcement brings FortisBC's Eagle Mountain Woodfibre Gas Line Project one step closer to construction. so the project remains contingent on Woodfibre LNG making a final investment decision.

Overall, our highly executable and low-risk capital plan is expected to increase rate base by over $10 billion over the next 5 years, supporting average annual rate base growth of approximately 6%.

Beyond our base capital plan, we have a long CapEx runway focused on climate adaptation, innovation and a cleaner energy future in support of our stakeholders' expectations. This blueprint is expected to support sustainable growth for the foreseeable future. With respect to near-term growth opportunities, momentum at ITC continues to build. During the first quarter, MISO advanced its long-range transmission plan, announcing the first tranche of projects across the MISO Midwest subregion comprised of 18 projects with total associated costs of approximately USD 10 billion. These projects require MISO board approval, which is currently anticipated in late July. 6 of the projects run through ITC service territory, including Michigan and Iowa where right of first refusal provisions exist for incumbent transmission owners.

Other projects within this portfolio may be subject to competitive bidding depending on the state they are located in. Based on this preliminary information, ITC estimates transmission investments of approximately USD 1 billion to USD 1.5 billion through 2030 associated with these projects. ITC is working on finalizing the timing and costs associated with these projects. In the coming months, we look forward to determining which will be included in our 5-year capital plan.

Next, the $1.7 billion Lake Erie Connector project continues to advance. In March, Province of Ontario issued an Order in Council and Ministerial Directive to the IESO to negotiate with ITC on finalizing a transmission service agreement on or before August 15, 2022. The proposed 1,000 megawatt direct current underwater transmission line will provide the first direct interconnection between the wholesale electricity markets operated by the IESO in Ontario and the PJM interconnection in the United States. This project will be additive to our growth outlook. With a strong track record of increasing dividends for the past 48 consecutive years, coupled with our low-risk growth strategy, we remain confident in our 6% average annual dividend growth guidance through 2025.

Now I will turn the call over to Jocelyn for an update on our first quarter financial results.

[Jocelyn Perry, executive]

Thank you, David, and good morning to everyone.

Turning to Slide 13 and looking at the first quarter results. Adjusted net earnings of $369 million or $0.78 per common share was $0.01 higher than the first quarter of 2021. We continue to see earnings growth driven by rate base growth across the group and the recovery of the tourism industry in the Caribbean. Hydroelectric production was lower in Belize this quarter and Central Hudson also experienced higher operating costs. The waterfall chart on Slide 14 highlights the EPS drivers for the quarter by segment. As mentioned, we continue to see rate base growth across our utilities, supported by investments of nearly $1 billion during the quarter. Combined, our Western Canadian utilities and ITC contributed a $0.03 EPS increase driven mainly by rate base growth.

At our other electric segment, EPS increased $0.01 driven by sales growth in the Caribbean as a result of the tourism-related activities with first quarter sales up 3% from pre-pandemic levels. At Central Hudson, earnings were favorably impacted by rate base growth and the conclusion of its rate case in 2021. However, they did experience higher operating costs associated with the implementation of a new customer information system and restoration costs associated with winter storms, decreasing EPS by $0.01 for the quarter.

For our Energy Infrastructure segment, EPS decreased by $0.01 due to lower hydroelectric production in Belize. Production in the first quarter of 2022 was 17 gigawatt hours compared to 53 gigawatt hours in the first quarter of 2021, and this was due to lower rainfall. As expected, with our dividend reinvestment plan, EPS decreased by $0.01 due to higher weighted average shares outstanding.

And finally, while not depicted on the slide, earnings at UNS were broadly consistent with the first quarter of 2021 and in line with our expectations. UNS benefited from higher long-term wholesale sales, transmission revenues, customer growth and lower planned maintenance costs. Earnings in the quarter were offset by the timing of earnings associated with the Oso Grande wind generating facility.

Turning to Slide 15, we were once again active in the debt capital markets with our regulated utilities raising over $900 million in long-term debt, largely in support of their capital programs. With the backdrop of a rising interest rate environment, several of our utilities accelerated debt issuances in the first quarter, locking in attractive rates. ITC also entered into additional interest rate swaps to mitigate refinancing risks. Our recent debt issuances, coupled with over $3 billion available on our credit facilities, places us in a strong liquidity position, supporting our $20 billion 5-year capital plan that David referred to earlier. We continue to maintain strong investment-grade credit ratings. In March, S&P confirmed our A- issuer credit rating and BBB+ unsecured debt rating and stable outlook. We are comfortably positioned within our existing investment-grade credit ratings, providing financial flexibility as we pursue incremental growth opportunities.

Turning to recent regulatory updates. First, ITC continues to await a final rule from FERC in relation to the supplemental Notice of Proposed Rulemaking or NOPR on transmission incentives, which proposes to eliminate the 50 basis point RTO return on equity incentive adder.

Next, FERC issued a NOPR in late April addressing regional transmission planning and cost allocation stemming from the initial advanced NOPR released last year. The NOPR contains several constructive proposals, including a requirement that transmission planning regions conduct long-term plan, a formal role for states in developing the cost allocation for projects and the reinstatement of federal right of first refusal under certain circumstances.

Initial comments on the proposal are due 75 days from the date of publication. And earlier this week, TEP submitted a notice of intent with the Arizona Corporation Commission, or ACC, to file a general rate application in June 2022, requesting new rates to become effective no later than September 1, 2023.

The application will seek new rates using a 2021 test year that addresses infrastructure investments made since the last rate case as well as changes in fuel and non-fuel operating expenses. The filing will also include proposals to eliminate certain adjustor mechanisms as well as modify an existing adjustor to provide more timely recovery of clean energy investments. In British Columbia, the generic cost of capital proceeding continues this year and the effective date of any changes in the cost of capital parameters remain unknown.

In March, the Alberta Utilities Commission issued a decision on the 2023 generic cost of capital proceeding, Fortis Alberta's current cost of capital parameters were extended for 2023. The AUC also confirmed it will begin a separate process later this year for cost of capital for 2024 and beyond, including the consideration of a formula-based approach.

And that concludes my remarks. I'll now turn the call back to David.

[David Hutchens, executive]

Thank you, Jocelyn.

We are pleased with the progress our team has made in the first quarter to advance our sustainability and growth initiatives. With the 2050 net-zero target, we are building on our commitment to deliver a clean energy future while ensuring the affordable and reliable energy service, our customers demand. With our regulated transmission and distribution business, highly executable capital plan and CapEx runway, we are in a strong position to support our dividend growth guidance through 2025.

I will now turn the call back over to Stephanie.

[Stephanie Amaimo, executive]

Thank you, David. This concludes the presentation. At this time, I'd like to open the call to address questions from the investment community.

[Operator]

[Operator Instructions]

Your first question comes from the line of Maurice Choy from RBC Capital Markets.

[Maurice Choy, analyst]

My first question is to follow up on the MISO LRTP. You quoted the USD 1 billion to USD 1.5 billion of investment in Tranche 1, which represent around 10% to 15% share of the overall cost. Was this in line with your expectations? And as a follow up besides the MISO board approval, what are some of the variables that remain unknown right now that if you have better visibility, you'd be able to finalize the subset higher or lower and the timing of the capital spend.

[David Hutchens, executive]

Yes. Thanks, Maurice, and thanks for that question. I should start off by letting everybody know that we actually are in person for the first time with this entire team for an investor call in 3 years. So it will be great to be able to send some of the details of these questions to our team that's actually sitting right here in the same room in St. John. So I wanted to start out and let people know that.

But on the MISO long-range transmission plan, yes, that's the USD 1 billion to USD 1.5 billion that we put out there, is our current best estimate based on the projects and based obviously on the initial cost projection that MISO has put out there. As you noted, it's Tranche 1 of future 1. So what's going to happen further in the future related to the remaining tranches and whether or not we go into the future 2 and 3 scenarios as well remains to be seen. Obviously, timing around the MISO board approval of the projects, getting those details, figuring out the timing of construction. And of course, doing our own project cost estimates, will all be things that will go into the mix as we go forward and what we expect to get more visibility on that with each step that MISO takes going forward.

So I think you asked about expectations. We're pleased -- $1 billion. So we forget how much money $1 billion is. The USD 1 billion to USD 1.5 billion of additional projects that aren't currently in our forecast is a pretty big chunk. And of course, these things are going to come in, in varying -- as you do, these tranches will come in, I'll say, kind of in varying areas. So we're not sure how to really project what the next tranches might be. Was this maybe light in our footprint? Will the next one, if you have a different weighting in our footprint? That stuff is really hard to get clear visibility on.

[Maurice Choy, analyst]

And maybe I'll just pick on -- sorry, a quick follow-up. I suppose the spending occurs within the next 5 years; how do you see yourself managing the funding for the spend?

[Jocelyn Perry, executive]

Yes, Maurice, I think it's early to talk about specific funding for this. I think we need to get visibility of the timing because we do expect some of it, I would think, to extend beyond the 5 years. So when we firm up the timing, we'll firm up the funding, but I've said a number of times, we've been pleased with where we've moved the balance sheet, so not looking to move that backwards too materially or forward too materially. So I don't expect there to be a complicated funding plan, but stay tuned and we'll firm that up as we affirm the timing of these capital expenditures.

[Maurice Choy, analyst]

And my final question is on the net-zero 2050 target, and congrats on that. I assume the look at Slide 7, many of the initiatives you've shown in there relate to initiatives that get you to your 2035 midterm target. So I assume much of what gets you to net-zero by 2050 related to Arizona. And if so, what are some of the post-2035 initiatives there? And your thoughts on navigating through the affordability theme that tie on the regulated agenda in Arizona?

[David Hutchens, executive]

Yes. So the last -- well, the majority of that last 25% is related to gas generation in Arizona, and that's the part that we're going to have time to figure out exactly how we address that. Remember, this is a net-zero target. We've got a really solid and defined plan of how we get from the 2019 emissions to that 75% reduction as laid out in that slide. And most of that's activities related to the generation in Arizona. That last 25% will need new technology. We do have gas generation down there. we'll need cleaner fuels, things, possibilities like hydrogen, renewable natural gas, carbon capture and storage. It's hard to say where -- which technology will win, but we want to make sure that we've got a view on all of those.

So the path after 2035 is obviously less clear at this point because it's so far out and so much to be done from a technology perspective. but we will make sure -- I mean, that is -- you mentioned our guardrails, and it might sound like we talk about these words so often that we forget how meaningful they are, but the affordability and reliability of our service to our customers is going to be most important and is right in the visibility of our regulators and customers as we sit here today, more so than probably any time in the past as well, at least in recent memory.

So we will make sure that the things that we do are in line with that. And so we'll keep an eye on it. And obviously, our industry is keeping an eye on this, looking for those technologies that can help us accelerate what we're doing and continue what we're doing down to the efforts of net-zero. And I should say that when you get out there, 2 offsets are an option as well. We don't need offsets to get to that 75% Greenhouse Gas Reduction goal that we currently have in 2035, but that's got to come into play in the future.

[Operator]

Your next question is from the line of Linda Ezergailis from TD Securities.

[Linda Ezergailis, analyst]

I'm wondering if you could give us some more thoughts on the Lake Erie Connector. Specifically, how confident are you in your $1.7 billion cost estimate? Maybe you can give us a sense of how much contingency is there? Or is that estimated future costs or how much that might go up. And then what would be the key gating factors beyond this August 15 deadline to get to an FID and how this proceeds.

And I guess my final question related to Lake Erie Connector is around the Ontario provincial election and how that might affect the timing or potentially the outcome of this project?

[David Hutchens, executive]

Yes. So you mentioned the OIC, the Order-in-Council that we received, and that they did give -- they gave the IESO, a deadline of August 15 to get a transmission service agreement signed up. That is the next big gating item. Now as far as costs go, that's the things that we're working on is to finalize that. We don't have anything that we can disclose publicly as we try to finalize all of the details within that negotiation process. Obviously, cost is a big one.

We're going to need EPC Contracts out there, et cetera. So all of those pieces will be filled in over the next few months and are obviously have to be known before we get to that TSA. So that's the big gating item. Obviously, besides our own internal approvals as well as MISO's approval, which you referenced there from an election perspective, I would -- the plan that we have here in the TSA timeline here, we don't see that, that would be affected by the timing of the elections in Ontario. This is -- and to be frank, this is a great project. So it will stand on its own merits. We think no matter who's looking at it, and that's always been the goal for a project like this is to show those the benefits -- the cost benefit ratio that we have and that it's a good project. So we're not concerned about, from an electric perspective.

[Linda Ezergailis, analyst]

And maybe just a bigger picture conceptual question around bill pressure for your customers and just the inflationary environment that we're seeing. How are you thinking across your jurisdictions around mitigating that impact on customer build? Might you see regulators potentially try to dial back capital expenditures to mitigate the operating expense pressures? Might you see more deferral accounts or potentially changes in depreciation rate to the extent that certain assets could have a longer life than initially anticipated? Might there be also some friction around ROE going up even as interest rates and inflation marches up?

Can you talk about how you're thinking about approaching that and what you're hearing from other stakeholders?

[David Hutchens, executive]

Yes, you hit on, I think, every single category that I would list. But it is obviously right in the center of every conversation that we have with our regulators and with our customers making sure that we are, particularly in this inflationary environment as well as high natural gas and purchased power costs across North America, well across the world for the most part. Those are things that we have to really be paying attention to because not only does it matter to our customers and our regulator, it matters to us that our customers are having to pay that much.

So we're looking at ways of helping them mitigate their bills. We do the standard stuff only in much more rigor, things around promoting energy efficiency, conservation, build management, levelized billing, things like that. We do know and recognize that when there are big spikes in pass-through costs because these are costs that we don't make any money on in our regulated utilities that we look at ways of helping our customers. And some of those you've mentioned, deferrals that we have at a couple of our utilities now that are spreading out the cost recovery. So the current impact isn't so severe.

We have to make sure that we're paying attention to that and watching not just the bill impact on the customers. But of course, that affects our cash flow, which means we really have to be focused on other ways of reducing costs across our organization. O&M, Operations and Maintenance et cetera. Those are some of the big ones. Bill assistance is, I think, another one that we've been steering our customers too because they're our federal billing programs that can help at least down in the U.S. that can help people pay their bills. So those are most of the items as far as the regulators and how are they seeing this.

Nobody likes increasing costs and rates, no matter how justifiable they are. I don't see or don't hear any conversations related to slowing down CapEx because this CapEx is needed for a variety of very strong policy requirements. Obviously, reliability for one, as I mentioned earlier, making sure we're making the investments in our systems that can manage the increasing severity of storms, et cetera, but also shifting to clean energy. Some of the ways that we do that like in Arizona, even save our customers' money. So that's good. That's a no-brainer capital expenditure.

But some of the other ones on resiliency, adaptation, things like that, we have to make sure that we're doing those in the most responsible manner that we can and then the timing that we can to manage those -- the overall bill impact.

[Operator]

Our next question is from the line of Rob Hope from Scotiabank.

[Robert Hope, analyst]

I just want to touch on the Tucson Electric refiling that we should be expecting next month. What are the key things that are you looking for in the new rates, whether it be kind of a higher ROE, clean energy tracker? Can you just kind of add a little bit of color there?

[David Hutchens, executive]

Yes. We've got a batch of normal stuff in what I'll call normal stuff in a rate case. So you look at things like rate design and cost allocation. Obviously, we have a chunk of rate case that has increased that we'll be asking for. We will look for higher ROE. We think we got a pretty low one in that last rate case. It was at the end of -- end of 2019. So it was end of 2019. Is that right?

Yes, end of 2020. And that was obviously right in the middle of COVID. And we think that we have a good argument for getting a bit of a stronger ROE in that jurisdiction, particularly with the backdrop of where we see interest rates right now. As far as the clean energy tracker, Susan and her team are doing a great job of looking at how we can reduce some of the trackers and transition away from them, things related to -- things like the DSM, Demand Side Management, energy efficiency, et cetera, and replace those and even the renewable energy tracker and replace those with a new clean energy tracker.

And I know I've talked about that with you all in the past. And that's a real important part of our rate filing because that will allow us to invest and accelerate our investments in clean energy and be able to get more prompt recovery of those investments through a tracker mechanism.

[Robert Hope, analyst]

All right. That's helpful. Appreciate the color. And then just as a follow-up, just on the Lake Erie Connector project, let's assume that we get a contract in Q3, Q4 for that -- when do you expect to mobilize on that project? And kind of when would capital start to be put out the door there?

[David Hutchens, executive]

Yes. So I'm going to kick that one over to Linda, as the CEO of ITC and she's got those details.

[Linda Blair, executive]

Yes. Great. Thanks, Dave, and thanks, Rob, for the question. With respect to -- I would say presuming everything goes as we would anticipate, if we were to have with all the agreements in place. Yet this year, we would anticipate that we would be sort of preparing and readying for construction starts in the first half of next year. And I think as we have mentioned before, it is a [ 4-year ] anticipated construction. So that would put us into the first half of 2027, assuming all those as anticipated between now and getting the agreements in place.

[Operator]

So your next question is from the line of Ben Pham from BMO.

[Benjamin Pham, analyst]

May I start off with the recent rise in interest rates. And maybe you could remind us what percentage of your utilities you can seamlessly pass through higher interest expense? And maybe comment on your debt position. And then you also mentioned the low ROE at TEP. Any other utilities we have automatic adjustments to the ROE, you see the base ROE moving up? Is a good chance to maybe move more aggressively on that area.

[David Hutchens, executive]

Yes, I'll talk a little bit about the inflationary impacts from a rate perspective at the subs and kick over to Jocelyn to talk about the impact, debt, timing et cetera. But I suppose I should first say we don't really have like a good thumb rule for what the percentage of our costs that would be able to be passed through on a sort of Fortis wide basis because we have different regulatory constructs in our jurisdictions, everything from ITCs, which basically just a matter of timing, but we'll get -- it can pass through all their costs at their full formula transmission rates to [ PVR ] methods that vary in the level of interest and how that's treated on the annual true-ups.

It's a little bit different in BC than Alberta and Ontario, but they all generally have mechanism for capturing at least a good portion of that -- of the higher costs from inflation et cetera. And then, of course, in Arizona, it's a historical test year. So those are risks that we would bear and then recover it in the next case. -- just one of those things that kind of go up and down based on the rate case timing.

I'll turn it over to Jocelyn to answer the interest rate question.

[Jocelyn Perry, executive]

Yes, Ben, with respect to your question on the rising interest rates, not that we're not doing all the right things to manage rising interest rates for customer affordability because we're doing that. But we do have a number of various regulatory mechanisms in each of our utilities that actually does provide for a rising interest rate environment. So ITC would have an annual true-up and we have other various mechanisms in each of other facilities. With the exception, as David talked about with UNS because they are on a historical test year. So obviously, they play catch up with interest rates -- rising interest rates when they go to set rates, which they'll do with this particular test year that they are about to file. I would say, so the most exposure outside of UNS will clearly be in the holding company.

And within our disclosures this quarter, as we've identified that, we have entered into further interest rate swaps to actually mitigate some of that refinancing risk. So we are doing the right things. And even at the regulated utilities, I would say we were pretty active this quarter in terms of advancing some of the debt issuances regardless of the regulatory mechanisms that we have. We're doing the right things in terms of getting in front of the curve so that we can actually try to combat some of the impact on our customers.

[Benjamin Pham, analyst]

And then on the ROE, is there any obvious outliers there where it's well below North American utility averages or relative to what the [ CapEx ] is? [ Just tell me ] will you [ be there ] in the 30 year?

[David Hutchens, executive]

Yes. We don't have any tracking -- ROEs to track currently. So there is a general generic cost of capital going on, in BC. Obviously, the case in Arizona will go through its own calculations to determine the right ROE when we do that rate filing. Alberta has pushed their existing capital structure and ROE out another year, and then we'll start a generic cost of capital later this year that will be in effect in 2024. Other than that, there's not any adjustment mechanisms that would be changing it on the interim basis.

[Benjamin Pham, analyst]

And then maybe switching to Woodfibre, and there's a recent article around the second pipeline being proposed through a tunnel and there's some references to the costs going up by, I think, [ $300 ] million plus. So I'm just wondering if you can comment on that. And is that on that cost, if that's correct? And if you can recover that in rate base.

[David Hutchens, executive]

Yes. So I'll give you to Roger here for the details. But it is good to see the progress that's being made on that project in general. Woodfibre did put out a notice to proceed in April to its main contractor. That's obviously the LNG facility contractor. We're building the pipeline, which that tunnel is part of -- and I'll let Roger give you the details on that.

[Roger Dall’Antonia, executive]

Ben. Thanks for the question. So the 2-tunnel issue is a bit of, I think, confusion from the reporter. The second pipe -- sorry, one tunnel, 2 pipe relates to the design under the [indiscernible] Squamish estuary. There's about a 9-kilometer tunnel building under the estuary -- we're going to be backfilling that tunnel, so it will be very difficult to access the pipe. So we're putting in a second pipe for redundancy and reliability so that Woodfibre not be disrupt as a service. And now it's just an evolution of design.

I think there was reported there were 2 pipes serving Woodfibre. It's one overall pipeline system that we're expanding to serve Woodfibre, but a second pipe for redundancy in the tunnel portion. As far as cost, a number of the costs are being finalized. We are seeing a little bit of pressure, but not significant at this stage.

[Benjamin Pham, analyst]

Okay. You would say that the reported -- that cost referenced may not be reliable at this point in time?

[Roger Dall’Antonia, executive]

For the pipeline or for the Woodfibre LNG facility?

[Benjamin Pham, analyst]

It is for the pipeline.

[Roger Dall’Antonia, executive]

Yes, we are seeing some cost increases on pipe. But as far as the overall cost, we're still finalizing our cost estimates.

[Operator]

Our next question is from the line of Mark Jarvi from CIBC Capital Markets.

[Mark Jarvi, analyst]

Want to come back to the topic of affordability. Is there any discussions? Have you heard anything in terms of either at a federal level or state level in terms of either it's like a subsidy or some other way to help alleviate customer bill pressure while still allowing utilities to make the media investments around decarbonization might obviously at the federal level, there was talk of the CPP, which has been gaining traction? Was there anything else at the state level or anything else at the federal level, you think can be done to help manage affordability while still doing the rate on decarbonization.

[David Hutchens, executive]

Yes, none that we know of other than the pieces of the build back better plan if those come back in those tax credits start flowing that. That can really help. But nothing from a state level that I'm aware of across our jurisdictions anyway.

[Mark Jarvi, analyst]

And just obviously, on the NOPR that went through FERC, a couple of weeks ago. Just any sort of initial thoughts on that, the Federal ROFR, cost allocation in terms of bringing in the stage. Is there any chance that the involvement of state utility commission slows the process at all? Just sort of what your sort of initial thoughts are on that as you digested it.

[David Hutchens, executive]

Yes. We're still digesting all the details. Obviously, it's out there for comments. But overall, it's constructive. I mean to get better, more defined planning process to get more transparency in the planning process, to have these cost allocation discussions and bringing the states in, that I think is probably where you get most of the rub is, if you get states involved early, it should help out the process. I wouldn't think it would slow it down.

And then, of course, the federal ROFR rights for certain projects and situations, that's a positive for us as well with ROFR rights in 3 states in the Midwest.

[Mark Jarvi, analyst]

Good. Last question. Just I think there's a refund that has to go for Tucson Electric in terms of some of the peak prices that happened at summer of 2020. Can you just comment on how much that is and whether or not that's going to flow through adjusted earnings?

[David Hutchens, executive]

Say that again.

[Mark Jarvi, analyst]

I believe there was like an order saying there has to be a refund from a handful of utilities, including the TEP, back to some high commodity charges in the summer of 2020. I'm just curious if you guys -- if that's right and how much it is and whether or not there's an earnings impact?

[David Hutchens, executive]

The first I heard of it, and we're looking physical here, so I don't -- we don't know anything on that one.

[Operator]

Next question is from the line of Richard Sunderland from JPMorgan.

[Richard Sunderland, analyst]

Good morning. Thank you for the time today. Maybe just circling back to the rate case and thinking about the Arizona regulatory backdrop more broadly, you obviously have some activity in the state and then a big one coming with TEP here. Any sense on kind of reading the key leaves on sentiment and how things stand from a regulatory backdrop maybe with you versus other peers in the state, given some of the noise you've seen in the state over the past few years.

[David Hutchens, executive]

Yes. I've said repeatedly that we've got a good relationship with our regulators in Arizona, even though it might be a bit more of a tangly relationship for others in that jurisdiction. As I mentioned earlier, the 2020 rate case, we got a good outcome. I told you I wasn't a fan of the ROE. But other than that, a very, very constructive outcome on post test-year plant, getting 2 new trackers, all of those things really were positive and constructive from our view. So we're taking that long history of working with trust and transparency with our regulators every time we go up there, and that will give us the ability to get good outcomes, good reasonable outcomes. And we know it's -- that's the way we have to manage these relationships, and it's how we continue to do it.

[Richard Sunderland, analyst]

Fair enough. It's very helpful. And then apologies if I missed this earlier, but just thinking about the net-zero outlook and your long-term environmental goals just in light of today's update, can you speak to how RNG fits into the larger picture here?

[David Hutchens, executive]

Yes. RNG can fit into the larger picture. Specifically in this call, we're talking about Scope 1 emissions and that can fit into a piece of, say, the gas generation in Arizona, which will be that 25%, that's left after 2035. So it does play a role there. It's hard to say how much of a role as we sit here today versus hydrogen, et cetera. It also plays a role in us focusing on, say, Scope 3 emissions that we do up in British Columbia, we do have a strong goal of getting 15% of our supply from renewable gases in British Columbia. That's a big chunk of natural gas. And RNG is playing a big part of that. The team up there has done a great job in pulling together contracts for a good portion of that already and has the eye on being able to figure out the last percentage, a few percentages there that they need by the 2030 deadline that they have for that 15%.

[Operator]

Our next question is from the line of Andrew Kuske from Credit Suisse.

[Andrew Kuske, analyst]

I mean, you're in an interesting position because you've got transmission opportunities in both Canada and the U.S. And maybe the question is directed to Linda, but how do you think about the benefits associated with either of those jurisdictions. And in one case, obviously, it's intertwined, given you're connecting the 2 countries.

[David Hutchens, executive]

Yes, go ahead, Linda.

[Linda Blair, executive]

Maybe just from a little bit of history, certainly, we do think our geography is strategic. And if you think back to actually what ITC stands for, it is International Transmission Company. and it was originally developed on the premise to take advantage of our unique geography and our close geographies to Ontario. Certainly, as we continue to develop the Lake Erie project, I think it sort of brings us back to our roots in terms of sort of how we envision the business and that strategic geography.

So I think we are well positioned, certainly, as markets evolve, both in the U.S., particularly the Midwest ISO as well as how the Ontario market evolved. They did evolve in different directions. And so certainly, we are, I think, very pleased from a strategic perspective that we are able to leverage the geography. And I think it does give us some further, I don't want to call them opportunities, that would be premature.

But I think just in terms of thinking and thinking about taking advantage of sort of the border and certainly a project like the Lake Erie project, but it certainly puts -- gives us a foot with experience in terms of undersea cable technology. So certainly, we certainly view this project as something that we hope that we could leverage into the future.

[Andrew Kuske, analyst]

Okay. That's helpful. And then cyber was mentioned earlier on the call, and obviously, that's critical in normal course of business operations and the cyber capabilities that you've got, especially at an entity like ITC, immensely capable. Do you see this as a competitive advantage at this point in time to maybe roll up other utilities into the future that don't have that kind of capability? Or is it really just a competitive necessity at this stage?

[David Hutchens, executive]

Yes, I think it's just a flat-out necessity at this stage. I don't think we would look at -- put that as maybe a competitive advantage from an acquisition standpoint. But the competitive advantage is the fact that we have such a great -- we have great teams across our entire footprint. But ITC, given their huge transmission footprint and how big their systems are, they had really strong depth in their IT world. That's why our CIO from a Fortis Inc, perspective, we sold them from ITC and brought them up to Fortis Inc. to help coordinate that across the entire organization. And that's that type of double layer of skills that we have across our organization are able to share that skill, is a competitive advantage for us because we were able to take best practices and push them across the entire organization. And obviously, that's just one of many ways that we work our business model.

[Operator]

Our next question is from the line of David Quezada from Raymond James.

[David Quezada, analyst]

Just one for me, and it just relates to your, I guess, near-term planning horizon to renewables of TEP. Just curious if you can provide any color on what you're looking to procure over that period and if the Department of Commerce investigation into solar panels from Southeast Asia, I mean, related tariffs there could cause you to juggle any kind of -- type of projects between wind and solar in that area?

[David Hutchens, executive]

Yes. We don't really have much of an impact yet on the tariff issue on both TEP and our smaller subsidiary, UNS Electric and Arizona put out RFPs last month. And we're looking for a good chunk of renewables that can be PPAs build on transfer et cetera, both for renewables and for firm capacity, which can be in the form of batteries or other generation alternatives. So we'll have better answers for that, when we get midyear when we start seeing the results of those -- of that RFP. And then later in the year, when we actually analyze them and assign or enter into contracts related to that process.

[Operator]

Our next question is from the line of Matthew Weekes from iA Capital Markets.

[Matthew Weekes, analyst]

I think I was just going to ask about the quarter and some of those costs related to Central Hudson, just wondering if those are really transitory kind of one time cost to implement those systems or if you're expecting any more going forward. And then on the other side, looking at, I think, some commentary in FortisBC about some lower expenses there. Were there any sort of timing-related impacts there? Was that just due to effective cost management and productivity savings on the O&M [ MA ] side there?

[David Hutchens, executive]

Yes. First on the CH, I'll answer these pretty quick. First on the CH, they are transitory, they're related to that system implementation. So we're not expecting repeated cost impacts on a going-forward basis. And of course, Charlie and his team are working hard to figure out how to offset some of those cost impacts as we go throughout the remaining part of this year. On the BC one, I think that is just good old strong O&M management by the team up there and not timing.

[Operator]

Our next question is from the line of Michael Sullivan from Wolfe Research.

[Michael Sullivan, analyst]

Wanted to circle back to this upcoming rate case filing that you have in Arizona. Can you just remind us how much you've added to rate base in that jurisdiction since the last case? And then on the fuel power side, just how we should be thinking about that impact on the overall bill and how that fits into the case filing?

[David Hutchens, executive]

Yes. So we don't want to front run the filings. So we're putting all those numbers together because there's a lot of stuff that goes into that. Not just the test year that we've obviously already closed, but also post test year adjustments and other things that we may need to be looking at. So don't want to -- the #1 thing about your regulators don't surprise them by saying stuff before they know it. So I can -- we'll save that for the June filing.

[Michael Sullivan, analyst]

Okay. Maybe on the fuel and purchase power that you just got an order on, what sort of bill impact there was there? And then how to factor that into the future?

[David Hutchens, executive]

Yes. So it was only, I think, around 3% was the overall bill impact of the purchased power and fuel adjustment clause that we just got approved, and that's -- that 3% was for historical costs that will be then collected over the next 18 months.

[Michael Sullivan, analyst]

Got it. Okay. And shifting over to the MISO transmission. Can you clarify the USD 1 billion to USD 1.5 billion, is that just in the ROFR states that you're in? Or that's across your footprint and the ROFR states is a piece of that.

[David Hutchens, executive]

Yes. I'll turn that over to Linda to answer.

[Linda Blair, executive]

Yes, the projects that comprise the USD 1 billion to USD 1.5 billion, those projects are either in Michigan or Iowa. And we have state ROFRs in both of those states. So I think in answer to your question, the projects that have been identified, that are ITCs, would be in ROFR states. There are no other projects identified that would be outside of those states for ITC.

[Michael Sullivan, analyst]

Okay. And could you maybe just give a high-level view of your thoughts on how things may go in the non-ROFR states? Is it still going to be the incumbents largely winning as I think we've seen historically? Or are you sensing maybe there's more openness to competition now?

[Linda Blair, executive]

Yes, I would really hesitate I think, to speculate on kind of what's going to happen in those other states with respect to competitive bidding. As you may know, FERC's recent NOPR on transmission planning included some provisions that suggest that they may be open to reinstating federal rights of first refusal, if projects are jointly owned. And while we don't specifically truly know or understand what FERC might be thinking or certainly where they might make a decision. But certainly, if that's proceeding were to proceed, and there was a decision, and I'm using a lot of if, if there was a decision, perhaps whatever may come out of that NOPR in a final order perhaps could apply back to these projects in non-ROFR states. So I'm talking pretty high level off the cusp because I think, really, the best answer is we don't know yet what might happen in those other states and how incumbent utilities may position themselves or how developers or people who are participating potentially in that competitive solicitation process.

We don't know where they might bid or how they would bid, who they would partner with. So I think there's a lot of unknowns at this point in time to truly understand what that means. But what I would say, just as that we really expect to ITC. I just maybe -- perhaps to the little bit of our own horn, I think sort of anticipation of this tranche 1 portfolio process, I think that's why we were so focused on securing the right of first refusal in the states where we have predominantly most of our assets.

And so the timing we just completed, getting our state ROFR in Michigan late last year. And so certainly from our perspective, the timing was critical so that we could secure the rights to these projects that have been identified.

[Operator]

Your next question is from the line of Dariusz Lozny from Bank of America.

[Dariusz Lozny, analyst]

Just wanted to touch on the Arizona rate case filing briefly. Can you maybe just talk a little bit about what your -- I guess what the strategy is, number one, behind the timing of filing midyear. I think one of the other utilities in the state also is looking to file probably around the same time? And then secondarily, in terms of the goal of reducing the number of riders out there.

Anything strategic that you're trying to accomplish as part of that? Or is it just trying to align with the commission stated goals of having fewer riders out there?

[David Hutchens, executive]

Yes. I think the last part first, yes, it's aligning with goals of both the commission and other stakeholders looking to simplify the number of riders. And it helps us as well so that we don't have so many proceedings going on all the time. So getting the fewer good straightforward riders is better than having a bunch of small ones. And as far as the rate case timing, we make the decisions based on what we need to do, not what other utilities may or may not do. So we were used in the last test year and the last full year that as a test year, and this is the time that we could get all our numbers together and the time that we need to go in and address the rate shortfall we have in rate case.

[Dariusz Lozny, analyst]

Okay. One more quick one, if I can, just on the quarter. It looked like sales at Central Hudson ticked down about 3%. Was that a weather-driven number? Or was there anything else attributable to that?

[David Hutchens, executive]

Charlie, do you have the details on that?

[Charles Freni, executive]

I would say it's probably more weather-driven than anything else. I mean certainly, pricing resulted in customers cutting back as well. But we have revenue decoupling. So I think ultimately, that works through, through the course of the year, particularly as we work through sales -- unbilled sales as well.

[Operator]

Thank you. As there is no further question, I would like to turn the call back over to Ms. Amaimo.

[Stephanie Amaimo, executive]

Thank you, Ruel. We have nothing further at this time. Thank you for participating in our first quarter 2022 results conference call. Please contact Investor Relations, should you need anything further. Thank you for your time, and have a great day.

[Operator]

Thank you for participating, ladies and gentlemen. This concludes today's conference call. You may disconnect.