Hawaiian Electric Company, Inc. PFD SER E 5%

Thank you. Welcome, everyone, to HEI's First Quarter 2026 Earnings Call.

Joining me today are Scott Su, HEI President and CEO; Paul Ito, HEI and Hawaiian Electric's Senior Vice President and CFO; Shelly Kimura, Hawaiian Electric President and CEO; and other members of senior management. Our earnings release and our presentation for this call are available in the Investor Relations section of our website.

As a reminder, forward-looking statements will be made on today's call. Factors that could cause actual results to differ materially from expectations can be found in our presentation, our SEC filings and in the Investor Relations section of our website.

Today's presentation also includes references to non-GAAP financial measures, including those referred to as core items. You should refer to the information contained in the slides accompanying today's presentation for definitional information and reconciliations of historical non-GAAP measures to the closest GAAP financial measure.

We will take questions from institutional investors at the end of this call. Individual investors and others can reach out to Investor Relations.

Now Scott Seu will begin with his remarks.

Welcome, everyone. For today's call, I'll start with an update on the Maui wildfire tort settlement and discuss our progress on other key priorities.

Paul Eagle will walk through our financial results and then open it up for questions. Since the Maui wildfires in 2023, we've told you we would take the actions necessary to offer those who suffered loss an accelerated path to recovery and to regain the financial strength and stability of our enterprise.

Resolving the Maui wildfire tort litigation was a fundamental step in this process. We came to key terms of a comprehensive settlement agreement in August of 2024 and signed on to a definitive settlement agreement shortly thereafter.

Last month, on April 10, the final conditions of the settlement were satisfied when the last subrogation insurers withdrew their appeals. We then immediately made the first of our 4 annual $479 million payments as stipulated under the agreement.

I'm grateful to all parties involved that we were able to work through an extremely complex and challenging process and begin compensating those who suffered loss. This marks a pivotal milestone for those who were impacted by the Maui wildfires, and our hearts are with them as they continue on their journey of healing and recovery.

While we've advanced the wildfire settlement agreement, we've worked in parallel to reduce wildfire risk across our communities as quickly as possible. Our utility teams continue to work with urgency toward reducing wildfire risk and strengthening the resilience of our grid.

On April 13, we submitted our first update to our Wildfire Mitigation Plan, or WMP, to the Public Utilities Commission, which covers 2026 and 2027. In accordance with the PUC's approval of our WMP at the end of 2025, we'll continue to submit updated WMPs every other year starting in 2027, with each update covering a 2-year period.

This schedule will foster a predictable, deliberate approach toward planning and implementing our wildfire risk reduction measures. Proactive risk management and continuous improvement will continue to define our approach as we move forward.

Turning to the next slide. Affordability is a core focus of ours and affordability pressures have intensified given the recent increase in fuel prices across the globe.

We've always been committed to supporting our communities during times of uncertainty, and we've displayed this commitment during the pandemic, the Maui wildfires and in the current period of high oil prices. In early April, we told our customers to prepare for potential increases in energy costs in the coming months, driven by rising global oil prices linked to escalating geopolitical tension.

We also rolled out new options to support our customers through this challenging time. Starting April 6, we began offering customers options that can smooth short-term billing spikes and provide additional financial flexibility.

These include interest-free payment plans for up to 6 months and $50 bill credits to customers in areas that rely more heavily on diesel fuel generation, which has seen the largest increase in fuel costs. As we work to help customers through this higher cost period, we continue to advance strategies that systemically address household energy burden.

This includes supporting electrification, rooftop solar and EV adoption, all of which have contributed to an average household energy burden in Hawaii that is below the national average. We also believe we're well positioned as a company to navigate the impacts from the sharp rise in fuel costs.

Paul will talk more about our strong liquidity position, but I'll note that our prudent balance sheet management ensures we're well prepared for the unexpected. Current global events highlight the importance of a diversified energy mix to limit the impact of geopolitical instability and price volatility.

Reducing customer bill volatility is one of the many reasons we supported adding renewable energy, such as solar plus storage to our grids. Renewables not only contribute to our state's renewable energy and decarbonization goals, they also increase bill stability.

Turning to the next slide. We're in a transitional year as we prepare for our expected reset of rates in 2027.

On March 6, we submitted our rate rebasing request jointly with Ulupono Initiative, an intervenor in many of our PUC proceedings and a working group party in performance-based regulation. This joint proposal advances an unprecedented stakeholder-driven nontraditional approach to utility rate adjustment.

The approach is consistent with the fundamental principles of PBR, which encourages innovation and the evolution of utility regulation. Our request prioritizes customer affordability while allowing the utility to undertake the investments and expenses that are critical to safety, reliability and resilience.

Our proposed rebasing would increase consolidated base rates by approximately 5.3%, phased in over 2 years to moderate customer impacts. This equates to an increase in the average customer bill of $8 to $12 in 2027 and then an additional $2 to $3 in 2028, varying slightly by island.

The requested increase could also help improve our return on equity, which we expect will continue to be impacted in this year of transition as we prepare to enter our second multiyear rate period. Paul will discuss our expectations for 2026 in more detail.

Performance incentive mechanisms, or PIMs, are also an essential element of PBR. And although development of PIMS for the second multiyear rate period has not yet been completed, our joint proposal recommends that a total of 200 basis points of PIMs be available, composed of 150 basis points of award potential and 50 basis points of penalty potential.

Affordability is fundamental to our regulatory framework. And by the end of our current multiyear rate period, we'll have provided more than $100 million in revenue requirement reductions to customers.

As we implement any approved rate rebasing in our second multiyear rate period, we'll continue working with our customers to provide options to address affordability pressures. Turning to an update on Waal.

In late March, the PUC issued a decision and order approving our proposed Waal Generating Station repowering project, which had been selected in December 2023 after a competitive bidding process. This is a milestone approval, allowing us to move ahead with a critically important firm generation project that will enhance energy reliability and resilience for our customers.

The commission approved cost recovery through our exceptional project recovery mechanism or EPRM, totaling $908 million. This amount includes the original estimated project cost of $847 million plus an adjustment for inflation.

We do foresee project costs will exceed this amount since as many of you know, there have been significant and unforeseeable cost increases that have impacted power generation projects worldwide over the 2 years since our original cost estimate. However, the commission has confirmed that we may seek recovery above the currently approved amount in a future rate case or rate rebasing proceeding, which may be in 2031.

Including the inflationary adjustment that will recover through the EPRM, the projected incremental amount we'll seek recovery for after the project is in service totals $247 million. At the end of April, following the PUC's approval, we executed contracts for the purchase of 6 gas turbines for the Waal project to secure production slots and remove exposure to non-tariff price increases.

In summary, we expect 2026 to be a year of transition now that we've reached the pivotal milestones of finalizing the tort litigation settlement and launching our alternative rate rebasing process. We're no longer navigating a crisis.

We're strengthening our foundation while working to build a safer, more resilient future for the communities we serve. Our focus going forward will continue to be on the critical processes underway with key stakeholders, including the liability cap rulemaking and rate rebasing processes underway with the commission and executing well on our Waal repowering project.

We'll continue to be laser-focused on affordability and supporting our customers and communities, especially given fuel price impacts from the Iran conflict. I'll now turn the call over to Paul Ito to discuss our financial results.

Thank you, Scott. I'll start with our financial results on Slide 7.

For the first quarter of 2026, we generated net income of $30.5 million or $0.18 per share compared to $26.7 million or $0.15 per share in the same quarter of 2025. The results include less than $1 million of pretax Maui wildfire-related expenses net of insurance recoveries and deferrals.

This is down considerably from roughly $4.5 million in the same quarter of last year. Excluding the Maui wildfire-related expenses and excluding last year's losses from our strategic review of Pacific Current, which we refer to as noncore, consolidated core net income and EPS were $31 million and $0.18, down from $39.8 million and $0.23 in the first quarter of 2025.

Utility core net income for the quarter was $35.7 million compared to $49.7 million in 2025. There were unprecedented heavy rains and damaging wind events from February through March, requiring 35 days of emergency response by the utility.

Kona Low storms in March caused massive flooding across multiple islands with an estimated $2 billion in damages, resulting in President Trump issuing a federal disaster declaration in early April. The decrease in utility net income primarily reflects higher O&M expenses from the quarter's severe weather.

We also saw higher O&M expenses due to higher insurance costs, primarily related to the deferral of wildfire liability premiums in 2025. Interest expense was also higher compared to last year due to the $500 million high-yield debt issuance last September.

Holding company core net loss for the quarter was $4.8 million compared to $9.9 million in 2025. The lower core net loss was driven by lower interest expense due to the lower debt balance following the retirement of holding company debt in April of last year.

Turning to the next slide. As of the end of the first quarter, the holding company and the utility had approximately $10 million and $437 million of unrestricted cash on hand, respectively.

In addition, the holding company has approximately $535 million in combined liquidity available under its ATM program and credit facility capacity. The utility also has approximately $518 million of liquidity available under its accounts receivable facility and credit facility capacity.

Scott discussed rising fuel costs and while we have a fuel cost pass-through mechanism, the higher costs started to impact our working capital following quarter end since we pay for fuel when delivered based on the daily average prices of the previous month. For example, prices for fuel delivered and paid for in April are based on daily average prices in March.

Those higher fuel costs are reflected in rates with a lag of approximately 1 to 2 months. With our strong liquidity, we believe we are well positioned to handle the increase in working capital requirements due to the sharp rise in fuel prices.

As mentioned, we made our first $479 million settlement payment on April 10. This payment was made using the funds previously set aside in a special purpose vehicle.

We expect to make future payments in April of 2027, 2028 and 2029. Our financing plans for these payments are unchanged from what we communicated last quarter.

We still expect to fund the second settlement payment with debt and/or convertible debt and expect that payments thereafter will be funded with a mix of debt and equity depending on market conditions. We intend to manage our settlement financing consistent with targeting investment-grade credit metrics.

We continue to see positive momentum from the rating agencies. Following the finalization of the global settlement and our first settlement payment, Moody's upgraded the utility to Ba1 from Ba2 1 notch below investment grade and the holding company to Ba2 from Ba3.

Turning to the next slide. We've updated our CapEx forecast to reflect the WIA approval, and we are now expecting approximately $157 million of Waal CapEx in 2026 versus previous expectations of approximately $90 million.

As Scott mentioned, we will request that about $247 million of WIL CapEx that is not being recovered separately through EPRM be recovered in the next rate case or rate rebasing proceeding. Lastly, as Scott mentioned, we do expect higher O&M in 2026 as we progress through a year of transition ahead of our rate rebasing.

This is due to the following factors: higher insurance premiums, primarily reflecting our deferral treatment of wildfire insurance premiums prior to 2026, storm response expenses related to severe weather in February and March, higher vegetation management expenses as we prioritize safety following record rainfall in the first quarter, higher overhauls and station maintenance expenses as we prioritize reliability, higher IT-related costs as we improve our cyber defenses and higher labor and benefit costs. We expect these expenses to drive an O&M increase that significantly outpaces inflation this year.

In addition, we also expect to realize the maximum penalty under our fuel cost risk sharing mechanism, or FCRS. This mechanism provides for earnings upside and downside based on procured fuel costs compared to benchmarks.

You can see exactly what those benchmarks are in the appendix of this presentation. But as you might expect, due to the global energy situation that's unfolded since late February, we are now considerably above those levels.

As a reminder, the FCRS runs through our revenue, so penalties are recorded as a revenue reduction. Our rate rebasing request is intended to address many of these higher costs such as the increased insurance premiums we experienced over the last few years.

Additionally, we are in the process of reprioritizing work to mitigate the expected impact of the increases. With that, let's open up the call to questions.

So first one, the rebasing proposal you showed today shows $145 million in '27 and then an incremental $25 million in '28 or $170 million. Our understanding from the March 6 filing is still $170 million, but it was $125 million and then $45 million.

Can you clarify whether the phasing has been revised? any update on when the PUC might provide a procedural schedule?

Yes. Thanks, James.

This is Scott Su. Let me ask Joe Viola, he's our Senior Vice President, who oversees our regulatory process area to respond to your question.

James, to your first question, no, there hasn't been any change to the way we're going to phase in the proposed revenue increase. And second, we're waiting for further guidance from the commission.

When we filed the proposal since this was a novel process, we suggested a procedural process to review this that would allow for public input. And also, we expect that we need to get a certification from the commission that we complied with the order that allowed this proposal.

So we're confident we did, but we're just waiting on that order and further guidance on what the process will be to review it.

Got you. Appreciate that.

So on the repowering and the $247 million gap that Paul spoke to that is in the slides there, that you're going to seek in the next rate proceeding, which you estimate is around 2031. How should we think about the carrying cost of that?

I'm going to, I'll call it, $250 million, just $0.25 billion between in-service and rate recovery and more importantly and pertinent to that current proceeding, how does the existence of the gap have or not have any impact on the current rebasing?

So Jay, let me answer the first question. So the question was how our carrying costs accounted for associated with the project.

So we would accrue AFUDC at our current approved weighted average cost of capital. which on Oahu, I believe, is about 7.37% for -- on a combined basis.

So we would accrue AFUDC at that rate.

Perfect. Okay.

Got you. And so is there any interaction with the current rebasing proposal?

Or is this all something that would be allocated towards 2031?

James, this is Joe Viola again. No, there's no interaction.

That project was not part of our rebasing proposal because it's not in service yet, right? So we got approval to recover about 80% of that through a special recovery mechanism.

And then in the next rebasing process around -- we would expect around 2031, we would seek the final cost there.

Got you. Has the PUC opened or indicated any kind of time line for opening a formal rule-making docket on the wildfire liability cap under Act 258.

So I'm not talking about new legislation. I get the legislative sessions were through that.

But the one that was already one addressing Act 258, the cap.

Yes, James, this is Scott again. The PUC has not issued anything formal.

We understand as they alluded to in the report that they filed at the end of last year that they would be initiating their work on the rule-making process. And other than throwing out an 18- to 24-month expected time frame to complete that rule-making process, they've not said anything further publicly.

Okay. Fair enough.

We hadn't seen anything either, but just wanted to check. Last one I'll ask is just S&P and Fitch, as you guys mentioned, now have positive outlooks on both HEI and Hawaiian Electric.

So with the settlement now resolved and congrats again on that. What are the rating agencies communicating as the remaining gating items for an upgrade?

And is the liability cap explicitly part of that conversation?

Yes. So in our discussions with the rating agencies, and of course, what they tell us is they don't tell us exactly here's what you need to do to get upgraded.

But what our discussions have included and what the reports show, what they're focused on is, of course, the outcome of the rate rebasing progress on reducing wildfire risk across our system, but also the liability cap and the wildfire recovery fund. So all of those are taken as inputs into their rating methodology.

As I mentioned, they're focused on it. We just don't know and they don't disclose exactly which elements have to be present for an upgrade.

But as you mentioned, we were very pleased to see that Moody's upgraded us both the holding company and the utility one notch based on the settlement being final. And now they're turning their attention, obviously, to the other things that I mentioned, the rate rebasing and the liability cap.

I was just wondering if you could talk about -- more about the drivers of the increase to your capital program. The separate recovery bucket was increased in your slide.

I know some is associated with the repowering. Just wondering if you could talk about other drivers and how much of it is EPRM recovery and therefore, likely to earn higher ROE?

Michael, this is Paul. Yes.

So in our CapEx forecast, we are forecasting generally what we describe as our baseline CapEx. So these are more business as usual type of projects, roughly $350 million to $400 million a year.

And the increase in CapEx is, as you mentioned, largely due to separately recovered projects like Wa and Wana Best are 2 examples. So those are the bigger drivers.

We have 2 buckets in that category approved and applications waiting to be approved. So in the approved bucket, the change for this quarter was that Waal is now approved.

And so as an example, for -- I'll just use 2027, there's about $250 million of capital in that particular bucket for the approved. But we still have capital that is not approved and pending approval, and that totals about $135 million in 2027.

So you can find the details in our appendix in our earnings deck. But hopefully, that gives you the color of the baseline CapEx and then the capital that we're putting to work where we get separate recovery or special recovery in between rate cases.

And then now that the settlement has been approved and you made your first payment, what are your current thoughts on the timing of raising the funds for the second payment? I know as of the last earnings call, you said you were leaning towards a convertible bond, but probably wouldn't issue it very far in advance of the second payment date.

Yes. So we have basically about a year to determine when and how to raise the next settlement payment.

So it gives us a lot of flexibility on timing. Our decision will really be based on market conditions, and we're going to be opportunistic in raising the second payment.

As mentioned, convertible debt is an option. It does appear to be one of the cheaper sources of capital, at least at the moment, but that could change.

So we're going to monitor conditions. And when we feel like it's a good time to access the market, we'll do so.

And then also wondering if you could talk more about how you're feeling with the higher oil prices, fuel costs and your liquidity position. It sounds like you feel like you're in a good spot.

Do you expect to be there with just the cash on your balance sheet and existing credit facilities? Or do you think you'll rely heavily on commercial paper as well?

Just wondering how you expect to bridge the gap, the timing mismatch between fuel payments and customer recovery?

Yes. So at the end of the quarter, we had almost $1 billion of liquidity split between cash on our balance sheet, our senior credit facility of $300 million and our AR ABL facility that is about $250 million, but based on AR at the time, about $218 million.

So we have significant liquidity available. We do -- as we mentioned, we do have a full fuel cost pass-through, but there is a lag, and so it could affect our working capital.

Typically, the lag is a few months. We have a little bit over a month of fuel inventory.

And then, of course, we bill customers and the daily sales outstanding is roughly 20 to 25 days. So it's, again, a couple of months.

So I guess the question and how much of an impact to liquidity we'll see is really how long this elevated fuel price situation stays in place. But again, regardless of whether it's short term or long term, we do feel very confident that we have sufficient liquidity to weather it.

And then given the high oil prices, do you have an expectation for what you think bad debt expense could be if they remain elevated for the rest of the year or maybe like an amount per month?

Yes. And maybe the way I'll describe the potential impact, and this goes to the view of whether it's a long-term or short-term impact in elevated fuel prices.

I'll use back when COVID occurred and then shortly thereafter, there was the Ukraine-Russia war. And in that situation, our bad debt write-off percentage peaked at about 51 basis points.

Typically, we're in the 10 to 20 basis point range. So obviously, a significant increase of our baseline.

But generally speaking, really good or limited impact in terms of bad debt compared to what we've seen in other places. Part of that is, of course, we have -- we're not connected, right, to other areas.

And so if you're living in Hawaii, you have to connect to the utility. So again, we're ready for that.

But again, it comes down to whether it's a near or long term in terms of how much that write-off percentage would increase.

And then just wondering if you could share amid these elevated oil prices, your thoughts on your confidence around the rebasing proposal and high customer bills. I know it's somewhat of a modest rebasing request, but just share your confidence about it getting approved right now and also what your expectations are of when you'll get a decision on it?

Yes. Mike, this is Scott.

So I think it's fair to say that our Public Utilities Commission is very focused on impacts to customers because of the high oil prices. And as they look at our rate rebasing request, we understand that, that context, it puts pressure on them.

It puts pressure on us. At the same time, as you mentioned, we really worked hard, including with Uupono initiative to come up with a rate rebasing proposal that is pretty solid and at the same time, really tries to moderate the impacts on our customers and spread out some of those impacts.

So again, I can't predict exactly ultimately what the PUC will decide here. But hopefully, they understand that we also are putting customer affordability at the forefront.

And then lastly for me, I was just wondering if you could talk about the PIMs in the rebasing proposal, the achievability of them. I know the prior framework didn't seem so conducive to achieve the reward.

Michael, this is Joe Viola again. That's actually an ongoing discussion with the stakeholders in that process and with the commission.

So as you know, we've all lived and learned. So I think we're in a good position to identify design-wise, what works and what doesn't work.

So that's actually the section of the process we're in right now. We're proposing or we're going to be proposing changes to the PIMs to make sure that they are reasonably within our control to achieve and the targets are clear and based on good baselines and things like that.

So again, really just lessons learned from the first time around, take those into consideration, pose PIMs that we think will be meaningful

So just a quick follow-up on the Wa repowering. So the AFUDC would only be through COD in, I believe, it's late 2029.

Is that right? And then after that, you have depreciation drag and so on.

So I guess, in summary, how should we kind of think about the incremental lag towards the end here or just the incremental lag until it's factored in, in that 2031 filing?

Yes. So you should think of the Waha as essentially sort of 3 projects in a larger project.

So there are 6 turbines, 2 turbines to be put into service in different years. So the first pair is in 2029.

-- second pair is in 2031, third pair is in 2033. So -- and it's important to remember that we are approved for a baseline of recovery, right, of $909 million across those 6 turbines.

What remains to be determined is when that first pair goes into service, we would have to file for recovery at that point in time and to be determined, which is what we're going to be asking for at that point in time. But I want to make clear that because it's going into service in different years, we would start getting recovery in those separate years once those turbines are put into service.

Thank you all for calling in today. In closing, we've reached a pivotal milestone now that we've resolved the Maui wildfire litigation.

2026 will continue to be a year of transition for us. But with our streamlined business model solely focused on our regulated utility operations, we believe we have a strong foundation to continue providing our communities with safe, reliable and resilient service for the long term.

So again, thanks, everybody, for joining us, and thank you for your support as we go forward.