Hawaiian Electric Q3 2026 GAAP profit falls to $13.5M

HEI’s quarterly GAAP and Core results moved in opposite directions, with an after-tax investment gain included in GAAP results.

Available on EDGAR 11/09/2026 - 06:08 AM EST Accepted by SEC EDGAR 11/09/2026 - 06:07 AM EST Learn about SEC filing dates

Rhea-AI Filing Summary

Hawaiian Electric Company, Inc. furnished an investor presentation covering Hawaiian Electric’s regulatory plans, wildfire mitigation, liquidity and third-quarter results. Hawaiian Electric reported third-quarter 2026 GAAP net income of $13.488 million, versus $36.988 million a year earlier, and Core net income of $27.597 million, versus $39.640 million. HEI, the parent, reported consolidated GAAP net income of $35.450 million, compared with $30.747 million, while consolidated Core net income was $22.960 million, versus $32.808 million. HEI’s GAAP result included a $64.146 million after-tax gain on an investment, excluded from Core earnings.

Quarter-end liquidity was reported at $1,324 million for Q3 2026. Hawaiian Electric has $350 million of approved 2025–2027 wildfire mitigation costs, with securitization planned to limit customer bill impact. Its rate-rebasing illustration shows $83 million of revenue impact in 2027 and a $125 million full first-year run rate, assuming the PUC approves the request in full as presented; 2027 rates are shown effective May 1, 2027. The alternative rate-rebasing application and PBR Phase 6 review were in process. HEI’s S&P rating was upgraded to BB- from B+ in July.

2 points · 0 major

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Positive

• Moderate pointHEI consolidated Q3 GAAP net income: $35.450 million, versus $30.747 million.
• Moderate pointHEI S&P credit rating upgraded to BB- from B+.

Negative

• Moderate pointHawaiian Electric Q3 GAAP net income: $13.488 million, versus $36.988 million.
• Moderate pointHawaiian Electric Q3 Core net income: $27.597 million, versus $39.640 million.
• Moderate pointHEI consolidated Q3 Core net income: $22.960 million, versus $32.808 million.

8-K Event Classification

2 items: 7.01, 9.01

2 items

Item 7.01 Regulation FD Disclosure Disclosure

Material non-public information disclosed under Regulation Fair Disclosure, often investor presentations or guidance.

Item 9.01 Financial Statements and Exhibits Exhibits

Financial statements, pro forma financial information, or exhibit attachments filed with this report.

Key Figures

Hawaiian Electric GAAP net income: $13.488 million Hawaiian Electric Core net income: $27.597 million HEI consolidated GAAP net income: $35.450 million +5 more

8 metrics

Hawaiian Electric GAAP net income $13.488 million Three months ended September 30, 2026; compared with $36.988 million in 2025.

Hawaiian Electric Core net income $27.597 million Three months ended September 30, 2026; compared with $39.640 million in 2025.

HEI consolidated GAAP net income $35.450 million Three months ended September 30, 2026; compared with $30.747 million in 2025.

HEI consolidated Core net income $22.960 million Three months ended September 30, 2026; compared with $32.808 million in 2025.

Quarter-end liquidity $1,324 million Q3 2026.

Approved wildfire mitigation costs $350 million 2025–2027 Wildfire Mitigation Plan costs.

Illustrative rate-rebasing revenue impact $83 million in 2027; $125 million full first-year run rate Assumes full PUC approval as requested; 2027 rates shown effective May 1, 2027.

HEI after-tax investment gain $64.146 million Three months ended September 30, 2026; excluded from Core earnings.

Key Terms

Core Earnings Per Share (EPS), Performance-Based Regulation, Annual Revenue Adjustment (ARA), Exceptional Project Recovery Mechanism (EPRM), +1 more

5 terms

Core Earnings Per Share (EPS) financial

"Core Earnings Per Share (EPS), Core Net Income, Core Return on Equity (ROE)"

Core earnings per share (EPS) is a measure of a company's profit per share that removes one-time, unusual or non-recurring items to show the underlying, repeatable earnings available to shareholders. It matters because it gives investors a clearer view of the business's ongoing profitability and makes comparisons across periods or companies fairer; think of it as judging a car by its regular fuel efficiency rather than a single unusually fast trip.

Performance-Based Regulation regulatory

"Unique Performance-Based Regulatory Model"

Annual Revenue Adjustment (ARA) regulatory

"Annual Revenue Adjustment (ARA)"

Exceptional Project Recovery Mechanism (EPRM) regulatory

"Exceptional Project Recovery Mechanism (EPRM)"

Performance Incentive Mechanisms (PIMs) regulatory

"Performance Incentive Mechanisms (PIMs)"

FAQ

AI-generated questions and answers. How Rhea-AI works. Not financial advice.

What were HAWEL’s third-quarter 2026 earnings?

Hawaiian Electric reported GAAP net income of $13.488 million and Core net income of $27.597 million for the three months ended September 30, 2026. For the same quarter in 2025, the respective figures were $36.988 million and $39.640 million.

What revenue impact does HAWEL’s rate-rebasing illustration show?

The illustration shows $83 million of revenue impact in 2027 and a $125 million full first-year run rate, assuming the PUC approves the rate-rebasing request in full as presented. It shows 2027 rates effective May 1, 2027, and describes the figures as illustrative, not guidance or a forecast.

AI-generated analysis. How Rhea-AI works. Not financial advice.

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00003547070000046207falsefalse00003547072026-11-092026-11-090000354707he:HawaiianElectricCompanyInc.Member2026-11-092026-11-09

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the

Securities Exchange Act of 1934

Date of Report: November 9, 2026

Exact Name of Registrant			Commission			I.R.S. Employer
as Specified in Its Charter			File Number			Identification No.
Hawaiian Electric Industries, Inc.			1-8503			99-0208097
Hawaiian Electric Company, Inc.			1-4955			99-0040500

State of Hawaii

(State or other jurisdiction of incorporation)

 1001 Bishop Street, Suite 2900, Honolulu, Hawaii  96813 - Hawaiian Electric Industries, Inc. (HEI)

1099 Alakea Street, Suite 2200, Honolulu, Hawaii  96813 - Hawaiian Electric Company, Inc. (Hawaiian Electric)

(Address of principal executive offices and zip code)

 Registrant’s telephone number, including area code:

 (808) 543-5662 - HEI

(808) 543-7771 - Hawaiian Electric

  Not applicable

(Former name or former address, if changed since last report.)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

☐    Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

☐    Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

☐    Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

☐    Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Securities registered pursuant to 12(b) of the Act:

Registrant			Title of each class			Trading Symbol(s)			Name of each exchange on which registered
Hawaiian Electric Industries, Inc.			Common Stock, Without Par Value			HE			New York Stock Exchange

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule12b-2 of the Securities Act of 1934 (§240.12b-2 of this chapter).

Emerging growth company

Hawaiian Electric Industries, Inc. ☐ Hawaiian Electric Company, Inc. ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.

Hawaiian Electric Industries, Inc. ☐ Hawaiian Electric Company, Inc. ☐

Item 7.01 Regulation FD Disclosure.

    In accordance with Regulation FD, Hawaiian Electric Industries, Inc. (the “Company”) hereby furnishes a presentation that the Company intends to use with investors, analysts and others beginning on or after November 9, 2026. Such presentation is attached to this Current Report on Form 8-K as Exhibit 99. A copy of the investor presentation is posted on the Company’s website at www.hei.com.

Item 9.01 Financial Statements and Exhibits.

    

(d) Exhibits
Exhibit 99			November 2026 EEI Investor Meetings
104			Cover Page Interactive Data File (embedded within the Inline XBRL document)

The information furnished in connection with this current report on Form 8-K shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the Exchange Act), or incorporated by reference in any filing under the Securities Act of 1933, as amended, or the Exchange Act, except as shall be expressly set forth by specific reference in such a filing.

1

SIGNATURES

    Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrants have duly caused this report to be signed on their behalf by the undersigned thereunto duly authorized. The signature of the undersigned companies shall be deemed to relate only to matters having reference to such companies and any subsidiaries thereof.

HAWAIIAN ELECTRIC INDUSTRIES, INC.						HAWAIIAN ELECTRIC COMPANY, INC.
(Registrant)						(Registrant)
/s/ Paul K. Ito						/s/ Paul K. Ito
Paul K. Ito						Paul K. Ito
Senior Vice President and						Senior Vice President,
Chief Financial Officer						Chief Financial Officer and Treasurer
Date: November 9, 2026						Date: November 9, 2026

2

HEI 2026 EEI Financial Conference Investor Meetings

Non-GAAP Financial Information This presentation refers to certain financial measures that were not prepared in accordance with U.S. generally accepted accounting principles, including Core Earnings Per Share (EPS), Core Net Income, Core Return on Equity (ROE) and other Core measures. Reconciliations of those non-GAAP financial measures to the most directly comparable GAAP financial measures can be found in the Appendix herein. • See Appendix for definition of Core Earnings, Core EPS and Core Return on Equity (ROE). 2

3 Key Takeaways • Hawaiian Electric is well-positioned for long-term value creation, with a greatly improved risk profile, near-term catalysts to improved earnings, a favorable regulatory construct, and an elevated capex cycle ahead Positive Trajectory • Hawaiian Electric has consistently executed on the objectives communicated since 2023, with each key objective of financial and operational strength moving in the right direction Track Record of Execution • Hawaiian Electric has visibility and a clear plan to achieve a stronger financial foundation through continued execution. Rate rebasing and other regulatory processes, and achieving efficiencies while executing through elevated capex cycle, are expected to lead to stronger credit metrics and returns on equity Clear Path and Visibility

4 Topics of Focus HEI at a Glance and How We Got Here Regulatory framework provides steady, predictable revenues, with rate rebasing underway Implementing industry leading wildfire mitigation efforts and reducing operating risk 1 3 2 Strong balance sheet and liquidity with improving credit metrics4 Executing through historic capital cycle5

HECO 71% HELCO 15% MECO 14% • ~$4.1 Bn total rate base • ~5,800 sq. mile service territory • 1,608 MW owned generation • Ba1 / BB- / BB- credit ratings2 Hawaii Maui Lānaʻi Oʻahu Operating Vertically-Integrated Electric Utility Serving ~95% of Hawaii’s Population 5 Note: All data as of December 31, 2025 unless otherwise stated. 1. As of 11/6/2026. Enterprise value calculated using debt and unrestricted cash balances as of 9/30/26. 2. Credit ratings from Moody’s, Fitch and S&P, respectively. Key Attributes • Serving 1.4 million people across five separate grids, with customers including communities, U.S. military facilities, resorts and agricultural operations • Operating vertically integrated 100% electric utility with unique Performance Based Regulation framework providing stable, predictable revenues • Sales decoupling provides additional revenue stability and predictability • Currently in transitional period, with rate rebasing underway for next five-year rate cycle providing revenue enhancement opportunities • $1.5 Bn market cap1 • $3.5 Bn enterprise value1 • Ba2 / B+ / BB- credit ratings2 Residential 33% Commercial 32% Industrial 35% Revenues by Customer Class Rate Base by Company Revenues by Company HECO 68% HELCO 15% MECO 17% Molokaʻi

6 Strong Execution on Objectives STRONG EXECUTION OF STRATEGY, RESULTING IN MEANINGFUL ADVANCEMENT OF EACH KEY FINANCIAL AND OPERATIONAL OBJECTIVE ✓ Reduce Wildfire Risk No PUC-approved wildfire mitigation plan Wildfire Mitigation Plan in development PUC-approved 2025 – 2027 Wildfire Mitigation Plan being implemented rapidly, and PSPS in place. Significant risk reduction achieved to date ✓ Restore Credit Ratings HEI: NR / BBB+ / BBB- HECO: Baa1 / A- / BBB HEI: B1 / B / B- HECO: Ba3 / B / B- HEI: Ba2 / B+ / BB- HECO: Ba1 / BB- / BB- ✓ Enhance Liquidity $522 million at 2Q 2023 $243 million at 4Q 2023 More liquidity than pre-wildfire; $1,324 million at 3Q 2026 ✓ Rebuild Capital Markets Access Full access - $375 million of undrawn revolvers Impaired - revolvers fully drawn, common dividend suspended $558 million equity issuance and a $500 million utility high yield offering executed, with $600 million of undrawn revolvers and $250 million AR facility ✓ Resolve Maui Tort Litigation No wildfire claims outstanding Unquantified claims outstanding First of its kind global settlement signed in record time and upheld by the Hawaii Supreme Court; first $479 million installment paid April 2026, additional $80 million prepaid in Sept. / Oct. ✓ Limit Economic Risk from Wildfires No legislative protections in place Efforts initiated Liability cap legislation enacted, with PUC to establish amount. Wildfire fund study completed and fund deemed warranted (consistent with our view) ✓ Secure Wildfire Cost Recovery No wildfire-specific recovery mechanism None approved $350 million Wildfire Mitigation Program costs approved, with planned securitization to limit customer bill impact ✓ Streamline and Simplify the Business Utility + bank (ASB) + Pacific Current No change Simplified business fully focused on vertically- integrated regulated Utility TodayPost-Wildfire (Q4 2023)Pre-Wildfire (Q2 2023)Key Objectives

7 Delivering on Key Operational Priorities 2.26 1.67 1.84 1.45 2.17 1.341.40 1.70 1.20 1.68 1.08 0.801.04 0.86 0.88 0.87 1.35 1.03 1.07 1.24 0.66 1.… 0.68 0.45 0.00 0.50 1.00 1.50 2.00 2.50 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 YTD Total Case Incident Rate1 Lost Time Rate 2 61 65 69 69 74 74 77 73 72 67 74 77 2 4 13 15 5… 43 69 41 40 20 56 86 0 10 20 30 40 50 60 70 80 90 100 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 YTD Residential Customer Satisfaction Score3 Peer Percentile3 1. Total Case Incident Rate measures how many work-related injuries and illnesses occur per 100 employees. TCIR is calculated as follows: Number of Occupational Safety and Health Administration (OSHA) recordable cases multiplied by 200,000 productive hours (i.e. 2,000 work-hours per year per employee multiplied by 100 employees) divided by total number of productive hours for the year. 2. Lost Time Rate measures any occupational injury or illness which results in an employee being unable to work a full assigned work shift after an incident per 100 employees. LTR is calculated according to OSHA guidelines as follows: number of Lost Time cases (injury or illness which an employee is unable to work a full assigned work shift as a result of a work-related injury or illness) multiplied by 200,000 productive hours divided by the total number of productive hours for the year. 3. Customer satisfaction score is the company’s raw score from the Escalent Residential Customer survey. The percentile reflects the percentile compared to peer utilities. 4. YTD safety figures are as of 9/30/26. YTD customer satisfaction data is an average of scores for the first three quarters of 2026. 5. Escalent Residential Customer Benchmark Survey of more than 100 utilities. Improved employee safety and customer satisfaction while advancing wildfire risk reduction and post-wildfire recovery priorities Best safety metrics on record in 2025 and 2026 52% improvement in TCIR1 since 2024 (lower is better) Top-tier overall customer satisfaction growth From 20th to 86th percentile since 2024 Among industry leaders across broad range of customer satisfaction indicators • Of 15 dimensions in national customer satisfaction benchmark survey,5 ten were in the top decile for 3Q26 • Two dimensions rated in 99th percentile for 3Q26: employees and service reputation

8 Financing investments at lower cost Increasing customer options and support Reducing and stabilizing energy costs Supporting stronger incomes Initiatives target both energy cost and customer income sides of affordability equation • Improving credit ratings through risk reduction • Securitizing up to $500M of wildfire mitigation, resilience and grid modernization costs (~$2 / month bill impact) • Pursuing additional federal funding opportunities, including a DOE loan, to reduce financing costs Modest rate rebasing request • Rate rebasing request seeks recovery of three discrete cost categories, with Company-proposed reduction to manage affordability • Phased over two years to moderate bill impact • $100 million in realized customer savings to date from PBR • Modernizing generation to increase efficiency • Adding renewables through competitive procurement to improve bill stability • Driving operating efficiency and process improvements • All fuels RFP to be launched in late 2026 • Helping LMI customers with bill credits, payment plans and pre-disconnection solutions • Expanding bill management options, including bill due date choice • Working with partners on workforce, economic development and affordable housing efforts to help Hawaii families earn more and spend less 3.32% of monthly household spending 2.55% of monthly household spending 89% 77% 9%22% 2% 2% vs. █ Electricity █ Natural Gas █ Rooftop Solar LCOE Hawaii’s household energy burden is below national average 1. Household energy burden is calculated as household energy spending (retail electricity sales + retail natural gas sales + levelized cost of residential solar) divided by the number of total households, as a % of median household income. 2025 data is the latest currently available as of November 2026. Addressing Customer Affordability on Multiple Fronts Hawaiʻi U.S. Average

9 Topics of Focus HEI at a Glance and How We Got Here Regulatory framework provides steady, predictable revenues, with rate rebasing underway Implementing industry leading wildfire mitigation efforts and reducing operating risk 1 3 2 Strong balance sheet and liquidity with improving credit metrics4 Executing through historic capital cycle5

Unique Performance-Based Regulatory Model Supports Five-Year Period of Stable, Predictable Revenues 10 Incremental earnings incentives and opportunities driven by three main sources Illustrative Total • ARA spending below inflationary adjustment Annual Revenue Adjustment (ARA) • Annual inflationary adjustment Total Earnings Separate RecoveryIncremental ARA Earnings PIMs Earnings ARA Spend • Baseline O&M & baseline capex • Exceptional Project Recovery Mechanism (EPRM) • Innovative pilot projects • Renewable Energy Infrastructure Program (REIP) • Z-factor recovery for exogenous events • Performance incentive mechanisms Incremental Earnings Under PBR 1 2 3 PERFORMANCE-BASED REGULATION ALIGNS UTILITY BUSINESS MODEL WITH REGULATOR-APPROVED PRIORITY OUTCOMES

Annual Revenue Adjustments Provide Visibility, With Recovery Mechanism for Exogenous Events Annual revenue adjustment formula: i-factor x-factor z-factor customer dividend Accounts for annual inflation • Measured by Gross Domestic Product Price Index (GDPPI) from Blue Chip Economic Indicators forecast as of October of each year • October 2025 forecast for 2026: 2.8% • October 2026 forecast for 2027: 2.8% Productivity factor • Initially set at 0% (where it currently remains) Ex post opportunity to recover costs for exogenous events • Review and approval determined on case-by- case basis • Example: COVID-19- related costs recovered through Z-Factor • Potential mechanism for storm cost recovery (e.g., Hurricane Lala) Three components: (i) 0.22% adjustment ~Compounds over time. 2026 amount is $14.6M. (ii) Management audit savings commitment made in Hawaiian Electric 2020 rate case, approved by PUC at $6.6M annually (iii) ERP benefits returned to Hawai‘i Electric Light and Maui Electric customers. 2026 amount in effect is $3.3M 11 • Annual target revenues set with ARA during each 5-year Multi-year Rate Period (MRP)

12 Rate Rebasing and PBR Review for Second Five-Year Rate Period Progressing PBR Review / Redesign Process Nearing Conclusion 20272026 Oct. 23 Phase 6 commenced with Staff Proposal Early Jan. PUC’s Inclinations on final scope expected, to be followed by a procedural schedule Nov. 13 Parties’ replies to Staff Proposal due Continuing into 2027 Collaborative workshops, information requests, statements of position and briefs • Key procedural milestone complete, with public hearings held on all islands • Preliminary PUC schedule allows for a final decision and order in mid-to-late April 2027 • Awaiting revised procedural schedule, expected in the near term Starting from a place of relative alignment, with Staff Proposal focused on many of our own objectives 1. See slide 13 for detailed Company priorities for Phase 6. Rate Rebasing Milestones $83.2 $125.0 $169.8 $46.9 $5.1 $44.8 GDPPI adjustment Insurance expenses O&M reductions Total 2027 increase 2028 Depreciation adjustment Total increase requested Proposed Gradual Rate Increases Aligned with Inflation • PBR stakeholder group has continued to meet regularly since 2024 • Phase 6 will address design of specific PBR mechanisms; Company objectives include modifications to ARA, PIMs and EPRM1 • Reflects prior Company input and aligns with the Company’s expectations and planned approaches PBR Phase 6

Modifying forecasted GDPPI inflation adjustment • Base the inflation adjustment on actual rather than forecasted inflation, and better reflect actual inflationary pressures in our unique island operating environment • Use a blended index that incorporates the utility labor cost index Revising PIM Portfolio • Ensure target performance is within the company's control to achieve, and limit number of PIMs to avoid dilution of effort and focus while ensuring PIMs cover core objectives • Expand reward potential to fulfill PUC's original intent3 that they provide a meaningful opportunity. Proposing up to 200 bps at risk (downside of 50 bps / upside of 150 bps) Terminate Subtractive ARA Components • Eliminate the Management Audit Savings Commitment and return of ERP Benefits through Customer Dividend Additional • Expand scope of EPRM to allow recovery for large “business-as-usual” costs; Revise approved cost of capital in future EPRM projects to reflect higher risk; Pension and OPEB tracker modifications4 13 Additional Revenue-Enhancing Opportunities Being Pursued in Phase 6 PUC’s Guidance on PBR Phase 6 • Proceeding to examine specific PBR mechanisms to determine what modifications should be adopted heading into MRP2 • Stated focus is on Performance Incentive Mechanism (PIM) portfolio, Customer Dividend and collective revenue opportunities offered by i-factor and EPRM1 • Phase 6 commencing concurrently with alternative rate rebasing proposal2 1. As stated in PUC Decision and Order No. 41876. 2. PUC Order, including a Staff Proposal, issued on October 23, 2026, commencing Phase 6. 3. Proposed 200 bps structure directly implements PUC staff’s original recommendation for “between three and six PIMs that, in total, would provide the HECO Companies with incentives that would increase or decrease earnings by 150 - 200 basis points.” (Staff Proposal for Updated Performance-Based Regulations, filed on February 7, 2019 in Docket No. 2018-0088). 4. Modifications contemplated include adding 401(k) costs to the tracker, and eliminating unamortized balances at the end of each calendar year to avoid the need to reset tracker balances for amortization purposes at the end of MRP2. Our Phase 6 Objectives Include:

14 Topics of Focus HEI at a Glance and How We Got Here Regulatory framework provides steady, predictable revenues, with rate rebasing underway Implementing industry leading wildfire mitigation efforts and reducing operating risk 1 3 2 Strong balance sheet and liquidity with improving credit metrics4 Executing through historic capital cycle5

Strategic Spending and Investment Support Rapid Reduction of Wildfire and Other Climate-Related Risk in Unique Island Service Territory 15 TARGETED SPENDING AND INVESTMENT Over $400 million1 in 2025 – 2027 spending to reduce wildfire risk and enhance grid resilience in the face of increasingly severe weather events $237 $407 $80 $79 $11 WMP capital WMP O&M Resilience Program capital Grid Modernization capital Total 2025 - 27 wildfire and resilience spend Wildfire and resilience spending has rapidly reduced risk through technology implementation and operational changes, including Public Safety Power Shutoff program, advanced vegetation management and installation of A.I. cameras and weather stations to monitor conditions 1. Expected to be recovered primarily through securitization. Resilience program capital expected to be recovered through EPRM.

Accelerated Progression of Wildfire Risk Reduction Efforts1 16 • Installed 135 weather stations along circuits in all high wildfire risk areas, providing key information about wind, temperature and humidity conditions • Installed 145 A.I. assisted high-definition video camera stations covering over 99% of high wildfire risk areas across our service territories Situational Awareness • Replaced or upgraded 5,072 wood poles • Replaced 52.9 miles of overhead copper conductor with stronger aluminum conductor or covered conductor • Replaced 16,114 expulsion fuses with firesafe fuses • Replaced 4,594 lightning arresters with firesafe lightning arresters Grid Hardening and Redesign • Public Safety Power Shutoff program in place since July 2024 • 24/7 watch office stood up to monitor for potential ignitions and forecast weather events • Spotters deployed in risk areas during hazardous weather conditions • In risk areas, set circuit breakers to automatically shut off faster when a disturbance is detected; in addition, lines are not re-energized until fully inspected • Developed risk maps based on potential of ignition • Conducted circuit inspections in high-risk areas Operational Practices • Participated in more than 90 in-person and virtual public outreach events on Maui, Molokai, Oahu and Hawaii Island in 2025 • Shared information through emails and printed mail, on social media and online, working to broaden the accessibility of information regarding critical wildfire safety issues, such as the PSPS program Stakeholder and Community Partnerships Substantial Reduction in Risk of Ignition from Utility Equipment 1. Includes installations from 1/1/24 through 9/30/26.

Hawaiian Electric’s Risk Profile is Differentiated from California 17 622 74,000 Hawaiian Electric 6 CA Utilities T&D Miles in High Wildfire Risk Areas (119x)1 9,800 265,000 Hawaiian Electric 6 CA Utilities Total T&D Miles2 (27x) 5,800 156,000 Hawaiian Electric 6 CA Utilities Service Territory2 (Square Miles) (27x) Differentiating Factors • Only 6% of Hawaiian Electric's T&D is in high wildfire risk areas, vs. 28% for California utilities • Hawaii’s potential fuels are non-native grass and shrub, not coniferous forest • Scale is roughly 1/27th of California's system, allowing faster, fuller mitigation coverage Hawaiian Electric's system is a fraction of California's in size and wildfire-exposed mileage — 622 high-risk T&D miles vs. 74,000 — enabling faster implementation of mitigation measures across its highest risk areas Hawaiian Electric's Wildfire Mitigation Plan has adopted many best practices from other wildfire-exposed utilities, allowing Hawaiian Electric to rapidly reduce risk through operational changes, including fast trip, block auto-reclose, public safety power shutoff (PSPS), proactive vegetation management, and installing AI cameras and weather stations to monitor conditions for PSPS shutoffs 1CA Utility Data from 2022 California State Auditor – Electrical System Safety Report 2CA Utility Data from CPUC Undergrounding Programs Description (CPUC Undergrounding Programs Description)

Actions Beyond the Utility Further Reduce Wildfire Risk 18 ✓ Approved 40 remote automatic weather stations ✓ Began installations with federal partners, of a total of 80 fire-detection sensors with 24-hour alerting capabilities ✓ Continued collaborations with federal partners, nonprofit organizations and local communities ✓ Revamped siren protocols in conjunction with counties New Governor-Directed Actions Whole-of- society efforts reduce statewide wildfire risk ✓ Act 303: Requires owners / occupants of property located in hazardous fire areas to maintain effective fire breaks and practice other fire prevention activities ✓ Act 302: Addresses priorities from Fire Safety Research Institute Phase 3 report (Jan 14, 2025) • Established formal Office of the State Fire Marshal • Statewide risk assessment, oversight of fire code development & enforcement • Develops training standards for prevention, inspection & suppression • Develops wildfire hazard map identifying risk zones New Legislation Greater Financial Resources ✓ $24.7M in other federal funds and $7M in general funds for hazard mitigation and emergency operations center ✓ Department of the Hawaiian Homelands added $20M for wildfire response, recovery and prevention measures ✓ $7.4 million in general funds for fire response and fuels reduction contracts for Division of Forestry and Wildlife ✓ $10M in general funds for fire and emergency response equipment for Division of Forestry and Wildlife ✓ $2.4M for fire prevention, erosion control and fire suppression dip tanks on Maui EVOLUTION OF HAWAII’S WILDFIRE RISK THE RESULT OF STATE LEADERSHIP, COLLABORATION AND GREATER RESOURCES

19 Unique Legislative and Legal Protections Limit Economic Exposure to Potential Wildfires ✓ State law establishes liability cap, with amount currently being determined • As directed by Act 258, the PUC is working to determine the amount of an aggregate liability cap on economic damages from future wildfires. The utility’s Wildfire Mitigation Plan, required for asserting the cap, has already been approved by the PUC1 ✓ Wildfire fund determined to be warranted in the future, following establishment of liability cap • In 2025, the PUC completed a study examining establishment and implementation of a wildfire recovery fund. The study concluded that, “a wildfire recovery fund is likely warranted in the future,” and recommended that the liability cap be established first, along with conducting an actuarial study to “determine an appropriate size and structure for a wildfire recovery fund.” ✓ Long-standing Hawaii law provides other unique protections • State law includes protections against non-economic damages, which often make up the bulk of damages awarded in wildfire cases in other states • Hawaii’s “Limitation on pain and suffering” statute states: “Damages recoverable for pain and suffering as defined in section 663- 8.52 shall be limited to a maximum award of $375,000; provided that this limitation shall not apply to tort actions enumerated in section 663-10.9(2),3” capping a significant category of damages in personal injury cases ✓ Favorable Supreme Court ruling helps mitigate wildfire liability by limiting subrogation claims against defendants once the underlying claims against those defendants have been settled ✓ Inverse condemnation has not been applied to utilities for wildfires like it has in California 1. Act 258 requires that the utility, “have a wildfire mitigation plan that is approved by the Commission and shall have sought and received a determination from the Commission that the plan is being implemented on the timeline approved by the Commission.” 2. Pain and suffering is one type of noneconomic damage and means the actual physical pain and suffering that is the proximate result of a physical injury sustained by a person. 3. The torts listed in HRS § 663-10.9(2), are: “(A) Intentional torts; (B) Torts relating to environmental pollution; (C) Toxic and asbestos-related torts; (D) Torts relating to aircraft accidents; (E) Strict and products liability torts; or (F) Torts relating to certain motor vehicle accidents. Act 258 became law in 2025, acknowledging the importance of “protecting the financial integrity of Hawaii’s electric utilities” and “improving the utility's credit rating and lowering costs passed on to customers”

20 Topics of Focus HEI at a Glance and How We Got Here Regulatory framework provides steady, predictable revenues, with rate rebasing underway Implementing industry leading wildfire mitigation efforts and reducing operating risk 1 3 2 Strong balance sheet and liquidity with improving credit metrics4 Executing through historic capital cycle5

Capital markets access affirmed and liquidity position strengthened through $558M equity issuance Rate rebasing to improve ROE, FFO/Debt, Debt/Equity Continued Progress Toward Investment Grade Credit Ratings 21 Sub investment grade (higher customer cost and risk) Investment grade (lower customer cost and risk) Accelerated wildfire mitigation work to reduce risk Signed global settlement agreement in Maui wildfire tort litigation Post-wildfire credit ratings1: HEI: B1 / B / B- HECO: Ba3 / B / B- Continuing to maintain strong liquidity position Hawaii Supreme Court ruling ends the insurers’ efforts to derail the class settlement Act 258 (regarding liability cap, securitization and wildfire fund) signed into law Successful RCF upsize and $500M utility high yield offering executed Court approval of global settlement agreement achieved WE ARE HERE1 HEI: Ba2 / B+ / BB- credit ratings HECO: Ba1 / BB- / BB- credit ratings 1. Credit ratings from Moody’s, Fitch and S&P, respectively. Post-wildfire ratings reflect ratings at the end of 2023, following two downgrades from S&P and one each from Fitch and Moody’s. Determine liability cap amount as directed by Act 258 Establish wildfire recovery fund LIQUIDITY AND BALANCE SHEET MANAGEMENT, ONGOING WILDFIRE MITIGATION WORK, LEGAL PROCESS SUCCESSES FOLLOWING WILDFIRES HAVE SUPPORTED PATH BACK TOWARD INVESTMENT GRADE Wildfire fund study completed, determining that a fund is “warranted”

Positive Credit Ratings Trajectory Continues With Recognition of Wildfire Mitigation Plan Progress 22 HEI CREDIT RATINGS 2022 – 2026 • July S&P upgrade to BB- from B+ acknowledges progress in improving wildfire safety profile • Follows Moody’s upgrade in April • PUC’s liability cap rulemaking process underway, with liability cap implementation a potential catalyst for further upgrades Fitch Moody’s S&P B- AAA AA+ AA_ AA- A+ A_ A- BBB+ BBB_ BBB- BB+ BB_ BB- B+ B_ B- Aaa Aa1 Aa2 Aa3 A1 A2 A3 Baa1 Baa2 Baa3 Ba1 Ba2 Ba3 B1 B2 B3 AAA AA+ AA_ AA- A+ A_ A- BBB+ BBB_ BBB- BB+ BB_ BB- B+ B_ B- In v e s tm e n t G ra d e ( IG ) S u b -I G 2022 2023 2024 2025 2026 2022 2023 2024 2025 2026 2022 2023 2024 2025 2026 HoldCo Utility

Our Settlement Financing Strategy Focuses on Minimizing Dilution Annual cash tax benefits realized over time from settlement payment tax deductions decrease the amount of capital to be raised 23 FUNDING SETTLEMENT OBLIGATIONS – CURRENT EXPECTATIONS1 $75 $1,990 $479 $82 $100 $297 $479 $479 One 'Ohana Contribution First Payment (2026) Prepayment of Second Payment Addtl. Planned Prepayment of Second Payment (2027) Second Payment (2027) Third Payment (2028) Fourth Payment (2029) HEI Settlement Obligation Reimbursed by insurance Funded by 2024 equity issuance To be funded primarily by debt / convertible debt 1. Expected financing and timing of payments may change due to capital markets conditions and other factors. 2. Company prepaid $80M, which reduced the gross liability by ~$82M due to the prepayment discount. Early payment made in Sept/Oct Planned prepayment using ASB and insurance proceeds To be funded by mix of capital

HEI at a Glance and how we got here Regulatory framework provides steady, predictable revenues, with rate rebasing underway Implementing industry leading wildfire mitigation efforts and reducing operating risk Strong balance sheet and liquidity with improving credit metrics 24 Topics of Focus 1 3 2 4 Executing through historic capital cycle5

Potential Financial Impacts of Rate Rebasing and Proposed PIMs—Illustrative Revenue Enhancement Opportunities1 25 1. The information on this slide is illustrative only and does not constitute guidance, a forecast, or a commitment or target of the Company. It shows hypothetical financial results that would occur if the Public Utilities Commission (PUC) approves, in full and as requested, the Company's pending and proposed rate rebasing and performance incentive mechanisms (PIMs). The PUC may approve, modify, delay, or deny these requests, and actual results could differ materially. 2. Substantially all holding company employees became Hawaiian Electric employees as of the third quarter 2026, and associated costs previously recorded at the holding company began being recorded at the utility. 3. Performance Incentive Mechanisms are being evaluated under Phase 6 of the PBR proceeding and subject to PUC approval. $ millions 2027 (rates effective 5/1/2027) Full 1st Year Run Rate Rate Rebasing Revenue (revenue impact) Scenarios Provided $83 $125 Utility Core ROE (includes impact of HEI integration costs of 30 basis- points2) 7.3% – 7.8% 8.3% – 8.8% Additional Potential Revenue Enhancements Potential Value Contribution from PIMs3 (if 50 basis-points were achieved) after tax $11 Contribution from PIMs3 (if 100 basis-points were achieved) after tax $22 Contribution from PIMs3 (if 150 basis-points were achieved) after tax $33 Penalty from PIMs3 (if 50 basis-points of penalties were assessed) after tax ($11)

26 Utility ROE—Our Strategy Sets Path to Improvement Illustrative scenario assuming full year impact of rate rebasing (excludes potential PIMs) Current Utility Core ROE Rate Rebasing ARA and Separately Recovered Revenues Taxes and Other Miscellaneous Items O&M, Depreciation, and Return on Rate Base HEI Integration Forecasted Full Year Run Rate ROE Rate Rebasing Request Targeted ARA and Separate Recovery Mechanisms • Company’s 5.3% base rate increase request supports critical investments needed to operate a safe, reliable and resilient system while recognizing the affordability challenges customers face in the current inflationary environment • Annual revenue increases cover inflationary pressures in our cost base and additional separately recovered revenues fund new wildfire, resilience, and generation assets. 1. Utility LTM Core ROE as of 9/30/2026 of 5.2% includes year-to-date storm cost impacts of approximately 60 basis-points and HEI integration costs of approximately 10 bps . Excluding only storm costs, utility Core ROE is ~5.8%. 3.0% 8.8% 5.8%1 1.0% 0.3% 0.5% - 1.0% 0.2% Taxes and Other Misc. Items • Primarily driven by additional tax expense from higher rebasing, ARA, and separately recovered revenues Targeted O&M, Depreciation, Return on Rate base • Operating within the annual revenue adjustment will be a key strategic priority through the second Multi-year Rate Period of PBR, helping company reach its allowed ROE HEI Integration • HEI costs transferred to the Utility in 3Q26 and management continues to focus on driving efficiencies throughout the integration process. 8.3%

$3,723 $3,845 $4,029 $4,213 $4,342 $4,452 $4,580 $4,739 $245 $254 $236 $325 $317 $701 $635 $1,021 $105 $172 $212 $3,968 $4,099 $4,265 $4,538 $4,659 $5,258 $5,387 $5,972 $0 $1,000 $2,000 $3,000 $4,000 $5,000 $6,000 $7,000 2024 Actual 2025 Actual 2026E 2027F 2028F 2029F 2030F 2031F Ra te B as e ($ m ill io ns ) Consolidated Year-End Rate Base Forecast ARA Capex Approved Separately Recovered Capex Pending / Not Yet Filed Separately Recovered Capex Rate Base Forecast1 27 1. Note: Figures are net of contributions in aid of construction (CIAC) and capital planned to be financed by securitization. 2026 – 2031 rate base includes separately recovered capex (through the EPRM, REIP, and MPIR mechanisms).

$236 $247 $400-$425 $375-$425 $375-$425 $375-$425 $375-$425 $375-$425 $32 $34 $230-$250 $200-$250 $350-$400 $325-$425 $225-$325 $225-$325 $791 $87 $70-$75 $347 $368 $700-$750 2024A 2025A 2026E 2027E 2028E 2029E 2030E 2031E ARA Recovery Safety, Reliability and Resilience Drive Capital Investment 28 ▪ Capex supports strategic objectives of reducing wildfire risk, increasing reliability and resilience and repowering firm generation ▪ Approval of securitization will shift wildfire spend and reduce the capital forecast Capital Expenditures Forecast ($ in millions) Separate Recovery Wildfire and Resilience Capex Note: Capital expenditure figures are net of contributions in aid of construction (CIAC). 1. $71 million of 2024 wildfire mitigation costs are classified as ARA recovery, but are included in this bar for comparison purposes Total Capex (incl. Securitization capex) $675-$800 Total Capex (excl. securitization capex) $575-$675 Total Capex (incl. Securitization capex) $775-$925 Total Capex (excl. securitization capex) $725-$825 $700-$850 $600-$750 $600-$750

29 Wildfire Mitigation Plan (WMP) Costs Approved Securitization Ensures Critical Work Done at Least Cost to Customers $270 $80 $350 Total WMP Costs Approved O&M Capital $18.5 $240.5 $82.7 $8.6 • EPRM approval ensures cost recovery, with securitization planned to minimize bill impact • Approved cost covers capital and O&M • Additional approval received for recovery of up to $11.5 million of 2025 WMP O&M2, and $3.9 million of annual ongoing WMP O&M in 2028+ • Affordability remains our focus, and planned securitization ensures customer affordability while allowing critical investments to continue Grid Hardening Operational Practices Situational Awareness Other1 $350M 1. Includes costs for wildfire risk analytics, strengthening stakeholder and community partnerships, and wildfire management and governance. 2. $11.5 million of estimated incremental 2025 O&M was approved by the PUC for deferral and subsequent recovery. The utility’s incremental 2025 O&M incurred was $9.6 million, which was recorded to a regulatory asset as of December 31, 2025. The utility will therefore recover the actual expenses incurred of $9.6 million.

Planned Resilience and New Generation Support Significant Grid Investment Opportunities 30 C o m pe tit iv e p ro cu re m en ts WMP im plem en ta tio n Foste rdis tr ib u te d gen er at io n In v estin m odern, resilientgrid Holistic planning to deliver safety, reliability, resilience, affordability ✓ Retiring aging power plants sooner by accelerating addition of modern firm generation ✓ Launching one of the largest competitive procurements in state history • ~1,650 GWh of variable renewable energy, 465 MW of grid forming resources, and 111 MW of firm generating capacity ✓ RFP for all fuels (liquids and gaseous) filed by the end of 2026 ✓ Continued progression of Stage 3 RFP projects (4 PPAs now approved, 7 pending) Significant grid investment required to accommodate generation additions Meet Growing Energy Needs and Modernize Generation Fleet ✓ $1.3 billion in investments through 2035 to build or expand interconnection points between renewable projects ✓ ~$60 million of investments in distribution upgrades over the next 10 years ✓ $190 million over the next 5-years for climate adaptation program1 Strengthen Grid for Resilience, Public Safety and Decarbonization 1. Supported by grant for $95 million in federal funds, officially awarded on August 7, 2024.

Appendix

Solid Liquidity and Improving Credit Metrics Support Strong Financial Position and Path Back to Investment Grade 32 ACTIONS FOLLOWING WILDFIRES HAVE ENSURED FINANCIAL STRENGTH S&P ADJUSTED FFO/DEBT1 ON POSITIVE TRAJECTORY 1. All adjusted FFO/debt figures are as of year-end, and as reported by S&P. CONTINUING TO TARGET INVESTMENT GRADE CREDIT METRICS WHILE FINANCING REMAINING SETTLEMENT PAYMENTS $522 $403 $243 $257 $463 $1,165 $1,153 $1,232 $910 $1,611 $1,572 $1,506 $1,339 $1,324 Quarter-end Liquidity ($ millions) HECO RCF HECO ABL HEI RCF HEI ATM Cash & cash equivalents 2Q 3Q 4Q 1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q 1Q 2Q 2023 2024 2025 2026 17.0 17.5 14.1 9.3 11.4 21.1 22.8 23.8 11.1 12.8 19.7 23.3 15.5 19.9 0.0 5.0 10.0 15.0 20.0 25.0 2021 2022 2023 2024 2025 S&P Adjusted FFO/Debt (%) HEI Consolidated HECO HECO (excl. settlement) HEI Consolidated (excl. settlement) 3Q

Maintaining Solid Liquidity and Financial Strength Through Transitional Year 33 • As of 9/30, the HoldCo and Utility had $48 million and $176 million of unrestricted cash on hand, respectively. $1.1 billion in additional liquidity is available from the ATM program ($250 million), utility accounts receivable-backed credit facility ($250 million) and corporate credit facility capacity ($600 million) – Strong liquidity positions company well in environment of significantly higher fuel costs – No meaningful increase in bad debt expense or net write offs despite impacts of higher fuel prices • Utility declared $11 million dividend to HEI for the third quarter LIQUIDITY UPDATE FINANCIAL POSITION REMAINS STRONG IN HIGH FUEL PRICE ENVIRONMENT $1.0 $0.7 $0.4 $0.7 $0.6 0.11% 0.13% 0.14% 0.14% 0.12% Q3 2025 Q4 2025 Q1 2026 Q2 2026 Q3 2026 Bad debt expense ($ millions) Net write off (%)

Utility LTM ROE 9.5% ROE (%) Non-recoverable items1 Allowed ROE 8.9% ROE less Structural Items Actual O&M, depreciation & return on rate base over recovery2 Actual Q3 LTM 2026 Core ROE Others, Net 5.2% GAAP TO NON-GAAP RECONCILIATION OF UTILITY LTM ROE6 ($ in millions) 9/30/2026 9/30/2025 12mo Simple Average 9/30/2026 GAAP Common Stock Equity $1,908.8 $1,548.6 $1,728.7 (less): GLST-13 - (287.3) (143.6) HEI equity infusion related to wildfire claims payment (470.2) - (235.1) Maui wildfires4 1,326.7 1,416.1 1,371.4 Core Simple Average Common Stock Equity 2,721.3 Non-GAAP (Core) Net Income $141.6 Core ROE5 5.2% 1. Includes incentive compensation, advertising and charitable contributions. 2. Includes 60 bps impact from total O&M storm-related costs (~$23.0 million pre-tax) based on preliminary estimates as of September 30, 2026 and are subject to change. Incremental costs that are expected to be deferred (to be followed by a subsequent request for recovery) is estimated to range between approximately 75%-85% of the total O&M storm-related costs, which is currently estimated at approximately $19.3 million. 3. Equity interest of GLST-1 was assigned by HEI on June 30, 2025 and adjusted down to nil after the first installment payment was made in the second quarter of 2026. 4. Life-to-date Maui wildfire related expenses, net of insurance recoveries and approved deferral treatment. 5. Non-GAAP (Core) Net Income / Core Simple Average Common Stock Equity. 6. Columns may not foot due to rounding. 34 9.5% (0.6%) 8.9% (2.9%) (0.8%) 5.2% Includes approximately (60) bps impact from storm costs2

3Q 2026 Financial Performance & Highlights 35 GAAP Results Include Wildfire and Pacific Current Expenses1 Utility Holding Co. & Other 3Q 2026 Earnings EPS Net Income (GAAP) $35.5M $0.20 excl.: Maui wildfire-related expenses $14.0M $0.08 excl.: Gain on sale of investment and net unrealized gain on investments ($64.1M) ($0.37) excl.: Loss from Pacific Current asset impairments $37.7M $0.22 Core $23.0M $0.13 HEI Consolidated Year-on-Year Variance—Core Net Income2 ($ in millions) $0.23 $0.16 ($0.04) ($0.03) $0.19 $0.13 2025 2026 1. Columns may not foot due to rounding. 2. See appendix for reconciliation of “Core” metrics to the equivalent GAAP metric. 3. Includes reduction of costs due to HEI integration cost transferred to the utility of $4.2M (After-tax), net of lower interest income due to 1st installment payment. 4. Includes ARA revenues, PIMS and impact from worse heat rate performance. 5. Return to Provision adjustment, net of Uncertain Tax Provision. 6. “Other” consists primarily of higher depreciation, partially offset by AFUDC. 7. Includes higher storm response and IMT costs of $11.6M (After-tax), HEI integration costs of $4.2M (After-tax), and higher other O&M, partially offset by lower WMP costs. 8. Includes higher interest expense of $3.4M, net of $0.1M in investment interest income $32.8 $23.0 $2.2 $7.0 $2.0 $0.5 $16.8 $3.3 $1.4 Q3 2025 Other segment loss Revenues Tax Adjustments Other O&M Interest expense Fossil fuel cost risk share adj Q3 2026 3 5 3Q Core EPS1 85 73

3Q Adjusted O&M Excluding Pension (non-GAAP)1 1. Includes other post-employment benefits and excludes pension nonservice retirement benefits. 2. Columns may not foot due to rounding. 36 $139.8 $158.9 3Q25 3Q26 GAAP TO NON-GAAP RECONCILIATION OF O&M, NET OF EXCLUSIONS2 3Q 2025 3Q 2026 GAAP O&M $161.8 $181.6 (less): Pension1 12.6 11.3 Covered by surcharges 5.9 5.4 Covered by third parties 3.5 6.0 Adjusted O&M $139.8 $158.9 $ in millions

YTD Adjusted O&M Excluding Pension (non-GAAP)1 1. Includes other post-employment benefits and excludes pension nonservice retirement benefits. 2. Columns may not foot due to rounding. 37 $398.1 $441.8 YTD3Q25 YTD3Q26 GAAP TO NON-GAAP RECONCILIATION OF O&M, NET OF EXCLUSIONS2 YTD 3Q 2025 YTD 3Q 2026 GAAP O&M $463.1 $510.5 (less): Pension1 36.9 34.5 Covered by surcharges 16.6 16.0 Covered by third parties 11.4 18.2 Adjusted O&M $398.1 $441.8 $ in millions

Hawaiian Electric Crews Responded Rapidly Despite Hurricane Lala’s Severity 38 • Hawaiian Electric crews responded rapidly • Although outages, at their peak, impacted over 40% of customer accounts across the utility’s service territories, utility crews made rapid progress restoring service, with more than 95% of affected customers restored by August 19 • Hawaiian Electric is strengthening the grid while repairing damage • As storm-damaged power lines are replaced, the utility is strengthening the electric system where possible • In high wildfire risk areas, copper wire is being replaced with aluminum wire during restoration and repair work • O&M impact from Hurricane Lala estimated at ~$14 million1. Lala O&M, along with O&M from other storms in the third quarter and the Kona Low storms earlier in the year, totals approximately $23 million1 • Approximately $19 million1 of the total storm O&M is estimated as incremental and potentially eligible for recovery • The Company filed an application on October 21, 2026 requesting deferral accounting treatment for qualifying incremental storm costs, and expects to seek recovery separately once costs are finalized. 41.6% 24.7% 7.8% 4.1% 2.8% 1.4% 0 20 40 60 80 100 120 140 1.0 2.0 3.0 4.0 5.0 6.0 HECO - Oahu HELCO - Hawaii Island MECO - Maui County % of statewide customers affected 16-Aug 17-Aug 18-Aug 19-Aug 20-Aug 23-Aug Efforts of Hawaiian Electric crews resulted in accelerated restoration despite severe damage C u s to m e rs i m p a c te d • Hurricane Lala caused extensive statewide damage as it passed through the southern portion of the island chain August 14 – 16 • Severity of damage resulted in Presidential emergency declaration signed August 25 1. The amounts presented reflect management's estimates as of September 30, 2026 based on information currently available. Actual total costs may differ materially from these estimates and such estimates do not factor in potential insurance coverage. Whether, and to what extent, the Company defers storm costs as a regulatory asset and ultimately recovers from customers depends on a review and approval by the PUC. The Company can give no assurance that recovery will be authorized, or that it will be authorized in the amounts, on the timeline, or on the terms requested. A disallowance or delay could have a material adverse effect on the Company's financial condition, results of operations, and cash flows.

Long-term Debt Maturities (as of 9/30/26) 39 11 5 77 5 24 34 44 28 13 0 0 - - - - - - - - - - - - - - 7 7 - - - - 100 68 35 150 - 100 608 50 - - 140 150 45 150 70 80 40 50 15 80 120 - - 20 $0 $100 $200 $300 $400 $500 $600 $700 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046 2047 2048 2049 2050 2051 2052 2053 2054 2055 M a tu ri n g A m o u n t ($ ) Debt Maturity Schedule by Entity ($ in millions) HEI HECO (HECO + HELCO + MECO) Includes $500M HY debt maturity 1 1. Includes ~$49 million of Mahipapa (previously classified as held for sale)

Note: Capital expenditure figures are net of contributions in aid of construction (CIAC). 1. Key projects listed may not sum to capex range shown on bar chart due to rounding. 2. Separate recovery /securitization applies to capex after Jan 1, 2025 and to expense after May 1,2025. 3. 2024 Wildfire Mitigation Costs are classified as ARA recovery, but are included in this line for comparison purposes. 4. $30.3M in forecasted capex spend for 2026, net of forecasted IIJA reimbursement of $34.5 million. Safety, Reliability and Resilience Drive Capital Investment 40 Capital Expenditures Forecast Detail ($ in millions) Status Key Capex Projects 1 2024 Actual 2025 Actual 2026 Forecast 2027 Forecast 2028 Forecast 2029 Forecast 2030 Forecast 2031 Forecast Recovery Mechanism Approved Waiau Repower $1 $143 $149 $242 $223 $96 $119 EPRM/Securitization Wildfire Mitigation Plan (WMP) Program 2 $71 3 $64 $76 $92 $70 $64 $64 $64 EPRM/Securitization WSS Securitization Reimbursement ($92) ($67) ($24) ($19) Securitization Grid Modernization Phase 1 $12 MPIR Resilience Program $8 $23 ($4) 4 $30 $13 $6 EPRM Army Privatization $9 $11 $26 $50 $73 $39 $22 $18 Contractual Waena BESS + PV Project $6 $13 $88 $13 EPRM 100% CIAC / Other $5 $9 ($6) ($18) $32 $33 $45 $29 EPRM/REIP/Other Sub-Total $111 $121 $323 $224 $363 $341 $208 $230 Awaiting PUC approval or to be filed Grid Modernization Phase 2 (GMS2) $11 $29 $25 $25 $17 EPRM/Securitization GMS2 Securitization Reimbursement ($11) ($29) Securitization EV Expansion Programs $2 $3 $5 $6 EPRM Other Separately Recovered Major Projects $4 $17 $47 $74 $55 EPRM/REIP/Other Sub- Total $4 $19 $75 $104 $78 ARA recovery Baseline Capex $236 $247 $400-$425 $375-$425 $375-$425 $375-$425 $375-$425 $375-$425 ARA Total Capex - excl. Securitization Capex $347 $368 $700-$750 ~$575-$675 ~$725-$825 ~$700-$850 ~$600-$750 ~$600-$750 Total Capex - incl. Securitization Capex ~$675-$800 ~$775-$925

Fossil Fuel Cost Risk Sharing • Symmetrical mechanism • Variations in fossil fuel price above or below baseline shared 98% customers / 2% utility • Applies to utility fossil fuel generation (not IPP generation or non-fossil fuels), includes fuel efficiency impacts • Baseline price: January fuel prices for each fossil fuel type 41 Hawaiian Electric (Oahu) Hawaii Electric Light (Hawaii Island) Maui Electric (Maui County) Annual upside / downside cap +/-$2.5 million +/-$600,000 +/-$633,000 January 2026 fuel price ($ per bbl) Low Sulfur Fuel Oil (LSFO) $94.82 Intermediate Fuel Oil (IFO) $79.93 $76.76 Diesel $107.72 $110.35 $111.18

Status of Key Open Dockets 42 Subject and Description Docket # Latest Developments Next Milestone Performance-Based Regulation Proceeding to evolve regulatory framework to better align with customer interests and state clean energy policy 2018-0088 Beginning in 2024, this docket has focused on (a) whether - and if so, by what process - the utility’s rates should be rebased before the beginning of the next PBR multiyear rate period to commence in 2027 (“MRP2”), and (b) whether modifications to the PBR Framework were warranted for MRP2. On 2/27/2025, the PUC issued an order establishing that the utility may rebase rates with a 2026 test year consolidated rate case type proceeding. On 8/13/2025, the PUC issued an order providing process guidance for development of proposed PBR Framework modifications (PBR proceeding “Phase 6”), including potential party-proposed changes to the Annual Revenue Adjustment (“ARA” mechanism, EPRM mechanism and the PIMs portfolio). On 8/28/2025, the utility filed a request to extend the time to file a rate case to allow collaboration among the PBR Working Group parties on an alternative rate rebasing proposal that could eliminate the need for a general rate case application and process. The PUC approved the request on 9/29/25 and noted that if the parties were unsuccessful in developing an alternative rebasing proposal, or if such a proposal were submitted and rejected by the PUC, the utility can file a 2027 test year rate case type proceeding in the second half of 2026. The PUC also noted that, depending on outcome of the alternative rate rebasing process, the PUC may defer the start of MRP2 beyond January 2027. On 3/6/2026, the utility filed an alternative rebasing proposal jointly with PBR Working Group party Ulupono Initiative. The rebasing request proposed an increase in revenues of $170 million, which represents a consolidated increase of 5.3% compared to total operating revenues at current effective rates. In an order issued on 6/15/2026, the PUC directed the utility to re-submit its request for an increase in its revenue requirement, with supporting materials, in the form of a new application, and established a tentative procedural schedule for the new proceeding. On 6/25/2026, the utility’s filed a motion for reconsideration of the PUC’s 6/15/2026 order regarding the rejection of the utility’s reservation of rights provision and the procedural schedule established in the order. On 10/23/26, the PUC issued an order that introduced a proposal prepared by PUC staff, which identified possible modifications of certain PBR mechanisms in preparation for MRP2 (Staff Proposal). The PUC stated that the Staff Proposal is intended to be a starting point for discussion among the PBR Parties, which may result in further modification(s) of mechanisms or development of entirely different mechanism structures. To facilitate an open discussion, the PUC instructed the PBR Parties to file initial comments regarding the Staff Proposal by November 13, 2026. Order from the PUC addressing the utility’s motion for reconsideration of the PUC’s 6/15/2026 order. Phase 6 of the PBR proceeding is in process and will vet and fully develop modifications to the PBR Framework for MRP2. Following consideration of the PBR Parties’ replies on the Staff Proposal, the PUC anticipates issuing an order by early January 2027, outlining its inclinations on some or all of the PBR mechanisms discussed in the Staff Proposal to provide guidance regarding the PUC’s priorities for the remainder of these proceedings. The PUC then plans to host a workshop with the PBR Parties, followed by Parties filing statements of position, a discovery period, a second workshop, an evidentiary hearing, and a briefing period. The dates for these procedural steps will be determined by the PUC. Alternative Rebasing 2026-0162 In accordance with the PUC’s order in Docket No. 2018-0088, the utility filed its application for approval of its rebasing proposal on 7/17/2026. The PUC held public hearings regarding the utility’s application on the islands of O‘ahu, Maui, Lānaʻi, Molokaʻi, and Hawai‘i Island in late September through early November. Awaiting a procedural schedule from the PUC for review of the utility’s application for approval of its rebasing proposal.

Status of Key Open Dockets, Continued 43 Subject and Description Docket # Latest Developments Next Milestone Stage 3 RFP Hawaii Island seeks up to 325 GWh of energy annually and up to 65 MW of capacity. Oahu seeks at least 965 GWh of energy annually and 500-700 MW of firm capacity. Maui seeks at least 425 GWh of energy annually and at least 40 MW of firm capacity. 2017-0352 Stage 3 RFP On 12/30/2024, PPA were executed for AES’s Keamuku (86 MW PV and 86 MW / 344 MWh BESS on Hawaii Island) and Kuihelani Phase 2 (40 MW PV and 40 MW / 160 MWh BESS on Maui) projects. On 3/25/2025 a PPA was executed for Ameresco’s Puuloa Solar project (6 MW / 30 MWh BESS on Oahu). Applications for PUC approval were filed for all three projects; however, the PUC dismissed all three without prejudice pending resubmission upon completion of the IRS. Kuihelani Phase 2 was re-filed on 12/23/2025, and Puuloa Solar was re-filed on 12/19/2025. On 11/24/2025, a PPA was executed for Mahi Solar (40 MW / 120 MWh BESS on Oahu) and an application for PUC approval was filed on 11/26/2025. On 9/22/2025 a PPA was executed for Ameresco’s Ukiu Energy project (40 MW firm generation facility on Maui) and an application for PUC approval was filed on 9/26/2025. On 11/12/2025, the PUC suspended the docket and instructed the utility to detail the project’s compliance with the Hawaii Environmental Policy Act and demonstrate that environmental review for the project is not required by HRS Chapter 343-5. On 3/11/2026, the utility filed its Amended and Restated (A&R) PPA executed by the utility and Ukiu Energy LLC and other matters relating to the 40 MW firm dispatchable capacity and energy. On 3/25/2026, the PUC issued an order that lifted the suspension of this docket. On 5/21/2026, an A&R PPA for Keamuku was executed and an application for PUC approval was filed on 5/29/2026. On 5/21/2026, an A&R PPA for Kaheawa Wind Power (30 MW wind) was also executed and an application for PUC approval was filed on 5/29/2026. On 5/26/2026, 6/16/2026, and 6/24/2026, the PUC approved the PPAs with Mahi Solar, Puuloa Solar, and Kuihelani Phase 2, respectively. Additionally, on 8/31/2026, an application for PUC approval for an A&R PPA with Kalaeloa Partners, L.P. was filed, which is a 208 MW of firm capacity on Oahu and is the largest PPA under the Stage 3 RFP. On 9/30/2026, a PPA for Pulehu Solar (20 MW / 80 MWh BESS on Maui) was executed and an application for PUC approval was filed on 10/5/2026, The Companies continue to advance the remaining selected projects through negotiations and execution and the PUC approval process. Stage 3 RFP Contract negotiations ongoing; PUC approvals pending.

44 Subject and Description Docket # Latest Developments Next Milestone 2025-2027 Wildfire Mitigation Plan (2025-2027 WMP) 2025-0156 On 12/31/2025, the PUC issued Decision and Order No. 42228, which (1) approves the utility’s WMP, (2) provides instructions for updating the WMP for 2026-2027, and (3) establishes Areas for Continued Improvement that the utility is required to meet for its 2026-2027 WMP update and next iteration of its WMP for 2028-2029. On 4/13/2026, the utility filed the 2026-2027 WMP Update. On 6/15/2026, the PUC issued an order regarding the updated Procedural Schedules that shall govern the review of utility’s: (1) Compliance with year 2025 of its WMP; and (2) 2026-2027 WMP Update. On 7/31/2026, the PUC issued an order which establishes a fourth track to evaluate Updated Guidelines for Hawaiian Electric’s future WMPs, starting with the 2028-2029 WMP. On 9/1/2026, the Consumer Advocate filed its Statement of Position on the Companies’ 2026-2027 WMP Update (Track 2). The Consumer Advocate recommends that the Commission approve the 2026-2027 WMP Update, subject certain recommendations. On 9/9/2026, the Company, the Consumer Advocate, and Life of the Land filed their respective Statements of Position regarding Track 4 WMP Guidelines. On 9/15/2026, the Company filed its Reply Statement of Position regarding the WMP 2026-2027 Update (Track 2). On 9/24/2026, the Commission issued an order to revise the Track 3 (2025 WMP Compliance) Procedural Schedule. The Commission notes that sequencing the remaining Track 3 milestones after the Track 2 and Track 4 milestones allows the Commission to complete its review of the Company’s information request responses and any subject matter expert interviews before issuing the Preliminary Compliance Assessment, and preserves the time provided for the Parties and LOL to consider that assessment in their Statements of Position. On 10/12/2026, the Company and the Consumer Advocate filed their respective Reply Statements of Position regarding Track 4 WMP Guidelines. Track 2 (WMP 2026-2027 Update)- Pending PUC Order Track 3 (2025 WMP Compliance)- PUC 2025 WMP Compliance Assessment extended to Nov 20. Consumer Advocate and LOL Statement of Positions are due Dec 7. HECO Reply Statement of Position due Dec 22. Track 4 (WMP 2028-2029 Guidelines)- Pending PUC Order Status of Key Open Dockets, Continued

45 Subject and Description Docket # Latest Developments Next Milestone 2026-2027 WMP Update Exceptional Project Recovery Mechanism (EPRM) 2026-0221 On 10/1/26, the utility filed an application requesting approval to recover, through the EPRM, $30.5 million in incremental O&M expenses from 2027- 2029 and $4.8 million annually thereafter (plus 3% escalation), necessary to implement the Areas for Continued Improvement (ACIs) that the PUC directed be incorporated into the 2026-2027 WMP Update. The utility intends to not effectuate cost recovery for any approved costs through the EPRM until the PUC has issued an order addressing the utility’s application for a financing order pursuant to HRS §269G-2. Awaiting a procedural schedule from the PUC for review of the utility’s application Securitization Financing 2026-0235 On 10/9/26, pursuant to HRS Chapter 269G, the utility filed an application requesting PUC approval of a financing order authorizing the issuance of bonds to finance infrastructure resilience costs. The utility seeks to finance through securitization approximately up to $350 million for the 2025-2027 WMP, $31 million for the 2026-2027 WMP Update, additional costs for the 2028-2029 WMP, $121 million for Grid Modernization Phase 2, and upfront financing costs, limited to project costs that are incurred first in accordance with HRS § 269G-2(b)(2). Awaiting a procedural schedule from the PUC for review of the utility’s application Storm Deferral 2026-0245 On 10/21/26, the utility filed an application to defer storm restoration costs. The utility requested to approve deferred accounting treatment for costs incurred in connection with the utility’s response and restoration efforts arising from (1) the Kona Low Storms and (2) a separate extraordinary period of tropical cyclone activity in the fall of 2026 that included Hurricanes Lala, Lowell, Nolo. The requested deferral period would extend through December 31, 2026. The utility requested PUC approval by December 15, 2026. Awaiting a procedural schedule from the PUC for review of the utility’s application Integrated Grid Planning-Second Cycle (IGP) Next phase of long-range planning, combining planning and procurement of traditional and non-traditional resources 2026-0001 On 1/2/2026, the PUC issued an order to open the second cycle of IGP. By 1/31/2026, the PUC ordered the utility to file (1) a Second Cycle Workplan in this docket, and (2) an initial inputs-and-assumptions package. On 3/2/2026, the utility filed its Second Cycle Workplan and initial inputs-and-assumptions package for PUC and stakeholder review. On 6/30/2026, the utility filed its IGP Action Plan Annual Update. On 7/17/2026 the utility requested that the PUC open a new proceeding to review and approve an RFP for ~500 MW of fuel flexible firm generation on Oʻahu, to be administered concurrently with the utility’s IGP RFP. On 8/5/2026 the PUC responded, informing the utility that a demonstration of need must be made before advancing a procurement of this size. On 9/15/2026, the Companies submitted the IGP Second Cycle Inputs and Assumptions and Grid Needs Assessment Methodology for Commission and stakeholder review. On 9/28/2026, Life of the Land filed a motion to establish a dedicated storm-hardening and multi-hazard resilience track in IGP Phase 2. On 9/28/2026, the Company filed a Memorandum in Opposition to Life of the Land’s motion. TBD Status of Key Open Dockets, Continued

How Do Separate Recovery Mechanisms Work? • EPRM: Provide specific revenue requirements for each project. Revenues are accrued with minimal lag, starting the first day of the month following project completion ‒ Total revenue requirement (RR) for each project consists of a capital revenue requirement and an expense revenue requirement ‒ RR = O+T+D+r(RB); Operating expenses + taxes + depreciation + return on rate base • Pilot Projects: Intended to foster innovation by establishing an expedited implementation process for pilots that test new technologies, programs and business models. The utility can submit specific proposals and the PUC will target issuing a decision within 45 days, otherwise the proposal is considered approved as submitted ‒ Allows utility to defer and recover total annual expenditures, subject to an annual cap of $10M, over twelve months 46

PBR Timeline – Key Annual Dates and Reports 47 *Utility’s annual Pilot Update and annual PIM/SSM Performance Review due by March 31. Report Filing date Key content relevant to projecting utility’s financials Fall Revenue Report (Preliminary) October 31 Target revenues including: • RBA Balance as of September 30, effective January 1 of the following year • ARA for 2027 using GDPPI projections (October Blue Chip) • Any actual and known revenue adjustments (not estimates) January 1 Effective date of approved target revenues MPIR/EPRM, PIM & Pilot Project Update February 28* • Schedules/workpapers for all known attained PIMs/SSMs & MPIR/EPRM revenue adjustments • Pilot Project Update report Spring Revenue Report (Comprehensive) March 31 • Actual PIM performance from previous year • MPIR/EPRM adjustments • ESM adjustments • Any approved Z-factor costs • Any approved Pilot Project costs June 1 Effective date of approved target revenues including adjustments from the Spring Revenue Report

Cautionary Note Regarding Forward Looking Statements This report and other presentations made by Hawaiian Electric Industries, Inc. (HEI) and Hawaiian Electric Company, Inc. (Hawaiian Electric) and their subsidiaries contain “forward-looking statements,” which include statements that are predictive in nature, depend upon or refer to future events or conditions and usually include words such as “will,” “expects,” “anticipates,” “intends,” “plans,” “believes,” “predicts,” “estimates” or similar expressions. In addition, any statements concerning future financial performance, ongoing business strategies or prospects or possible future actions are also forward-looking statements. Forward-looking statements are based on current expectations and projections about future events and are subject to risks, uncertainties and the accuracy of assumptions concerning HEI and its subsidiaries (collectively, the Company), the performance of the industries in which they do business and economic, political and market factors, among other things. These forward-looking statements are not guarantees of future performance and actual results and financial condition may differ materially from those indicated in the forward-looking statements. • Risks, uncertainties and other important factors that could cause actual results to differ materially from those described in forward-looking statements and from historical results include, but are not limited to, the following: • the potential for further trade policy changes under the current administration could disrupt our supply chains and increase costs, e.g., the Utilities’ capital goods and equipment purchases and those of its independent power producers (IPPs) that contain components, sub-components, or raw materials sources from outside the U.S. could experience increases in costs, which could threaten the viability of projects and impact our ability to meet customer demand and the Utilities’ ability to achieve renewable portfolio standards (RPS) goals; • the impact of the Maui windstorm and wildfires, including potential liabilities in excess of settlement amounts and potential regulatory penalties, which may result in significant costs that may be unrecoverable (or not reimbursed on a timely basis) through insurance and/or rates; • an increase in insurance premiums and the inability to fully recover premiums through rates or the potential inability to obtain wildfire and general liability insurance coverage at reasonable rates, if available at all; • the ability to raise the amount of capital necessary on reasonable terms, if at all, for the Company’s and the Utilities’ contribution to the Maui wildfire tort litigation settlement in order to alleviate future conditions that may cause substantial doubt about HEI’s and the Utilities’ ability to continue as a going concern; • potential further dilution to existing shareholders if the Company raises funds by issuing additional equity or equity-linked securities; • the inability to execute financing plans to alleviate future conditions that may cause substantial doubt about HEI’s and the Utilities’ ability to continue as a going concern prior to the issuance of their respective annual financial statements, which could result in an event of default and an acceleration of the Company’s and the Utilities’ debt and lead to filing for bankruptcy protection if waivers from lenders are not received; • extreme weather events, including windstorms and other natural disasters, particularly those driven or exacerbated by evolving climate dynamics, which could increase the risk of the Utilities’ equipment being damaged, becoming inoperable or contributing to a wildfire; • future suspension, material reduction or extended delay in dividends or other distributions from operating subsidiaries to HEI; • further downgrades by credit rating agencies in their ratings of the securities of HEI and Hawaiian Electric and their impact on results of financing efforts; • the risks of suffering losses and incurring liabilities that are uninsured (e.g., damages to the Utilities’ transmission and distribution system and losses from business interruption) or underinsured (e.g., losses not covered as a result of insurance deductibles or other exclusions or exceeding policy limits), and the risks associated with the operation of transmission and distribution assets and power generation facilities, including public and employee safety issues, and assets causing or contributing to wildfires; • international, national and local economic and political conditions—including the state of the Hawaii tourism, defense and construction industries; the strength or weakness of the Hawaii and continental U.S. real estate markets; decisions concerning the extent of the presence of the federal government and military in Hawaii; the implications and potential impacts of federal government shutdowns, including the impact to the Utilities’ customers’ ability to pay their electric bills and the impact on the State of Hawaii economy; the implications and potential impacts of U.S. and foreign capital and credit market conditions and federal, state and international responses to those conditions; the potential impacts of global and local developments (including global economic conditions and uncertainties, unrest, terrorist acts, wars, conflicts, political protests, deadly virus epidemic or other crisis); the effects of changes that have or may occur in U.S. policy, such as with respect to immigration and trade; and pandemics; • the ability to adequately address risks and capitalize on opportunities related to the Company’s and the Utilities’ sustainab ility priority areas, which include safety, reliability and resilience, including relating to wildfires and other extreme weather events, decarbonization, economic health and affordability, secure digitalization, human capital management, employee engagement, and climate-related risks and opportunities; • citizen activism, including civil unrest, especially in times of severe economic depression and heightened social and political divisions, which could negatively impact customers and employees, impair the ability of the Company and the Utilities to operate and maintain their facilities in an effective and safe manner, and citizen or stakeholder activism that could delay the construction, increase project costs or preclude the completion of third-party or Utility projects that are required to meet electricity demand, resilience and reliability objectives and RPS and other climate-related goals; • the effects of actions or inaction of the U.S. government or related agencies, including those related to the U.S. debt ceiling or budget funding, monetary policy, trade policy, energy and environmental policy, and other policy and regulatory changes advanced or proposed by the current administration; 48

Cautionary Note Regarding Forward Looking Statements continued • weather, natural disasters (e.g., hurricanes, earthquakes, tsunamis, lightning strikes, lava flows and the effects of evolving climate dynamics, such as more severe storms, flooding, droughts, heat waves, and rising sea levels) and wildfires, including their impact on the resilience and reliability and cost of the Company’s and Util ities’ operations, and the economy; • the timing, speed and extent of changes in interest rates and the shape of the yield curve, which could result in higher borrowing costs and changes in market liquidity; • the continued ability of the Company and the Utilities to access the credit and capital markets to fund necessary investments and expenditures (e.g., to obtain short-term and long-term debt financing, including lines of credit, and, in the case of HEI, to issue common stock) under volatile and challenging market conditions, and the potential higher cost of such financings, if available, and due to the uncertainties associated with the costs related to the Maui windstorm and wildfires; • the risks inherent in changes in the value of the Company’s pension and other retirement plan assets, and the risks inherent in changes in the value of the Company’s pension liabilities, including changes driven by stock market values, interest rates and mortality improvements; • changes in laws, regulations (including tax regulations), market conditions, interest rates and other factors that result in changes in assumptions used to calculate retirement benefits costs and funding requirements; • the potential delay by the Public Utilities Commission of the State of Hawaii (PUC) in considering (and potential disapproval of actual or proposed) proposals related to rate rebasing, performance-based regulation (PBR), wildfire safety, renewable energy or grid resiliency, among others, and related costs; reliance by the Util ities on outside parties such as the State, IPPs and developers; supply-chain challenges; and uncertainties surrounding technologies, solar power, wind power, biofuels, liquefied natural gas, environmental assessments required to meet RPS and other climate-related goals; the impacts of implementation of the wildfire mitigation, renewable energy and resilience proposals on future costs of electricity and potential penalties imposed by the PUC for delays in the commercial operations of renewable energy projects; • the ability of the Utilities to develop, execute and recover the implementation costs of the Utilities’ action plans included in their Integrated Grid Plan, which was accepted by the PUC in 2024, due to the recent issuance of the PUC’s 2024 Inclinations on the Future of Energy in Hawaii, Governor Josh Green’s Executive Order No. 25-01, Accelerating Hawaii’s Transition Toward 100 Percent Renewable Energy, and the Hawaii State Energy Office’s Alternative Fuel, Repowering and Energy Transition Study on the aforementioned plans of the Util ities; • the ability of the Utilities to recover undepreciated cost of fossil fuel generating units, if they are required to be retired before the end of their expected useful life; • capacity and supply constraints or difficulties, especially if generating units (utility-owned or IPP-owned) fail or measures such as demand-side management, distributed generation, combined heat and power or other firm capacity supply-side resources fall short of achieving their forecasted benefits or are otherwise insufficient to reduce or meet peak demand; • high and/or volatile fuel prices, which increases working capital requirements and customer bills, or delivery of adequate fuel by suppliers (including as a result of the Iran war, Russia-Ukraine war and conflicts in the Middle East), which could affect the reliability of utility operations, and the continued availability to the Utilities of their Energy Cost Recovery Clauses (ECRCs); • the continued availability to the Utilities or modifications of other cost recovery mechanisms, including the Purchased Power Adjustment Clauses (PPACs), annual revenue adjustment (ARA) and pension and postretirement benefits other than pensions (OPEB) tracking mechanisms, and the continued decoupling of revenues from sales to mitigate the effects of declining kilowatt-hour sales; • the ability of the Utilities to recover increasing or additional costs (e.g., due to trade policies imposed by the current administration, tariffs, inflation, or other factors impacting prices) and earn a reasonable return on capital investments not covered by the ARA, while providing the customer dividend required by PBR; • the impact from the PUC’s modification of the PBR for the Utilities pursuant to Act 005, Session Laws 2018, including the potential changes to existing and/or addition of new Performance Incentive Mechanisms (PIMs), third-party proposals adopted by the PUC, and the implications of not achieving performance incentive goals; • the impact of fuel price levels and volatility on customer satisfaction and political and regulatory support for the Utilities; • unfavorable changes in economic conditions, such as sustained inflation, higher interest rates or recession, that negatively impact the ability of the Company’s customers to pay their utility bills and increase operating costs of the Utilities that cannot be passed on to, or recovered, from customers; • the risks associated with increasing reliance on renewable energy, including the availability and cost of non-fossil fuel supplies for renewable energy generation and the operational impacts and related cost impacts of adding intermittent sources of renewable energy to the electric grid; • the growing risk that energy production from renewable generating resources may be curtailed and the interconnection of additional resources will be constrained as more generating resources are added to the Utilities’ electric systems and as customers reduce their energy usage; • the ability of IPPs to deliver the firm capacity anticipated in their power purchase agreements (PPAs); • the potential that, as IPP contracts near the end of their terms, there may be less economic incentive for the IPPs to make investments in their units to ensure the availability of their units; • the ability of the Utilities to negotiate, periodically, favorable agreements for significant resources such as fuel supply contracts and collective bargaining agreements and avoid or mitigate labor disputes and work stoppages; 49

Cautionary Note Regarding Forward Looking Statements continued • new technological developments that could affect the operations and prospects of the Utilities or their competitors such as the commercial development of energy storage and microgrids; • the potential that cyber or physical security incidents, including potential incidents at HEI, its subsidiaries (including at electric utility plants), third-party service providers, contractors and customers with whom they have shared data (IPPs, distributed energy resources aggregators and customers enrolled under distributed energy resources programs) and incidents at data processing centers used, to the extent not prevented by physical and cybersecurity protections, could result in operational disruption; the misappropriation or loss of confidential or proprietary assets, information or data, including customer, employee, financial, or operating system information, or intellectual property; corruption of data; or potential costs, lost revenues, litigation, or reputational harm; • failure to achieve remaining cost savings commitment related to the management audit recommendations of $6.6 million per year during the multi-year rate period (MRP) from June 2021 to May 2026, and continuing until the second MRP begins; • federal, state, county and international governmental and regulatory actions, such as existing, new and changes in laws, rules and regulations applicable to HEI and the Utilities (including changes in taxation and tax rates, increases in capital requirements, regulatory policy changes, environmental laws and regulations (including result ing compliance costs and risks of fines and penalties and/or liabilities), the regulation of greenhouse gas emissions, governmental fees and assessments, and potential carbon pricing or “cap and trade” legislation that may fundamentally alter costs to produce electricity and accelerate the move to renewable generation); • the impact from the PUC’s implementation of wheeling for the Utilities, including cost shifting and customer equity considerations, the potential increased competition, and other legal and technical implications, pursuant to Act 266, which authorizes wheeling of renewable energy and requires the PUC to establish associated policies and procedures; • the impact of competitive pressures from third-party alternative generation resources and regulatory changes affecting the Company’s utility franchise may negatively impact its growth prospects, market position, and stock price; • developments in laws, regulations and policies governing protections for historic, archaeological and cultural sites, and plant and animal species and habitats, as well as developments in the implementation and enforcement of such laws, regulations and policies; • discovery of conditions that may be attributable to historical chemical releases, including any necessary investigation and remediation, and any associated enforcement, litigation or regulatory oversight; • decisions by the PUC in rate cases and other proceedings (including the risks of delays in the timing of decisions, adverse changes in final decisions from interim decisions and the disallowance of project costs as a result of adverse regulatory audit reports or otherwise); • decisions by the PUC and by other agencies and courts on land use, environmental and other permitting issues (such as required corrective actions, restrictions and penalties that may arise, such as with respect to environmental conditions or RPS); • the risks associated with the geographic concentration of HEI’s businesses; • changes in accounting principles applicable to HEI and its subsidiaries, including the adoption of new U.S. accounting standards, the potential discontinuance of regulatory accounting related to PBR or other regulatory changes, the effects of potentially required consolidation of variable interest entities (VIEs), or required finance lease or on-balance-sheet operating lease accounting for PPAs with IPPs; • the final outcome of tax positions taken by HEI and its subsidiaries; • the ability to effectively utilize federal and state net operating loss carryforwards; • the Company’s reliance on third parties and the risk of their non-performance; and • other risks or uncertainties described elsewhere in this report (e.g., Item 1A. Risk Factors) and in other reports previously and subsequently filed by HEI and/or Hawaiian Electric with the Securities and Exchange Commission (SEC). Forward-looking statements speak only as of the date of the report, presentation or filing in which they are made. Except to the extent required by the federal securities laws, HEI, Hawaiian Electric, Pacific Current and their subsidiaries undertake no obligation to publicly update or revise any forward-looking statements, whether written or oral and whether as a result of new information, future events or otherwise. 50

51 Explanation of HEI’s Use of Certain Unaudited Non-GAAP Measures HEI management uses certain non-GAAP measures to evaluate the performance of HEI. Management believes these non-GAAP measures provide useful information and are a better indicator of the companies’ core operating activities. Core earnings and other financial measures as presented here may not be comparable to similarly titled measures used by other companies, and they should be considered in addition to, and not as a substitute for, results prepared in accordance with GAAP. The accompanying tables provide a reconciliation of reported GAAP earnings to non-GAAP Core earnings. The reconciling adjustments from GAAP earnings to Core earnings are limited to the items related to the Maui wildfires, including the settlement remeasurement and accretion, impacts from HEI’s ownership stake in American Savings Bank, including realized and unrealized gains, and costs related to HEI’s exit from Pacific Current operating businesses. Management does not consider these items to be representative of the company’s fundamental Core earnings.

52 Reconciliation of GAAP to Non-GAAP Measures—HEI 1 Accounting principles generally accepted in the United States of America. 2 Current year composite statutory tax rate of 25.75%. 3 Includes $6.3 million recognized as an adjustment to the Wildfire tort-related claims for the nine months ended September 30, 2026. Includes insurance recovery related to the settlement of the securities class action of $35.5 million for the three and nine months ended September 30, 2025. Also, for the three and nine months ended September 30, 2025, includes adjustments related to costs that are no longer probable of recovery under the insurance policies. 4 Represents an adjustment related to remeasuring the remaining settlement liability at present value in accordance with Accounting Standards Codification Topic 835-30 Imputation of Interest 5 Represents accretion expense related to remeasuring the remaining settlement liability. 6 Capital gains composite tax rate of 23.9%, net of valuation allowance release. Three months ended September 30 Nine months ended September 30 (in thousands) 2026 2025 2026 2025 HEI Consolidated GAAP1 net income (as reported) $ 35,450 $ 30,747 $ 189,100 $ 83,503 Excluding special items related to the Maui windstorm and wildfires (after tax)2: Legal expenses 744 4,302 4,629 15,245 Outside services expense — — — 100 Wildfire securities-related claims — 35,454 — 35,454 Other expense 23 4,375 1,046 13,127 Interest expense — 295 — 2,449 After tax expenses 767 44,426 5,675 66,375 Insurance recoveries3 (154) (36,434) (6,966) (39,630) Settlement remeasurement4 — — (114,248) — Accretion expense5 13,372 — 26,525 — Deferral of cost — (4,631) — (16,193) Total Maui windstorm and wildfires related items, net (after tax) 13,985 3,361 (89,014) 10,552 Gain on sale of investment and net unrealized gain on investment measured at fair value (after tax)6 (64,146) — (64,146) — Loss (gain) on sale of subsidiaries and impairment losses on subsidiary assets sold and assets formerly classified as held for sale (after tax)2 37,671 (1,300) 40,430 13,951 Non-GAAP adjustments (12,490) 2,061 (112,730) 24,503 Non-GAAP (Core) net income $ 22,960 $ 32,808 $ 76,370 $ 108,006 GAAP Diluted earnings per share (as reported) $ 0.20 $ 0.18 $ 1.09 $ 0.48 Non-GAAP (Core) Diluted earnings per share $ 0.13 $ 0.19 $ 0.44 $ 0.62

53 Reconciliation of GAAP to Non-GAAP Measures—Hawaiian Electric 1 Includes $8.5 million recognized as an adjustment to the Wildfire tort-related claims for the nine months ended September 30, 2026. 2 Pretax insurance recoveries includes adjustments related to costs that are no longer probable of recovery under the insurance policies. For the three and nine months ended September 30, 2025, adjustments amount to $1.0 million and $7.6 million, respectively, of which, $0.5 million and $4.5 million were deferred to a regulatory asset, respectively, and are reported on line “Deferral of cost”. 3 Represents an adjustment related to remeasuring the remaining settlement liability at present value in accordance with Accounting Standards Codification Topic 835-30 Imputation of Interest. 4 Represents accretion expense related to remeasuring the remaining settlement liability. 5 Pursuant to the PUC order received on February 12, 2025, deferral accounting treatment limited to insurance premiums and outside services and legal costs associated with the asset-based lending facility credit agreement incurred in 2025 was granted. Applicable amounts were deferred to a regulatory asset. 6 Current year composite statutory tax rate of 25.75%. 7 Accounting principles generally accepted in the United States of America. Three months ended September 30 Nine months ended September 30 (in thousands) 2026 2025 2026 2025 Maui windstorm and wildfires related items Pretax expenses: Legal expenses $ 1,028 $ 4,316 $ 3,592 $ 12,469 Other expense — 5,791 1,116 17,278 Interest expense — 131 — 2,543 Pretax expenses 1,028 10,238 4,708 32,290 Insurance recoveries1,2 (35) (430) (8,866) 126 Settlement remeasurement3 — — (153,870) — Accretion expense4 18,010 — 35,724 — Deferral of cost5 — (6,237) — (21,809) Total Maui windstorm and wildfires related items, net 19,003 3,571 (122,304) 10,607 Income taxes6 (4,894) (919) 31,493 (2,731) After-tax adjustments $ 14,109 $ 2,652 $ (90,811) $ 7,876 Hawaiian Electric consolidated net income GAAP7 net income (as reported) $ 13,488 $ 36,988 $ 186,689 $ 123,954 Excluding special items related to the Maui windstorm and wildfires (after tax)6: Legal expenses 763 3,205 2,667 9,258 Other expense — 4,300 828 12,829 Interest expense — 97 — 1,888 After tax expenses 763 7,602 3,495 23,975 Insurance recoveries1,2 (26) (319) (6,583) 94 Settlement remeasurement3 — — (114,248) — Accretion expense4 13,372 — 26,525 — Deferral of cost5 — (4,631) — (16,193) Total Maui windstorm and wildfires related items, net (after tax) 14,109 2,652 (90,811) 7,876 Non-GAAP (Core) net income $ 27,597 $ 39,640 $ 95,878 $ 131,830

GAAP TO NON-GAAP RECONCILIATION OF UTILITY ROE1 2027 (rates effective 5/1/2027) Full Year Run Rate of New Rates GAAP ROE 5.7% – 6.2% 6.7% – 7.2% Add back: Wildfire tort liability accretion 1.5% 1.5% Wildfire Legal/Claims expenses 0.1% 0.1% Non-GAAP (Core ) ROE 7.3% – 7.8% 8.3% – 8.8% 1. Columns may not foot due to rounding. 54 Reconciliation of GAAP to Non-GAAP Measures—Hawaiian Electric (cont’d)

55 Reconciliation of GAAP to Non-GAAP Measures—Holding Company & Other 1 Includes insurance recovery related to the proposed settlement of the securities class action of $47.8 million (pre-tax) for the three and nine months ended September 30, 2025. 2 Current year composite statutory tax rate of 25.75%, excluding capital gains, which are taxed at capital gains composite tax rate of 23.9%, net of valuation allowance release. 3 Accounting principles generally accepted in the United States of America. 4 Capital gains composite tax rate of 23.9%, net of valuation allowance release. Three months ended September 30 Nine months ended September 30 (in thousands) 2026 2025 2026 2025 Maui windstorm and wildfires related costs Pretax expenses: Legal expenses $ (26) $ 1,478 $ 2,642 $ 8,063 Outside services expense — — — 135 Wildfire securities-related claims — 47,750 — 47,750 Other expense 31 101 293 401 Interest expense — 267 — 756 Pretax expenses 5 49,596 2,935 57,105 Insurance recoveries1 (172) (48,640) (515) (53,500) Total Maui windstorm and wildfires related expenses, net of insurance recoveries (167) 956 2,420 3,605 Pretax gain on sale of investment and net unrealized gain on investment measured at fair value (64,146) — (64,146) — Pretax loss (gain) on sale of subsidiaries and impairment losses on subsidiary assets sold and assets formerly classified as held for sale 50,736 (1,013) 54,452 12,376 Income taxes2 (13,022) (534) (14,645) 646 After-tax adjustments $ (26,599) $ (591) $ (21,919) $ 16,627 Holding and Other Companies net income (loss) GAAP3 net income (loss) (as reported) $ 21,962 $ (6,241) $ 2,411 $ (40,451) Excluding special items related to the Maui windstorm and wildfires (after tax)2: Legal expenses (19) 1,097 1,962 5,987 Outside services expense — — — 100 Wildfire securities-related claims — 35,454 — 35,454 Other expense 22 75 217 298 Interest expense — 198 — 561 Maui windstorm and wildfires related expenses (after tax) 3 36,824 2,179 42,400 Insurance recoveries (after tax)1,2 (127) (36,115) (382) (39,724) Total Maui windstorm and wildfires related expenses, net of insurance recoveries (after tax) (124) 709 1,797 2,676 Gain on sale of investment and net unrealized gain on investment measured at fair value (after tax)4 (64,146) — (64,146) — Loss (gain) on sale of subsidiaries and impairment losses on subsidiary assets sold and assets formerly classified as held for sale (after tax)2 37,671 (1,300) 40,430 13,951 Non-GAAP adjustments (26,599) (591) (21,919) 16,627 Non-GAAP (Core) net loss $ (4,637) $ (6,832) $ (19,508) $ (23,824)

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