Fortis Inc. (NYSE:FTS) Q4 2023 Earnings Call Transcript

Fortis Inc. (NYSE:FTS) Q4 2023 Earnings Call Transcript February 9, 2024

Fortis Inc. isn’t one of the 30 most popular stocks among hedge funds at the end of the third quarter (see the details here).

Operator: Good morning everyone. Thank you for standing by. My name is Lara, and I will be your conference operator today. Welcome to the Fortis Q4 2023 Earnings Conference Call and Webcast. During the call all participants will be in a listen-only mode. There will be a question-and-answer session following the presentation. [Operator Instructions] At this time, I would like to turn the conference over to Stephanie Amaimo. Please go ahead, Ms. Amaimo.

Stephanie Amaimo: Thanks, Lara, and good morning, everyone, and welcome to Fortis’ fourth quarter and annual 2023 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 2023 MD&A. Also, unless otherwise specified, all financial information reference is in Canadian dollars. With that, I will turn the call over to David.

David Hutchens: Thank you and good morning everyone. Today we are pleased to report strong 2023 operational and financial results. During the year, we provided reliable service to our customers, invested $4.3 billion of capital in our energy systems, concluded key regulatory applications, sold the non-regulated Aitken Creek natural gas storage facility, and further reduced our carbon emissions. Adjusted EPS grew approximately 9%, excluding foreign exchange impacts, with rates growth and the regulatory outcomes in British Columbia and Arizona serving as key drivers. And with our track record of executing a regulated growth strategy, we increased our fourth quarter dividend by 4.4%, marking 50 consecutive years of increases in dividends paid, a milestone of which we are very proud.

Our utilities operate electric and natural gas transmission and distribution systems across North America, and we know that the safety and reliability of the service we provide is imperative to our customers and employees and is embedded in everything we do. In 2023, our metrics were top quartile for safety and reliability relative to our North American peer benchmarks. As we make the necessary investments in our utilities, we remain focused on managing customer bill impacts. While we have limited control of energy commodity costs and higher interest rates, both of which are passed through to our customers, we continue to manage operating costs through these innovation and process improvements. We also work with our customers to help them manage their bills through our energy efficiency and demand-side management, or DSM, programs.

Just last week, the British Columbia Utilities Commission of [ph] FortisBC’s 600 million DSM plan for 2024 through 2027. This plan continues cost-effective initiatives for customers to save on energy use, while incorporating new programs to further align with the CleanBC roadmap to 2030. Customer affordability is critical as we execute our clean energy goals and invest in the resiliency of our energy systems. We continue that track record of dependable shareholder returns despite a challenging year for the utility sector. In 2023, we delivered an annual total shareholder return that ranked in the top quartile of our utility peer group. Over a 20-year period, we have had an average annual return of approximately 11%, significantly higher than the returns generated by the benchmark indices.

Through 2023, we achieved a 33% reduction in Scope 1 emissions compared to 2019 levels. The closure of the coal-fired San Juan generating station in June 2022, as well as the start of seasonal operations of the Springerville Units in 2023, contributed to the emissions reductions. With this continued progress, we are on track to achieve our targets to reduce Scope 1 greenhouse gas emissions 50% by 2030, 75% by 2035, and net zero by 2050. While all of our utilities play a part in reducing carbon emissions, the bulk of the reductions will be achieved through the execution of TEP’s integrated resource plan. In November, both TEP and UNS Electric filed their 2023 IRPs with the Arizona Corporation Commission. TEP’s IRP calls for the addition of over 2,200 megawatts of renewable generation, over 1,300 megawatts of energy storage, and 400 megawatts of natural gas peaking units through 2038, and supports the closure of TEP’s remaining 900 megawatts of coal-fired generation by 2032.

This balanced portfolio supports the delivery of cleaner, reliable, and affordable energy for our customers. The new natural gas capacity will accelerate renewable energy additions and will support TEP using less coal generation through 2032, further reducing cumulative Scope 1 emissions. In December, TEP and UNS Electric issued a joint all-source request for proposals, seeking new resources and support of the IRPs. The RFP calls for over 600 megawatts of renewables and energy efficiency resources, and over 800 megawatts of firm capacity. As for the next steps on the IRPs, we expect a decision from the ACC in the fall. Looking ahead, we expect to release our climate report during the first quarter of 2024, showcasing the climate scenario work completed by our utilities over the past two years to ensure we are building climate resiliency into our operations.

In the third quarter, we announced our highly executable, low-risk $25 billion five-year capital plan, our largest to date. In the fourth quarter, as part of the Iowa Right of First Refusal proceeding, a district court placed an injunction on MISO’s long-range transmission projects in Iowa. As a result, ITC’s Tranche 1 projects located in Iowa are currently on hold. Jocelyn will speak to this in more detail in the regulatory update. In late December, the BCUC denied FortisBC’s application for the Okanagan Capacity Upgrade, our smallest major capital project, estimated at approximately $200 million. While the BCUC agreed with the need to address pipeline capacity shortfalls in the Okanagan region, they instructed FortisBC to investigate other options to meet capacity needs and submit a plan by the end of July.

FortisBC’s investment in the Eagle Mountain Woodfibre Gas Line project is now forecasted at $750 million, through 2027, compared to $420 million previously estimated. The increase was a result of amendments made to agreements with Woodfibre LNG and other partners that became effective following the completion of certain conditions, including the BCUC approval of an amended transportation rate schedule. This allows for an increase in our rate base without increasing customer rates. Our five-year capital plan of $25 billion remains on track, supporting average annual rate based growth of approximately 6%. Our next five-year plan is in progress and we expect to release it in the fall. Beyond the plan, we continue to pursue additional opportunities.

ITC continues to work with MISO on tranche two of the long-range transmission plan, and we expect MISO board approval in the second half of this year. In addition, we estimate between US$2.5 billion and US$5 billion of incremental investments through 2038 at TEP and UNS Electric to support their IoTs. We also anticipate growth opportunities associated with renewable natural gas solutions and LNG infrastructure in British Columbia. Across all of our utilities we expect additional growth opportunities to support climate adaptation, grid resiliency and the clean energy transition. As mentioned earlier, we increased our common share dividend in the fourth quarter by 4.4%, marking 50 consecutive years of increases in dividends paid. In 2023, we also extended our 4% to 6% annual dividend growth guidance through 2028, supported by our low-risk regulated growth profile.

Now we’ll turn the call over to Jocelyn for an update on our fourth quarter and annual financial results.

Jocelyn Perry: Thank you, David. And good morning everyone. Before I get into the results, I want to point out that we are now reporting the former Energy Infrastructure segment, which included Aitken Creek and FortisBC within the Corporate and Other segment. With the sale of Aitken Creek in the fourth quarter, we will report FortisBC in this segment going forward. Reported earnings per common share for the fourth quarter of 2023 were $0.78, $0.01 higher than reported in the fourth quarter of the prior year. Adjusted EPS for the fourth quarter of 2023 was $0.72, consistent with the fourth quarter of 2022. Results for the quarter were in line with expectations and reflect the timing of adjustments related to Aitken Creek. As we stated on the last earnings call, Aitken Creek had an effective sale date of March 31 and with the transaction now closed as of November 1, we have excluded adjusted earnings of $24 million, or approximately $0.05 per common share, initially recorded in the second and third quarters of 2023.

The remaining EPS decrease for the Corporate and Other segment reflects lower earnings at Aitken Creek, driven by the timing of the disposition and higher margins recognized in the fourth quarter of 2022. At our regulated utilities the $0.09 increase in EPS quarter-over-quarter was driven by rate based growth, higher retail revenue in Arizona associated with new customer rates at TEP, and the new cost of capital parameters at FortisBC. As David mentioned, we delivered strong EPS growth in 2023. Reported EPS was $3.10, $0.32 higher than 2022. Adjusted EPS was $3.09, reflecting 9% growth over 2022. Our western Canadian utilities contributed an $0.18 EPS increase, $0.10 of which related to the new cost of capital parameters approved by the BCUC in September 2023.

Rate based growth also contributed to the increase. For our regulated U.S. and electric and gas utilities almost half of the $0.12 EPS increase was driven by new rates at TEP effective September 1. Higher retail sales associated with warmer weather and customer growth, an increase in the market value of certain investments that support retirement benefits and lower depreciation associated with the retirement of the San Juan generating station in 2022, also favorably impacted results. Our largest utility, ITC, increased EPS by $0.06, reflecting 6% year-over-year earnings growth. Strong rate based growth and an increase in the market value of investments that support retirement benefits was tempered by higher non-recoverable finance costs. At of our Other Electric segment, rate based growth, higher sales and equity income from the Wataynikaneyap project contributed a $0.02 increase in EPS.

For the Corporate and Other segment, this decrease mainly reflects higher holding company finance costs as well as $0.03 related to lower hydroelectric generation in Belize and lower earnings at Aitken Creek. For 2024, we do expect the sale of Aitken Creek to be neutral to EPS. And lastly, the favorable impact of a higher average U.S. to Canadian dollar foreign exchange rate was partially offset by higher weighted shares outstanding issued under our dividend reinvestment plan. All in all, a very strong growth year across our portfolio of regulated utilities. Looking back, Fortis has delivered rate based growth of 6.5% and adjusted EPS growth of approximately 6% on average annually over the past three years. In 2023, we issued approximately $3 billion of debt to refinance maturing debt and to fund our capital program.

Our primary earnings exposure to elevated interest rates pertains to holding company debt as our regulated utilities ultimately recover changes in interest rates through regulatory mechanisms and periodic rebasing of customer rates. In the upcoming year, we have approximately US$600 million of non-regulated debt coming due, with the maturity at ITC Holdings largely prefunded in 2023. We also have 250 million of preference shares with dividend rate resets in early 2024 and 600 million in December 2024. We’ll continue to monitor the debt capital markets and consider interest rate hedges and additional prefunding opportunities. With proceeds from our debt issuances and the sale of Aitken Creek as well as over 4 billion available on our credit facilities.

We remain in a strong liquidity position to execute our $25 billion capital plan. As we outlined at Investor Day, the majority of our capital plan is expected to be funded from cash from operations and debt issued at our regulated utilities. Equity funding is expected from our DRIP program with a $500 million ATM program available for additional funding flexibility if required. To date, we have not raised any equity under the ATM program. We achieved a Moody’s cash flow to debt ratio of 11.6% and an S&P FFO to debt ratio of 11.4% in 2023, both coming in stronger than our forecast outlined at Investor Day. Our S&P metric was below our new threshold of 12%, which S&P raised from 10.5% in November. S&P also revised its outlook on our issuer rating to negative, citing rising physical risks due to climate change, including wildfires.

We were surprised by S&P’s report. We have a strong track record of managing climate risk, including wildfires and other climate events, and they have not had a significant impact on our operations and financial results to date. Fortis also benefits from constructive regulatory jurisdictions and legal environments. Over the next year, we will continue to engage with S&P on this matter. We do not expect to alter our funding plan, which remains on track to achieve average annual cash flow to debt metrics of approximately 12% over the next five years. As David mentioned earlier, in December, the Iowa District Court ruled that the Iowa ROFR legislation was unconstitutional on procedural grounds. The District Court also granted a broad injunction on the ROFR legislation preventing additional actions on the Tranche 1 projects in Iowa that were previously awarded to ITC Midwest by MISO in July 2022.

ITC has filed a motion for reconsideration with the District Court. While the timing and outcome of the proceeding remains unknown, ITC will continue to aggressively pursue the new ROFR bill in Iowa. It’s important to highlight that the District Court ruled on the manner in which the Iowa ROFR was passed and not on the merits of the ROFR. Further and importantly, MISO is the only entity charged with determining what projects are to be competitively bid pursuant to its tariff. Also, approximately 70% of the Tranche 1 projects are upgrades to ITC Midwest facilities along existing rights of way, which under MISO’s tariff grants ITC Midwest the option to construct the upgrades regardless of the outcome of the ROFR legislation. And furthermore, for any portion of the first tranche of the MISO LRTP projects to be competitively bid, we believe it would require a federal decision that significantly departs from existing rules under the MISO tariff.

Last month, the ACC issued its decision on UNS Electric’s general rate application approving among other things, a 9.75% allowed return on equity and a 54% common equity layer. The new rates became effective on February 1. The ACC also approved a System Reliability Benefit or SRB mechanism. The SRB allows UNS Electric to recover generation investments between rate cases subject to an annual cap and earnings test. The SRB is expected to reduce volatility in customer rates and the frequency of future rate cases. With regards to our regulatory calendar for 2024, the general rate application at Central Hudson remains ongoing as the current three-year plan ends on June 30. The New York Service Commission staff and intervenor testimony was filed in November with staff recommending a one year rate increase including a 9.2% allowed ROE and 48% equity thickness.

This litigated proceeding remains on track. At FortisBC, the current multiyear rate plan concludes at the end of 2024, and an application for the next plan is expected to be filed with the BCUC in the first half of 2024. In Alberta, the formulaic allowed ROE was set at 9.28% for 2024 and will be reset annually in the fourth quarter. Lastly, there are no new updates to report on the outstanding FERC MISO base ROE or NOPRs on transmission incentives at ITC. Overall, we expect a lighter regulatory year as compared to 2023. And with that, I’ll now turn the call back to David.

David Hutchens: We are pleased with our accomplishments in 2023 and we appreciate the contributions of every employee who helped to make last year a success. We recognize that it’s no small task to keep each other safe, deliver reliable service to the customers, invest over 4 billion of capital, obtain key regulatory outcomes, and deliver solid financial results. For 2024 and beyond, we are focused on executing our regulated growth strategy to ensure we continue our operational and financial track record for the benefit of our customers and shareholders. That concludes my remarks. I will now turn the call back over to Stephanie.

Stephanie Amaimo: Thank you, David. This concludes the presentation. At this time, we’d like to open the call to address questions from the investment community.

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Q&A Session

Operator: Thank you. We will now conduct a question-and-answer period. [Operator Instructions] And we kindly request you speak loudly and slowly to ensure all participants can hear your questions. One moment, please, for your first question. Our first question comes from the line of Maurice Choy from RBC Capital Markets. Please go ahead.

Maurice Choy: Thank you, and good morning, everyone. I wanted to follow up on your comments on the funding plan, which you do mention that you do not expect to alter back the Investor Day. Getting to 12% would have meant you had about 100 basis points to 150 basis points of cushion versus your downgrade thresholds. That cushion is obviously, effectively wiped out at S&P when it moved to goalposts. What are some of the push and takes on keeping the 12% target and any proactive actions you’re considering to restore the cushion if the cushion is important to you?

Jocelyn Perry: Hi, Maurice. This is Jocelyn. Yes, it’s a good question. Clearly, that was a big jump in the threshold to go from 10.5% to 12%. So you’re right, we’ve eliminated the cushion. But we do have a plan that sees us getting to on average 12% over the five years and obviously getting above that 12%. We’re going to be laser focused on this of course. And as we go through the year, I mean, we’re always looking at our cash flows and we’re also getting confirmations around certain tax rules. And we thought first that the minimum tax was going to impact us. Now it’s not. So that gives us a little bit of a room to push our metrics forward. But we’ll continue to push forward with our cash flows, refine them as we go out through the year. We do have the ATM available to us, even though right now I don’t have any firm plans to use at ATM.

Maurice Choy: Great, thanks. And just to follow up on that. As you look out through 2024, are there any events, items that we should look out for that might motivate you to want to restore the cushion?

Jocelyn Perry: I think, Maurice, I mean, we’re going to continue to have conversations with S&P clearly, we want to set ourselves up to rebuild that cushion, but again, this was a surprise. We’ll continue to have further conversations with S&P about the nature of their concerns around wildfire risk and climate risk, and just understand the goalposts a little better. But the aim is to certainly meet the threshold and to start building back that cushion. But I don’t see any other event that other than speaking with S&P throughout the year. Just trying to fully understand the nature of the negative outlook.

Maurice Choy: Got it. Thank you. And my final question is on Arizona in terms of the potential repealing of the state’s renewable energy standard and tariff. TEP obviously does have a new IRP that was filed. What does the repealing of the REST mean in terms of TEP’s decarbonization growth plans?

David Hutchens: Yes, Maurice, this is Dave. Thanks for that question. It doesn’t mean anything because we’ve already exceeded the renewable portfolio standard. It was only a 15% requirement, which we have surpassed already. Obviously, the cost recovery of historical items from that will continue to be – continue to make sure that we get those through the normal regulatory processes. But overall, the goal isn’t – it doesn’t really have any impact on us. If you’ll remember, a couple of years ago, there was quite a lengthy debate as to whether or not Arizona was going to adopt some more aggressive goals, even all the way to net zero goals, but that never did happen. The renewable portfolio standard is a bit out of date. I think there isn’t probably any utility, at least any of the big ones that haven’t already met the 2025 requirements.

Maurice Choy: Perfect. Thank you.

Operator: Our next question comes from the line of Rob Hope with Scotiabank. Please go ahead.

Rob Hope: Good morning, everyone. I want to circle back on the Okanagan decision. So maybe looking forward, how do you work with the regulator, whether it’s in BC or other jurisdictions, especially on the natural gas side, such that your views of demand growth line up with how the regulator is seeing the world. So that, for example, you think you need to get this pipeline to serve demand and they think that demand may not necessarily show up there. So how do you bridge that gap moving forward?

David Hutchens: That’s a great question, Rob. And we’ve got a couple of different jurisdictions that we see this in Arizona. We actually don’t have this conversation, really there isn’t – hasn’t been a pushback on natural gas infrastructure or demand on a going forward basis. I’m going to kick it over to Roger Dall’Antonia, the CEO of FortisBC, to talk a little bit about BC, and then you can spring back and I can talk a little bit about New York as well.

Roger Dall’Antonia: Thanks, David. Thanks, Rob. Maybe I’ll start a little bit with the OCU decision itself. Disappointed, of course, that it was denied. We’d put quite a bit of work into that application. I think there’s three things that come out of the decision that are – that’s important to understand. The first is the commission does see the need for capacity upgrade, so they’re not denying the basis for it. The second is, they’ve – while they’ve denied it, they’ve directed us to come back with a mitigation plan. So they are expecting us to provide some solution, which we will do. I think the third issue, and really the heart of your question is what’s changed that, they’re not accepting our load forecast.

And I think when you look at their reasoning, it’s really not so much that they don’t think we have a role from the point of view of a commission regulating natural gas. It’s more that with the policy direction that BC is going, with clean BC, significant uncertainty right now on how does BC meet some fairly aggressive emissions targets, what does that mean for solutions that are 56 years life, like the OCU pipeline upgrade, relative to what the long-term forecast is versus the near-term capacity shortfall. So it’s – for us, it’s really incumbent that we demonstrate a variety of scenarios where we think the capacity issue may not be resolved over the long term. How do you do that? I think what we’ve always done in the past is looked at load growth with the contingency factor looking at on the upside, making sure that you’re never short.

I think what commissions are looking at when there’s policy uncertainty is really going to be more around a variety of scenarios. And what is the ability to scale up in your asset mix? So you’re not building the largest program or the largest facility. But is there a way to mitigate with near-term solutions, but also expand if load growth proves to be higher than they’re expecting? So I think it’s going to be a change in how we approach the load forecasting over the next number of applications until we get some certainty around how clean BC in our instance goes from policy into specific regulations. So more to come on that for sure.

David Hutchens: Thanks, Roger. And Rob it is – it’s important, I think, as we look out in the future, that we are really looking at more incremental and many steps in a longer-term planning process, which may be an outcome of what FortisBC looks at with their regulator. It may be a stack of shorter and middle and longer-term investment opportunities instead of starting at the long term, which can be more expensive. Obviously, if you’re building incrementally and have that flexibility, it will cost you. That optionality always costs you a little bit of money. But at the end, it might provide a bit more flexibility for us to see the future a little bit clearer in the shorter-term periods of time.

Rob Hope: All right. Thanks for that.

David Hutchens: I was going to talk back on the New York piece, so there is a New York legislation that’s called the Affordable Gas Transition Act. That can – it limits the amount of free footage or actually zeros out the free footage that’s allowed for new gas customers. So it would increase the amount of contribution needed to get gas service, which would increase upfront cost for homes, et cetera. There’s some other growth limitations in there as well. Obviously, we’re looking at that and don’t necessarily agree with that policy as well. But at the end of the day, when you look at our service territory one, our gas service territory is pretty small. It’s a small part of our overall business from a Fortis perspective.

But also the gas and electricity customers are basically almost completely overlapped in Central Hudson’s service. So it’s actually a great way to look at it similar to how Roger looked at the Kelowna [ph] that the Kelowna situation where we serve electricity and natural gas. It’s a great way for us to apply the right amount of electrification and natural gas and energy solutions to our customers when you can provide both sides of it. So one could be a growth opportunity, but the most important thing is to be managing the customer affordability on the pace of these transitions.

Rob Hope: I appreciate that. And that actually leads to kind of the second of my questions. On the electric side, we’ve seen another number of system operators increase demand expectations across the content [ph] for a variety of reasons. When we take a look at your service territories, where do you think you could see the greatest upward revision on a demand forecast moving forward and why?

David Hutchens: Yes. I think there is probably a little of that in almost every service territory. I’ll say the big ones are likely Arizona. Just seeing the economic growth that’s happening there, whether it’s battery factories, data centers, semiconductor chip manufacturing, that’s statewide. But some of that’s in our service territory, and some of it will be coming to our service territory in the near future. So that’s on the back of additional conversations on manufacturing increasing in the area. And of course, Arizona is always a net migration state as well, where we end up with good, strong population growth, typically decade after decade. The other one is in the Midwest. I think the manufacturing boom that I think we’ll see and are seeing in our main jurisdiction there like Michigan will definitely lead to additional infrastructure needs, additional transmission needs for us.

It’s manufacturing which obviously drives jobs, which drives housing, which drives the economy in general. And some of the Inflation Reduction Act incentives for domestic content are really driving some of these manufacturing facilities. So it’s good to be in that service territory. And that’s really setting aside even the latest Michigan Clean Energy Legislation that is increasing the pace at which they have to get to 100% clean energy, which is by 2040 now due to that legislation, which I think is missing in a fair number of forecasts. Now that’s not on the demand side. That’s on the supply side. But of course, that drives renewables transmission and the rest of the things that we are really fond of.

Rob Hope: Appreciate that. Thank you.

Operator: Our next question comes from the line of Linda Ezergailis from TD Cowen. Please go ahead.

Linda Ezergailis: Thank you. I’m just wondering if you can help us understand just a further to Maurice’s question. Given the lack of wiggle room in your financing and your debt metrics, might that tilt you towards kind of pre-funding to kind of give you a little bit more, not wiggle room, but to anticipate maybe some surprises and maybe might you be more inclined to opportunistically consider divestitures and how might that manifest itself? I’m also wondering how you’re approaching opportunistic acquisitions. Would you need to high-grade that or might that prompt using the ATM given some of the other moving parts?

Jocelyn Perry: Linda, this is Jocelyn. I’ll take the first part of that question. Yes, I mean, we’re always looking at pre-funding opportunities if the market should open and timing of when we actually go into the market, but with respect to this particular rating, I wouldn’t expect it to materially impact our costing if we had to go to market even with this negative outlook there, so – but you’re right. I mean, we do look for opportunities to go to market, so I would say that’s always on the docket for us. And with respect to the ATM, the ATM is there and that’s exactly why we put the ATM in place. It was to give us some financial flexibility for events, particularly around growth that is either unforeseen or timing of cash flows from our subs or whatever it may be.

So as we go through the year, that’s why I say we’re not firm on any plans to use the ATM, but the ATM is there. And so we’ll continue to monitor it as we go through the year and we’ll firm up those plans as the year unfolds. I’ll pass the – ask the divestiture question over to David.

David Hutchens: Yes, obviously the focus that we have from a strategy perspective is executing that $25 billion capital plan. Now, of course, as fiduciaries, we’re always looking for opportunities to add value for our shareholders, so it’s on us to make sure that we’re looking at opportunities. But as Jocelyn mentioned, we’re not dependent on anything other than the funding plan that we laid out pretty clearly in the Investor Day back in the fall.

Linda Ezergailis: Thank you. And maybe just as a follow-up, a higher-level question. I don’t know if this is for Linda or maybe someone more honed in on the regulatory situation. The Chevron doctrine that’s been in place for 40 years approximately and addresses an ability for an agent’s – U.S. federal agency’s reasonable interpretation of any sort of ambiguous statutes is being challenged. What sort of impact would the discarding or removal of the Chevron doctrine potentially have on your business? And also, beyond that decision, we do have a U.S. election coming this fall, so just wondering how you’re thinking generally about FERC and any sort of other potential shifts in how your regulated businesses in the U.S. might have to adjust to any sort of new macro environment.

David Hutchens: That’s a great question, Linda, and it’s interesting because the Chevron doctrine has held precedence for deference to regulatory bodies for years and years and years and is an often cited precedent that obviously has been used by regulators too. I’ll say, coloring around those grey areas where legislation hasn’t really determined who has the responsibility to be able to make those calls. This has probably been a – well, it’s obviously been a conversation that’s been going on for decades, but it is interesting to hear the conversation. I don’t think in the long run it changes anything from our perspective. It’s I think what – the main purpose of this conversation is to understand or determine whether or not regulatory agencies are overstepping what – the – I will say the bounds that are put on by legislation that isn’t clear.

So, – and frankly, recently, because it is so hard to get legislation done in the U.S., it is left up to the regulatory bodies to kind of reach in and there is a fine line between regulation and policy. So I don’t see it having – it’s an interesting conversation. I don’t see it really having any impact on what we see today. I just think it may make it maybe a little more difficult to legislate by regulation on a going forward basis if it is challenged.

Linda Ezergailis: Thank you. And any other comments beyond this particular Supreme Court challenge to any sort of shift maybe in kind of regulatory, like what’s going on at FERC and where their priorities might be or any other commentary would be appreciated?

David Hutchens: Yes, I think, FERC, obviously down to three commissioners, is focused on a couple of things clearly. I think the planning and cost allocation, NOPR has been discussed in depth as being sort of frontline. It was great to see the interconnection queue. Final rule come out. And this is sort of the next thing in the queue from a bigger, broader transmission policy perspective. Due to the benefits, too, of having that closer to the front of the queue is that part of that NOPR is asking the question about whether or not to reinstate the federal Right of First Refusal for certain projects, which Order 1000 took away many years ago. So that’s part of that conversation as well. So we like to see that moving, and we hope it stays at the front of mind from a FERC perspective.

Linda Ezergailis: Thank you.

David Hutchens: Thanks, Linda.

Operator: We have our next question come from the line of Mark Jarvi with CIBC. Please go ahead.

Mark Jarvi: Thanks. Good morning everyone. Maybe, Jocelyn, if you could clarify just the comments around the reconsideration of the ROFR issue in Iowa. Did you say that it would be a parallel process to push through legislation? Maybe just kind of give us an update on where you think that effort is right now in terms of – right now legislation in Iowa.

David Hutchens: Well, yes, he asked you, Jocelyn.

Jocelyn Perry: Yes…

David Hutchens: Wait a minute. So, yes, thanks for the question. It is a parallel path. The reconsideration was filed in December and obviously in a parallel path that we’re trying to get new ROFR legislation through Iowa.

Mark Jarvi: And David, any sort of rough timelines on when you think that could be cabled and try to go to a vote?

David Hutchens: Not, don’t really have a good timeline for that. We’re obviously shooting for this legislative session, which is still newish. And so we’re trying to get it as quick as we can and to get it done and approved during this legislative session, which I think goes through April-ish timeframe.

Mark Jarvi: All senses at this point are that there is a political will to push that through and drive that forward at this point?

David Hutchens: Yes, so far we’re seeing good reception and hoping to get that pushed through.

Mark Jarvi: Okay. And then coming back to BC, what’s – with the year-end now done, just clarification on the equity injection with the equity thickness step-up, has that been determined and what is that amount that has to go in 2024?

Jocelyn Perry: Yes, Mark, that’s been determined. It was $300 million.

Mark Jarvi: So that’s a little bit less than you would have thought a couple months ago, is that right?

Jocelyn Perry: Yes, it was about what we thought. It may have been a little bit lower.

Mark Jarvi: Okay. And then just if you think broadly around that question around the Okanagan pipeline and gas needs and this transition around electrification, but obviously BC struggled with forest fires, wildfires, drought conditions, which has hampered their whole sub-verse of the generation market there. So what conversation goes on around sort of reliability and costability that the gas assets offer versus some of the pressures that the electric network might have faced over the last couple of years?

David Hutchens: Well, that depends on the jurisdiction. Obviously, in Arizona, we have natural gas now in our newest integrated resource plan for both Tucson Electric Power and UNS Electric, our two electric utilities there. There is – Alberta is a whole different conversation as well, recognizing the need and just looking and seeing a lot of additions of natural gas capacity from a generation standpoint coming on this year. And obviously, a lot of conversations in that jurisdiction at the – as a distribution-only company we’re sort of a bit on the sidelines on that. But in British Columbia, you don’t hear a whole lot of conversation around natural gas generation because they have so much hydro. So a lot – most of the conversation is like Site C expansion and around hydro and renewables at this point.

I think it is incumbent on us as folks who operate in every one of our jurisdictions to make sure that we’re getting out and having those conversations of getting that balanced portfolio that allows us to get to that cleaner energy future as fast as we can, but with the big asterisk around affordability and reliability. And I think we’re having a lot more constructive discussions with government regulators. And I think overall, we will see more, I think, positive and balanced discussions and outcomes due to that conversation.

Mark Jarvi: Okay. Thanks, everyone.

David Hutchens: Thanks, Mark.

Operator: Our next question comes from the line of Ben Pham from BMO. Please go ahead.

Ben Pham: Hi. Thanks. Good morning. I was wondering if you can maybe add a bit more color on your comments on asset rationalization. What conditions or factors does a core asset move into a non-core asset?

David Hutchens: So if I understand the question right, it’s you know what – what do we consider non-core assets? I mean all of our assets that I would say that we define as core is what our business is all about, and that’s regulated utility assets. That’s why Aitken Creek was an unregulated asset, and that made sense to monetize for a variety of reasons. But one is to take that almost $500 million proceeds and use it to invest in the main thing, which is our regulated utility businesses. So that –from that perspective, we’re 99 and change, I mean, it almost rounds to 100% regulated assets. And so we don’t have – we don’t kind of define the things as non-core per se.

Ben Pham: Is your non-reg, is that the only thing really left? Is that just the Belize hydro assets?

David Hutchens: Yes, the Belize hydro assets are the only non-regulated assets that we have.

Ben Pham: Okay, got it. Thank you.

Operator: We have our next question come from the line of David Quezada from Raymond James. Please go ahead.

David Quezada: Yes, thanks. Good morning, everyone. Just one for me. I am just curious, going back to the Iowa ROFR issue, I wonder if that proceeding or some of the decisions there affects, or if you think it might affect or prompt challenges to the ROFR you have in other states? Just any commentary around how you see that potentially playing out in the other states.

David Hutchens: Yes, there have been challenges in other states, some that we operate in, some that we have ROFRs in and other states as well. You have to make sure that you define these ROFRs so that they meet those challenges, like the one that we have in Minnesota has met that challenge. So that’s obviously part of the conversation when we go to look at a new ROFR in Iowa is making sure that from a constitutionality perspective and from the principles of that, that it ends up being a good, solid ROFR that we can – we know that if challenge will still survive. But, yes, that’s already happened. It’s happened in Texas and other places as well. But we think, and we strongly believe that these ROFRs are the absolute right way for us to develop transmission on a going forward basis for a variety of reasons.

But the big ones are affordability, reliability, and getting clean energy on the grid as fast as we can and making sure that we don’t sacrifice any one of those three things. And I’ll say the sad part about having the injunction sitting there is it’s negative to all three of those things. These are projects that improve affordability by interconnecting cheaper resources, delivering cleaner energy, and/or are there for reliability and having those delayed is a negative to the three absolute tenants of our utility sector. So we want to make sure that we have the ability to get those projects done and get them done fast and affordably for our customers.

David Quezada: Excellent. Thank you. Appreciate it.

Operator: We have our next question coming from the line of Patrick Kenny from National Bank Financial. Please go ahead.

Patrick Kenny: Thank you. Good morning, everybody. Just on the Woodfibre project, I know it’s still a relatively small investment, but just wondering if you could provide a bit more color on the key drivers of the increase in costs there. And then it looks like you’re fully protected through regulatory approval for now. But just given the three-year construction window, how should we be thinking about being protected from any further potential escalations in construction costs between now and then? Thanks.

David Hutchens: Yes, sure. These aren’t escalations these are really due to the ability of us to do more of a rate-based investment and for the Woodfiber parties to have less of a contribution in aid a construction. So it shouldn’t be a read through that this was a project increase cost and/or scope, it’s just that we now have a bigger piece of that overall pipeline pie. Now, Roger happened to have been up there at the Woodfiber site just the last couple of days, so he can opine on that as well. Roger?

Roger Dall’Antonia: Yes, thanks, David. Good morning, Patrick. Dave has it right. We have a long-term transportation service agreement with a specific rate schedule dedicated to Woodfiber, and there is the ability to manage the contribution to aid construction, which will then change the total structure over the 40 years. So this was by design. As the project went into construction, we started construction in our pipeline late last year at Woodfiber site. I was there on Wednesday into site prep and construction. So as we finalized the transportation service schedule agreement with updated costs ahead of construction, we ended up adjusting the contribution aid construction, which now has us investing $750 million directly in the project recovered by the transportation service agreement over the life of the project.

David Hutchens: Patrick, I have to note that that might be the first time I’ve heard is $750 million not being that big of a project?

Patrick Kenny: Good point. Good point, David. And then just back to S&P’s report. I know you’ll be having further discussions with them throughout the year, but any sense as to know incremental risk mitigation measures you might be needing to put in place here over and above what you are already doing just in order to relieve some of their concerns? And then I guess just given the relatively low precipitation out west this winter, if you can comment on any proactive activities you might be undertaking ahead of the next wildfire season.

David Hutchens: Yes, so we have been involved and engaged in trying to find the best ways to mitigate climate impacts in general, but wildfires in particular. And we’ve been doing that not only amongst our own utilities, through our Fortis operating group and sharing the best practices and trying to understand additional technologies, practices, procedures, recovery ways that we can coordinate with emergency services when there is a fire, all of those things. And we also do that externally across the broader North American utility sector. There is a lot of good ideas. There is a laundry list of things that you can do to mitigate wildfire impacts. Those may or may not apply. Every single utility has a different jurisdiction, a different fire threat, et cetera, but it’s incumbent on us to make sure that we’re doing all the things necessary in our jurisdictions to mitigate it.

Now, we think we are now, based on what we know today, as we learn and know more, and as the sector grows their knowledge in this and learns and knows what works and what doesn’t work, we’ll look at implementing those. And we just have to match up knowledge that we’re gaining across the entire sector with the expectations of rating agencies to make sure that we’ve got this covered and that we’re all talking on the same terms and have the same level of expectations of what that means. So I’ll leave at that.

Patrick Kenny: Okay, that’s great. Thank you.

Operator: We have our next question coming from the line of Michael Sullivan from Wolfe Research. Please go ahead.

Michael Sullivan: Hey, everyone. Good morning.

David Hutchens: Hey, Michael.

Michael Sullivan: Just a quick one back to the MISO Tranche 2 process, I think, you mentioned approvals in the second half of the year. Any sense of when we might see like a first look at initial project awards?

David Hutchens: Yes, so the way that the process goes is, I think, that batch doesn’t come out probably because right now they’re still doing all the modeling to figure out which are the right projects. I don’t think we would get a good view into that level of project detail, probably until summer sometime.

Michael Sullivan: Okay, great. And then just coming out of the UNS rate case and now that you got the SRB there, just how you think about how that translates over to TEP and the regulatory and renewables build out strategy there?

David Hutchens: Yes, that’s a great question. So, obviously, we didn’t get the SRB and TEP’s rate case and UNS Electric did. And obviously, every rate case is different. And the size of these investments for the smaller UNS Electric is a bit different than the larger Tucson electric power portfolio. But we do see this as definitely as a positive. We don’t necessarily need it now because a lot of our renewable and storage investments are towards the tail end of our five-year plan. But it is something that we now see as a framework to be able to use for TEP when it files its next rate case. So, nothing urgent to try to figure out something between now and that next rate case. And of course, we don’t have a very rigid or defined rate case schedule, but we think we can manage, obviously, with the investment tax credits and production tax credits helping to fill in that regulatory lag that we can manage effectively and not have any changes in our plan or our integrated resource plan based on what we know today.

Michael Sullivan: Great. Thanks so much.

Operator: [Operator Instructions] We have our next question coming from the line of Tanner James from Bank of America. Please go ahead.

Tanner James: Hi, good morning. Thank you for taking my questions. Following on Michael’s first question, how are or how could the Iowa Transmission ROFR proceedings affect your strategy regarding MISO Tranche 2 projects and further planning in the region? And then in the event Tranche 1 projects could be affected, are there opportunities for contingent spend elsewhere, either at ITC or across the organization?

David Hutchens: So what was the last part, contingent what? I missed the last part.

Tanner James: Contingent spend elsewhere.

David Hutchens: Okay. Yes, so obviously, our whole multipronged approach here is to get the injunction removed from those Tranche 1 projects so that we can continue getting those projects developed. The parallel piece that I mentioned, there is actually two parallel pieces here. One is to get the Iowa ROFR, a new Iowa ROFR passed, which if we can do that that would hopefully be in place before the Tranche 2 projects are allocated. And the third one that I mentioned earlier, too, is the focus on looking to get some level of federal ROFR in the planning and cost notification ROFR. So those are kind of the three things that we’re looking at. Contingent spend wise, we are always looking for additional investments, remember the MISO long-range transmission plan is a big piece of the planning process, but there is also the annual MTEP projects that get brought in there as well.

And then there is additional things like the Joint Targeted Interconnection Queue investments that could provide an opportunity, which are investments that go across some of the different – connect the different RTOs, et cetera. So all of those things we’re always looking for contingent spend for sure.

Tanner James: All right, great. Thank you very much.

Operator: Thank you. As there are no further questions, I would like to turn the call back to Ms. Amaimo.

Stephanie Amaimo: Thank you, Laura. We have nothing further at this time. Thank you, everyone, for participating in our fourth quarter and annual 2023 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, ma’am. Thank you for participating. This concludes today’s conference call. You may disconnect.