HAWAIIAN ELECTRIC CO INC

1 The rate schedules of the Utilities currently contain Energy Cost Recovery Clauses (ECRCs) through which changes in fuel oil prices and certain components of purchased energy costs are passed on to customers.

2 The rate schedules of the Utilities currently contain Purchased Power Adjustment Clauses (PPACs) through which changes in purchased power expenses (except purchased energy costs) are passed on to customers.

3 Starting in the fourth quarter of 2025, certain Wildfire Mitigation Plan costs were deferred and continued to be deferred in 2026.

4 kWh sales were slightly lower compared to the same quarter in prior year. The decrease in sales was attributed to cooler weather conditions.

The Utilities’ effective tax rates for the first six months of 2026 and 2025 were 24% and 21%, respectively. For the second quarters of 2026 and 2025, the Utilities’ effective tax rates were 25% and 21%, respectively. The higher effective tax rates for the first six months and second quarter of 2026, compared to the same periods in 2025, were primarily due to a discrete tax expense recognized in 2026 resulting from the remeasurement of the Utilities’ remaining wildfire tort-related settlement liability at present value.

Hawaiian Electric’s consolidated return on average common equity (ROACE) was 15.0% and 3.7% for the twelve months ended June 30, 2026 and 2025, respectively.

For more information of the Utilities’ incremental items related to the Maui windstorm and wildfires for thethree and six months ended June 30, 2026 and 2025, see“Results of operations—Maui windstorm and wildfires related items, net” in HEI’s MD&A.

See “Economic conditions” in the “HEI consolidated” section above.

Executive overview and strategy. The Utilities provide electricity on all the principal islands in the State of Hawaii, other than Kauai, to approximately 95% of the State’s population, and operate five separate grids. The Utilities’ mission is to empower their communities and customers with safe, reliable, resilient, affordable, and clean energy. The goal is to create a safe, modern, resilient, flexible, and dynamic electric grid that protects Hawaii from impacts of climate dynamics, position the Utilities to achieve the expectations of their customers and communities and earn their trust, and achieve Hawaii’s decarbonization goals that are aligned with the statutory goal of 100% renewable portfolio standard and net-negative carbon emissions by 2045.

Wildfire safety measures. In January 2025, the Utilities developed and filed with the PUC a 2025-2027 Wildfire Mitigation Plan (WMP), which identifies risk mitigation strategies to perform over the next three years across their service territories. The measures, including wildfire risk analysis, implementation of the Public Safety Power Shutoff (PSPS) program, grid design changes, and system hardening, have been integrated into the 2025-2026 WMP. The strategies and actions include additional operational changes, grid hardening work, enhanced inspections and vegetation management, and risk modeling to inform and prioritize hardening work and operational actions. On December 31, 2025, the PUC approved the Utilities’ 2025-2027 WMP. The PUC also directed the Utilities to provide a WMP update bi-annually. On April 13, 2026, the Utilities submitted their 2026-2027 WMP update to the PUC. On June 25, 2026, the PUC approved the Utilities’ request for Exceptional Project Recovery Mechanism (EPRM) cost recovery estimated at $350 million. See also “Utility projects” in Note 4 of the Condensed Consolidated Financial Statements.

The PSPS program calls for the Utilities to preventatively de-energize circuits in areas identified as high fire risk during certain weather conditions. The PSPS program launched on July 1, 2024 has been used when it is needed, to protect customers, communities and employees. Since the July 2024 implementation, the Utilities have continued to mature the PSPS program as it has gained experience executing the program along with public safety partners, communities, and residents. For example, the Utilities now have an in-house meteorologist and additional strategically placed weather stations to enhance their forecasting capability and situational awareness of localized hazardous conditions. The PSPS protocols will evolve over time as more analytical, forecast, and situational awareness capabilities and wildfire mitigations are deployed. De-energizing circuits in high wildfire risk areas will lead to extended interruptions for many customers, even if not in a high wildfire risk area. The Utilities will continue to work with key stakeholders in balancing the risk of utility-related wildfires with the risk to the public arising from not having electricity.

Transition to a decarbonized and sustainable energy future. The Utilities are fully committed to leading and enabling pathways to a decarbonized and sustainable energy future for Hawaii. A sustainable energy future is one that focuses on delivering electricity safely, reliably and affordably, strengthening resilience and shifting away from fossil-fueled resources. The Utilities believe that a holistic approach to evolving climate dynamics is needed, working on both climate mitigation efforts along with climate adaptation efforts. Climate mitigation requires achieving the Utilities’ decarbonization and renewable energy commitments, facilitating and promoting beneficial electrification, and deploying carbon removal and offsets among other levers to reduce statewide emissions.

Climate action plan. In the fourth quarter of 2021, the Utilities outlined their Climate Action Plan to cut carbon emissions from power generation 70% by 2030, compared to a 2005 baseline. The emissions covered by this goal include stack emissions from generation owned by Hawaiian Electric and IPPs who sell electricity to the Utilities. Since that time, delays and cancellations in the commercial operation of new renewable third-party generation resources and higher costs as a result of supply chain disruptions and inflationary pressures, as well as federal policies have slowed the pace of progress toward reducing greenhouse gas emissions. Also, see the “Developments in renewable energy efforts—New renewable PPAs” section below. The One Big Beautiful Act signed into law on July 4, 2025 may impact the ability of recently selected and new wind and solar projects to qualify for federal tax credits. Any loss in renewable energy tax credits could lead to project risk for new wind and solar projects in development and will likely result in higher prices for new renewable projects, which rely on such incentives to provide clean, affordable energy. Further, new tariffs imposed on equipment and materials used in the construction of renewable facilities will have an impact on pricing of new renewable projects. As a result of these challenges and the downgrade of Hawaiian Electric’s credit ratings after the Maui windstorm and wildfires, the Utilities expect the planned 70% reduction in carbon emissions to be achieved later than the original 2030 target date. However, the Utilities will continue to replace significant amounts of fossil fuel generation with renewable energy between now and 2030 RPS goals and expect to meet or exceed the State of Hawaii’s 2030 RPS goals. The Utilities estimate a reduction of carbon emissions of approximately 25% for 2025. This represented an increase in emissions compared to the 27% reduction in 2024 due to higher customer electric usage. As renewable energy replaces fossil fuel generation, carbon emissions are expected to continue to decline over time.

Hawaiian Electric has also committed to achieving net zero carbon emissions from power generation by 2045 or sooner. While the timing of the Utilities’ carbon reduction goals will be impacted by federal policies, key elements of the 2030 plan have already been completed or remain on track to be completed by 2030, including the closure of AES Hawaii, Inc., the State’s last coal-fired IPP plant, increasing rooftop solar capacity by more than 50% over 2021 levels, retiring six fossil fuel generating units, increasing grid-scale and customer-owned storage, expanding geothermal resources, and creating customer incentives for using clean, lower-cost energy at certain times of the day and using less fossil-fueled energy at night. The retirement of fossil-fueled generating units is consistent with state policy and supported by Hawaii state law.

State of Hawaii laws and policies. In January 2025, the State of Hawaii issued two key policy documents and an alternative fuel study. The PUC issued its 2024 Inclinations on the Future of Energy in Hawaii (2024 PUC Inclinations). The 2024 PUC Inclinations are intended to provide a guide for the completion of energy infrastructure upgrades for public safety, reliability and resiliency. This includes among other items, strategic hardening, diversification and enhancements of transmission and distribution systems, expedited replacement of older fossil fired generation, streamlined interconnection for renewable utility scale and distributed energy resources, including a specific goal to limit fossil fuel generation to no more than 40% on each island by 2030, software and hardware improvement to prevent cybersecurity threats, creation of resilience hubs, and integration of electric, gas, and renewable resources to support continuity of energy, telecommunications, water and wastewater services. The 2024 PUC Inclinations specifically state that “Strategic ownership of new generation (by the Utilities) may be beneficial, especially when such ownership stabilizes utility finances, benefits from low-interest federal loans or advances other objectives such as operational accountability, resilience and public safety.”

Governor Josh Green issued Executive Order No. 25-01, Accelerating Hawaii’s Transition Toward 100 Percent Renewable Energy (EO 25-01). EO 25-01 sets forth collective actions to accelerate the State’s decarbonization, stabilize and reduce energy costs, lower the State’s carbon footprint, strengthen energy security, and gain access to capital for the energy transition. Among other actions, EO 25-01 calls for 100% renewable electricity production in the counties of Hawaii and Maui by 2035 and achieving a 70% reduction of Oahu’s greenhouse gas emissions reductions from the electricity sector by 2035, using 2005 as a baseline, calls for the maximization of distributed solar energy paired with energy storage, including the installation of 50,000 new distributed energy resources by 2030, accelerating permitting tied to renewable energy, approving interconnection, and addressing energy burdens on low- and moderate-income residents.

The Hawaii State Energy Office’s Alternative Fuel, Repowering and Energy Transition Study (Alternative Fuel Study) expresses concern about the speed of the transition to renewable energy and cites to the continued reliance on imported oil as a driver of high bills and intense carbon emissions. The report makes a case for the use of liquefied natural gas on Oahu to replace low sulfur fuel oil during the transition to 100% renewable energy, and names several entities as potential investors that could help speed the transition. On October 6, 2025, the Office of the Governor of the State of Hawaii, JERA Co., Inc. (JERA Co.), Japan’s largest power producer, and its U.S. subsidiary, JERA Americas Inc. (JERA Americas), signed a non-binding Strategic Partnering Agreement that establishes a framework for long-term collaboration to support Hawaii’s decarbonization goals and energy transition. The Strategic Partnering Agreement supports the implementation of the Hawaii State Energy Office’s Alternative Fuel Study to pursue fuel diversification, including liquified natural gas, to reduce near-term reliance on oil. On March 17, 2026, JERA Co. provided a proposal to the State of Hawaii to modernize Oahu’s energy system to accelerate the replacement of oil-fired generation with new energy assets, including an approximately 500-MW hybrid combined-cycle and simple-cycle power facility supported by offshore liquefied natural gas import infrastructure. On July 17, 2026, JERA Americas filed a notice of intent with the PUC to file a Certificate of Public Convenience and Necessity (CPCN) for the development, ownership, and operation of a new, proposed regulated power generation company (GenCo) and associated utility-scale generation facilities on Oahu totaling 500 MW. JERA Americas intends to file the CPCN application in the first quarter of 2027. JERA Americas’ proposal is not intended to replace Hawaiian Electric’s role as the retail utility, system operator, and continued ownership and operation of existing generation resources, but is intended to provide regulated wholesale generation service within the existing integrated electric system. Hawaiian Electric believes that any significant new generation resource serving Oahu customers should be evaluated through a transparent, competitive procurement process designed to ensure that customers receive the best overall value and that all qualified market participants have an opportunity to compete. Hawaiian Electric believes that competition, together with oversight by the PUC and input from all stakeholders pursuant to the State's competitive bidding framework, provides an effective mechanism to evaluate project costs, reliability benefits, operational characteristics, commercial viability, and customer impacts. Accordingly, on July 17, 2026, Hawaiian Electric filed a request with the PUC to open a new proceeding and establish an expedited process for approval of a request for proposals (RFP) for approximately 500 MW of fuel-flexible firm generation capacity on Oahu. Hawaiian Electric proposed that the RFP be administered concurrently with its Integrated Grid Planning (IGP) procurement process and that proposals received through the respective procurements be evaluated through a single integrated portfolio assessment to identify the resources that provide the greatest overall benefit to customers. On August 5, 2026 the PUC issued a letter responding to the Utilities’ July 17 request, with the PUC noting that a demonstration of need for the additional 500 MW of fuel‑flexible firm generation would be required, and without demonstrating need, it is not reasonable and in the public interest to open a docket or otherwise expedite review and approval of Hawaiian Electric’s Firm RFP request at this time. The timing, scope, and outcome of the PUC's consideration of any future proceeding relating to JERA Americas’ proposed CPCN application, remain uncertain.

The Utilities are engaged in planning activities designed to support the State’s energy policy objectives, including the transition to a more affordable, reliable, and sustainable energy system. These planning efforts evaluate a range of resource, fuel, and technology options and are informed by state energy policy guidance and stakeholder input. Importantly, all three documents recognize that to achieve the State’s ambitious goals is a collective effort that will require government agencies, electric utilities, and private stakeholders to work together, acknowledging that each of these groups has an important role to play. The 2024 PUC Inclinations for example state: “Energy utilities, government agencies and private stakeholders must embrace an ethos of collective responsibility to confront and effectively mitigate the vulnerabilities revealed by Lahaina’s heartbreaking tragedy, the COVID pandemic, ongoing global unrest, cybersecurity threats and the overarching climate crisis.” The PUC later states: “The Commission does not expect energy utilities to accelerate their transformation without regulatory assistance and third-party resources.” All three documents also recognize the progress made to date towards the State’s renewable energy goals. The Utilities remain committed to working with all stakeholders to support the State’s energy policy objectives and reach Hawaii’s ambitious renewable energy goals.

Hawaii’s renewable portfolio standard law requires electric utilities to meet an RPS of 30%, 40%, 70% and 100% by December 31, 2020, 2030, 2040 and 2045, respectively. Hawaii law has also established a target of sequestering more atmospheric carbon and greenhouse gases than emitted within the State by 2045. The Utilities’ strategies and plans are fully aligned in meeting these targets (see also “Integrated Grid Planning” below).

The Utilities have made significant progress on the path to clean energy and have been successful in achieving RPS goals. To date, the Utilities have met all of the statutory RPS goals, including exceeding the latest milestone RPS target of 30% for 2020, where it achieved an RPS of 34.5%. The Utilities expect to continue to meet the RPS milestones under the amended RPS law. See “Developments in renewable energy efforts” below.

If the Utilities are not successful in meeting the RPS targets as mandated by law, the PUC could assess a penalty of $20 for every megawatt-hour (MWh) that an electric utility is deficient. Based on the level of total generation in 2025, a 1% shortfall in meeting the 2030 RPS requirement of 40% would translate into a penalty of approximately $2.1 million. The PUC has the discretion to reduce the penalty due to events or circumstances that are outside an electric utility’s reasonable control, to the extent the event or circumstance could not be reasonably foreseen and ameliorated. In addition to penalties under the RPS law, failure to meet the mandated RPS targets would be expected to result in a higher proportion of fossil fuel-based generation than if the RPS target had been achieved, which in turn would be expected to subject the Utilities to limited commodity fossil fuel price exposure under a fuel cost risk-sharing mechanism. The fuel cost risk-sharing mechanism apportions 2% of the fuel cost risk to the Utilities (and 98% to ratepayers) and has a maximum exposure (or benefit) of $3.7 million. Conversely, the Utilities have incentives under PIMs that provide a financial reward for accelerating the achievement of renewable generation as a percentage of total generation, including customer supplied generation. In 2025, the Utilities achieved a 36.8% RPS accruing a reward of $1.9 million based on $10/MWh in exceedance of 35.0% RPS. In 2026, the Utilities are eligible for a reward of $10/MWh in exceedance of 36.0% RPS.

The Utilities are fully aligned with, and supportive of, state policy to achieve a decarbonized future and have made significant progress in reducing emissions through renewable energy and electrification. This alignment with state policy is reflected in management compensation programs and the Utilities’ long-range plans, which include aspirational targets in order to catalyze action and accelerate the transition away from fossil fuels throughout their operations at a pace more rapid than dictated by current law. The long-range plans, including aspirational targets, serve as guiding principles in the Utilities’ continued transformation, and are updated regularly to adapt to changing technology, costs, and other factors. While there is no financial penalty for failure to achieve the Utilities’ long-range aspirational objectives, the Utilities recognize that there are environmental and social costs from the continued use of fossil fuels.

The State of Hawaii’s policy is supported by the regulatory framework and includes a number of mechanisms designed to maintain the Utilities’ financial stability during the transition toward the State’s decarbonized future. Under the sales decoupling mechanism, the Utilities are allowed to recover from customers, target test year revenues, independent of the level of kWh sales, which have generally trended lower over time as privately-owned distributed energy resources have been added to the grid and energy efficiency measures have been put into place. Other regulatory mechanisms under the PBR Framework reduce some of the regulatory lag during the multi-year rate plan, such as the annual revenue adjustment to provide annual changes in utility revenues, including inflationary adjustments, and the EPRM, which allows the Utilities to recover and earn on certain approved eligible projects placed into service. See “Regulatory proceedings” in Note 4 of the Condensed Consolidated Financial Statements.

Integrated grid planning. Achieving high levels of renewable energy and a carbon free electric system will require modernizing the grid through coordinated energy system planning in partnership with local communities and stakeholders. To accomplish this, the Utilities are implementing an innovative systems approach to energy planning intended to yield the most cost-effective renewable energy and decarbonization pathways that incorporates customer and stakeholder input.

The IGP process utilizes an inclusive and transparent stakeholder engagement model to provide an avenue for interested parties to engage with the Utilities and contribute meaningful input throughout the IGP process. The first cycle of the IGP was accepted by the PUC on March 7, 2024, and is the culmination of more than five years of partnership with stakeholders and community members across the islands. Together, they forecasted future energy needs and identified strategies to meet Hawaii’s growing energy demand with 100% renewable resources. The Integrated Grid Plan proposes actionable steps to decarbonize the electric grid on the State of Hawaii’s timeline, with a flexible framework that can adapt to future technologies. On January 2, 2026, the PUC opened the Second Cycle of the Integrated Grid Plan to continue to plan for future resources needed on the Utilities’ systems.

Demand response programs. Pursuant to PUC orders, the Utilities are developing an integrated Demand Response Portfolio Plan that will enhance system operations and reduce costs to customers. The reduction in cost for the customer will take the form of either rates or incentive-based programs that will compensate customers for their participation individually, or by way of engagements with turnkey service providers that contract with the Utilities to aggregate and deliver various grid services on behalf of participating customers and their distributed assets.

In 2022, the Utilities were approved to expand the Energy Demand Response Program (EDRP) on the islands of Maui and Oahu, which provides approximately 8 MW and 43 MW on Maui and Oahu, respectively. The PUC approved the cost recovery of the additional incentives for both Oahu and Maui through the Demand Side Management Surcharge.

During the time that EDRP was available, Bring Your Own Device Level 1 was launched on April 1, 2025, to succeed EDRP, which closed on July 1, 2024, on Oahu. The Bring Your Own Device Level 1 later evolved into Bring Your Own Device Plus, which began on May 15, 2025. Enrollment for the Bring Your Own Device Plus program will be available until total enrolled program capacity reaches 50 MW statewide, 3 MW of which is currently provided statewide.

Grid modernization. The overall goal of the Grid Modernization Strategy (GMS) is to deploy modern grid investments at an appropriate priority, sequence and pace to cost-effectively maximize flexibility, minimize the risk of redundancy and obsolescence, deliver customer benefits and enable greater resiliency, reliability, distributed energy resources and renewable energy integration.

The Utilities filed their initial application with the PUC on September 30, 2019 for an Advanced Distribution Management System as part of Phase 2 of their GMS implementation. However, as the Utilities were unsuccessful in securing Infrastructure Investment and Jobs Act federal funding in 2024, the Utilities are currently re-scoping GMS Phase 2 and plan to file another updated and supplemented PUC application for updated project costs in the third quarter of 2026.

Investigation on the establishment of wheeling. On July 1, 2024, the PUC issued an order to institute a proceeding to investigate the establishment of electricity wheeling policies and procedures for the electric utilities for the State of Hawaii. The PUC stated that it intended to address matters using lessons learned in the initial three docket phases to explore implementation of an intragovernmental wheeling policy and an evaluation of retail wheeling in subsequent phases, as appropriate.

On August 29, 2025, the PUC issued an order dividing the proceeding into two tracks, Track A, focused on retail wheeling, and Track B, focused on an intragovernmental credit share program that was the subject of the prior procedural schedule in the docket.

On October 22, 2025, the Utilities filed feedback on the PUC’s proposed Track B, Intragovernmental Shared Credit Program. The Utilities support the program but emphasize that careful program design is necessary to ensure technical feasibility, administrative efficiency, and fairness for all customers. The Utilities agree that the program could support the development of renewable energy zones by unlocking government lands for renewable projects and enabling proactive transmission planning.

On November 10, 2025, the Utilities filed their Track A Retail Wheeling Straw Proposal. The Utilities’ Straw Proposal provides an overview for the application process, a discussion of technical standards for grid interconnection and monitoring, provisions for metering and monitoring and a discussion of pricing mechanisms in the tariff structure and how to appropriately allocate wheeling costs. The Consumer Advocate and stakeholders provided comments on the Utilities’ Straw Proposal by January 20, 2026. The Utilities filed responses to the comments of the Consumer Advocate and stakeholders on March 6, 2026. On April 7, 2026, the PUC held a technical conference and stakeholder workshop where the Utilities provided a presentation on the Track A Retail Wheeling Straw Proposal and addressed the various comments and questions raised by the PUC, Consumer Advocate, and stakeholders in the proceeding.

On July 29, 2026, the PUC issued an order providing guidance on the proposed Track A retail wheeling program and addressing procedural matters. The order established an Oahu-only Retail Wheeling Pilot Program framework intended to satisfy Act 266 by January 1, 2027, and directed the Utilities to file an updated Track A proposal, draft tariff, and proposed pilot framework by August 19, 2026. The updated proposal must address, among other things, cost allocation, customer protections, technical standards, reporting requirements, and considerations for future program enhancements and expansion. The PUC directed the Utilities to include an Oahu-only pilot proposal, with a recommended two- to five-year duration, a plan for data collection and reporting on billing impacts, lost utility revenues and developer profits, opportunities for stakeholder feedback, annual performance monitoring, and recommendations for future expansion. In addition, the order provided staff guidance that the updated proposal should address refinements to the application and interconnection processes, a draft wheeling agreement and consumer protection disclosures, necessary revisions to Rule 14H and interconnection requirements, wheeling fee and administrative metering fee methodologies, curtailment clarification, and sample bill credit and wheeling fee calculations. The PUC further adopted a statement of issues for Track A focused on whether the updated proposal and draft tariff comply with Act 266, and whether the proposed application process, technical standards, pricing mechanism, proposed allocation of wheeling costs, and proposed pilot framework are reasonable and in the public interest. The order also adopted a supplemental Track A procedural schedule to govern the remainder of Track A unless otherwise ordered by the PUC.

Regulatory proceedings. On December 23, 2020, the PBR D&O was issued, establishing the PBR Framework. The PBR Framework implemented a five-year multi-year rate period (MRP), during which there will be no general rate case applications. On July 17,2026, the Utilities filed their application for approval of their re-basing proposal. See “Regulatory proceedings” in Note 4 of the Condensed Consolidated Financial Statements for a discussion of re-basing, PBR Framework and decoupling.

Regulated returns. As part of the PBR Framework’s annual review cycle, the Utilities track their rate-making ROACEs as calculated under the earnings sharing mechanism, which includes only items considered in establishing rates. At year-end, each utility’s rate-making ROACE is compared against its ROACE allowed by the PUC to determine whether earnings sharing has been triggered. The D&O in the PBR proceeding modified the earnings sharing mechanism to a symmetric arrangement. Effective with annual earnings for 2021, the earnings sharing will be triggered for achieved rate-making ROACE outside of a 300 basis points dead band above and below the current authorized rate-making ROACE of 9.5% for each of the Utilities (i.e., above 12.5% or below 6.5%). Earnings sharing credits or recoveries will be included in the biannual report (formally known as annual decoupling filing) to be filed with the PUC in the spring of the following year.

On August 31, 2023, the PUC issued an order temporarily suspending the Earnings Sharing Mechanism (ESM) until further notice. The intent of the order is to address the unintended consequence of customers potentially bearing the costs associated with the Maui windstorm and wildfires through the operation of the ESM without prior PUC review. In accordance with the order, the ESM remains suspended and there is no earnings sharing adjustment for 2026 as of June 30, 2026.

Actual and PUC-allowed returns, as of June 30, 2026, were as follows:

1 Based on recorded operating income and average rate base, both adjusted for items not included in determining electric rates.

2 Based on recorded net income divided by average common equity.

3 Based on recorded net income adjusted to remove items not included in determining electric rates, divided by rate making equity.

Rate-making calculations remove the impacts of the Settlement Agreements and eliminate the balances for the asset-based lending facility (ABL Facility) on a stand-alone company basis. The Utilities have stated that customers will not be impacted by payments related to the Settlement Agreements for the Maui windstorm and wildfires, which totals $1.9 billion (see Note 2 of the Condensed Consolidated Financial Statements). The ABL Facility contains certain intercompany costs related to the ABL Facility that are eliminated on a consolidated basis, and these transactions are eliminated on a stand-alone company basis for rate-making. Therefore, the rate-making returns were adjusted to exclude these impacts.

The gap between PUC-allowed ROACEs and the ROACEs achieved is generally due to the exclusion of certain expenses from rates (for example, incentive compensation and charitable contributions), and depreciation, other operation and maintenance (O&M) expense and return on rate base that are in excess of what is currently being recovered through rates (the last rate case plus authorized Rate Adjustment Mechanism revenue and ARA revenues). Maui Electric's returns are lower than authorized levels due to higher sustained maintenance and investments than what is recovered in current rates.

Developments in renewable energy efforts. The Utilities continue to procure renewable energy ambitiously. The Utilities’ renewable energy goals depend, in large part, on the success of renewable projects developed and operated by independent power producers. Significant project delays or failures of these projects increase the risk of the Utilities not meeting the renewable portfolio standards or other climate related goals, eligibility for Performance Incentive Mechanisms associated with the speed of increasing renewable generation, and the ability to retire fossil fuel units. Developments in the Utilities’ efforts to further their renewable energy strategy include renewable energy projects discussed in Note 4 of the Condensed Consolidated Financial Statements and the following:

New renewable PPAs.

•Under a request for proposal process governed by the PUC and monitored by independent observers, the Utilities issued Stage 2 Renewable Request for Proposals (RFPs) for Oahu, Maui and Hawaii Island and Grid Services RFP on August 22, 2019. Of the 11 PPAs filed by the Utilities, six PPAs were declared null and void by the independent power producers and one PPA was mutually terminated. The four remaining projects have received PUC approval. The Utilities filed three requests with the PUC for approval of amendments related to previously-approved PPAs for changes in pricing and/or guaranteed commercial operations dates to support completion of the projects while maintaining system reliability. The PUC approved all three amendments. To date, two Stage 2 projects have reached commercial operations. See also “Purchase commitments” in Note 4 of the Condensed Consolidated Financial Statements. Separately, the PUC approved the Utilities’ Waena Battery Energy Storage System project under Stage 2. See “Utility projects” in Note 4 of the Condensed Consolidated Financial Statements.

A summary of the remaining four approved Stage 2 PPAs and the self-build project is as follows:

1 Project delays have resulted in guaranteed commercial operations date being missed.

The total projected annual payment of $55.4 million for these PPAs will be recovered through the PPAC to the extent such costs are not included in base rates.

Tariffed renewable resources.

•As of June 30, 2026, there were approximately 746 MW, 159 MW, and 165 MW of installed distributed renewable solar energy technologies at Hawaiian Electric, Hawaii Electric Light and Maui Electric, respectively, for tariff-based private customer generation programs, namely Standard Interconnection Agreement, Net Energy Metering, Net Energy Metering Plus, Customer Grid Supply, Customer Self Supply, Customer Grid Supply Plus, Interim Smart Export, Smart Distributed Energy Resources — Export, Smart Distributed Energy Resources — Non-Export, and Community-Based Renewable Energy. As of June 30, 2026, an estimated 45% of single-family homes on the islands of Oahu, Hawaii and Maui have installed private rooftop solar systems, and approximately 25% of the Utilities’ total customers have solar systems.

•The Utilities’ feed-in tariff program is designed to encourage the addition of more renewable energy projects in Hawaii. As of June 30, 2026, there were 44 MW, 2 MW and 6 MW of installed feed-in tariff capacity from renewable energy technologies at Hawaiian Electric, Hawaii Electric Light and Maui Electric, respectively.

Biofuel sources.

•On August 23, 2024, the Utilities issued an RFP for biodiesel fuel supply commencing February 1, 2026. Proposals were due on September 30, 2024, and the Utilities have completed negotiations with two suppliers and submitted an application to the PUC on April 3, 2025. On June 2, 2025, the Utilities and Pacific Biodiesel Technologies, LLC (PBT) signed an agreement for supply of biodiesel commencing February 1, 2026, which was approved by the PUC on January 14, 2026. On May 18, 2026, the Utilities and Par Hawaii Refining, LLC (PAR Hawaii) signed an agreement for supply of renewable diesel, which will become effective upon PUC approval.

•Hawaiian Electric also has a spot buy contract with PBT to purchase additional quantities of biodiesel at or below the price of diesel. Some purchases of “at parity” biodiesel have been made under the spot purchase contract, which was extended through June 2027.

•Hawaiian Electric has a contingency supply contract with REG Marketing & Logistics Group, LLC to also supply biodiesel to any generating unit on Oahu in the event PBT is not able to supply necessary quantities. This contingency contract has been extended to November 2027 and will continue with no volume purchase requirements.

Requests for renewable proposals, expressions of interest, and information.

•The Hawaii Island Stage 3 RFP, seeking 65 MW of renewable firm capacity and 325 gigawatt-hours (GWh) of renewable dispatchable energy annually, was issued on November 21, 2022. Proposals were received on April 20, 2023. The Stage 3 RFPs for Oahu and Maui opened for bids on January 20, 2023. For Oahu, the Utilities sought 500 to 700 MW of renewable firm capacity, and at least 965 GWh of renewable dispatchable energy annually. For Maui, the Utilities sought at least 40 MW of renewable firm capacity, and at least 425 GWh of renewable dispatchable energy annually. Proposals for the firm generation portion of the Maui Stage 3 RFP were received on August 17, 2023, and Priority List selections were announced on October 9, 2023. On March 11, 2026, the Utilities filed an amended and restated contract for a firm generation project on Oahu, and the PUC unsuspended the docket on March 25, 2026. On May 21, 2026, a contract for renewable dispatchable energy on Maui was executed and subsequently filed with the PUC for approval on May 29, 2026. Also, on May 29, 2026, the Utilities filed an amended and restated contract for one solar-plus project on Hawaii Island. In May 2026, the PUC approved one solar-plus project on Oahu, and in June 2026, the PUC approved one solar-plus project on Oahu and one solar-plus project on Maui. Negotiations for the remaining projects are ongoing.

On March 28, 2025, the Utilities filed an application to the PUC for their self-build project - Waiau repower project. See “Utility projects” in Note 4 of the Condensed Consolidated Financial Statements.

A summary of the Stage 3 PPAs and self-build project is as follows:

•On August 19, 2024, the PUC opened a docket for the Utilities’ Integrated Grid Planning RFP (IGP RFP). On August 26, 2024, the Utilities filed their draft IGP RFP for Oahu and Hawaii Island. The Oahu portion of the IGP RFP seeks 750 GWh per year of energy and 350 MW of grid forming resources by November 1, 2030, and 81 MW of renewable firm capacity by December 2033. The Hawaii Island portion of the IGP RFP seeks 435 GWh per year of energy and 115 MW of grid forming resources by November 1, 2030, and 30 MW of renewable firm capacity by December 2032. On August 18, 2025, the Utilities filed a request with the PUC for approval to not offer utility-owned sites to other potential bidders. On September 9, 2025, the Consumer Advocate filed a response indicating it did not object to the Utilities’ request and a party to the docket filed a response requesting that the PUC consider the broader market impacts that limiting available sites would have on the available interconnection capacity and market competitiveness. On December 12, 2025, and on February 6, 2026, the Utilities filed their responses to additional PUC information requests. On June 17, 2026, the PUC approved the IGP RFP with minor modifications. The Utilities filed their final IGP RFP on July 17, 2026, and anticipate issuing the RFP in August 2026. On July 17, 2026, the Utilities also filed a letter requesting the PUC open a new proceeding for 500 MW of fuel-flexible firm generation on Oahu with an expedited timeline that would allow for issuance of the RFP by the end of 2026. The Utilities stated that a transparent, competitive RFP process supports customer affordability considerations and could accommodate technologies that may not fit within the framework of the ongoing IGP RFP process. On August 5, 2026 the PUC issued a letter responding to the Utilities’ July 17 request, with the PUC noting that a demonstration of need for the additional 500 MW of fuel‑flexible firm generation would be required, and without demonstrating need, it is not reasonable and in the public interest to open a docket or otherwise expedite review and approval of Hawaiian Electric’s Firm RFP request at this time.

Legislation and regulation. Congress and the Hawaii legislature periodically consider legislation that could have positive or negative effects on the Utilities and their customers. Also see “Environmental regulation” in Note 4 of the Condensed Consolidated Financial Statements.

Legislation. On June 6, 2025, Act 191 was signed into law, which allows the State to “step-in” for the Utilities in the case of utility financial distress, ensuring project owners receive payment, addressing concerns of some independent power producers’ ability to procure low-cost financing for new renewable energy and storage projects due to the Utilities’ credit ratings. The Utilities are working with the State to implement Act 191 and anticipate that a Master Agency Agreement and Step-In Agreements for certain power purchase agreements will be executed shortly. On July 1, 2025, Act 258 was signed into law, which directs the PUC to study the viability of a wildfire relief fund, establish an aggregate liability cap on economic damages from future wildfires and authorizes securitization to finance wildfire safety and resilience infrastructure improvements. On July 8, 2025, Act 301 was signed into law, which appropriates funds to address the State of Hawaii’s share in the settlement of claims related to the Maui wildfire and windstorm tort litigation settlement. Act 258 is expected to help support the Utilities’ financial stability to move forward, while Act 301 provides a resolution to those affected by the Maui windstorm and wildfires and provides assurance for a global settlement to move forward. Act 191 supports the Utilities’ ability to procure energy and gives IPP’s assurance to bid on projects in order to provide customers and communities with safe, reliable and affordable clean energy.

As noted above, on July 2, 2025, Act 266 was signed into law. Among other things, Act 266 authorizes wheeling of renewable energy and requires the PUC to establish policies and procedures to implement wheeling of renewable electricity for a capacity of not more than two megawatts, as well as microgrid service tariffs, by January 1, 2027. Act 266 also requires the PUC to establish an installation goal for new customer-sited distributed energy resources and establish tariffs to achieve the installation goal and for grid service programs, microgrids, and community-based renewable energy. The Utilities are currently assessing the potential impact related to wheeling as the PUC works to establish the provisions and terms for the implementation of wheeling in compliance with Act 266. For more information on wheeling, see discussion in “Investigation on the establishment of wheeling” above.

The One Big Beautiful Act signed into law on July 4, 2025 may impact the ability of the Utilities’ recently selected and new wind and solar projects to qualify for federal tax credits. Regulations continue to be developed, so the complete scope of potential impacts remains unknown at this time. Any loss in renewable energy tax credits could lead to project risk for new wind and solar projects in development and will likely result in higher prices for such projects, developers of which rely extensively on federal tax credits to finance such projects. It is also possible that the sunsetting of these tax credits will impact the supply chain for projects throughout the U.S. as developers rush to meet the four-year safe harbor timeline. The legislature is expected to consider legislation to provide a state tax credit to fill the void left by the expiration of the federal solar tax credit. However, due to budget shortfalls, the likelihood of its passage is limited.

Trade policies. In February 2026, the U.S. Supreme Court ruled against previously imposed across-the-board tariffs under the International Emergency Economic Powers Act. In response, the federal administration is reconstructing its trade policies. The impact on the Utilities from trade policies imposed by the U.S. or its trading partners remains uncertain at this time. The Utilities estimated that majority of the Utilities’ capital goods were purchased domestically at this time. However, the Utilities and their independent power producers procure capital goods that flow through global supply chains and may include raw materials, sub-components, or components sourced or assembled outside the U.S. Utility capital costs and the cost of power procured from independent power producers may increase due to new trade policies and changes in trade policy from the U.S. and its trading partners, based on the amount of foreign content of capital goods. It is also possible that trade policies could impact commodities and raw materials costs, leading to inflation of utility capital costs indirectly through the broader supply chain. Utility-scale battery projects planned by both Hawaiian Electric and independent power producers may see significant cost increases or supply chain challenges, as the majority of battery components are currently manufactured in, or have significant supply chain exposure to, the People’s Republic of China. The Utilities continue to assess the potential impact of evolving trade policies.

Federal grant. On August 7, 2024, the Utilities received a notification from the U.S. Department of Energy that their climate adaption transmission and distribution resilience program application for $95 million in federal funds was officially awarded. On July 16, 2026, the Utilities received a notification of an award modification from the DOE that updated certain terms and conditions including the removal of the scope related to community benefits plans and the associated funding for those deliverables. As a result, the federal share total was reduced from $95 million to $92.6 million. See “Utility projects” in Note 4 of the Condensed Consolidated Financial Statements for additional discussions. There is no assurance that the federal government will reimburse in a timely manner or may dispute reimbursement.

Fuel contracts. On June 30, 2021, the Utilities issued two RFPs for all fuels for supply commencing January 1, 2023. On February 1, 2022, the Utilities and PAR Hawaii entered into a fuel supply contract (Supply Agreement) commencing January 1, 2023, which was approved by the PUC on December 1, 2022. On August 14, 2024, the Utilities entered into a second amendment of the Supply Agreement. The second amendment extends the term of the Supply Agreement by additional three years and creates savings in fuel costs. The second amendment became effective on June 18, 2025, upon the issuance of the PUC’s final decision and order.

On March 3, 2022, as part of economic sanctions amid the Russia-Ukraine war, PAR Hawaii announced that it was suspending all purchases of Russian crude oil, which accounted for at least 25% of Hawaii’s supply. To help ensure adequate fuel supply, the Utilities entered into a backup fuel supply contract with Vitol Inc. (Vitol), effective December 1, 2022 through June 30, 2023, with annual extensions if mutually agreed by both parties. The fuel supply contract has been extended through June 30, 2027. On December 1, 2022, the PUC issued a final decision and order approving the Vitol backup fuels supply contract, and costs incurred under the contract are recovered through the Utilities’ respective ECRCs.

FINANCIAL CONDITION

Liquidity and capital resources. HEI’s and the Utilities’ future results of operations involve significant risks and uncertainties. Factors that could affect HEI’s and the Utilities’ future operating results and could cause actual results to vary materially from expectations include, but are not limited to, access to capital, ability to attract and retain key personnel, and pending or threatened litigation. On April 10, 2026, the final condition to payment under the Settlement Agreements was satisfied when the December 30, 2025 judgment obtained by HEI and Hawaiian Electric on the subrogation claims brought by insurers became final and unappealable. Accordingly, on April 10, 2026, HEI and Hawaiian Electric paid the first of four equal annual $479 million installments. See Note 2 of the Condensed Consolidated Financial Statements for additional information.

The price of crude oil has increased 51.9% over the same quarter in the prior year, which has moderately impacted the Utilities’ liquidity. The Utilities have a fuel pass-through mechanism with limited fuel cost-risk sharing. However, the Utilities expect cash flow impacts from the timing of the disbursements for fuel inventories and subsequent collection of accounts receivable, resulting in higher working capital requirements.

Hawaiian Electric’s objective continues to be to operate a strong, financially healthy enterprise to empower a thriving future for Hawaii. While the fundamentals of their business remain strong, the Utilities took prudent and measured actions to strengthen their financial position while continuing to provide reliable service to their customers and reinforcing their commitment to serving the community for the long term. On September 5, 2025, HEI and Hawaiian Electric each entered into a fourth amended and restated credit agreement with a syndicate of eight financial institutions, increasing each of their committed capacities to $300 million (see Note 5 of the Condensed Consolidated Financial Statements). Longer term, the Utilities entered into an asset-based credit facility that allows borrowing up to $250 million (see Note 5 of the Condensed Consolidated Financial Statements) and are also evaluating other sources of liquidity that could include securitization, re-prioritizing capital spending and reducing O&M, issuing unsecured debt, and conducting asset sales, among others.

The following table provides the components of Hawaiian Electric’s available liquidity under existing facilities.

As of June 30, 2026, Hawaii Electric Light and Maui Electric had short-term borrowings from Hawaiian Electric in the amount of nil and $28.5 million, respectively, and had long-term intercompany loans from Hawaiian Electric in the amount of $25 million and $90 million, respectively.

See Note 5 of the Condensed Consolidated Financial Statements for a brief description of Hawaiian Electric’s loans.

Management believes that HEI’s and the Utilities’ current cash and cash equivalents balances, as of June 30, 2026, amounting to $52.3 million and $186.3 million, respectively, the available capacity on Hawaiian Electric’s ABL Facility and revolving line of credit (see Note 5 of the Condensed Consolidated Financial Statements), and the additional liquidity from HEI’s at-the-market offering program, provide sufficient liquidity to fund operations and satisfy their other obligations for the short term.

As of June 30, 2026, the Utilities are in compliance with all applicable financial covenants and expect to continue to be in compliance with all the financial covenants in the next 12 months. The Utilities’ liquidity has improved, but continues to be impacted from the downgrades of their credit ratings, which result in higher credit spreads compared to investment grade credit spreads. However, the Utilities cannot predict the future effects on the Utilities’ ability to access additional capital or the future impacts on the Utilities’ financial position, results of operations, and cash flows.

The rebuilding of Lahaina will be a community-led effort and will occur over an extended period of time. The cost of rebuilding Maui Electric’s infrastructure is not yet known, but could be significant because the infrastructure that may be required is expected to be different than what previously existed. For example, to mitigate wildfire risk, grid hardening strategies, such as undergrounding of lines in high-risk locations will be significantly more expensive than using overhead lines and will thus result in increased costs.

Hawaiian Electric utilizes cash on hand to support normal operations and will draw on its revolving line of credit or ABL Facility, as needed, to supplement any operational needs. Hawaiian Electric may also borrow short-term from HEI for itself and on behalf of Hawaii Electric Light and Maui Electric, and Hawaiian Electric may borrow from or loan to Hawaii Electric Light and Maui Electric on a short-term basis. The intercompany borrowings among the Utilities, but not the borrowings from HEI, are eliminated in the consolidation of Hawaiian Electric’s financial statements. The Utilities also utilize long-term debt, borrowings of the proceeds of special purpose revenue bonds issued by the State of Hawaii Department of Budget and Finance, the issuance of privately placed unsecured senior notes bearing taxable interest, and high yield capital markets, to finance the Utilities’ capital improvement projects, or to repay short-term borrowings used to finance such projects. The downgrades of Hawaiian Electric’s credit ratings will continue to adversely impact the Utilities’ ability to access lower cost sources of capital.

Credit ratings. On April 21, 2026 and July 22, 2026, Moody’s and S&P, respectively, upgraded the credit ratings of Hawaiian Electric. As of July 31, 2026, the Fitch, Moody’s, and S&P ratings of Hawaiian Electric were as follows:

1 As of December 31, 2025. In March 2026, S&P revised Hawaiian Electric’s outlook to “Positive” from “CreditWatch Positive” and reaffirmed the “B+” issuer credit rating.

2 Rating withdrawn due to preferred stock redemption in the fourth quarter of 2025.

• Not rated.

NP - Not Prime

WR - Withdrawn rating

Note: The above ratings reflect only the view, at the time the ratings are issued or affirmed, of the applicable rating agency, from whom an explanation of the significance of such ratings may be obtained. Such ratings are not recommendations to buy, sell or hold any securities; such ratings may be subject to revision or withdrawal at any time by the rating agencies; and each rating should be evaluated independently of any other rating.

Asset-based lending facility credit agreement. On May 17, 2024, Hawaiian Electric, through a special-purpose subsidiary, entered into an ABL Facility credit agreement (ABL Credit Facility Agreement) with several banks, which, subject to the limitations and conditions set forth in such agreement, allows borrowings of up to $250 million on a revolving basis using certain accounts receivable as collateral. The ABL Facility was approved by the PUC, became effective on July 24, 2024 and will expire on July 24, 2027. As of June 30, 2026, total available capacity under the ABL Facility was $250 million and remains undrawn.

Taxable debt. On July 24, 2025, the Utilities received PUC approval to issue during the three-year period of 2025 through 2027, unsecured obligations bearing taxable interest (Hawaiian Electric up to $900 million, Hawaii Electric Light up to $115 million and Maui Electric up to $150 million), to finance capital expenditures, repay long-term and/or short-term debt used to finance or refinance capital expenditures, and/or to reimburse funds used for payment of capital expenditures. Pursuant to the approval, on September 18, 2025, Hawaiian Electric issued $500 million in unsecured senior notes with an interest rate of 6.00% (2025 Notes). A portion of the proceeds was used to repay the outstanding balance of the Utilities’ revolving and term loan facilities and the remaining proceeds are intended to be used to 1) finance capital expenditures, 2) repay long-term debt and short-term debt used to finance or refinance capital expenditures, and 3) reimburse funds used for the payment of capital expenditures. The 2025 Notes will mature on October 1, 2033.

On November 3, 2025, Hawaiian Electric made long-term intercompany loans to Hawaii Electric Light and Maui Electric in the amount of $25 million and $90 million, respectively. The interest rate and term of the loans are the same as Hawaiian Electric’s 2025 Notes. The long-term intercompany loans are eliminated in the total consolidated Hawaiian Electric amounts. See summary table below for remaining authorized amounts as of June 30, 2026 for each respective utility.

As of June 30, 2026, the Utilities have $2.06 billion of long-term debt, of which nil is due or expected to be repaid within 12 months.

Equity. On October 28, 2025, the Utilities received PUC approval to issue and sell each utility’s common stock over a three-year period from January 1, 2025 through December 31, 2027 (Hawaiian Electric sale/s to HEI of up to $210 million, Hawaii Electric Light sale/s to Hawaiian Electric of up to $70 million, and Maui Electric sale/s to Hawaiian Electric of up to $145 million) and the purchase of Hawaii Electric Light and Maui Electric common stock by Hawaiian Electric. As of June 30, 2026, Hawaiian Electric, Hawaii Electric Light, and Maui Electric have $210 million, $70 million, and $79 million, respectively, of remaining common stock authorization.

Cash flows. The following table reflects the changes in cash flows for the six months ended June 30, 2026 compared to the six months ended June 30, 2025:

Net cash provided by operating activities. The decrease in net cash provided by operating activities was primarily driven by higher cash paid for fuel oil stock, and higher customer bills due to higher fuel oil prices.

Net cash used in investing activities. The increase in net cash used in investing activities was primarily driven by an increase in capital expenditures related to construction activities.

Net cash used in financing activities. The increase in net cash used in financing activities was largely driven by higher dividend paid.

Material cash requirements. Material cash requirements of the Utilities include payments related to settlement of tort-related legal claims and cross claims to the extent HEI does not make such payments, O&M expenses, labor and benefits costs, fuel and purchase power costs, debt and interest payments, operating and finance lease obligations, their forecasted capital expenditures (including capital expenditures related to wildfires and wildfire mitigations) and investments, their expected retirement benefit plan contributions and other short-term and long-term material cash requirements. The cash requirements for O&M, fuel and purchase power costs, debt and interest payments, and operating and finance lease obligations are generally funded through the collection of the Utilities’ revenue requirement established in the last rate case and other mechanisms established under the regulatory framework. The cash requirements for capital expenditures are generally funded through operating cash flows, the issuance of debt, and contributions of equity from HEI and generally recovered through the Utilities’ revenue requirement or other capital recovery mechanisms over time.

Hawaiian Electric’s consolidated capital structure was as follows:

The Utilities’ credit rating downgrades related to the Maui windstorm and wildfires will continue to limit their ability to readily access low-cost sources of capital. Through the sale of common stock in September 2024, HEI has raised sufficient cash to pay the first installment of the settlement of wildfire tort claims and paid the first installment on April 10, 2026. HEI is currently working with its financial advisors on a financing plan to raise the additional capital required to fund the remaining settlement payments for the wildfire tort claims. While management believes that HEI will be able to raise the necessary capital, there is no assurance that management’s plans will be successful. The damages and losses related to the Maui windstorm and wildfires and related lawsuits (see further information in Note 2 of the Condensed Consolidated Financial Statements), the economic impact of higher fuel prices, inflation, higher interest rates, tightening of monetary policy, and geopolitical situations, create significant uncertainty, and the Utilities cannot predict the extent or duration of these conditions, the future effects that these conditions will have on the Utilities’ financing plan, cost of capital and their ability to access additional capital, or the future impacts on the Utilities’ financial position, results of operations, and cash flows.