Hawaiian Electric Industries, Inc. Stock

Thank you for standing by, and welcome to the HEI Second Quarter 2026 Earnings Conference Call. [Operator Instructions].

I would now like to turn the call over to Mateo Garcia, Director of Investor Relations. Sir, please go ahead.

Welcome, everyone, to HEI's Second Quarter 2026 Earnings Call. Joining me today are our CEO, Scott Seu; our President, Shelee Kimura; our Senior Vice President and CFO, Paul Ito, 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.

Aloha kakou! Welcome, everyone. For today's call, I'll start with updates on key strategic priorities and regulatory processes. Paul Ito will walk through our financial results and then open it up for questions.

As you will recall, in December of last year, the PUC approved the utility's 3-year Wildfire Mitigation Plan, or WMP, concluding that our proposed strategy can be expected to reduce wildfire risk. In June, the PUC granted our request to recover approximately $350 million of WMP spending through the Exceptional Project Recovery Mechanism, or EPRM. This includes roughly $270 million of capital and $80 million of O&M. In addition, the PUC approved recovery of up to $11.5 million of WMP related O&M already spent in 2025 and $3.9 million of annual ongoing WMP related O&M spending in 2028 and beyond.

Act 258, which authorizes securitization for recovery of infrastructure resilience costs was signed into law after we had submitted our request for recovery of WMP costs. We plan to request recovery of WMP costs through securitization rather than the EPRM. And we're currently working on an application requesting the commission's issuance of a financing order. Affordability remains a core focus of ours and securitization will allow us to implement these critical investments at the least possible cost to customers. We expect that EPRM recovery would only be used for WMP costs that may not be eligible for securitization.

Turning to the next slide. As we discussed last quarter, we're in a transitional year as we prepare for our expected reset of rates in 2027. We submitted our rate rebasing request in early March. And in June, the commission accepted our proposed rate rebasing methodology, issued a tentative procedural schedule and directed us to refile our request in a new docket. We resubmitted our rebasing request last month, and our request continues to have stakeholder support. The commission's tentative procedural schedule allows for a final decision and order in mid- to late April of 2027 with public hearings to begin soon. Our total $170 million proposed base rate increase is phased in over 2 years with $125 million of the increase proposed to take effect beginning in 2027. We've requested that the commission issue an interim decision by December 18, 2026, so that new rates reflecting this first phase of the rebasing can go into effect by January 1, 2027.

Turning to the next slide. In June, we filed our annual action plan update to our Integrated Grid Plan, or IGP. As a reminder, our IGP lays out a pathway that includes a short-term action plan and long-term strategy to meet the energy needs of our customers while balancing reliability, affordability and decarbonization needs.

Our June IGP update proposes actions that prioritize affordability, identifying what we can do within the next 5 years to stabilize rates and advance energy equity. These actions include using competitive procurements for all types of renewable generation to attract the lowest pricing for customers.

Last month, on July 17, we submitted the final IGP request for proposals or RFP to the PUC in advance of its issuance today, August 7. Our RFP is intended to meet our customers' growing energy needs and modernize the generation fleet. It will be one of the largest competitive procurements for generation resources in state history, seeking nearly 1,650 gigawatt hours of variable renewable energy, 465 megawatts of grid forming resources and 111 megawatts of firm generating capacity.

We're also requesting to launch an RFP for all fuels by the end of 2026, including both liquid and gaseous fuels, to provide a competitive evaluation of price, sourcing, environmental impact and other measures. A competitive process best serves the interest of customers.

In line with this, in our July 17 request, we also ask that the PUC allow us to issue a new RFP to consider all options for development of up to 500 megawatts of additional firm generation on Oahu. Above and beyond the IGP RFP and the projects selected in the Stage 3 RFP, including our Waiau repowering project.

On August 5, the PUC responded to our letter informing us that a demonstration of need must be made before advancing such a significant procurement. The commission noted that the demonstration of need should include thorough analysis of system capacity and reliability needs, consider substantial stakeholder engagement and explain how the proposed new generation aligns with the IGP. We believe the commission's request is reasonable and prudent and we plan to respond to the PUC accordingly.

We're also continuing to move forward with bringing new resources from our previous procurements online. In June, the commission approved 2 more PPAs for solar plus storage projects from our 2023 Stage 3 RFP. There are now 3 solar plus storage contracts approved from our Stage 3 RFP totaling 166 megawatts of solar and 670-megawatt hours of battery storage, and multiple firm generation projects, including Waiau, 7 other Stage 3 projects have been or will be submitted to the commission for review.

While we advance our competitive procurements, we'll continue to work in parallel to grow a thriving competitive marketplace for customer scale renewable generation, including by targeting roughly 1.2 gigawatts of private rooftop solar by 2030. We have a responsibility to plan for the holistic needs of our system, and we can't simply consider generation, transmission or distribution requirements in isolation. Delivering safe, reliable and resilient electricity for our customers while also meeting the state's renewable energy policy goals requires a modern and resilient grid.

We've identified over $1.3 billion in investments through 2035 and to build or expand in connection points between renewable projects, nearly $60 million of investments in distribution upgrades required over the next 10 years and $190 million over the next 5 years for our PUC-approved climate adaptation program to harden the grid and implement other resilience measures.

In summary, successfully delivering the service our customers expect while making the critical investments required in transmission, distribution and generation, not to mention the critical need to increase resilience to wildfire and other severe weather event risk, requires holistic planning and excellent execution. Our wildfire mitigation plan and Integrated Grid Plan have been years in the making and are designed to be dynamic and evolving. We'll continue our focus on execution of our plans to deliver safe, reliable, resilient and affordable service to our customers.

I'll now turn the call over to Paul to discuss our financial results.

Thank you, Scott. I'll start with our financial results on Slide 6. For the second quarter of 2026, we generated net income of $123.2 million or $0.71 per share. The results include the impacts of a noncash accounting adjustment to the remaining Maui wildfire settlement liability.

Following the final conditions to payment under the settlement agreement being met, The wildfire tort liability became a contractual liability rather than a contingent liability. This required an accounting remeasurement of the remaining liability to present value. The remaining settlement liability was adjusted down from $1.44 billion to $1.3 billion, reducing expenses by $153.9 million. The benefit recognized will reverse over time through the accretion of interest expense over the next 3 years. The remeasurement totaled $136.2 million pretax, net of the accretion recognized this quarter. We also recognized $8.5 million in insurance recoveries this quarter related to the Maui wildfire tort liability.

Excluding these Maui wildfire settlement-related impacts and excluding losses related to Pacific Current asset sales, both of which we refer to as noncore, consolidated core net income and EPS were $22.5 million and $0.13, down from $35.4 million and $0.20 in the second quarter of 2025. Utility core net income for the quarter was $32.6 million compared to $42.5 million in 2025. The decrease in utility core net income primarily reflects higher interest expense related to the higher debt balances following last September's debt issuance and higher O&M expenses. Higher O&M expenses were driven by higher vegetation management expenses, higher generation overhaul and maintenance costs and higher overhead and underground inspection and maintenance costs.

Holding company core net loss for the quarter was $10.1 million compared to $7.1 million in 2025. The higher core net loss was primarily driven by lower interest income due to lower cash balances following the first settlement payment.

Turning to the next slide. As of the end of the second quarter, on a consolidated basis, total liquidity was approximately $1.3 billion. The holding company and the utility had approximately $52 million and $186 million of unrestricted cash on hand, respectively. In addition, the holding company has approximately $550 million in combined liquidity available under its ATM program and credit facility capacity. The utility also has approximately $550 million of liquidity available under its accounts receivable facility and revolving credit facility.

We continue to believe that we are well positioned to meet increased working capital requirements due to sustained higher fuel prices. We have not seen a meaningful increase in bad debt expense or write-offs this year, and as you can see on Slide 7, bad debt expense is actually lower than it was at this time last year, while net write-offs have been relatively flat. Our financing plans for the remaining settlement payments are unchanged from what we communicated last quarter. We intend to manage our settlement financing consistent with targeting investment-grade credit metrics.

We continue to see a positive trajectory with our credit ratings. And in July, S&P upgraded HEI and Hawaiian Electric 1 notch to BB-. In doing so, S&P recognized the progress made to reduce our wildfire risk exposure through implementation and commission support of our WMP. The S&P also revised their assessment of HEI's and Hawaiian Electric's business risk profile to Satisfactory from Fair. S&P's action follows Moody's 1 notch upgrade for both the utility and holding company in April of this year.

As Scott mentioned, we are very focused on affordability and we plan to finance our $350 million in approved wildfire mitigation plan CapEx through securitization. Later this year, we'll be submitting our request to the commission for the financing order required to launch our securitization.

Turning to the next slide. Our expected CapEx over the next 3 years remains largely unchanged, although we've tightened the ranges now that our WMP is approved for separate recovery. As mentioned last quarter, we do expect higher O&M for the full year as we progress through a year of transition ahead of our rate rebasing. The higher O&M is driven by numerous factors, many of which we talked about last quarter. As a reminder, we deferred approximately $28 million of pretax wildfire-related expenses last year, and we are no longer authorized to defer such costs. These include wildfire insurance premiums, which are authorized for deferral treatment prior to 2026.

As discussed on our first quarter earnings call, we've also incurred significant storm response expenses related to severe weather and historic flooding in February and March and higher vegetation management expenses as we've prioritized safety and reliability following record rainfall in the first quarter. Higher overhauls and station maintenance expenses have also driven higher O&M as we've prioritized reliability and IT-related costs have been elevated as we improve our cyber defenses. We've also faced higher labor and benefit costs in the current inflationary environment.

In addition, we continue to expect to realize the maximum penalty under our fuel cost risk-sharing mechanism or FCRS. We also do not expect to achieve the same level of PIM and shared saving mechanism rewards as we did last year. PIMs and SSMs last year totaled $7.5 million and we also achieved rewards from better heat rate performance of $3.3 million. We are currently expecting to accrue a loss from PIMs and SSMs for the full year 2026.

We'll also continue to see higher interest expense this year from the high-yield debt issuance completed in September of 2025. And following April settlement payment, we are no longer receiving interest income on the cash we had set aside for making the payment. As mentioned, we'll continue to see additional interest expense from accretion following the wildfire settlement liability remeasurement until we've made the settlement payments. However, this accretion is noncash and considered noncore. Our rate rebasing request is intended to address many of the higher costs, such as the increased insurance premiums we experienced over the last few years.

In parallel, what is designated as PBR Phase 6, our commission will consider potential PBR framework changes for the next multiyear rate plan. The commission intends to resume Phase 6 with a staff proposal informed by prior party input. We'll be pursuing modifications in Phase 6 that would address other drivers of structurally higher O&M expenses, including addressing the annual ARA increase based on forecasted GDPPI which has consistently lagged actual cost increases in utility supply chains nationwide. Additionally, we are in the process of reprioritizing work to mitigate expense headwinds and managing expenses to operate as efficiently as possible. This work is well underway as we progress through the remainder of the year.

With that, let's open up the call to questions.

[Operator Instructions]. Your first question comes from the line of Michael Lonegan with Barclays.

So you talked about the $350 million of securitization for the wildfire mitigation plan. Just wondering, does all that fall in your capital plan through 2028 that you detailed on Slide 9. Just wondering how we should think about rate-based items through 2028. Should we take out that full $350 million from the capital plan. Can you help us just understand your rate base growth outlook through '28?

Mike, this is Paul. Yes. So to the extent that we do get approval to securitize the wildfire mitigation plan expenses, then that would not be part of rate base that would be recovered through the securitization. So as we mentioned in our prepared remarks, we are planning to file the application this year, but the commission will then have to rule on whether those costs would be eligible for securitization, which we expect they would be.

And then on the rebasing proposal, I know the commission denied your ability to file a rate case afterwards. Can you just help us understand when you plan to file your next rate case? Is it -- or when you're able to file your next rate case, is it 5 years after the rebase rates go into effect after the next PBR term ends? Or could you come in sooner for a case?

Mike, this is Scott Seu. I'm going to ask Joe Viola, our Senior VP, who oversees regulatory affairs to respond.

Michael, yes, I think the expectation would be we're going to rebase rates right now for the next 5-year multiyear rate plan. So we would expect we'd be rebasing rates through some process in roughly the 2032 time frame.

Okay. And then obviously, you're saying you expect O&M to be materially higher than inflation. Any more detail you could provide on how much higher? I noticed your trailing 12 months earned ROE took a 2.6% hit from O&M and depreciation and other items. Is that something we could expect for the balance of the year?

Yes, Mike, the way I would look at it is, I would categorize O&M into 3 buckets. There are different drivers. So for the first bucket, like storm activity, these are costs that are episodic, difficult to predict. So I wouldn't view that as a normal run rate item.

The second bucket is we've been making a conscious decision to spend ahead of recovery in certain areas. So for example, a vegetation management to reduce risk in an effort to support safety and reliability and maintenance and overhead and underground maintenance. So that's just part of our core responsibilities. And I'll address how we're planning to manage that cost.

And then the third bucket would be, what I would call more of a structural change. And the higher insurance premiums are a clear example of that, where, just given what we've gone through with the fires, our insurance premiums have gone up significantly.

We are trying to address that in a number of ways, right? So the way that we're addressing all of these cost increases, as we mentioned, the rate rebasing is a key one, and the insurance increase is was one of the things that was contemplated in the rate rebasing request. But in addition to that, we're also making a lot of progress on reducing risk on our system through the operational changes and so we've actually been getting better insurance rates per million of coverage over time as we demonstrate the progress that we've been making. With that rate reduction, we're increasing coverage, so that also reduces risk.

The other thing that we're focused on in managing these costs is, as I mentioned, the Phase 6 process. right? So there are additional changes that we would be proposing to basically align the recovery with the cost increases that we're seeing provided that we perform. So that's another way that we're planning on addressing some of these higher costs.

And then the third way to address this is just internal efficiency measures. So for example, we're looking at key areas where it would make sense to in-source more work versus outsourcing to contractors. We're in that process right now. We're also looking at end-to-end processes to increase output for each dollar spend. So these efforts will take time to show up, but it's a critical initiative in managing our O&M going forward.

Yes, Mike, this is Scott. I think I'd just emphasize what Paul just said, we're essentially taking a pretty holistic viewpoint of how we manage across the business to address these various pressures.

And then lastly for me, I was just wondering your thoughts on JERA's proposal with the PUC to establish a regulated generation utility seems somewhat unprecedented. Just wondering if you could talk about engagement with stakeholders. From what I've seen, it seems like the governor is supportive of it.

Yes, certainly, Mike. Yes, it's been pretty public with the filings or the letter filings of that JERA made to the PUC back in July. Their intent is that in the Q1 of 2027 that they would submit an application to establish themselves as a new regulated GenCo utility here in Hawaii. So their letter filing actually has not formally kicked off any part of the process. The governor has been public in terms of his support of JERA's plans.

Our position on this is that ultimately, it needs to be whatever gets decided needs to be in the best interest of all customers in Hawaii. We have an existing framework that's been well established for many, many years that we operate under as the current regulated utility here serving 95% of the state. And we believe that, that framework should be followed, albeit we can certainly would suggest that it can be looked at from efficiency and effectiveness.

But I would just sum it up like this. Right now, we have JERA that is here trying to understand how they can serve here in Hawaii. We continue to serve Hawaii. And we will participate fully in terms of whatever process gets kicked off with the PUC.

And lastly, I would just say, I think we are all aligned in what the governor is trying to achieve here in terms of his energy vision to address affordability and reliability and clean energy. So it's really less of a question of the endpoint. It's more a question of how do we best get there.

Great. Thanks for taking my questions.

That concludes our question-and-answer session. I will now turn the call back to Scott Seu for closing remarks.

Thank you all for calling in today. In closing, 2026 continues to be a year of transition for us. We've made significant progress improving the safety of our system, and I'm pleased that this has led to credit ratings improvement and PUC approved costs for our WMP. We remain laser focused on affordability and our planned securitization for WMP costs as well as our plans for competitive procurements of resources, will help us improve reliability and resilience at lower cost to customers.

Thank you again. Aloha.

Ladies and gentlemen, this concludes today's call. Thank you all for joining. You may now disconnect.

Ladies and gentlemen, thank you for standing by. My name is Krista, and I will be your conference operator today. At this time, I would like to welcome everyone to HEI First Quarter 2026 Earnings Conference Call. I would now like to turn the conference over to Matteo Garcia, Director of Investor Relations. Please go ahead.

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.

Your first question comes from James Ward with Jefferies.

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.

Your next question comes from the line of Michael Lonegan with Barclays.

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

Your next question comes from the line of James Ward with Jefferies.

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.

And that concludes our question-and-answer session. I would now like to turn the conference back over to Scott Su, CEO, for closing comments.

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.

Ladies and gentlemen, this does conclude today's conference call. Thank you for your participation, and you may now disconnect.

Hello, and thank you for standing by. My name is Tiffany, and I will be your conference operator today. At this time, I would like to welcome everyone to the HEI Fourth Quarter and Full Year 2025 Earnings Conference Call.

[Operator Instructions]

I would now like to turn the call over to Mateo Garcia, Director of Investor Relations. Mateo, please go ahead.

Thank you. Welcome, everyone, to HEI's Fourth Quarter and Full Year 2025 Earnings Call. Joining me today are Scott Seu, HEI President and CEO; Scott DeGhetto, HEI Executive Vice President and CFO; and Shelee 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.

Aloha kakou! Welcome, everyone. For today's call, I'll start with an overview of the important accomplishments we've made over the past year and touched on our priorities going forward. Scott DeGhetto will walk through our financial results and then open it up for questions.

Over the past year, we continue to execute on the priorities we've communicated since the Maui wildfires in 2023, and I'm proud of the progress we've made. We've advanced key initiatives, including progressing the Maui wildfire tort settlement, pursuing legislative measures that support our communities as we deal with the risk of wildfires, implementing wildfire safety improvements that have reduced the risk of ignition from utility equipment and laying the groundwork for a successful second multiyear rate period under our performance-based regulation, or PBR framework.

Our actions to date help ensure our ability to serve and invest in our communities for the long term. Last quarter, we discussed the process to obtain final court approval of the Maui wildfire towards settlement. We continue to make good progress in resolving the remaining contingencies to payment. In late December, the Maui Circuit Court granted our motion for summary judgment on the subrogation insurers direct claims. In January, the court granted final approval of the class settlement agreement and provided a good faith settlement determination. We also received another favorable decision from the Hawaii Supreme Court. As previously disclosed, the subrogation insurers moved to intervene in the class settlement process, and the Maui Circuit Court denied this attempt last June. The insurers appealed, and the appeal was sent to the Hawaii Supreme Court. On February 10, the court affirmed the lower court's denial of the subrogation insurers motion to intervene in the class settlement.

In doing so, it made clear that a class settlement transforms an insurer's subrogation rights into lean rights the same way an individual settlement does, which is what the court rule on a year ago. This decision ends the insurer's efforts to derail the class settlement. And because they lack party status in the class action, the insurers should not be able to file a successful appeal to the final approval of the class agreement previously granted by the Maui Circuit Court. This positive result moves us one step closer toward final court approval of the settlement agreements.

In sum, we've continued to work through the administrative steps required to see the settlement through to completion and trigger our first payment. We're also pleased that we've been able to finalize settlements resolving both the shareholder class action and shareholder derivative lawsuits filed in connection with the Maui wildfires. As disclosed last quarter, in early November, we signed binding term sheets to settle the litigation. In late December and early January, the settlements were finalized and executed. The agreements provide for complete resolution of both sets of litigation with the company's obligations fully funded by insurance proceeds.

Turning to legislation. As we've discussed over the past few quarters, Hawaii's historic wildfire legislation signed into law last July acknowledges the need for legislative measures to protect our communities and support the financial stability of electric utilities in the face of increasingly severe weather events. The PUC's wildfire fund study was completed at the end of December, and this was a crucial first step in implementing our state's milestone legislation. Work continues to establish a liability cap with the PUC rule-making process expected to take 18 to 24 months. Details around the wildfire fund will be established sometime thereafter.

The PUC also approved the utility's 3-year wildfire safety strategy in late December, concluding that the strategy can be expected to reduce wildfire risk and emphasizing the importance of continuous improvement. The utility has achieved many of the operational objectives laid out in the strategy ahead of schedule, and we'll continue rapidly advancing the strategy as we progress through 2026. We'll be submitting our next update to the PUC in April. We've also continued to make our company stronger and more resilient through carefully managing our balance sheet.

Our successful $500 million utility debt issuance last year as well as our revolver upsize to $600 million support our financial flexibility and liquidity as we look toward the elevated capital cycle ahead. We also continue to advance our state clean energy goals with the utility reaching a 37% renewable portfolio standard or RPS in 2025. We remain on track to meet the 40% by 2030 statutory RPS requirement.

Affordability has been essential focus as we've advanced our strategic and operational priorities. Customer bills remained stable in 2025 despite the significant investments we've made in wildfire safety and resilience. The utility continues to offer financial assistance to working families including providing over $1 million in payment assistance.

Turning to the next slide. As we look ahead to our objectives for 2026, we'll continue working to resolve the conditions to payment in the tort litigation settlement agreements. We believe we're in the home stretch of this process as the only remaining steps are resolving all outstanding appeals. This includes resolving the appeal the insurers have taken from the judgment entered in our favor in their direct subrogation actions.

Turning to our ongoing rate rebasing. As discussed on our last earnings call, we are pursuing an alternative process that could allow for resetting rates without the time costs and resources typically required for a full rate case proceeding. We see this as an opportunity to develop a rate rebasing proposal in a nontraditional manner. Consistent with fundamental PBR tenants set forth by the commission and state legislature, encouraging innovation and honoring a stakeholder-driven process. We plan to submit a joint rebasing proposal with UluPono initiative, a PBR Working Group stakeholder party by March 6.

We'd also like to address some of the elements that could be improved under our PBR regulatory framework, including our annual inflationary adjustment and performance incentive mechanisms, or PIMS. This will happen in the process that the PUC has designated as PBR Phase 6. We expect further guidance from the TUC on a schedule for Phase 6 after the rebasing proposal is submitted. Affordability remains a central focus as we look ahead toward the commencement of the second multiyear rate period under PBR, especially given the elevated capital investment cycle projected over the next few years. We are pursuing low-cost financing options that would reduce impacts to customers from critical investments required for safety and results.

In the coming months, we'll be submitting a request to finance wildfire safety strategy CapEx and other infrastructure resilience costs via securitization, which is typically the lowest cost of capital available for these types of investments.

In summary, in 2026, we'll continue to execute on our key objectives of advancing the tort settlement and our rate rebasing process while implementing the wildfire risk reduction measures outlined in our wildfire safety strategy. Although much remains to be done, I'm optimistic about the path ahead and proud of what our team has accomplished to date.

Finally, we'll be seeing an executive transition at HEI at the end of the quarter. As previously determined by our Board of Directors in 2024, Scott DeGhetto's term as HEI's CFO expires on April 1. And as a result, Scott will resign effective April 2. Paul Ito, the current Treasurer and CFO of Hawaiian Electric will resume his prior role as HEI's CFO, effective April 2, 2026.

Scott joined us as our CFO shortly after the Maui wildfires in 2023, and he's played a crucial role in helping lead our company through the most challenging period we've ever been through. His leadership and expertise have been critical for our success, and I'd like to thank Scott for all that he's done. And even though he'll hand the CFO reins over to Paul come April, Scott won't be too far as we'll have him support us as our consultant. Again, I thank Scott and I welcome Paul back to his previous role.

Scott DeGhetto, I'll now turn the call over to you.

Thank you, Scott. And it's been a pleasure working alongside you in serving this company.

I'll start with our financial results on Slide 6. For the full year 2025, we generated net income of $123.1 million or $0.71 per share compared to a net loss of approximately $1.4 billion in 2024. The results include $16.5 million of pretax Maui wildfire-related expenses net of insurance recoveries and deferrals. Approximately $12.6 million of that amount was recorded at the utility. Results for the year also include $12.4 million of losses related to the strategic review of Pacific Current.

Excluding these items, which we refer to as non-core, consolidated core net income was $149.3 million or $0.86 per share. This compares to core income from continuing operations of $124.3 million or $0.98 per share in 2024. Utility core net income for the year was $177.5 million compared to $180.7 million in 2024. The decrease was driven by higher O&M expenses, primarily due to previously deferred consulting and legal fees, higher interest expense, higher depreciation and the recognition of tax credit benefits in the previous year.

Holding company core net loss was $28.2 million compared to $56.4 million in 2024. 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 and higher interest income from cash being held on the balance sheet to make the first settlement payment.

Turning to the next slide. As of the end of the fourth quarter, the holding company and the utility had approximately $16 million and $486 million of unrestricted cash on hand, respectively. In addition, the holding company has approximately $530 million in combined liquidity available under its ATM program and credit facility capacity. The utility also has approximately $540 million of liquidity available under its accounts receivable facility and credit facility capacity.

Consistent with last quarter, Hawaiian Electric's Board of Directors approved a $10 million quarterly dividend to HEI for the fourth quarter of 2025. There have been no changes to our settlement financing plans since 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. As Scott Seu mentioned, outstanding appeals must be resolved before we can make our first $479 million settlement payment, which we now expect to make in the second half of 2026.

Turning to the next slide. We still expect 2026 CapEx of $550 million to $700 million in 2027 and 2028 CapEx to increase further to $600 million to $800 million and $600 million to $850 million, respectively. This level of spend is consistent with our expectations communicated last quarter and is subject to additional PUC approvals and further resource adequacy initiatives and analysis.

At that, let's open up the call to questions.

[Operator Instructions] Your first question comes from the line of Michael Lonegan with Barclays.

Just wondering if you could talk about the latest appeal by the insurers. What do you see as the chances the Hawaii Supreme Court takes up the case? Or do you think it's possible that they deny to hear the appeal based on some of the language from the prior appeals or prior cases with the Supreme Court?

Mike, this is Scott. Thanks for the question. Yes. So the only remaining item here is that appeal, the subros appeal of the earlier summary judgment, which dismissed their claims, their direct claims against the defendants. There's been no briefing scheduled yet on this appeal that was just filed in January. I do think that ultimately, of course, I don't want to get ahead of our Hawaii Supreme Court. But essentially, this is the last step. And all decisions by the Circuit Court and the State Supreme Court have been very supportive of the settlements. Again, I won't speculate we'll speak for the Supreme Court. But I'm -- maybe I'll stop my comments there.

Okay. And then on financing the second settlement payment, what are your latest thoughts on a preference between debt or convertible debt or a combination thereof? And do you think you'll wait until after the settlement is approved to do this financing? Or is it something we could see like with the first settlement capital raise where you did that already with equity?

Mike, Scott DeGhetto. So no change in plans from what we've been saying over the past several quarters. It will be a relevering at HEI either through debt or convertible debt. Right now, based upon market conditions, I would say we're leaning more towards convertible debt and doing it all as convertible debt, but that certainly can change. as we go forward. And then in terms of the timing of that payment, we don't anticipate doing anything until after the settlements approved. As you know, that first payment was raised a while ago. It's being held in escrow.

And then once the settlement is approved, we have 30 days to make that payment. And so then we would look -- once that payment is made, we'll continue to look at the markets and determine at the appropriate time when we would raise that money. I don't think it will be a year in advance like we did the last one. But you just never know. It depends on where the market is at that particular time.

Great. And then you talked about financing your capital program with the prior debt issuance and then also retained earnings, a good portion of it. With the remaining amount, do you expect to use your $250 million ATM program, how much of that -- and what could be the cadence of issuances of that if you were to use that?

So in terms -- let me hit the ATM program first, and then I'll kick it to Paul Ito to talk a little bit a bit more about financing down at the utility and his thoughts on that. But in terms of the ATM, the ATMs out there, we have the ability to use it again, we'll be opportunistic in use of that. We may use it. We may not. It just again, depends on market conditions, but that's always an option for us.

And then lastly from me, American Savings Bank, you talked about selling the remaining roughly 10% stake of that. Is that assumed in your financing plan? Or how should we think about the timing of that potential sale?

So we still intend to divest that remaining 9.9% in calendar year 2026. Again, just depends on market conditions, how the bank is doing, et cetera. So we continue to look at that regularly. And again, we do have plans to divest that this year.

Your next question comes from the line of James Ward with Jefferies.

Congratulations, Paul. And Scott wishing you all the best. In terms of the PBR rebasing, what should we think about in terms of what's actually in that upcoming March 6 joint proposal. You've spoken to it at a high level, but the 2 to 3 most material elements may be target revenue methodology, PIM redesign of a follow-up on that, et cetera? How should we be thinking about what's in there?

Yes, James, I think we've described the high-level elements of what we're trying to work through. including the inflationary adjustment factor, having a true-up mechanism as opposed to the current structure. Looking at the PIMS and making sure the PIMS are nice and tight in terms of our ability to actually influence outcomes as well as also the potential return from those PIMs if we show that we have truly performed well there.

We've also mentioned in the past looking at expanding the scope of EPRM, the exceptional project recovery mechanism. So those are the key elements I'd say.

Okay. Got you. I have a follow-up on the pen but just first, in terms of like rebasing outcome, for risk just described this as the final extension. And what are the specific triggers that we should think about in terms of what would cause you to pivot back to a traditional 2027 test year rate case a second half '26. Like how are you managing the risk of that Jan 2027 new rate states slipping?

James, let me hand it over to Joe Viola at the utility. He's our Senior Vice President, overseeing our regulatory affairs.

The March 6 day is when we'll be submitting the rebasing proposal with one of the PBR stakeholders, Ulupono, as Scott had mentioned. The commission after that will just take a look. We figure in about 30 days. They'll make sure that everything as a formal matter administratively is in there that they expect and then give us an order to proceed with the rest of the process. We'll make -- the only thing that would cause us to pivot to a 2027 test year rate case is if that rate basing falls over denied.

Got it. Okay. That's very helpful. On the per design, we actually hosted a call recently, we posted a number of the past year, Hawaii-focused former regulators, other people attached to the political process and so on. And they were as clear for me, which I'm sure you guys already would be aligned with and happy to hear, but reiterating 150 to 200 basis points of incremental earnings power above your authorized ROE with the original intention for the PIMS and that's coming from on high.

With that in mind, and given how the initial ones were often designed with things that were outside of your control, unfortunately. And also the imbalances in terms of asymmetry in terms of downside and upside. What -- on the PIM redesign, what does a more meaningful package look like to you guys in practice? Like what would the top 2 or 3 PIM changes be that you're pursuing? And how should we think about that symmetry in terms of upside versus downside?

This is Joe again. I think in terms of the ultimate reward opportunity, we think -- we believe that the commission should eventually support what they said in the past at 150 to 200 basis points, and we'll support that. We think there's other support for that as well. In terms of what we want to see going forward, we've learned a lot, living under the first 5 years of PBR. So when we say more meaningful package, we want to make sure that the targets are reasonably set and the means to achieve them are reasonably within our control. That's the important part. We're going to look going forward, as Scott mentioned, we'll be discussing with the specific topics and specific priorities would be for those incentives. But it's -- to us, it's the design to make sure that we can achieve them. And that's our main goal. .

Yes. The only other thing I'd add, James, is we're also interested to see if we can actually reduce the total number of PIMS because that has been a bit of a challenge over the last few years managing a long list of PIMS.

Got it. That's very helpful. Last question I have is the wildfire platform here, legislation passed. So you're now guiding the 8 to 24 months for the liability cap process. wildfire fund thereafter. We obviously saw the PUC report at the end of the year to the legislature. So bringing it back right to the 24 months back to 2026, what are the 2026 milestones we should be watching for liability cap, wildfire fund, securitization. It sounds like wildfire fund might not be on there. I'll leave it open, but I think that's what the other part people would like to on.

Yes, James. So as you noted, right, at the end of last year, the PUC filed their report on the fund, the potential for a fund. And in that, they indicated that it should actually be taken up after the PUC rule-making process for a limitation of liability happens, which the PUC has indicated that, that would be the 18- to 24-month period beginning -- roughly the beginning of this year.

So as far as critical milestones, I mean a state agency rule-making process, 18 to 24 months, it will involve a lot of information gathering, data gathering. And eventually, they would file a proposed set of rules for comments and review and then they would go back and take those into account and issue the final. Once the final rule making is proposed, there is a certain period of time for the governor to actually be able to weigh in with his own comments. And at that point, once that is resolved, then the rule becomes final. So those are the high-level steps in the rule-making process. As far as other critical milestones this year, it's really all on that PUC rule-making process. And I think I would also say there's nothing that would be teed up for example, in front of the legislature this year.

Got it. Okay. I appreciate it, and see you next week at the conference.

That concludes our question-and-answer session. I will now turn the call back over to Scott Seu for closing remarks. .

I just want to close by saying again to all of our investors and interested stakeholders. Thank you for your support. 2025, like I said, was a year where we felt we really -- we're able to make a lot of progress in terms of advancing our key initiatives. I also want to one more time, just thank Scott DeGhetto for his service as HEI's CFO, coming to us shortly after the Maui wildfires in 2023. And Paul Ito, I welcome you back to our team at HEI. So with that, thank you very much.

Ladies and gentlemen, this concludes today's call. Thank you all for joining. You may now disconnect.

Hello, and thank you for standing by. My name is Tiffany, and I will be your conference operator today. At this time, I would like to welcome everyone to Hawaiian Electric Industries Q3 2025 Earnings Conference Call. [Operator Instructions] I would now like to turn the call over to Matteo Garcia, Director of Investor Relations. Sir, please go ahead.

Welcome, everyone, to HEI's Third Quarter 2025 Earnings Call. Joining me today are Scott Seu, HEI President and CEO; Scott DeGhetto, HEI Executive Vice President and CFO; and Shelee 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.

Aloha [ Hakkako. ] Welcome, everyone. For today's call, I'll start with an update on our continued progress on initiatives to improve our company's financial strength and resilience. I'll also touch on the ongoing implementation of our wildfire safety strategy and update you on the torque litigation settlement. Scott DeGhetto will walk through our financial results, and then we'll open it up for questions.

In the third quarter, we continued to take actions to ensure that we're best positioned to serve the communities in which we operate for the long term. We had a successful quarter progressing the initiatives we've talked about for much of the last 2 years, implementing wildfire safety improvements, advancing the Maui wildfire tort litigation toward final court approval, and laying the groundwork for a successful second multiyear rate period under our performance-based regulation, or PBR framework.

We also improved our liquidity and financial flexibility through [indiscernible] which Scott DeGhetto will discuss. In February, and as we had requested, the PUC issued an order establishing that Hawaiian Electric's target revenues should be rebased ahead of the second PBR multiyear rate period set to begin on January 1, 2027 and that a general rate case type proceeding is the most efficient means for doing so.

In August, we requested PUC approval to pursue an alternative non-rate case process to rebase rates. The innovative process would involve collaboration with the existing PBR working group parties to develop a rebasing proposal for the PUC's review and approval and it would avoid the time, cost and resource burden typically required for a formal rate case proceeding.

If successful, the process could result in rebased rates before the next multiyear rate period begins. We also made this proposal in recognition of the multiple resource-intensive processes that the PUC and other interested parties are and will be undertaking related to the newly enacted [ Act 25A. ] These include a wildfire recovery fund study due by the end of 2025.

Securitization financing and rule-making process to determine utility liability limits for catastrophic wildfire claims. In late September, the PUC granted our request directing us to collaborate with the PBR Working Group parties to develop a rebasing proposal by January 7, 2026.

If this process does not result in an approved rebasing proposal, Hawaiian Electric will file a 2027 test year rate case sometime in the second half of 2026. In that scenario, the PUC will determine whether the start of the next multiyear rate period will be pushed out beyond January 2027.

Turning to Slide 4. We continue to see progress toward implementation of the Maui Wildfire tort litigation settlement agreement. The process to obtain final court approval is advancing with the parties working through remaining administrative steps required for the settlement to take effect.

These include final approval of the class settlement agreement and a formal dismissal of the subrogation insurer claims. We expect the court to hold a hearing on January 8, 2026, to consider final approval of the class settlement agreement. And last week, we filed a summary judgment request to dismiss the subrogation insurer claims.

In sum, the settlement is on track and progressing as expected, and we still anticipate that our first payment will be due no sooner than early 2026. Turning to Slide 5. We continue strengthening our utility operational risk profile, which we believe has greatly improved since the 2023 Maui wildfires.

In the third quarter, we advanced implementation of the enhanced wildfire safety measures outlined in our wildfire safety strategy. We fully deployed all weather stations and AI-assisted high-definition video cameras outlined in our strategy ahead of schedule. For the first time, the utility now has its own in-house meteorologist.

Part of the utility's newly created watch office that will help us better predict and prepare for potential dangers from severe weather events. These are just a few examples of the many advancements we've made to help ensure the safety of our communities. We'll continue to make these kinds of critical investments as laid out in our wildfire safety strategy, which is currently under review by the PUC.

As we discussed last quarter, recently enacted legislation allows for securitization to finance these investments, ensuring these safety improvements can be implemented at a lower cost to customers. In summary, we continue making significant progress toward resolving the wildfire tort litigation, improving our operational risk profile and laying the foundation for a strong long-term outlook.

I'll now turn the call over to Scott DeGhetto.

Thank you, Scott. I'll start with our financial results for the quarter on Slide 6. In the third quarter, we generated net income of $30.7 million or $0.18 per share. Quarter's results include $4.5 million of pretax Maui wildfire-related expenses net of insurance recoveries and deferrals. Approximately $3.6 million of these expenses was recorded at the utility.

Excluding these items, which we refer to as non-core Consolidated core net income was $32.8 million for the quarter or $0.19 per share. This compares to core income from continuing operations of $32.7 million or $0.29 per share in the third quarter of 2024. Utility core net income for the quarter was $39.6 million compared to $43.7 million in the third quarter of 2024.

The decrease was driven by lower tax benefits from R&D tax credits, higher legal and consulting costs, which were deferred in 2024 and higher wildfire mitigation program expenses. Holding company core net loss was $6.8 million compared to $10.9 million in the third quarter of 2024. The lower core net loss was driven by lower interest expense due to the lower debt balance following the April debt retirement and higher interest income from holding company cash being held on the balance sheet primarily to make the first settlement payment.

Turning to the next slide, I'll provide a few key updates on our liquidity and settlement financing plans. As of the end of the third quarter, the holding company and the utility had approximately $40 million and $504 million of unrestricted cash on hand, respectively.

In addition, the holding company has approximately $519 million in combined liquidity available under its ATM program and credit facility capacity. The utility also has approximately $544 million of liquidity available under its accounts receivable facility and credit facility capacity.

In September, we completed a successful $500 million unsecured debt offering at Hawaiian Electric while also increasing our credit facility capacity at HEI and Hawaiian Electric by a combined $225 million. Proceeds from the Hawaiian Electric debt issuance will be used to finance CapEx and pay down debt.

Both September transactions not only enhance enterprise-wide liquidity but also show our readily available access to capital markets. Consistent with last quarter, the Hawaiian Electric Board of Directors approved a $10 million quarterly dividend HEI for the third quarter of 2025.

Turning to our funding expectations for the tort litigation settlement. $479 million continues to be held in a subsidiary created for addressing the first payment. This is included in restricted cash on the balance sheet until we make the first payment, still expected not sooner than early 2026.

We 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. Turning to the next slide. CapEx is projected to increase significantly in the coming years compared to historical levels. The higher CapEx will support key strategic objectives of reducing wildfire risk increasing reliability and resilience and repowering firm generation.

We expect to fund the higher spend primarily with retained earnings and proceeds from our recent debt issuance. As Scott Seu mentioned, we are working through the rate rebasing process with the PUC and PBR working group parties. We are also awaiting PUC approval of our utility wildfire safety strategy.

In October, we filed an application to increase the total cost for the [indiscernible] repowering project and the application remains subject to PUC approval. The results of these regulatory proceedings will impact our capital expenditure forecast. With those caveats, we are expecting 2025 CapEx to be approximately $400 million.

We expect 2026 CapEx of $550 million to $700 million. Of this total, CapEx recovered under the annual revenue adjustment mechanism or ARA, is expected to be $350 million to $400 million. EPRM-recovered CapEx is expected to add roughly $150 million to $200 million. Wildfire and resilience CapEx, which we are planning to finance via securitization is expected to be approximately $50 million to $100 million.

We expect 2027 and 2028 CapEx to increase further, driven by the [indiscernible] repowering, the wildfire safety strategy and the Army privatization project. Roughly $1.8 billion to $2.4 billion in total CapEx is expected over the next 3 years from 2026 to 2028. This level of spend is subject to additional PUC approvals and further resource adequacy initiatives and analysis.

With that, let's open up the call to questions.

[Operator Instructions] Your first question comes from the line of Julien Dumoulin-Smith with Jefferies.

It's James Ward on actually for Julien. How should we think about the revenue requirement and timing under the alternative rebate and filing the Gen 7 filing? What are the key elements that you're looking to align with the PBR Phase 6 modifications and so on? So just to that revenue requirement and timing.

Well, let me address the timing first and then I'll perhaps ask either Scott or one of our utility team to comment on some of our goals for the rebasing process. So as I mentioned, we are now -- we requested the PUC approval to enter into this alternative rebasing process. So the discussions with the PBR parties are underway.

The proposal for rebasing is due to the PUC on January 7 of 2026. And should that be successful, then we would go from there. If the proposal is not successful, then at that point later on in the year, we would consider filing for a 2027 test year rate case. So that's just a high level in terms of what the timing is.

And maybe I can defer to perhaps Joe Viola, who is our Senior Vice President at Hawaiian Electric Company, Head of overseeing Regulatory Affairs.

James, again, yes, Joe Viola here. In terms of what we're shooting for, for the rebasing process, really the way I think to think about that is we're setting a new starting point for the second multiyear rate plan. So we want to put ourselves in a position that we have new target revenues that would allow us with efficient performance to begin to earn our authorized ROE.

At the same time, we'll be developing potential changes to the next multi-area plane we call that MRP2 scheduled currently to begin in 2027. So working on setting a new starting point and then at the same time, have changes to the PBR framework that can make it successful during MRP2.

Got you. Both very much appreciated. Given that utility dividends have resumed, albeit in a small amount, but what's the sustainable cadence, utility, the holdco dividends through the settlement years? And what are the gating criteria?

So it's Scott DeGhetto. So what we have been doing, and I think you're aware of this, is the utility dividend to the holding company. At least over the past year or 2 has been set based on what the needs are at the holding company. I don't see that changing for the foreseeable future.

Got you. Okay. Just checking. That's very helpful. And the last one for me. I really appreciate the CapEx guidance, which obviously mentioned was a goal for you guys on the Q2 call so well done. As we look forward, how do you think about earnings guidance and ultimately, of course, EPS, which will have to include the financing element there.

Could we see EPS guidance in the Q4 call? Or is that not something we should put expectations on.

Too soon to say. Again, we really have been looking at reinstituting earnings guidance, but we really don't want to do that until we get through the final settlement approval process and put that behind us. And so there was a possibility that it could be at that particular point, but I wouldn't count on it. It just all depends on when the final settlement will be approved, and then we'll take a look at how the business is performing on a steady-state basis and get back to you.

Now keep in mind, going into the rate rebasing process, right? It's going to be hard for us to give guidance. We might be able to do it for a few quarters. But again, going into that process, we won't know the outcome of that process. And so what we don't want to do is give you guys guidance and then have to go back on that guidance or change it dramatically.

Your next question comes from the line of Nicholas Campanella with Barclays.

This is Michael Brown on for Nicolas Campanella. Can you provide an update on the sale of the remaining portion of the bank?

You're talking about the remaining or 9.9% ownership of American Savings?

Yes.

Yes. So we're always looking at what's going on in the market. And as we've said on previous calls, we do intend to monetize that stake. We haven't really given a time frame on it. I would say certainly -- I should wouldn't say certainly, but probably in the next 6 months or so, we'd probably look again pretty hard at that and see what it looks like. But we're not committing to a specific time line at this point.

Next question from me. What are the expectations of the commission's report on the wildfire fund going into the new legislative window?

Yes. So the Public Utilities Commission, they have been working on the study that is due to be submitted to the [indiscernible] legislature 20 days before the next legislative session starts. So that is on track. They have been working on information gathering, collecting stakeholder input. And there are -- as far as we know, they are on track to submit that report.

With the report, do you anticipate movement in 2026 in any key legislation?

It's -- I don't want to get ahead of the PUC. I'm not quite sure what will be in that report and whether they will recommend that legislation is needed next year. So too soon to say.

Okay. I appreciate that. That's the end of my question.

That concludes our question-and-answer session. I will now turn the call back over to Scott Seu for closing remarks.

I just want to thank all of our shareholders and a lot of our shareholders are our neighbors here in Hawaii. So again, thank you, Mahalo, for your continued investment in HEI. We're also very thankful to those of you who supported our successful debt issuance in September.

Again, we just really greatly appreciate your support as we continue to help our communities move forward to a sustainable future. So thank you, Mahalo, everybody.

Ladies and gentlemen, this concludes today's call. Thank you all for joining. You may now disconnect.