Earnings Call Transcript - FTS Q3 2023

Operator, Operator

Good morning, everyone. Thank you for being here. My name is Ludy and I will be your conference operator today. Welcome to the Fortis Q3 2023 Earnings Conference Call and Webcast. All participants will be in a listen-only mode during the call. At this time, I would like to turn the conference over to Stephanie Amaimo. Please go ahead, Ms. Amaimo.

Stephanie Amaimo, Executive Vice President

Thank you, Ludy, and good morning, everyone, and welcome to Fortis' Third Quarter 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. Today, Jocelyn will speak to the prepared remarks on behalf of Dave as he is recovering from laryngitis. Both Dave and Jocelyn will address questions at the end. Before we begin today's call, I want to remind you that the discussion will include forward-looking information, which is subject to the cautionary statement contained in the supporting slide show. Actual results can differ materially from the forecast projections included in the forward-looking information presented today. All non-GAAP financial measures referenced in our prepared remarks are reconciled to the related U.S. GAAP financial measures in our Third Quarter 2023 MD&A. Also, unless otherwise specified, all financial information referenced is in Canadian dollars. With that, I will turn the call over to Jocelyn.

Jocelyn Perry, Executive Vice President and CFO

Thank you, and good morning, everyone. The third quarter proved to be a busy and positive quarter for Fortis. We received a number of key regulatory decisions in Arizona and Western Canada, which I will speak to shortly. Together, rate base growth in the recent regulatory outcomes in British Columbia and Arizona supported strong earnings growth in the quarter and year-to-date. For those who attended in person or tuned in virtually, you know we held our Investor Day in September, outlining our new $25 billion capital plan for 2024 to 2028. This capital plan supports 6.3% average annual rate base growth and 4% to 6% annual dividend growth guidance through 2028. Lastly, the pending sale of Aitken Creek is progressing as expected, with the British Columbia Utilities Commission (BCUC) approving the sale last week. With all regulatory requirements satisfied, we expect the transaction will close in the fourth quarter. With decisions in the TEP rate case and the Generic Cost of Capital (GCOC) proceedings in Alberta and B.C., we have completed a number of large regulatory applications. In August, the Arizona Corporation Commission issued its decision in TEP's General Rate Application, approving an increase in non-fuel revenue of USD 100 million and a 9.55% allowed ROE and a 54% equity layer. New customer rates became effective on September 1st. Also, last month, the BCUC issued a decision on the GCOC proceeding. The decision resulted in an allowed ROE of 9.65% for both Fortis utilities, reflecting a 90 basis point increase for FortisBC Energy and a 50 basis point increase for FortisBC Electric. The equity thickness levels also increased from 38.5% to 45% for FortisBC Energy and from 40% to 41% for FortisBC Electric. The new cost of capital parameters are retroactive to January 1st. I'll speak later to the related financial impacts. In October, the Alberta Utilities Commission or AUC issued a decision on FortisAlberta's third performance-based rate-setting mechanisms as well as the 2024 GCOC placebo. Overall, the PBR decision was generally in line with management's expectations. FortisAlberta continues to evaluate the annual capital provisions included in the PBR decision, which were premised on 2018 to 2022 historical levels. In the GCOC decision, the AUC adopted a formulaic approach in determining the allowed ROE, which will be calculated annually. Although the 2024 allowed ROE calculation won't be finalized until later this year. Using today's inputs, we expect the allowed ROE for 2024 to be modestly higher than the notional ROE of 9%. All in all, we received balanced regulatory outcomes for our customers and stakeholders in Arizona and Western Canada. With $3 billion invested in our systems through September, our $4.3 billion annual capital plan remains on track. Major capital projects continue to advance in line with our plan. In August, FortisBC Energy commenced construction on the Eagle Mountain Woodfibre Gas Line project. Just a few weeks ago, TEP announced it will build the Roadrunner Reserve project, a 200-megawatt battery energy storage system. This system is expected to be operational in the summer of 2025, capable of serving approximately 40,000 homes for 4 hours when deployed at full capacity. This project supports system reliability as TEP exits from coal and expands its renewable resources. TEP expects to file its next integrated resource plan on November 1st. The preferred portfolio is expected to align with Fortis' Scope 1 greenhouse gas emissions reduction targets of 50% by 2030, 75% by 2035, and net-zero by 2050. Our 5-year $25 billion capital plan is comprised of virtually all regulated investments and a diverse mix of highly executable low-risk projects. This new plan is $2.7 billion higher than the previous 5-year plan. The increase is driven by regional transmission projects at ITC associated with Tranche 1 of the MISO long-range transmission plan, as well as investments in Arizona to support TEP's exit from coal. Investments supporting system adaptation, resiliency, and economic development are also driving capital growth for the benefit of our customers. We expect the rate base will increase by $12.6 billion to over $49 billion in 2028, supporting average annual rate base growth of 6.3%. In the third quarter, our Board of Directors declared a fourth quarter dividend increase of 4.4%, marking 50 years of consecutive increases in dividends paid. Fortis is proud to be one of only two companies listed on the Toronto Stock Exchange to achieve this significant milestone. In September, we also announced the extension of our 4% to 6% annual dividend growth guidance through 2028 supported by our sustainable growth outlook. Slide 8 provides a summary of our third quarter and year-to-date reported and adjusted earnings per share. Reported earnings include timing differences related to mark-to-market accounting of natural gas derivatives at Aitken Creek and the revaluation of deferred income tax assets related to a change in the corporate tax rate in the state of Iowa. Adjusted EPS was $0.84, $0.13 higher than the third quarter of 2022. On a year-to-date basis, adjusted EPS was $2.37, $0.31 higher than the same period last year. Key earnings drivers center around continued investments in our regulated rate base, the recent regulatory orders in B.C. and Arizona as well as warmer weather in Arizona. I'll get into the details of each on the next couple of slides. The waterfall turn on Slide 9 highlights the EPS drivers for the third quarter by segment. Our Western Canadian utilities contributed a $0.09 EPS increase reflecting the new cost of capital parameters approved by the BCUC in September 2023, totaling approximately $0.08 and including $0.05 per common share associated with the retroactive impact to January 1st. Rate base growth also contributed to the increase, which was partially offset by the timing of operating costs at FortisAlberta. EPS was higher by $0.01 for our U.S. electric and gas utilities with UNS increasing $0.02 and Central Hudson down $0.01. In Arizona, the quarterly results were mainly driven by new rates at TEP effective September 1st and higher retail sales due to warmer weather. New rates increased EPS by approximately $0.02, while weather in the quarter favorably impacted EPS by $0.04, with July being the hottest month on record in Tucson. Lower wholesale and transmission revenues, higher operating costs, and lower production tax credits for Oso Grande tempered the results at UNS for the quarter. Central Hudson's results reflect higher operating costs as expected due to the timing of costs in the first half of the year, partially offset by rate base growth. At our Other Electric segment, EPS increased $0.01 driven by rate base growth and higher sales. Our Energy Infrastructure segment contributed a $0.02 EPS increase for the quarter. This includes higher earnings at Aitken Creek reflecting market conditions, net of lower hydroelectric production in Belize. Elevated finance costs at corporate and higher weighted average shares outstanding issued under our dividend reinvestment plan were offset by the favorable impact of a higher average U.S. to Canadian dollar foreign exchange rate. And although not shown on the slide, ITC's rate base growth for the quarter was largely offset by higher nonrecoverable finance and stock-based compensation costs. Year-to-date EPS was impacted by many of the same factors discussed for the quarter. On a year-to-date basis, 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. Before I move on from earnings, I would like to take a moment to explain where we are with respect to the pending sale of Aitken Creek. As I mentioned, we expect to close the transaction in the fourth quarter. Until close, we continue to recognize earnings associated with Aitken Creek in accordance with U.S. GAAP. Upon close of the transaction, adjusted earnings will exclude the gain expected to be recorded on the sale as well as the earnings recognized since the March 31st effective date. For the third quarter, we recorded adjusted earnings at Aitken Creek of $13 million or $0.03 per common share and $24 million or $0.05 per common share for the 6-month period since March 31st. Through September, we have raised over $2 billion of debt, primarily to refinance maturing debt and to fund our capital program. With regards to upcoming maturities, we currently have about $1.7 billion due through the end of 2021, including almost USD 200 million in non-regulated debt at Fortis Inc. Our primary exposure to elevated interest rates pertains to holding company debt as our regulated utilities ultimately recover changes in interest rates through regulatory mechanisms and the periodic rebasing of customer rates. We'll continue to monitor the debt capital markets and consider interest rate hedges or pre-funding opportunities. With proceeds from our debt issuances and the expected sale of Aitken Creek, as well as over $4 billion available on our credit facilities, we remain in a strong liquidity position and are comfortably positioned within our investment-grade credit ratings as we execute our $25 billion capital plan. To summarize, we have made significant progress in 2023 to advance our growth strategy. We have executed our capital plan as expected, concluded key regulatory proceedings, and delivered strong earnings growth through the third quarter. With our recently announced 5-year capital plan, we are continuing to deliver regulated growth to support a more reliable and cleaner energy future. When combined with our regulated and geographic diversity, strong ESG story, and good governance model, we are well positioned for the future. That concludes my remarks. I'll now turn the call over to Stephanie.

Stephanie Amaimo, Executive Vice President

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

Operator, Operator

Your first question comes from Maurice Choy from RBC Capital.

Maurice Choy, Analyst

I just want to start with ITC. I assume you would have seen the U.S. Solicitor General comments earlier this week to the Supreme Court regarding Texas ROFR. Admittedly, this feels consistent with the past commentaries, but any thoughts on that submission? Do you think FERC will do anything on the back of that? And what does your Supreme Court decision mean for your existing ROFRs?

David Hutchens, President and CEO

Thanks for the question, Maurice. I'm going to kick that over to Linda Apsey, our CEO of ITC, to give you a little bit of color on that. But yes, we did see that you can explain some of those differences between what we have in Iowa and what Texas sees.

Linda Apsey, CEO of ITC

Great. Thanks, Dave, and good morning, Maurice. Yes, we too saw that solicitor general opinion on the Texas ROFR. Standing back from it, it was sort of a mixed bag in terms of some of the reflections of the solicitor general. Most importantly, it calls out a distinction between the Texas ROFR, which essentially does not provide any opportunity for any non-incumbent utility to participate in investment in the transmission in the state versus, for example, the Minnesota ROFR, which had also been challenged and was upheld by the District Court that covers the Minnesota area. Essentially, the Solicitor General indicated that they did not feel as though the issue was ripe for the Supreme Court to take up the issue and that there was still an opportunity for this issue to continue to play out. By and large, it was a sort of a mixed opinion; it’s not clear what the Supreme Court will do, if anything. Certainly, as I said, it was the Solicitor General's recommendation that the court not take up the issue. From our perspective, it does demonstrate that the ROFRs, whether in Minnesota, Michigan, or what had been proposed in Iowa, is distinctly different from what the Texas ROFR was.

David Hutchens, President and CEO

Linda, just a little additional color on that as well. One of the interesting parts about that argument is that it's not ripe due to the fact that FERC is obviously looking at reinstating federal ROFRs for some projects. That's part of the planning and cost allocation they have out there. So that's an interesting deference to FERC as well.

Linda Apsey, CEO of ITC

Yes. Thank you, Dave. Absolutely.

Maurice Choy, Analyst

Maybe like any thoughts on the timing of that potential for a clean statement?

David Hutchens, President and CEO

I think it probably will be a bit of time there because that's part of the planning and cost allocation ROFR NOPR, and I think they're really probably waiting to move that forward until they have a fuller complement of commissioners.

Maurice Choy, Analyst

And maybe just finishing off on FX. Clearly, FX is higher today than the 1.30 you have assumed in your 5-year plan? I know you provided sensitivities on Slide 22 for EPS and CapEx, but could you remind us of your cash flow or earnings hedges for the upcoming years? Assuming these FX rates hold, clearly helps to earnings, but how would you approach funding the additional CapEx?

Jocelyn Perry, Executive Vice President and CFO

Maurice, this is Jocelyn. Yes, we do hedge cash flows. We actually go out 2 years about and 100% of our cash flows. But you're right, with the rates where they are today, we're always watching that, and we hedge a little more sometimes and we hedge a little less sometimes. It does impact earnings, particularly we watch it around cash flows. So we used to do it actually 1 year out, but we moved to 2 years a few years ago. We continue to watch it and continue to adjust as the rates change.

Maurice Choy, Analyst

And can I ask what rate you've hedged those 2 years of cash flows at?

Jocelyn Perry, Executive Vice President and CFO

Well, I'd have to get that average rate. It's actually a good rate today because we've been in the market recently. So I'll have to get the specific rate for that. We have a lot of little hedges that we put in place.

Maurice Choy, Analyst

Thank you very much. And get well soon, Dave. You do sound good, I will say.

David Hutchens, President and CEO

I'm okay in the lower register.

Operator, Operator

Your next question comes from the line of Rob Hope from Scotiabank.

Robert Hope, Analyst

I was hoping you could give some additional color on the Tucson IRP, which will be filed in the coming days. Can you talk about how it has changed with the IRP, and whether we could see some upside or downside in your CapEx plan depending on the eventual outcome of the transition there?

David Hutchens, President and CEO

So Rob, I'd love to give you a bunch of details on that, but we're just around the corner from releasing that publicly, and we really don't want to front-run our commissioners in the process. That filing and all the details and comments that we'll make around that are just around the corner. So I'd ask for your patience and then call us back, and we'll give you as much information as you'd like on that.

Robert Hope, Analyst

Sounds good. And then maybe a follow-up there. How are you dealing with some of the supply chain issues that we're seeing there? Are you seeing them improve? Or are there still some headwinds? And how are you managing kind of the supply entities right now?

David Hutchens, President and CEO

So far, we haven't really seen that impact because we're not doing a whole ton of any one thing. We're not dependent on a huge amount of panels or wind or batteries, etc. It’s a very balanced portfolio approach that we're doing. As we sit here today, we don't feel like we have any issues there. Now obviously, those can change as we go forward, and we'll be watching that. But I think we're going to be just fine.

Operator, Operator

And your next question comes from the line of Mark Jarvi from CIBC Capital Markets.

Mark Jarvi, Analyst

I just wanted to come back to the comments around higher interest rates. Jocelyn, you mentioned about the holding company debt. Just at the operating subsidiaries, where are you feeling the most pressure from a regulatory lag or little leakage on interest rates versus deemed debt? And where will we see a carryover of that impact into 2024, if at all?

Jocelyn Perry, Executive Vice President and CFO

Thanks, Mark. Most of our utilities actually have mechanisms to capture the interest rate changes from year-to-year, like ITC and Alberta and B.C. The one area where there is a lag is at UNS. So until they go in for their next rate case, they won't reset any new debt issuances they have done. I would say, in large part, most of our utilities actually have those mechanisms, but that's probably the one area where it’s vulnerable. It's small, right? It will be a small impact relative to Fortis.

Mark Jarvi, Analyst

Anyway you can kind of put some metrics around that or quantify it to the level?

Jocelyn Perry, Executive Vice President and CFO

I find it hard to consider this material because you are referring to the changes in any new debt issuances over the next couple of years. I'm not sure if Susan has that figure available, but it likely amounts to a couple of hundred million, probably not more than that in the next two years. It’s the difference between their current rate and a roughly 2% difference. Again, it's not significant for Fortis. With UNS and their rates, there are positive and negative aspects, but it doesn't necessarily drag down earnings. It’s important to look at the entire picture as well.

Mark Jarvi, Analyst

And then just given where you think rates are today and you think about the maturities in 2024, any idea on when you look to address that? Is it something to be patient with, or do you want to clear this off earlier than later? Any sort of updated views in terms of how you deal with those maturities in the next 12 months?

Jocelyn Perry, Executive Vice President and CFO

We watch it daily, right? We make these decisions quite frequently. But what I will say is I prefer to get that risk behind us, right? In the past, we've had a lot of depth forward, and we continue to do that. It's a strategy that we've deployed before, and I suspect we'll deploy again. We’ll keep watching the market. It's still very volatile, but you have to reset your thinking week to week.

Operator, Operator

And your next question comes from the line of Ben Pham from BMO Capital Markets.

Benjamin Pham, Analyst

To continue the last question on refinancing. I'm wondering, are there any meaningful differences between when you think about the Canadian and U.S. market for refinancing upcoming debt such as the '24 and '26 maturities when you think about where interest rates are going between the two countries, your FX exposure, and where you want that to be and the cost of hedges?

Jocelyn Perry, Executive Vice President and CFO

Ben, that's what we do all day long. Every time in both markets, we're looking at where we're issuing, what we're issuing, the tenor, the currency. We've done some FX currency swaps with Canadian debt. We're active in that market. But as I said on the previous question, it is something you have to reset your thinking every week because it is changing. All of those things are considered every time we go to market.

Benjamin Pham, Analyst

And would you say your FX matching is mostly aligned with where you want to be?

Jocelyn Perry, Executive Vice President and CFO

Yes, I think we're comfortable where we are today. But again, yes, no, I'd leave it at that. We're comfortable where we are today, but we're always watching it.

Benjamin Pham, Analyst

I know the cost of capital decisions post Investor Day provided details and EPS sensitivities. That’s very useful. How do you think flow-through impacts credit metrics and if there's any impact on your equity needs?

Jocelyn Perry, Executive Vice President and CFO

I'm sorry, Ben. Your question pertains to the effect of the GCOC on our cash metrics. I believe it's around 20 basis points. However, that will depend on how it is recovered in rates. The team in Western Canada is still assessing how this will be reflected in customer rates, and we do not have the order yet on how it will actually flow through. Once everything is sold and incorporated into customer rates, it is likely to be about 20 basis points in British Columbia. We have submitted our compliance filing with the BCUC, and we anticipate that they will require around $300 million. We're uncertain when we will need to fund this, but it will probably be late this year or early next year.

Operator, Operator

And your next question comes from the line of David Quezada from Raymond James.

David Quezada, Analyst

Maybe a question just from a regulatory perspective. You've had some significant decisions recently. I'm wondering where you'll be turning your focus to going forward? Any updated thoughts around when we could see some development on the outstanding items at ITC?

David Hutchens, President and CEO

I'll turn it over to Linda to comment on the ITC for timing because some of that is still up in the air. But we always have something in the hopper related to regulatory filings. We still have a very small UNS electric case going down in Arizona. We're getting ready to file another multi-year rate plan at FortisBC. So a couple in, a couple out. We're always in this process for sure, but no real big regulatory decisions waiting on today other than those from FERC. Linda, if you want to opine on your opinion on base ROE and some of those other issues that are hanging out there?

Linda Apsey, CEO of ITC

Sure. We don't have any clarity around when FERC might act. As we've discussed previously, the composition of the FERC commission seems to be somewhat standing in the way of some progress on decisions around many of the pending matters. As a transmission owner group at MISO, we continue to be engaged around the base ROE matter. With respect to the incentive NOPR issue, it is our view that it is not a priority issue among the commissioners. We'll continue to track and monitor and be engaged as we can on those issues.

David Hutchens, President and CEO

Thanks, Linda. I totally forgot to do the round the horn in my head on all the different utilities and what's coming up. But Central Hudson obviously has a rate case that's currently filed and pending as well.

David Quezada, Analyst

And then maybe just one more for me. Thinking about the MISO long-range transmission plan, I'm wondering if you have thoughts around some of the things the IMM has put out there about fleet assumptions? Do you see that having any material effect on how things play out there?

Linda Apsey, CEO of ITC

Yes, we have great confidence in MISO's expertise, experience, and abilities around putting these future scenarios together. I think the futures reflect all of their member utilities, carbon reduction goals, and assumptions around electrification and how that impacts load demands. FERC has insight and perspective around the generator interconnection queue. We remain confident and comfortable in MISO's scenarios and their assumptions. We believe MISO is best prepared to respond to the IMMs issues and concerns, and we have confidence that they will continue with the futures they've developed and push forward with the transmission projects that will comprise Tranche 2. We are optimistic regarding MISO's ability to continue to advance.

Operator, Operator

And your next question comes from the line of Linda Ezergailis from TD Securities.

Linda Ezergailis, Analyst

Recognizing it's not as impactful to Fortis overall as ITC, but I am curious to hear your views on Alberta and your expectations around your utilities' ability to outperform and over-earn under PBR 3.0? What sort of efficiencies might be further squeezed out, realizing you've likely done a lot on that front?

David Hutchens, President and CEO

Yes, that's a great question, Linda. I'll turn that over to Janine Sullivan, our CEO of FortisAlberta, to provide color on the PBR and any other questions related to Alberta.

Janine Sullivan, CEO of FortisAlberta

Good morning, Linda, and thanks for that question. As you know, we've been working through the process to conclude this on PBR 3.0 for some time. Many of the issues that we were contemplating in the process, we were prepared for and filed evidence on. We've been planning for and thinking about how to adjust or accommodate some of the findings in this decision for some time. The findings were in keeping with where we expected things to go. We see a need for additional capital on the capital portion of the decision, where they promise future funding on historical additions, which doesn't consider what was approved for 2023 when we rebased under the cost of service. It includes years impacted by the pandemic. Looking forward, there are provisions in that plan that allow us to seek additional capital. Regarding efficiencies, there has been a lot of conversation around the need to identify efficiencies for customers, and we're committed to that. We're evaluating opportunities to deliver those efficiencies while reporting to the commission as part of the PBR plan. Yes, being in the third term requires us to delve deeper into our organization for efficiencies, but we were prepared for those expectations given the narrative around affordability and discussions in the PBR proceedings.

Linda Ezergailis, Analyst

As a follow-up, regarding the Alberta government's focus on customer affordability. Where do you see the levers to achieve that? Do you think anything really material can be done on the distribution or transmission wire side, or do you see that coming more from other parts of the bill like generation or other components?

Janine Sullivan, CEO of FortisAlberta

I’ll share that in Alberta, there's an extensive process led by the provincial government to address issues related to bills, taking a thorough approach to understanding the driving costs behind affordability concerns. All options are being considered. Regarding distribution, we work with them on opportunities to help customers manage affordability concerns. Programs like Demand-Side Management (DSM) and energy efficiency programming haven't been clearly defined in Alberta. We believe, as the front-facing customer utility service, we should be the ones delivering those programs. We're working with the government to advance those types of programs and the role the utility can play.

David Hutchens, President and CEO

Linda, I might add my personal opinion that of all the bill components in Alberta, the distribution one is the least likely target for cost reduction and efficiencies. That component is not growing or as volatile as the others. They are casting a wide net in this discussions.

Operator, Operator

Your next question comes from Dariusz Lozny from Bank of America.

Dariusz Lozny, Analyst

Just wanted to ask one on Arizona. Without wanting to front-run the IRP announcement that's coming next week, I just wanted to ask about the prospects for getting concurrent recovery in some form. There was a robust stakeholder process this time around, certainly some interest there, but it seems like there is still some opposition. I'm curious what learnings you can share or perhaps adjustments to your strategy on a go-forward basis as you pursue that concurrent recovery. Additionally, how does this impact your planning for owned generation versus PPAs?

David Hutchens, President and CEO

Thanks, Dariusz. There are a couple of data points. The first is the TEP rate case, where we asked for what we call the resource transition mechanism, which got morphed into something called the system reliability benefits adjuster. This is meant to recover some of these investments between rate cases and reduce regulatory lag. We did not receive that in the TEP case. We are now in the process of asking for the same mechanism in the UNS Electric, the smaller electric utility in Arizona, and so far, we’ve received support from staff and others for that. That just came out of the hearing process and we're waiting on a recommended opinion and order that we expect towards the end of this year with rates maybe in Q1 of next year. That will be the next indication of whether we can get this. If not, we always have the option to pursue a generic docket to have these discussions and retry in the next rate case. It's not as urgent for TEP because the investment and production tax credits provide some benefits between rate cases, reducing regulatory lag. Of course, we can always ask in the next rate case and gauge the commission and other utilities asking for similar mechanisms. Sooner or later, I think we'll get something like this; it's just about defining the parameters and figuring out how it will work going forward.

Operator, Operator

And there are no further questions at this time. I would like to turn it back to Ms. Amaimo.

Stephanie Amaimo, Executive Vice President

Thank you, Ludy. We have nothing further at this time. Thank you, everyone, for participating in our third quarter 2023 results conference call. Please contact Investor Relations should you need anything further. Thank you for your time, and have a great day.

Operator, Operator

Thank you, Ms. Amaimo, and this concludes today's conference call. Thank you for participating. You may now disconnect.