Hawaiian Electric Industries, Inc. 2026 Q2 Earnings Call

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.

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 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 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 megawatts 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 megawatts 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 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 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.

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.