Hawaiian Electric (HE) Q1 2026 Earnings Transcript

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DATE

Friday, May 8, 2026 at 4:30 p.m. ET

CALL PARTICIPANTS

• President and CEO — Scott W. Seu
• Senior Vice President and CFO — Paul Ito
• President and CEO, Hawaiian Electric — Shelee Kimura
• Senior Vice President, Regulatory Process — Joe Viola

TAKEAWAYS

• Maui Wildfire Settlement -- The company satisfied all final settlement conditions on April 10 and made the first of four annual $479 million payments under the agreement.
• Net Income -- Reported net income was $30.5 million ($0.18 per share), up from $26.7 million ($0.15 per share) in the year-ago quarter.
• Core Net Income (Excluding Maui Wildfire and Pacific Current Impacts) -- Consolidated core net income was $31 million ($0.18 per share), compared to $39.8 million ($0.23 per share) previously, reflecting the normalization of wildfire-related costs.
• Utility Core Net Income -- Utility core net income was $35.7 million, compared to $49.7 million last year, attributed to higher O&M expenses from severe weather and increased insurance costs.
• O&M Expenses -- Operations and maintenance costs rose sharply, with factors including record storms, increased insurance premiums, vegetation management, reliability-focused station maintenance, IT upgrades, and higher labor costs driving growth above inflation.
• Liquidity Position -- Nearly $1 billion in consolidated liquidity available through cash, credit facilities, and receivables-backed lines, with the holding company and utility having $535 million and $518 million in dedicated liquidity, respectively.
• Fuel Cost Pass-Through Mechanism -- While higher global fuel costs began impacting working capital after quarter-end, customer rates reflect these changes with a one- to two-month lag; all fuel costs are ultimately recoverable.
• Settlement Financing -- Future Maui wildfire settlement payments will use a mix of debt and/or equity, with the upcoming April 2028 payment currently expected to be funded by debt or convertible bonds, subject to market conditions.
• Utility Rate Rebasing Proposal -- Joint proposal filed March 6 seeks a 5.3% increase in consolidated base rates over two years, projecting an $8 to $12 monthly average bill rise in 2027 and an additional $2 to $3 in 2028 by island.
• Performance Incentive Mechanisms (PIMs) -- Proposal allows potential for 200 basis points total—150 for rewards, 50 for penalties—pending outcome of stakeholder negotiations and PUC approval.
• Waial Generating Station Project Approval -- PUC approved the $908 million repowering project, including an inflation adjustment; recovery for an incremental $247 million above this amount is deferred for future proceedings, expected around 2031.
• Capital Expenditure (CapEx) Forecast -- 2026 CapEx now includes $157 million for Waial, up from previous $90 million estimates, with total baseline utility CapEx projected at $350 million to $400 million per year and additional amounts pending regulatory recovery.
• Credit Ratings -- Moody’s upgraded the utility to Ba1 (from Ba2) and the holding company to Ba2 (from Ba3) following the settlement resolution; S&P and Fitch maintain positive outlooks.
• Fuel Cost Risk Sharing Mechanism (FCRS) -- The company expects to incur the maximum penalty this year, with revenue declines due to actual fuel costs exceeding benchmark levels set in the mechanism.
• Bad Debt Expense Reference -- CFO Ito stated, “our bad debt write-off percentage peaked at about 51 basis points” in prior global energy crises, versus a typical 10–20 basis point range.

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RISKS

• CFO Ito stated, these expenses are expected to drive an O&M increase that significantly outpaces inflation this year.
• Maximum penalty will be incurred under the fuel cost risk sharing mechanism, resulting in direct revenue reductions due to elevated fuel costs.
• Management cited intensified affordability pressures and higher customer bills linked to ongoing global oil price volatility and geopolitical tension.
• Carrying costs for $247 million in Waial CapEx not approved for immediate recovery will accumulate until potential cost recovery in 2031, creating risk of earnings lag.

SUMMARY

Management finalized the Maui wildfire settlement, triggering a $479 million payment and removing a key legal overhang. The company initiated its first post-settlement rate rebasing proposal, aiming to phase in base rate increases and recalibrate performance incentives. Regulatory approval for the $908 million Waial Generating Station marks a milestone, though full cost recovery will not be immediate due to deferred incremental expenses. Cash and liquidity resources remain ample, with plans to opportunistically fund future settlement payments based on market conditions. Disclosures indicate elevated O&M costs and maximum negative impact from risk-sharing mechanisms will compress margins in the transitional period.

• Management confirmed that recent CapEx increases primarily result from large, separately recovered projects like Waial, rather than shifts in baseline spending.
• CFO Ito described nearly $1 billion in total liquidity between cash, senior credit facilities, and asset-backed lines, providing confidence through current fuel payment and receivables timing mismatches.
• Rate rebasing design and the future timing of recovery for special projects remain subject to ongoing PUC proceedings and guidance, with customer affordability as the focal regulatory concern.

INDUSTRY GLOSSARY

• EPRM (Exceptional Project Recovery Mechanism): Regulatory mechanism allowing immediate cost recovery for approved utility capital projects outside the rate case cycle.
• PBR (Performance-Based Regulation): Regulatory framework incentivizing utility performance outcomes rather than traditional cost recovery.
• PIM (Performance Incentive Mechanism): Financial reward or penalty structure tied to achieving (or missing) regulatory performance targets within a PBR system.
• FCRS (Fuel Cost Risk Sharing Mechanism): Framework under which a utility shares fuel cost overruns or savings versus a benchmark with customers, impacting earnings and revenue directly.
• AFUDC (Allowance for Funds Used During Construction): Accounting method enabling utilities to capitalize financing costs incurred during project construction prior to those assets entering service.
• ATM Program: At-the-market equity offering program, allowing companies to raise capital by selling shares directly into the market at prevailing prices.
• AR ABL Facility: Accounts Receivable Asset-Based Lending facility; a revolving credit line secured by eligible receivables.

Full Conference Call Transcript

Scott W. Seu, Hawaiian Electric Industries, Inc. President and CEO; Paul Ito, Hawaiian Electric Industries, Inc. and Hawaiian Electric Senior Vice President and CFO; 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 and our SEC filings 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 W. Seu will begin with his remarks.

Scott W. Seu: Aloha kākou. Welcome, everyone. For today's call, I will start with an update on the Maui wildfire tort settlement, and discuss our progress on other key priorities. Paul Ito will walk through our financial results, and then we will open it up for questions. Since the Maui wildfires in 2023, we have 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 2024, and signed 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 four annual $479 million payments as stipulated under the agreement. I am 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 affected by the Maui wildfires, and our hearts are with them as they continue on their journey of healing and recovery. While we have advanced the wildfire settlement agreement, we have 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 in 2025, we will continue to submit updated WMPs every other year starting in 2027, with each update covering a two-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 have always been committed to supporting our communities during times of uncertainty, and we have 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 six 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 are 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 will note that our prudent balance sheet management ensures we are well prepared for the unexpected. Current global events highlight the importance of a diversified 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 are 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 two years to moderate customer impacts.

This equates to an increase in the average customer bill of $8 to $12 in 2027, and 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.

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 will 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 will continue working with our customers to provide options to address affordability pressures. Turning to an update on Waial.

In late March, the PUC issued a decision and order approving our proposed Waial 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 two 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 we will recover through the EPRM, the projected incremental amount we will seek recovery for after the project is in service totals $247 million.

In April, following the PUC's approval, we executed contracts for the purchase of six gas turbines for the Waial 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 have reached the pivotal milestones of finalizing the tort litigation settlement and launching our alternative rate rebasing process. We are no longer navigating a crisis. We are 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 Waial repowering project. We will continue to be laser focused on affordability and supporting our customers and communities, especially given fuel price impacts from the Iran conflict. I will now turn the call over to Paul Ito to discuss our financial results.

Paul Ito: Thank you, Scott. I will start with our financial results on Slide seven. 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 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. Turning to the next slide. As of the end of the first quarter, the holding company and the utility had approximately [inaudible] and [inaudible] 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 one to two 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 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, one notch below investment grade, and the holding company to Ba2 from Ba3. Turning to the next slide, we have updated our CapEx forecast to reflect the Waial approval and we are now expecting approximately $157 million of Waial CapEx in 2026 versus previous expectations of approximately $90 million.

As mentioned, we will request that about $247 million of Waial CapEx that is not being recovered separately through EPRM be recovered in the next rate case or rate rebasing proceeding. Lastly, as Scott W. Seu 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 has unfolded since late February, actual costs are now considerably above those levels. As a reminder, the FCRS runs through our revenues, 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 us open up the call to questions.

Operator: Thank you. If you would like to ask a question, please press star then 1. Your first question comes from Jamieson Ward with Jefferies. Please go ahead.

Jamieson Ward: Hi, guys. Thanks for taking the questions. So first one, the rebasing proposal you showed today shows $145 million in 2027 and then an incremental $25 million in 2028, 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 and, separately, is there any update on when the PUC might provide a procedural schedule?

Scott W. Seu: Yeah. Thanks, Jamieson. Let me ask Joe Viola—he is our senior vice president who oversees our regulatory process area—to respond to your question.

Joe Viola: Hi, Jamieson. To your first question, no, there has not been any change to the way we are going to phase in the proposed revenue increase. And second, we are 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 would expect that we need to get a certification from the commission that we complied with the order that allowed this proposal. We are confident we did, but we are just waiting on that order and further guidance on what the process will be to review.

Jamieson Ward: Got it. Appreciate that. So on the repowering and the $247 million gap that Paul spoke to and that is in the slides there, that you are going to seek in the next rate proceeding, which you estimated is around 2031. How should we think about the carrying cost of that—call it $250 million—between in-service and rate recovery and, I guess 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?

Paul Ito: Let me answer the first question. The question was how are carrying costs accounted for associated with the project. We would accrue AFUDC at our current approved weighted average cost of capital, which on Oahu, I believe, is about 7.37% on a combined basis. So we would accrue AFUDC at that rate.

Jamieson Ward: Perfect. Okay. Got it. And so is there any interaction with the current rebasing proposal, or is this something that would be allocated towards 2031?

Joe Viola: Hi, Jamieson. This is Joe Viola again. No. There is no interaction. That project was not part of our rebasing proposal because it is not in service yet. 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.

Jamieson Ward: Got it. Has the PUC opened or indicated any kind of timeline for opening a formal rulemaking docket on the wildfire liability cap under Act 258? I am not talking about new legislation; I guess that legislative session will work through that. The one that was already addressed in Act 258—the cap that was in until—

Scott W. Seu: Jamieson, this is Scott W. Seu 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 rulemaking process and, other than throwing out an 18- to 24-month expected time frame to complete that rulemaking process, they have not said anything further publicly.

Jamieson Ward: Okay. Fair enough. We had not seen anything either, but just wanted to check. Last one I will ask was just S&P and Fitch, as you guys mentioned, now have positive outlooks on both Hawaiian Electric Industries, Inc. and Hawaiian Electric. So with the settlement now resolving—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?

Paul Ito: In our discussions with the rating agencies—and, of course, what they tell us is not “here is exactly what you need to do to get upgraded”—but our discussions have included, and their reports show, that what they are focused on is the outcome of the rate rebasing, progress on reducing wildfire risk across our system, the liability cap, and the wildfire recovery fund. All of those are taken as inputs into their rating methodology. They are focused on it; we just do not know, and they do not 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 are turning their attention to the other things that I mentioned: the rate rebasing and the liability cap.

Jamieson Ward: Got it. Thank you for that. I will hop back in the queue and give anyone else an opportunity to ask.

Scott W. Seu: Alright. Thanks, Jamieson.

Operator: Your next question comes from the line of Michael Logan with Barclays. Please go ahead.

Michael Logan: Thanks for taking my question. I was just wondering if you could talk more about the drivers of the increase to your capital program. The separate recovery bucket was increased in your slide. I know some of that is associated with the repowering. I am just wondering if you could talk about other drivers and how much of it is EPRM recovery and therefore likely to earn higher ROE?

Paul Ito: Hey, thanks for the question. In our CapEx forecast, we are forecasting generally what we describe as our baseline CapEx—our more business-as-usual type of projects—roughly $350 million to $400 million a year. The increase in CapEx is, as you mentioned, largely due to separately recovered projects like Waial, and there are two examples. Those are the bigger drivers. We have two buckets in that category: approved and applications waiting to be approved. In the approved bucket, the change for this quarter was that Waial is now approved. As an example, for 2027 there is about $250 million of capital in that particular approved bucket.

But we still have capital that is not approved and pending approval, and that totals about $135 million in 2027. You can find the details in the appendix in our earnings deck. Hopefully, that gives you the color of the baseline CapEx and then the capital that we are putting to work where we get separate recovery or special recovery in between rate cases.

Michael Logan: Thank you. 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 would not issue it very far in advance of the second payment date.

Paul Ito: We have basically about a year to determine when and how to raise the next settlement payment. That gives us a lot of flexibility on timing. Our decision will really be based on market conditions, and we are 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 are going to monitor conditions and, when we feel like it is a good time to access the market, we will do so.

Michael Logan: Thank you. And then, also wondering if you could talk more about how you are feeling with the higher oil prices, fuel costs, and your liquidity position. It sounds like you feel like you are 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 will rely heavily on commercial paper as well? Just wondering how you expect to bridge the timing mismatch between fuel payments and customer recovery.

Paul Ito: 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—based on AR at the time, about $218 million. So we have significant liquidity available. We do, as mentioned, 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 days sales outstanding is roughly 20 to 25 days. So it is, again, a couple of months.

The question of how much of an impact to liquidity we will see really depends on how long this elevated fuel price situation stays in place. But, again, regardless of whether it is short term or long term, we feel very confident that we have sufficient liquidity to weather it.

Michael Logan: Thank you. 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 an amount per month?

Paul Ito: Maybe the way I will describe the potential impact—and this goes to the view of whether it is a long-term or short-term period of elevated fuel prices—I will use what we saw back when COVID occurred and then shortly thereafter the Ukraine–Russia war. In that situation, our bad debt write-off percentage peaked at about 51 basis points. Typically, we are in the 10 to 20 basis point range. So, obviously, a significant increase off our baseline, but generally speaking, a limited impact compared to what we have seen in other places. Part of that is, of course, we are not connected to other areas and, if you are living in Hawaii, you have to connect to the utility.

So, again, we are ready for that, but it comes down to whether it is a near- or long-term impact in terms of how much that write-off percentage would increase.

Michael Logan: Thank you. 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 is somewhat of a modest rebasing request, but just share your confidence about it getting approved right now and also what your expectations are for when you will get a decision on it.

Scott W. Seu: Yeah, thanks. I think it is fair to say that our Public Utilities Commission is very focused on impacts to customers of the high oil prices. And as they look at our rate rebasing request, we understand that context—it puts pressure on them, it puts pressure on us. At the same time, as you mentioned, we worked hard, including with Ulupono Initiative, to come up with a rate rebasing proposal that is pretty solid and really tries to moderate the impacts on our customers and spread out some of those impacts. We cannot predict exactly what the PUC will decide here, but hopefully they understand that we are also putting customer affordability at the forefront.

Michael Logan: Thank you. And then lastly for me, I was just wondering if you could talk about, in the rebasing proposal, the achievability of the PIMs. I know the prior framework seemed less conducive to achievement—the reward.

Joe Viola: Hi, this is Joe Viola again. That is actually an ongoing discussion with the stakeholders in that process and with the commission. We have all lived and learned, so I think we are in a good position to identify, design-wise, what works and what does not work. That is actually the section of the process we are in right now. We are proposing, or are 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—things like that.

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

Operator: We will now open the call for questions.

Operator: Your next question comes from the line of Jamieson Ward with Jefferies. Please go ahead.

Jamieson Ward: Hi, guys. Thanks. So just a quick follow-up on the Waial repowering. The AFUDC would only be through COD in, I believe, it is late 2029. Is that right? And then after that, you would have depreciation drag and so on. So, in summary, should we think about the incremental lag towards the end here, or just the incremental lag until it is factored in that 2031 filing? Thanks.

Paul Ito: You should think of Waial as essentially three projects in a larger project. There are six turbines—two turbines to be put into service in different years. The first pair is in 2029, the second pair is in 2031, and the third pair is in 2033. It is important to remember that we are approved for a baseline of recovery of $908 million across those six 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 that is what we will be asking for at that point in time.

To be clear, because turbines are going into service in different years, we would start getting recovery in those separate years once those turbines are put into service.

Jamieson Ward: Okay. Got it. Thank you. Thank you very much.

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

Scott W. Seu: Thank you all for calling in today. In closing, we have reached a pivotal milestone now that we have resolved the Maui wildfire tort 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. Again, thanks everybody for joining us, and thank you for your support as we go forward.

Operator: Ladies and gentlemen, this concludes today's conference call. Thank you for your participation, and you may now disconnect.

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