Hawaiian Electric (HE) Q2 2026 Earnings Call Transcript

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DATE

Friday, Aug. 7, 2026 at 4:30 p.m. ET

CALL PARTICIPANTS

• Director of Investor Relations - Mateo Garcia
• President and Chief Executive Officer - Scott Seu
• President - Shelee Kimura
• Senior Vice President and Chief Financial Officer - Paul Ito
• Senior Vice President of Regulatory Affairs - Joe Viola

TAKEAWAYS

• Net Income -- $123.2 million, or $0.71 per share, representing an increase from $26.1 million in the second quarter of 2025.
• Core Net Income -- $22.5 million, or $0.13 per share, excluding Maui wildfire settlement-related impacts and losses related to Pacific Current asset sales.
• Electric Utility Revenue -- $936.9 million, compared to $742.5 million in the prior-year period, reflecting the impact of the annual revenue adjustment mechanism.
• Wildfire Settlement Remeasurement -- $153.9 million reduction in expenses, reflecting the accounting reclassification of the Maui wildfire tort liability as a contractual liability following the finalization of the settlement agreement.
• Wildfire Mitigation Plan Recovery -- $350 million approved for recovery by the PUC, consisting of $270 million in capital and $80 million in operations and maintenance spending.
• Proposed Rate Increase -- $170 million total base rate increase requested over two years, with $125 million of the increase proposed to take effect in January 2027.
• Consolidated Liquidity -- $1.3 billion as of June 30, 2026, including approximately $1.1 billion in combined capacity under credit facilities and the ATM program.
• Utility Cash and Liquidity -- $186 million of unrestricted cash on hand and $550 million available under accounts receivable and revolving credit facilities.
• Integrated Grid Plan RFP -- 1,650 gigawatt-hours of variable renewable energy, 465 MW of grid forming resources, and 111 MW of firm generating capacity sought in a new procurement launched Aug. 7.
• Grid Hardening Investments -- $190 million planned over the next five years for the PUC-approved Climate Adaptation Program to improve resilience against severe weather.
• Interconnection Expansion -- $1.3 billion in identified investments through 2035 to build or expand points of interconnection for renewable energy projects.
• Fuel Cost Risk Sharing -- $3.7 million pretax maximum penalty expected for the full year 2026, recorded as a reduction of fuel revenue.
• Performance Incentive Mechanisms -- A net loss is expected for the full year 2026, compared to $7.5 million in rewards earned in 2025.
• Wildfire Expense Deferral -- $28 million of pretax expenses deferred last year that the utility is no longer authorized to defer, impacting current operation and maintenance costs.
• Solar and Storage Approvals -- 166 MW of solar and 670 megawatt-hours of battery storage approved from the 2023 Stage 3 RFP across three contracts.
• Private Rooftop Solar Target -- 1.2 gigawatts of capacity prioritized for development by 2030 to grow the competitive marketplace for customer-sited generation.
• Credit Rating Upgrade -- BB-minus rating issued by S&P in July, reflecting progress in implementing the Wildfire Mitigation Plan and reducing risk exposure.
• Insurance Recoveries -- $8.5 million recognized this quarter as an adjustment to wildfire tort-related legal claims.
• Interest Expense -- $48.4 million for the quarter, driven by higher debt balances and non-cash accretion related to the wildfire settlement remeasurement.
• Bad Debt and Write-Offs -- Expenses decreased compared to the prior-year period, with net write-offs remaining relatively flat despite higher fuel prices.

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RISKS

• Ito stated, "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," noting the sustained impact of the 2025 high-yield debt.
• Ito warned that higher operation and maintenance expenses were driven by "higher vegetation management expenses, higher generation overhaul and maintenance costs, and higher overhead and underground inspection and maintenance costs."
• Management warned that the utility expects to accrue a loss from Performance Incentive Mechanisms and Shared Savings Mechanisms for the full year 2026, compared to millions in rewards achieved last year.

SUMMARY

Hawaiian Electric Industries, Inc. (NYSE:HE) is executing a multiyear strategic transition centered on wildfire risk mitigation and regulatory rate restructuring. The company is seeking commission approval to securitize $350 million in wildfire-related costs to maintain customer affordability while upgrading grid resilience. Management is advancing a major renewable energy procurement process to modernize generation capacity across the islands. These initiatives coincide with a formal rate rebasing request intended to align the utility's revenue with increased operational requirements and insurance costs starting in 2027.

• CEO Seu characterized the current fiscal year as "a transitional year as we prepare for our expected reset of rates in 2027."
• CFO Ito indicated that management intends to manage settlement financing by "targeting investment-grade credit metrics" to support long-term financial stability.
• The company submitted an Integrated Grid Plan update that identifies "what we can do within the next five years to stabilize rates and advance energy equity."
• Management reported that the new Integrated Grid Plan RFP represents "one of the largest competitive procurements for generation resources in state history."
• The PUC notified the company that a "demonstration of need" must be established before advancing an additional procurement for 500 MW of firm generation on Oahu.
• S&P revised its assessment of the company's business risk profile to "satisfactory" from "fair" following the credit rating upgrade in July.
• Ito noted the company is "reprioritizing work to mitigate expense headwinds" through efficiency measures, including insourcing more work previously performed by contractors.

INDUSTRY GLOSSARY

• EPRM: Exceptional Project Recovery Mechanism, a regulatory tool used to recover costs for specific, approved projects outside of base rates.
• FCRS: Fuel Cost Risk Sharing Mechanism, which allocates the risk of fuel price volatility between the utility and its customers.
• IGP: Integrated Grid Plan, a strategy to meet customer energy needs through a combination of generation, transmission, and distribution investments.
• MW: Megawatt, a unit of power equal to one million watts.
• PBR: Performance-Based Regulation, a framework where utility rates are adjusted based on performance metrics rather than just cost of service.
• PIM/SSM: Performance Incentive Mechanisms and Shared Savings Mechanisms, which provide financial rewards or penalties based on utility performance.
• RFP: Request for Proposals, a competitive bidding process used to solicit projects or services from third parties.
• WMP: Wildfire Mitigation Plan, a strategic framework for reducing the risk of wildfires in utility service territories.

Full Conference Call Transcript

Operator: Thank you for standing by, and welcome to the HEI second quarter 2026 earnings conference call. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question and answer session. If you would like to ask a question during that time, simply press star, then the number 1 on your telephone keypad. I would now like to turn the call over to Mateo Garcia, Director of Investor Relations. Sir, please go ahead.

Mateo Garcia: Thank you. 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. Scott Seu will begin with his remarks.

Scott Seu: 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'll recall, in December of last year, the PUC approved the utility's three-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. 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 five 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 MW of grid forming resources, and 111 MW 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 interests of customers.

In line with this, in our July 17 request, we also asked that the PUC allow us to issue a new RFP to consider all options for development of up to 500 MW of additional firm generation on Oʻahu, 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 analyses 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 two more PPAs for solar plus storage projects from our 2023 Stage 3 RFP. There are now three solar plus storage contracts approved from our Stage 3 RFP, totaling 166 MW of solar and 670 megawatt hours of battery storage, and multiple firm generation projects, including Waiau. Seven 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 skill renewable generation, including by targeting roughly 1.2 GW 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 to build or expand interconnection points between renewable projects.

Nearly $60 million of investments in distribution upgrades required over the next 10 years and $190 million over the next five 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.

Paul Ito: Thank you, Scott. I'll start with our financial results on slide six. 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 non-cash 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 three years.

The remeasurement totals $136.2 million pre-tax 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 non-core, 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. As you can see on slide seven, 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 one notch to double B-minus. In doing so, S&P recognized the progress made to reduce our wildfire risk exposure through implementation and commission support of our WMP. 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 one-notch upgrade for both the utility and holding company in April of this year. As Scott mentioned, we are very focused on affordability. 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 three 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 pre-tax wildfire-related expenses last year. We are no longer authorized to defer such costs.

These include wildfire insurance premiums, which were 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. 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. 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 Savings Mechanism rewards as we did last year. PIMs and SSMs last year totaled $7.5 million. 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. Following April's 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 non-cash and considered non-core. 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 Six, our commission will consider potential PBR framework changes for the next multi-year rate plan. The commission intends to resume Phase Six with a staff proposal informed by prior party input.

We'll be pursuing modifications in Phase Six that would address other drivers of structurally higher O&M expenses, including addressing the annual area 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 while 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: As a reminder, if you would like to ask a question, press star, then the number one on your telephone keypad. To withdraw your question, simply press star one again. We will pause for just a moment to compile the Q&A roster. Your first question comes from the line of Michael Lonegan with Barclays. Please go ahead.

Michael Lonegan: Hi. Thanks for taking my question. 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 detail on slide nine? I am just wondering how we should think about rate base items through 2028. Should we take out that full $350 from the capital plan? Can you help us just understand your rate base growth outlook through 2028?

Paul Ito: Yeah. Hey, Mike, this is Paul. Yes. 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. As we mentioned in our prepared remarks, we are planning to file the application this year. The commission will then have to rule on whether those costs would be eligible for securitization, which we expect they would be.

Michael Lonegan: Okay. Thank you. On the rate 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? When you are able to file your next rate case, is it 5 years after the rebased rates go into effect, after the next PBR term ends, or could you come in sooner for a case?

Scott Seu: Yeah. Hey, Mike, this is Scott Seu. I am going to ask Joe Viola, our Senior VP who oversees regulatory affairs, to respond.

Joe Viola: Hi, Michael. Yeah, I think the expectation would be, we're going to rebase rates right now for the next five-year multi-year rate plan. We would expect we'd be rebasing rates through some process in roughly the 2032 timeframe.

Michael Lonegan: Okay, thank you. 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-month 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?

Paul Ito: Yeah, Mike, the way I would look at it is, I would categorize O&M into three buckets. There are different drivers. For the first bucket, like storm activity, these are costs that are episodic, difficult to predict. 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. For example, vegetation management to reduce risk, in an effort to support safety and reliability and maintenance and overhead and underground maintenance. That's just part of our core responsibilities, and I'll address how we're planning to manage that cost. The third bucket would be what I would call more of a structural change.

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? The way that we're addressing all of these cost increases is, as we mentioned, the rate rebasing is a key one. The insurance increase was one of the things that was contemplated in the rate rebasing request. In addition to that, we're also making a lot of progress on reducing risk on our system through the operational changes. 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, 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? 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. That's another way that we're planning on addressing some of these higher costs. The third way to address this is just internal efficiency measures. For example, we're looking at key areas where it would make sense to insource 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 spent.

These efforts will take time to show up, but it's a critical initiative in managing our O&M going forward.

Scott Seu: Yeah, 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.

Michael Lonegan: Thank you. Lastly from me, I was just wondering your thoughts on JERA's proposal with the PUC to establish a regulated generation utility. Seems somewhat unprecedented. Just wonder if you could talk about engagement with stakeholders. From what I've seen, it seems like the governor is supportive of it.

Scott Seu: Certainly, Mike. It's been pretty public with the filings or the letter filings 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. 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, 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. We believe that framework should be followed. Albeit we can certainly would suggest that it can be looked at from efficiency and effectiveness. 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.

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. It's really less of a question of the endpoint. It's more a question of how do we best get there.

Michael Lonegan: Great. Thanks for taking my questions.

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

Scott Seu: 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.

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

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