HAWAIIAN ELECTRIC INDUSTRIES INC

1 The rate schedules of the electric 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 electric utilities currently contain PPACs through which changes in purchased power expenses (except purchased energy costs) are passed on to customers.

3 Pursuant to an agreement to settle indemnification claims with the State of Hawaii. See Note 2 of the Condensed Consolidated Financial Statements.

4 kWh sales were lower compared to the same quarter in prior year. The decrease in sales can be attributed to generally cooler weather in 2024 and ongoing impacts from the Maui windstorm and wildfires. In addition, the continued adoption of energy efficiency measures and distributed energy resources contributed to the reduction in kWh sales.

The Utilities’ effective tax rates for the second quarter and the first six months of 2024 were 26% tax benefit and for the second quarter and the first six months of 2023 were 22% tax expense. The effective rates for the current quarter and six months ended June 30, 2024 was higher than the comparable period due to the substantial pre-tax loss resulting from the accrual of the loss contingencies related to the wildfire tort-related claims because the impact of permanent items had a smaller impact on the effective rate.

Hawaiian Electric’s consolidated ROACE was not meaningful and 8.2% for the twelve months ended June 30, 2024 and June 30, 2023, respectively.

For more information of the Utilities’ incremental expenses related to the Maui windstorm and wildfires for the year ended June 30, 2024, see“Results of operations—Maui windstorm and wildfires related expenses” in HEI’s MD&A.

The net book value (cost less accumulated depreciation) of utility property, plant and equipment (PPE) as of June 30, 2024 amounted to $5.6 billion, of which approximately 20% related to generation PPE, 65% related to transmission and distribution PPE, and 15% related to other PPE. Approximately 6% of the total net book value relates to generation PPE that has been deactivated or that the Utilities plan to deactivate or decommission by 2046.

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, other than Kauai, to approximately 95% of the state’s population, and operate five separate grids. The Utilities’ mission is to provide innovative energy leadership for Hawaii, to meet the needs and expectations of customers and communities, and to empower them with affordable, reliable and clean energy. The goal is to create a safe, modern, resilient, flexible, and dynamic electric grid that protects Hawaii from impacts of climate change and enables an optimal mix of distributed energy resources, such as private rooftop solar, demand response, and grid-scale resources to enable the creation of smart, sustainable, resilient communities and achieve its decarbonization goals that are aligned with the statutory goal of 100% renewable energy by 2045.

Performance-based regulations. On December 23, 2020, the PUC issued a D&O (PBR D&O) approving a new performance-based regulation framework (PBR Framework). See “Regulatory proceedings” in Note 4 of the Condensed Consolidated Financial Statements.

Interim Wildfire Safety Measures. The Utilities first began developing a Wildfire Safety Strategy in 2019 and continue to adapt the plan to address the elevated risks in Hawaii. Since the Maui windstorm and wildfires, the Utilities have developed a set of Interim Wildfire Safety Measures to reduce the risk of wildfires associated with utility infrastructure in service territory areas identified as posing a higher wildfire risk. These interim measures represent actions the Utilities have either already started, or will start in 2024, while simultaneously working to develop a more comprehensive strategy. These actions include wildfire risk analysis, operation procedures and grid design changes, enhanced inspection and vegetation management plans, and system hardening.

One of the interim measures is the Public Safety Power Shutoff (PSPS) program, which 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 and is ready to use, if and when it is needed, and as the last line of defense to protect customers, communities and employees. The initial PSPS protocols and operational procedures represent an early-stage iteration, which 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 public consequences of 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 climate change 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.

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 related to solar panel imports have slowed the pace of progress toward reducing GHG emissions. Also, see the “Developments in renewable energy efforts—New renewable PPAs” section below. The downgrade of Hawaiian Electric’s credit ratings after the Maui windstorm and wildfires is anticipated to be an additional impediment to completion of new renewable energy and storage projects. As a result of these challenges, 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 and expect to meet or exceed the State of Hawaii’s RPS goals.

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 adjusted, key elements of the 2030 plan have already been completed or remain on track to be completed by 2030, including the closure of the state’s last coal-fired IPP plant that occurred in September 2022, increasing rooftop solar 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.

On September 1, 2022, the last coal-fired IPP plant in the state, providing approximately 10% of Oahu’s generation, ceased operations, removing a significant source of GHG emissions from the Utilities’ generation mix. In advance of the retirement of the coal-fired IPP plant, the Utilities developed plans, including contingency plans, to ensure reliable service through the transition period. These plans include the anticipated addition of renewable energy/storage projects, reserve capacity from existing generation sources, the acceleration of maintenance work during periods with anticipated higher reserve levels, and multiple demand response/DER programs. For example, in 2024, the first solar-plus storage project on Maui, a 60 megawatt (MW) Stage 1 project which is the largest solar-plus storage project in the State of Hawaii, reached commercial operations on May 31, 2024. Additionally, a 12.5 MW Stage 1 solar-plus storage project on Oahu reached commercial operations on March 28, 2024. The first Stage 2 solar-plus storage project, a 42 MW project on Oahu, reached commercial operations on June 7, 2024.

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%. In July 2022, former Governor Ige signed Act 240 (H.B.2089), that amended the RPS calculation from renewable energy as a percentage of sales to renewable energy as a percentage of total generation. The amended RPS calculation results in a lower calculated percentage than the amount calculated under the previous methodology. For example, the 2022 RPS achieved under the revised RPS calculation was 31.8% versus 39.1% under the prior method. The change in the definition is effective from July 2022 forward and will require that the Utilities acquire more renewable energy than under the previous RPS calculation to comply with the RPS milestones; however, 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 2023, 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 2023, the Utilities achieved a 33.3% RPS earning a reward of $444,116 based on $15/MWh in exceedance of 33.0% RPS. In 2024, the Utilities are eligible for a reward of $10/MWh in exceedance of 34.0% 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 its 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 DER 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 (MRP), such as the annual revenue adjustment to provide annual changes in utility revenues, including inflationary adjustments, and the exceptional project recovery mechanism, 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 Integrated Grid Planning (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 IGP Stakeholder Council, Technical Advisory Panel and Working groups have been established and meet regularly to provide feedback and input on specific issues and process steps in the IGP. On March 7, 2024, the PUC accepted the Utilities’ final Integrated Grid Plan. 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. The Integrated Grid Plan 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.

On June 28, 2024, the Utilities filed its annual update of the Action Plan described in its 2023 final Integrated Grid Plan.

Demand response programs. Pursuant to PUC orders, the Utilities are developing an integrated Demand Response (DR) 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.

On June 8, 2021, the PUC approved the new program, Emergency Demand Response Program (EDRP), a battery storage incentive program to dispatch electricity between 6 p.m. to 8 p.m. daily from participating residential and commercial customers, to address the potential reserve shortfalls following the AES coal plant retirement. The Battery Bonus on Oahu is officially closed to new applications. As of June 30, 2024, the Utilities have received and approved applications totaling 46.79 MW on Oahu.

On March 30, 2022, the Utilities filed with the PUC to request expanding the EDRP for up to 15 MW on the island of Maui and received PUC approval on May 20, 2022. The EDRP on Maui became effective as of June 1, 2022. Subsequently on June 23, 2022, the PUC approved the cost recovery of the additional incentives for both Oahu and Maui through the Demand Side Management Surcharge. As of June 30, 2024, the Battery Bonus program on Maui has officially closed to new applications, and the Utilities have received and approved the applications totaling approximately 9.9 MW on Maui.

On October 31, 2022, the PUC issued an order, directing the Utilities to solicit comments from all interested parties and stakeholders on the Utilities’ Draft Grid Services RFP filed on June 30, 2022. The proposed Draft Grid Services RFP focused only on Maui and is seeking 15 MW of grid services. Hawaiian Electric issued the RFP on February 1, 2023 and bids were due on February 1, 2024. On February 23, 2024, Hawaiian Electric filed a letter to the PUC recommending to close the RFP as no bids were received. On April 3, 2024, the PUC terminated the RFP as recommended by the Utilities.

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 DER and renewable energy integration. On March 25, 2019, the PUC approved a plan for the Utilities to implement GMS Phase 1, which is the proportional deployment of advanced metering infrastructure (AMI). On February 28, 2022, the PUC expanded the scope of Phase 1 to the full service territory with a completion date set for the third quarter of 2024. The estimated cost of full deployment (including proportional deployment) is approximately $143 million in capital and deferred software cost and is expected to be incurred over five years. As of June 30, 2024, approximately $125 million of capital and deferred software cost has been incurred to date under Phase 1 and is currently being recovered under the MPIR mechanism until such costs are included in base rates. As of June 30, 2024, the Utilities have deployed about 440,000 advanced meters, servicing approximately 93% of total customers.

The Utilities filed an application with the PUC on September 30, 2019 for an Advanced Distribution Management System (ADMS) as part of Phase 2 of their GMS implementation. On March 31, 2021, the Utilities filed a supplement and update to the GMS Phase 2 ADMS application to include broad deployment of field devices, which the PUC suspended on November 16, 2021, to focus the Utilities’ attention on completing Phase 1. On April 17, 2023, the Utilities filed a motion with the PUC, requesting the suspended docket to be reopened and to allow the Utilities to file an updated and supplemented application for updated project costs and expansion of the Phase 2 scope to also include Operational Technology Cybersecurity Monitoring. On May 31, 2024, the Utilities filed another updated and supplemented application for updated project costs, as well as the addition of Private Long-Term Evolution expansion and Supervisory Control and Data Acquisition expansion to the prior GMS Phase 2 scope (ADMS, Field Devices, and Operational Technology Cybersecurity Monitoring). The estimated cost for the implementation of GMS Phase 2 over seven years, which includes capital, deferred software costs and O&M costs, is $215 million. The Utilities have requested PUC approval by the end of 2024.

Community-based renewable energy. In December 2017, the PUC adopted a community-based renewable energy (CBRE) program framework which allows customers who cannot, or chose not to, take advantage of private rooftop solar to receive the benefits of renewable energy to help offset their monthly electric bills and support clean energy for Hawaii. The program has two phases.

The first phase, which commenced in July 2018, totaling 8 MW of solar photovoltaic (PV) only with one credit rate for each island, closed on April 9, 2020. Two phase 1 projects (28.32 kW on Maui and 270 kW on Oahu) have been operational for three years and one Phase 1 project (3,000 kW on Oahu) achieved commercial operations on October 1, 2023. Two additional phase 1 projects achieved commercial operations on April 1, 2024 (Hawaii Island: 750kW and Molokai: 250kW).

The second phase, which commenced on April 9, 2020 and subsequently expanded on July 27, 2021, allows over 250 MW across all Hawaiian Electric service territories in two tranches for small (under 250 kW), mid-tier and large system sizes to encourage a variety of system sizes. To provide opportunities for low-to-moderate income (LMI) customers to participate in the program, 23 MW of capacity for dedicated-LMI projects were awarded on November 15, 2022 through three island specific RFPs for Oahu, Maui and Hawaii Island. LMI projects do not have a size cap nor do they decrease the 250 MW capacity available to other projects. One project has since been withdrawn by the selected CBRE developer and the remaining 20 MW of dedicated-LMI projects are expected to become operational in 2026.

The Utilities issued the CBRE Tranche 1 RFPs for Oahu, Maui and Hawaii on April 14, 2022. The RFPs closed on August 17, 2022, and proposals were evaluated. Tranche 1 projects, which are greater than or equal to 250 kW, were awarded on February 22, 2023. Two projects on Hawaii Island were subsequently withdrawn by the developer on October 18, 2023. Two additional Hawaii Island projects were disqualified on May 13, 2024. On June 14, 2024, a project on Oahu was withdrawn by the developer. There are no remaining Tranche 1 projects in development.

For Lanai, the Utilities combined the previously issued Variable Renewable Dispatchable Generation Paired with Energy Storage RFP and the CBRE RFP to optimize the benefits of procuring renewable energy, spur development and increase the likelihood of success of the CBRE Program on Lanai. See “Developments in renewable energy efforts–Requests for renewable proposals, expressions of interest, and information” for additional information.

One CBRE proposal for Lanai was selected but negotiations were terminated on June 15, 2022. With the concurrence of the independent observer, a replacement proposal was selected on July 1, 2022. On July 25, 2022, the Utilities announced the selection of a new developer for the Lanai CBRE RFP. On September 21, 2022, the Utilities were informed by Pulama Lanai of a project being planned on Lanai to remove the two large resorts from the grid, which represent approximately 40% of the load of the island and raises great uncertainty around the future energy needs for Lanai. On September 28, 2022, the Utilities notified the PUC that ongoing negotiations for the Lanai CBRE project would continue, but the Utilities did not execute a PPA at this time given the uncertainty due to the Pulama Lanai notification. The parties are currently exploring options to move forward with the project. On Molokai, proposals were only received from a single community co-op group. After evaluation of these proposals and with concurrence of the independent observer, the Utilities filed a letter on September 9, 2022, proposing to close the Molokai CBRE RFP and to work with the lone bidder to improve certain aspects of its two proposed projects outside of the RFP process for the benefit of the residents of Molokai. After successful negotiations, two contracts for solar plus storage facilities were executed and on September 29, 2023, the Utilities filed two applications with the PUC requesting approval of the contracts. On January 8, 2024, the PUC approved the two contracts.

The Utilities CBRE Phase 2 Rule 29 became effective on March 10, 2022. The Utilities are currently accepting project applications for small CBRE projects less than 250 kW in size. The PUC reserved 45 MW as well as a small amount of unallocated capacity from Phase 1 for small projects in Phase 2 on Oahu, Maui and Hawaii Island. The Utilities have developed a CBRE Portal where Subscriber Organizations can apply for small project capacity and manage subscribers for all CBRE projects in the program. Customers can also use the CBRE Portal to solicit subscription quotes, compare, and subscribe to a project once the Subscriber Organization has added their project to the portal.

Microgrid services tariff proceeding. In enacting Act 200 of 2018, the Hawaii legislature found that Hawaii’s residents and businesses were vulnerable to disruptions in the islands’ energy systems caused by extreme weather events or other disasters, and stated its belief that the use of microgrids would build energy resiliency into Hawaii’s communities, thereby increasing public safety and security. The purpose of Act 200 was therefore to encourage and facilitate the development and use of microgrids through the establishment of a standard microgrid services tariff. In July 2018, pursuant to Act 200, the PUC opened a proceeding to investigate the establishment of a microgrid services tariff. In August 2019, the PUC issued an order prioritizing items for resolution in the docket and directed the Parties to establish working groups (the Working Group) to address issues identified by the PUC.

On May 27, 2021, the Utilities filed the Microgrid Service Tariff. On September 21, 2021, the PUC provided guidance for Phase 2 of the Microgrid Tariff proceeding, specifically identifying the objective for Phase 2 to promote self-sufficiency and resilience among microgrid project operators, as well as to further streamline the Microgrid Services Tariff where applicable. Furthermore, the PUC instructed Parties to recommend priority topics, along with supporting rationale to better inform the topics that will be discussed during this phase of the proceeding, which the parties submitted by October 21, 2021.

On April 1, 2022, the PUC established its Prioritized Issues for Resolution for Phase 2 of the Microgrid proceeding, which includes the following: 1) Microgrid Compensation and Grid Services; 2) Utility Compensation; 3) Customer Protection and Related Considerations; 4) Interconnection; and 5) Working Group coordination with related microgrid and resilience Initiatives at Hawaiian Electric and government agencies. Furthermore, the PUC established a procedural schedule to consist of quarterly status conference meetings with the PUC, a Phase 2 Working Group Report, draft of a revised Microgrid Service Tariff, Party comments to the proposed Microgrid Service Tariff, followed by a PUC D&O.

On June 30, 2022, the PUC provided further guidance to the Working Group to prioritize discussion of the microgrid types in the following order: 1) Hybrid Microgrid - Third Party Developer using Utility lines/infrastructure; 2) Hybrid Microgrid - Utility Project with Partners; and 3) Customer Microgrid. Additionally, the PUC instructed the Working Group to discuss microgrid compensation and continue the involvement of microgrid developers in working group meetings.

The Working Group met from April 2022 through October 2022 to discuss the PUC’s objectives and respond to the Phase 2 priority issues. On October 31, 2022, the PUC issued a guidance letter and advised that the Working Group propose a new timeline for the Report. The Utilities and the Consumer Advocate filed a joint letter with a revised timeline on November 10, 2022. On November 21, 2022, the PUC issued an order to suspend the Phase 2 procedural schedule while it reviews the joint letter.

Decoupling. See “Decoupling” in Note 4 of the Condensed Consolidated Financial Statements for a discussion of 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. 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. Results for 2022 and 2021 did not trigger the earnings sharing mechanism for the Utilities.

On August 31, 2023, the PUC issued an order temporarily suspending the 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 earnings sharing adjustment for 2023 is zero until the PUC lifts the suspension.

Actual and PUC-allowed returns, as of June 30, 2024, were as follows:

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

** Recorded net income divided by average common equity.

*** ROACE adjusted to remove items not included by the PUC in establishing rates, such as incentive compensation.

NM - Not meaningful.

The Utility’s actual and allowed rates of return are not meaningful due to the accrual of estimated wildfire liabilities of approximately $1.71 billion (see Note 2 of the Condensed Consolidated Financial Statements).

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, 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 RAM adjustments and ARA revenues).

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. In the fourth year of the MRP, the PUC will comprehensively review the PBR Framework to determine if any modifications or revisions are appropriate. See also “Regulatory proceedings” in Note 4 of the Condensed Consolidated Financial Statements.

Developments in renewable energy efforts. The Utilities’ renewable energy goals depend, in large part, on the success of renewable projects developed and operated by independent power producers. Beginning in 2017, the Utilities embarked on an ambitious procurement effort, selecting multiple solar plus storage projects to help reach the Utilities’ renewable portfolio standards goals as well as to assist the Utilities in retiring fossil fuel generation. Several of the recently procured projects have experienced delays as a result of supply chain disruptions caused by impacts from the COVID-19 pandemic, solar product detentions at U.S. ports of entry ordered by the U.S. Customs and Border Protection agency, and unforeseen site conditions which resulted in unanticipated project costs or in some cases the inability to effectively use previously identified project sites. These impacts have resulted in five Stage 2 projects declared null and void by the independent power producers and one Stage 1 project and one Stage 2 project mutually terminating their PPAs with the Utilities. Projects have also indicated potential impacts from the investigation launched by the U.S. Department of Commerce on March 28, 2022, in response to a request by Auxin Solar Inc. in regard to solar panel imports. On June 6, 2022, President Biden created a bridge to temporarily facilitate U.S. solar deployers’ ability to source certain imported solar modules and cells free of certain duties for 24 months in order to ensure the U.S. has access to a sufficient supply of solar modules to meet electricity generation needs. The Utilities have negotiated amendments with several project developers regarding requests to increase previously approved prices and extend guaranteed commercial operations dates for those projects in order to ensure their viability given the impact of these recent market conditions. All of these amendments have been approved. 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.

•On December 31, 2019, Hawaii Electric Light and Puna Geothermal Ventures entered into an Amended and Restated Power Purchase Agreement (PGV ARPPA). The PGV ARPPA extends the term of the existing PPA by 25 years to 2052, expands the firm capacity of the facility to 46 MW and delinks the pricing for energy delivered from the facility from fossil fuel prices to reduce cost to customers. On March 16, 2022, the PUC issued a D&O, approving the PGV ARPPA, subject to conditions, that include requiring completion of a final environmental review prior to construction. On March 28, 2022, Puna Pono Alliance filed a Motion for Reconsideration seeking reconsideration, modification and/or vacation of the D&O. On June 6, the PUC denied Puna Pono’s Motion for Reconsideration. PGV notified the Utilities that changes in market conditions that transpired since the terms of the PGV ARPPA were negotiated impacted the financial viability of the Project, and that an amendment to the PGV ARPPA was necessary to mitigate the impacts. On March 27, 2023, the Utilities and PGV executed the First Amendment to the PGV ARPPA which increases the capacity payment and extends the GCOD. An application requesting approval of the First Amendment to the PGV ARPPA was filed on April 4, 2023. On June 13, 2023, PGV notified the Utilities of concerns of its ability to timely deliver on the terms of the ARPPA. PGV has been working to re-establish its capacity generation and has continued drilling and plans to drill additional wells, however, this process has taken longer than anticipated and PGV has become increasingly concerned about timely achieving the Contract Firm Capacity of 46 MW. In light of receiving this information and to allow the Utilities and PGV to determine the best path forward, on July 6, 2023 the Utilities asked the PUC to put the procedural schedule on hold for approval of the First Amendment to the PGV ARPPA. In order to address PGV’s concerns, the parties executed a Second Amendment to the PGV ARPPA, which among other things lowered the capacity needed to reach commercial operations and preserves the full contract capacity, effectuating a partial commissioning. On October 2, 2023 the Utilities filed a letter requesting the docket be reopened and seeking approval of the First and Second Amendments to the PGV ARPPA by the end of 2023. On December 29, 2023, the PUC issued a D&O conditionally approving the First and Second Amendments to the PGV ARPPA. As directed, on January 12, 2024, the Utilities filed a supplemental brief explaining its request for cost recovery. A response from the PUC is still pending.

•Under a request for proposal process governed by the PUC and monitored by independent observers, in February 2018, the Utilities issued Stage 1 Renewable RFPs for 220 MW of renewable generation on Oahu, 50 MW of renewable generation on Hawaii Island, and 60 MW of renewable generation on Maui. To date, the Utilities filed seven 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 has approved all seven amendments. AES West Oahu Solar project on Oahu and AES Kuihelani Solar project on Maui reached commercial operations on March 28, 2024 and May 31, 2024, respectively. See also “Purchase commitments” in Note 4 of the Condensed Consolidated Financial Statements. To date, five projects reached commercial operations.

A summary of the remaining seven PPAs is as follows:

The Utilities have received PUC approvals to recover the total projected annual payment of $66.4 million for the seven PPAs through the PPAC to the extent such costs are not included in base rates.

•In continuation of their February 2018 request for proposal process, the Utilities issued their Stage 2 Renewable RFPs for Oahu, Maui and Hawaii Island and Grid Services RFP on August 22, 2019. To date, the Utilities had filed 11 PPAs. Additionally, two GSPAs and two applications for commitments of funds for capital expenditures for approval of the utility self-build projects were filed with the PUC. Of the 11 filed PPAs, 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. To date, 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 has approved all three amendments. The Kupono Solar project on Oahu reached commercial operations on June 7, 2024. See also “Purchase commitments” in Note 4 of the Condensed Consolidated Financial Statements. The two GSPAs were approved by the PUC in December 2020. As of June 30, 2024, while the GSPA contracts have not yet achieved its contractual target, the aggregators continue to enroll customers every month. To date, two projects reached commercial operations.

A summary of the remaining four approved Stage 2 PPAs, is as follows:

• 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.

A summary of the GSPAs that were approved by PUC in December 2020 is as follows:

A summary of the utility self-build projects is as follows:

• The utility Self-Build project was denied by the PUC on May 25, 2022 and the Utilities filed a motion for reconsideration with the PUC. On January 26, 2024, the PUC granted the Utilities’ November 15, 2023 request to suspend the docket to focus on identified priorities. The Utilities provided the PUC with an updated assessment of the project on April 30, 2024 and requested to withdraw the application because the need that was to be served by the project can now be met by Stage 3 RFP resources. On July 8, 2024, the Utilities received approval from the PUC to withdraw the project.

Tariffed renewable resources.

•As of June 30, 2024, there were approximately 631 MW, 143 MW and 151 MW of installed distributed renewable energy technologies (mainly PV) 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 and Interim Smart Export. As of June 30, 2024, an estimated 41% of single family homes on the islands of Oahu, Hawaii and Maui have installed private rooftop solar systems, and approximately 23% of the Utilities’ total customers have solar systems.

•The Utilities began accepting energy from feed-in tariff projects in 2011. As of June 30, 2024, 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 June 30, 2021, the Utilities issued an RFP for all fuels, including biodiesel, for supply commencing January 1, 2023. The Utilities and Pacific Biodiesel Technologies, LLC (PBT) signed an agreement on December 13, 2021 for supply of biodiesel on all islands commencing January 1, 2023, which was approved by the PUC on December 1, 2022. 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 2025.

•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 2024, and will continue with no volume purchase requirements.

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

•On November 22, 2021, CBRE RFPs for Molokai and Lanai were opened. The RFP for Lanai sought a single PV paired with storage project, which included a 3 MW portion, reserved for CBRE. The Lanai RFP closed on February 14, 2022 and the Molokai RFP closed on March 1, 2022. A project was selected in the Lanai RFP, but negotiations were terminated. On July 1, 2022, a replacement project was selected and negotiations commenced. The RFP for Molokai sought 2.75 MW of new PV paired with storage projects for CBRE generation. No projects were selected in the Molokai RFP. However, with the concurrence of the independent observer, the Utilities worked with the lone bidder outside of the RFP process and filed two PPAs with a total of 2.45 MW of PV paired with 11.1 MWh of battery energy storage on September 29, 2023.The PUC approved both PPAs on January 8, 2024. See “Transition to a decarbonized and sustainable energy future—Community-based renewable energy” for additional information.

•On March 17, 2022, the CBRE LMI RFPs for Oahu, Maui and Hawaii Island were opened and proposals were received. In November 2022, seven projects were selected consisting of one standalone PV project on Oahu, three paired PV with storage projects on Maui, and three paired PV with storage projects on Hawaii Island. One project on Maui was subsequently withdrawn by the developer on April 11, 2024. The Utilities opened the CBRE Tranche 1 RFPs for Oahu, Maui and Hawaii Island on April 14, 2022. In March 2023, five projects were selected consisting of one paired PV with storage project on Oahu and four standalone PV projects on Hawaii Island. Two projects on Hawaii Island were subsequently withdrawn by the developer on October 18, 2023 and an additional project on Oahu was subsequently withdrawn by the developer on June 14, 2024. Two projects on Hawaii Island were disqualified on May 13, 2024. See “Transition to a decarbonized and sustainable energy future—Community-based renewable energy” for additional information.

•The Hawaii Island Stage 3 RFP, seeking 325 gigawatt-hours (GWh) per year of energy and 65 MW of renewable firm capacity, 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. For the Oahu and Hawaii Island RFPs, as well as for the variable generation portion of the Maui RFP. 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. 15 proposals were selected to the Final Award Group on December 8, 2023. Seven projects were selected on Oahu (three solar plus storage and four firm renewable) totaling 413 GWh of variable generation, 594 MW of firm generation, and 990 MWh of storage; four projects were selected on Maui (three solar plus storage and one wind) totaling 324 GWh of variable generation, and 320 MWh of storage; and four projects were selected on Hawaii Island (three solar plus storage and one firm renewable) totaling 512 GWh of variable generation, 60 MW of firm generation, and 834 MWh of storage. One project totaling 40 MW of firm renewable generation was selected to the Maui Firm Final Award Group on February 2, 2024. On May 24, 2024, a 20 MW / 80 MWh solar-plus storage project on Maui was withdrawn by the developer. Negotiations for the remaining projects are ongoing.

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.

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 Refining, LLC (PAR Hawaii) entered into a fuel supply contract commencing January 1, 2023. On December 1, 2022, the PUC issued a decision and order (D&O) approving the PAR Hawaii fuels contract and recovery of associated costs through ECRC.

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 accounts for at least 25% of Hawaii’s supply. The Utilities are taking additional measure to ensure adequate supply of fuel by entering into a backup fuel supply contract with Vitol Inc. (Vitol) commencing on December 1, 2022 through June 30, 2025 with annual extensions if mutually agreed by both parties. The PUC issued the final D&O approving the Vitol backup fuels supply contract on December 1, 2022 and the costs incurred under the contract with Vitol are recovered in the Utilities’ respective ECRCs.

Liquidity and capital resources.

In June 2024, the Utilities accrued estimated wildfire liabilities of approximately $1.71 billion (pre-tax) related to the settlement of the Maui windstorm and wildfire tort-related legal claims (see Note 2 of the Condensed Consolidated Financial Statements). For the three and six months ended June 30, 2024, the Utilities incurred net losses of approximately $1.23 billion and $1.19 billion, respectively.

When preparing financial statements for each annual and interim reporting period, management has the responsibility to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the Utilities’ ability to continue as a going concern within one year after the date that the financial statements are issued. In making its evaluation, the Utilities consider, among other things, risks and/or uncertainties related to its results of operations, contractual obligations, including near-term debt maturities, dividend requirements, debt covenant compliance, or other factors impacting the Utilities’ liquidity and capital resources. As of the date of filing of this Form 10-Q, management has not yet implemented a capital financing plan to address expected wildfire settlement payments. If the conditions resulting in the substantial doubt are not resolved prior to the issuance of the Utilities’ annual financial statements, or it is not yet probable that management's plans can be effectively implemented to address those conditions, the Utilities would be in default on certain terms of its taxable debt agreements and syndicated credit facility agreement, and lenders would have the option to call the outstanding debt. Management believes the Utilities’ current cash balance at June 30, 2024 of $88.6 million, and available capacity on the asset-based lending facility (ABL Facility) would not be sufficient to fund the Utilities’ planned expenditures and operational needs, which include potential payments to settle wildfire claims.

The Utilities are currently working with their financial advisors on a financing plan to raise the capital necessary to fund their contribution to the settlement of wildfire tort claims. The Utilities expect to finance the settlement payments over time through a mix of debt, common equity, equity-linked securities or other potential options. While management believes the Utilities will be able to raise the necessary capital, there is no assurance that management’s plans will be successful. If the financing plans are unsuccessful, the Utilities may need to consider other strategic alternatives. See further discussion in Part II. Other Information—Item 1A. Risk Factors.

The Utilities’ future results of operations involve significant risks and uncertainties. Factors that could affect 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 (including recent litigation noted above).

As of June 30, 2024, Hawaiian Electric had no commercial paper outstanding, $200 million outstanding on its revolving credit facility and no remaining available borrowing capacity under the Utilities’ committed line of credit. The cash proceeds were invested in highly liquid short-term investments, and as of June 30, 2024, the Utilities’ cash and cash equivalents balance was $88.6 million, compared to $106.1 million as of December 31, 2023.

Additionally, at June 30, 2024, Hawaii Electric had no borrowing from HEI with remaining available borrowing capacity of $75 million, pursuant to a standing commitment letter from HEI. See Note 6 of the Condensed Consolidated Financial Statements for additional information. At June 30, 2024, Hawaii Electric Light and Maui Electric had short-term borrowings from Hawaiian Electric of nil and $110.0 million, respectively, which intercompany borrowings are eliminated in consolidation.

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 its business remain strong, the Utilities took prudent and measured actions to strengthen their financial position while continuing to provide reliable service to its customers and reinforcing its commitment to serving the community for the long term. In August 2023, Hawaiian Electric fully drew down $200 million on its existing revolving credit facilities. The cash proceeds were primarily invested in highly liquid short-term investments and used for general corporate purposes. Longer term, the Utilities are evaluating other sources of liquidity that could include securitization, re-prioritizing capital spending and reducing O&M, issuing secured debt, and conducting asset sales, among others.

Accounts receivable balances remain elevated coming out of the pandemic and has led to higher bad debt expense and higher write-offs in 2023 and year-to-date June 2024, following the end of the moratorium on disconnections. The higher bad debt expense is expected to continue until the Utilities return to pre-pandemic collection practices, along with a decrease in volume, for delinquent accounts. The Maui windstorm and wildfires have not and are not anticipated to materially impact accounts receivable, however, it will lead to higher bad debt expense. As of June 30, 2024, approximately $13.8 million of the accounts receivables were over 30 days past due. Of the over 30 days past due amounts, approximately 36% were on payment plans. In addition to the cash flow impact from delayed collection of accounts receivable, lower kWh sales relative to the level of kWh sales approved in the last rate case generally result in delayed timing of cash flows, resulting in higher working capital requirements.

With the exception of Maui, the Utilities are continuing the disconnection process on a tiered basis, expanding the targeted balances, which is expected to reduce delinquent accounts receivable balances and accelerate cash collections. Service disconnections on Maui have been suspended through at least August 31, 2024, in accordance with the extension of Governor Josh Green’s emergency proclamation; however, efforts are ongoing to educate and inform customers impacted by the Maui windstorm and wildfires on the availability of financial assistance to manage delinquencies accordingly. See also “Regulatory assets and liabilities” in Note 4 of the Condensed Consolidated Financial Statements.

The rebuilding of Lahaina will be a community-led effort and will occur over an extended period of time. The cost of rebuilding the electric utility 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 lines in high-risk locations, are expected to be employed.

Hawaiian Electric’s consolidated capital structure was as follows:

Prior to the Maui windstorm and wildfires, Hawaiian Electric utilized short-term debt, typically commercial paper, to support normal operations, to refinance short-term debt and for other temporary requirements. 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 historically utilized long-term debt, borrowings of the proceeds of special purpose revenue bonds (SPRBs) issued by the State of Hawaii Department of Budget and Finance (DBF) and the issuance of privately placed unsecured senior notes bearing taxable interest, 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 capital markets and other sources of debt and equity financing, if at all, in a timely manner and on acceptable terms.

Credit ratings. On March 12, 2024, S&P revised Hawaiian Electric’s outlook to “Negative” from “Watch Negative” and affirmed the “B-” issuer credit rating.

See “Credit and Capital Market Risk” in Item 1A. Risk Factors in HEI’s and Hawaiian Electric’s 2023 Form 10-K. The downgrades of Hawaiian Electric’s credit ratings will continue to adversely impact the Utilities’ ability to access capital markets and other sources of debt financing, if at all, in a timely manner and on acceptable terms. In addition, the downgrades of Hawaiian Electric’s credit ratings triggered certain cash or payment requirements with the Utilities’ vendors. However, the Utilities believe additional vendor collateral or payment requirements will not have a material impact on the Utilities’ liquidity.

Asset-based lending facility credit agreement. On May 17, 2024, Hawaiian Electric, through a special-purpose subsidiary, entered into an asset-based lending facility (ABL Facility) credit agreement (ABL Credit Facility Agreement) with several banks, which, subject to the limitations and conditions set forth in such agreement, including approval by the PUC, allows borrowings of up to $250 million on a revolving basis using certain accounts receivable as collateral. Hawaiian Electric filed an application with the PUC for approval to (i) sell accounts receivable, and (ii) establish a long-term credit facility. The first approval would allow the ABL Credit Facility Agreement to become effective for 364 days and the second approval would extend the term of the ABL Credit Facility Agreement from 364 days to three years. The ABL Credit Facility Agreement has an initial term of 364 days, with an automatic extension to three years upon receipt of the second PUC approval, with three separate options to extend one additional year, subject to the consent of the lenders. On June 27, 2024, Hawaiian Electric received the first approval from the PUC for the ABL Credit Facility Agreement that allows short-term borrowings of up to $250 million, subject to the availability of a sufficient borrowing base of eligible receivables. Per the parties’ proposed stipulated procedural schedule, the second PUC decision is expected on October 30, 2024. The ABL Facility became effective on July 24, 2024.

Credit agreement. On August 23, 2023, Hawaiian Electric fully drew down $200 million on its existing revolving credit facilities. The cash proceeds were invested in highly liquid short-term investments and will be used for general corporate purposes. The $200 million line of credit facility remained fully drawn as of June 30, 2024. See Note 6 of the Condensed Consolidated Financial Statements for additional information.

SPRBs. Special purpose revenue bonds (SPRBs) have been issued by the Department of Budget and Finance of the State of Hawaii (DBF) to finance (and refinance) capital improvement projects of Hawaiian Electric and its subsidiaries, but the sources of their repayment are the non-collateralized obligations of Hawaiian Electric and its subsidiaries under loan agreements and notes issued to the DBF, including Hawaiian Electric’s guarantees of its subsidiaries’ obligations.

On June 10, 2019, the Hawaii legislature authorized the issuance of up to $700 million of SPRBs ($400 million for Hawaiian Electric, $150 million for Hawaii Electric Light and $150 million for Maui Electric), with PUC approval, prior to June 30, 2024, to finance the Utilities’ multi-project capital improvement programs (2019 Legislative Authorization). The Utilities did not issue SPRBs under the 2019 Legislative Authorization which lapsed on June 30, 2024.

Taxable debt. On December 20, 2022, the Utilities received PUC approval to issue, over a four-year period from January 1, 2023 to December 31, 2026, unsecured obligations bearing taxable interest (Hawaiian Electric up to $230 million, Hawaii Electric Light up to $65 million and Maui Electric up to $105 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 January 10, 2023, the Utilities executed through a private placement, $150 million in unsecured senior notes (2023 Notes). The 2023 Notes had a delayed draw feature and the Utilities drew down all the proceeds on February 9, 2023. See summary table below for remaining authorized amounts as of June 30, 2024 for each respective utility.

As of June 30, 2024, the Utilities have $1.9 billion of long-term debt, net, of which $47.0 million and $145.3 million are due within 12 and 24 months, respectively.

Equity. On December 20, 2022, the Utilities received PUC approval to issue and sell each utility’s common stock over a four-year period from January 1, 2023 through December 31, 2026 (Hawaiian Electric’s sale/s to HEI of up to $75 million, Hawaii Electric Light sale/s to Hawaiian Electric of up to $25 million, and Maui Electric sale/s to Hawaiian Electric of up to $55 million) and the purchase of Hawaii Electric Light and Maui Electric common stock by Hawaiian Electric from 2023 through December 31, 2026. As of June 30, 2024, Hawaiian Electric, Hawaii Electric Light, and Maui Electric have $75 million, $25 million, and $55 million, respectively, of unused common stock authorization.

Cash flows. The following table reflects the changes in cash flows for the six months ended June 30, 2024 compared to the six months ended June 30, 2023:

Net cash provided by operating activities. The decrease in net cash provided by operating activities was primarily driven by an increase in fuel oil stock due to less consumption, as well as lower cash from an increase in customer accounts receivable due to payment on a large delinquent commercial customer account in 2023.

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

Net cash used in financing activities. The increase in net cash used in financing activities was driven by lower net cash from long-term and short-term borrowings.

For a discussion of 2023 operating, investing and financing activities, please refer to the “Liquidity and capital resources” section in Item 7, “Management Discussion and Analysis of Financial Condition and Results of Operations—Electric utility,” in the Company’s 2023 Form 10-K.

Material cash requirements. Material cash requirements of the Utilities include payments related to settlement of tort-related legal claims and cross claims, legal and consulting costs related to the Maui windstorm and wildfires (see further information in Note 2 of the Condensed Consolidated Financial Statements), O&M expenses, labor and benefit 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.

The substantial doubt about the Utilities’ ability to continue as a going concern and the Utilities’ credit rating downgrades related to the Maui windstorm and wildfires will continue to adversely impact its ability to access capital markets and other sources of debt financing, if at all, in a timely manner and on acceptable terms. The Utilities are currently working with their financial advisors on a financing plan to raise the capital required to settle its wildfire claims. While management believes that the Utilities will be able to raise the necessary capital, there is no assurance that management’s plans will be successful. The potential 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.