Building strength through Partnering to make Hawaii a better place to live Leadership Richard M. Rosenblum President and Chief Executive Officer Hawaiian Electric Company, Inc. Mr. Rosenblum, 61, was named president and chief executive officer of Hawaiian Electric Company, Inc. effective January 1, 2009, and on February 23, 2009 he was appointed a director of the HECO Board. Mr. Rosenblum was born in New York City and raised in Scarsdale, New York. He earned a bachelor of science degree as well as a master of science degree in nuclear engineering from Rensselaer Polytechnic University. Mr. Rosenblum has 32 years of experience in all facets of the utility business at Southern California Edison (SCE), California’s largest electric utility. He had retired on June 1, 2008 as senior vice president of generation and chief nuclear officer responsible for all power generating facilities, including nuclear and related fuel supplies. During that tenure, he helped initiate the world’s largest solar photovoltaic project which aims to install 250 megawatts of solar generating capacity on commercial rooftops in Southern California. Previously, he served as senior vice president of SCE’s transmission and distribution business unit, responsible for high-voltage bulk transmission and retail distribution of electricity in their 50,000 square mile service territory of 4.6 million customers. He has also held the positions of vice president of engineering and technical services responsible for engineering construction, safety oversight, and other engineering support activities; and vice president of SCE’s distribution business unit, including responsibility for customer service. Richard F. Wacker President and Chief Executive Officer American Savings Bank, F.S.B. Mr. Wacker, 49, was named president and chief executive officer of American Savings Bank effective November 15, 2010. He also serves as a director on the ASB Board. Prior to joining ASB, Mr. Wacker was the chairman of Korea Exchange Bank (KEB), the fifth largest Korean bank with $90 billion in assets and operations in 22 countries. He joined KEB in February 2004 as chief operating officer and served as president and chief executive officer from 2005 to 2009. He also served as the chairman of the KEB Foundation. Mr. Wacker was recognized in 2008 as one of Korea’s “Most Respected CEOs.” Earlier, Mr. Wacker worked for General Electric (GE), domestically and abroad, for 20 years in a wide range of senior leadership positions in both GE’s industrial and financial services businesses. He was a company officer and member of GE’s Corporate Executive Council, the top leadership group in GE. Originally from St. Louis, Mr. Wacker graduated from the University of Missouri with a bachelor of science degree in mechanical engineering. Mr. Wacker is a member of the Hawaii Business Round Table and the Hawaii Banker’s Association, and he serves on the board of directors of Child and Family Service. He is also a member of the board of trustees of the University of Hawaii Foundation.

Constance H. Lau Chairman American Savings Bank, F.S.B. President and Chief Executive Officer Hawaiian Electric Industries, Inc. Chairman Hawaiian Electric Company, Inc. Ms. Lau, 59, was named president and chief executive officer of Hawaiian Electric Industries, Inc. in May 2006. She also serves as chairman of Hawaiian Electric Company, Inc. and chairman of American Savings Bank. Born and raised in Honolulu, Hawaii, Ms. Lau joined the HEI companies in 1984, serving first as assistant corporate counsel and treasurer of Hawaiian Electric Company, Inc. and then as treasurer of HEI. In 1999, she became a director and senior executive vice president and chief operating officer of American Savings Bank, rising to president and chief executive officer in June 2001. She also served as an HEI director from 2001 through 2004, and has been serving as an HEI director since May 2006. Prior to joining the HEI companies, Ms. Lau practiced law in San Francisco, California. She has a bachelor of science degree from Yale College, a juris doctor degree from the University of California Hastings College of the Law and a master’s degree in business administration from the Stanford Graduate School of Business. James A. Ajello Executive Vice President, Chief Financial Officer and Treasurer Hawaiian Electric Industries, Inc. Mr. Ajello, 58, joined Hawaiian Electric Industries, Inc. in January 2009. Prior to joining HEI, Mr. Ajello was senior vice president - business development at Reliant Energy, Inc. (Reliant). He joined Reliant in 2000 as president of Reliant Energy Solutions LLC and was named Reliant’s senior vice president and general manager of commercial & industrial marketing in 2004. Mr. Ajello’s experience prior to joining Reliant includes serving as senior banker/managing director of the business development/corporate finance group of UBS Securities, Inc. and as managing director of the energy & natural resources group of UBS Warburg/UBS Securities LLC. He also worked at Enron North America, and was responsible for a team originating business with large industrial clients. Before Enron, his work experience included a project management role at the U.S. Synthetic Fuels Corporation and as a management intern with the U.S. Department of Energy focusing on renewable energy development and naval nuclear reactors. Mr. Ajello holds a bachelor’s degree from the State University of New York and an MPA from Syracuse University. In addition, he is a graduate of the Advanced Management Program of the European Institute of Business Administration in Fontainebleau, France. Mr. Ajello is Chairman of the U.S. Department of Energy’s Environmental Management Advisory Board. He is also a board member of the Hawaii Pacific University Board of Trustees and its affiliate, the Oceanic Institute, as well as a member of the Board of Trustees of Enterprise Honolulu (Oahu Economic Development Board). Shelee M.T. Kimura Manager, Investor Relations & Strategic Planning Hawaiian Electric Industries, Inc. Ms. Kimura, 38, was named manager, investor relations & strategic planning of HEI in November 2009. She joined HEI as director, corporate finance and investments in August 2004. Prior to joining HEI, Ms. Kimura was a consulting manager with Arthur Andersen LLP and KMH LLP in Honolulu. She was a University of Hawaii Presidential Scholar and graduated summa cum laude with a bachelor of business administration degree in accounting in 1995. She is a certified public accountant.

FORWARD-LOOKING STATEMENTS

This presentation and other presentations made by Hawaiian Electric Industries, Inc. (HEI) and Hawaiian Electric Company, Inc. (HECO) 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 “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 and market factors, among other things. These forward-looking statements are not guarantees of future performance.

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:

· international, national and local economic 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 (including the fair value and/or the actual performance of collateral underlying loans held by American Savings Bank, F.S.B. (ASB), which could result in higher loan loss provisions and write-offs), decisions concerning the extent of the presence of the federal government and military in Hawaii, the implications and potential impacts of U.S. and foreign capital and credit market conditions and federal and state responses to those conditions, and the potential impacts of global developments (including unrest, conflict and the overthrow of governmental regimes in North Africa and the Middle East, terrorist acts, the war on terrorism, continuing U.S. presence in Afghanistan and potential conflict or crisis with North Korea or Iran);

· weather and natural disasters (e.g., hurricanes, earthquakes, tsunamis, lightning strikes and the potential effects of global warming, such as more severe storms and rising sea levels), including their impact on Company operations and the economy (e.g., the effect of the March 2011 natural disasters in Japan on its economy and tourism in Hawaii);

· the timing and extent of changes in interest rates and the shape of the yield curve;

· the ability of the Company to access credit markets to obtain commercial paper and other short-term and long-term debt financing (including lines of credit) and to access capital markets to issue HEI common stock under volatile and challenging market conditions, and the cost of such financings, if available;

· the risks inherent in changes in the value of pension and other retirement plan assets and securities available for sale;

· changes in laws, regulations, market conditions and other factors that result in changes in assumptions used to calculate retirement benefits costs and funding requirements;

· the impact of the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010 (Dodd-Frank Act) and of the rules and regulations that the Dodd-Frank Act requires to be promulgated;

· increasing competition in the banking industry (e.g., increased price competition for deposits, or an outflow of deposits to alternative investments, which may have an adverse impact on ASB’s cost of funds);

· the implementation of the Energy Agreement with the State of Hawaii and Consumer Advocate (Energy Agreement) setting forth the goals and objectives of a Hawaii Clean Energy Initiative (HCEI), revenue decoupling and the fulfillment by the electric utilities of their commitments under the Energy Agreement (given the Public Utilities Commission of the State of Hawaii (PUC) approvals needed; the PUC’s potential delay in considering (and potential disapproval of actual or proposed) HCEI-related costs; reliance by the Company on outside parties like the state, independent power producers (IPPs) and developers; potential changes in political support for the HCEI; and uncertainties surrounding wind power, the proposed undersea cables, biofuels, environmental assessments and the impacts of implementation of the HCEI on future costs of electricity);

· capacity and supply constraints or difficulties, especially if generating units (utility-owned or IPP-owned) fail or measures such as demand-side management (DSM), distributed generation (DG), 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;

· the risk to generation reliability when generation peak reserve margins on Oahu are strained;

· fuel oil price changes, performance by suppliers of their fuel oil delivery obligations and the continued availability to the electric utilities of their energy cost adjustment clauses (ECACs);

· the impact of fuel price volatility on customer satisfaction and political and regulatory support for the utilities;

· the risks associated with increasing reliance on renewable energy, as contemplated under the Energy Agreement, including the availability and cost of non-fossil fuel supplies for renewable energy generation and the operational impacts of adding intermittent sources of renewable energy to the electric grid;

· the ability of IPPs to deliver the firm capacity anticipated in their power purchase agreements (PPAs);

· the ability of the electric utilities to negotiate, periodically, favorable fuel supply and collective bargaining agreements;

· new technological developments that could affect the operations and prospects of HEI and its subsidiaries (including HECO and its subsidiaries and ASB) or their competitors;

· cyber security risks and the potential for cyber incidents, including potential incidents at HEI, ASB and HECO and their subsidiaries (including at ASB branches and at the electric utility plants) and incidents at data processing centers they use, to the extent not prevented by intrusion detection and prevention systems, anti-virus software, firewalls and other general information technology controls;

· federal, state, county and international governmental and regulatory actions, such as changes in laws, rules and regulations applicable to HEI, HECO, ASB and their subsidiaries (including changes in taxation, increases in capital requirements, regulatory changes resulting from the HCEI, environmental laws and regulations, the regulation of greenhouse gas (GHG) emissions, governmental fees and assessments (such as Federal Deposit Insurance Corporation assessments), and potential carbon “cap and trade” legislation that may fundamentally alter costs to produce electricity and accelerate the move to renewable generation);

· 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 and restrictions and penalties that may arise, such as with respect to environmental conditions or renewable portfolio standards (RPS));

· potential enforcement actions by the Office of the Comptroller of the Currency, the Federal Reserve Board (FRB), the Federal Deposit Insurance Corporation (FDIC) and/or other governmental authorities (such as consent orders, required corrective actions, restrictions and penalties that may arise, for example, with respect to compliance deficiencies under existing or new banking and consumer protection laws and regulations or with respect to capital adequacy);

· ability to recover increasing costs and earn a reasonable return on capital investments not covered by revenue adjustment mechanisms;

· the risks associated with the geographic concentration of HEI’s businesses and ASB’s loans, ASB’s concentration in a single product type (i.e., first mortgages) and ASB’s significant credit relationships (i.e., concentrations of large loans and/or credit lines with certain customers);

· changes in accounting principles applicable to HEI, HECO, ASB and their subsidiaries, including the possible adoption of International Financial Reporting Standards or new U.S. accounting standards, the potential discontinuance of regulatory accounting and the effects of potentially required consolidation of variable interest entities (VIEs) or required capital lease accounting for PPAs with IPPs;

· changes by securities rating agencies in their ratings of the securities of HEI and HECO and the results of financing efforts;

· faster than expected loan prepayments that can cause an acceleration of the amortization of premiums on loans and investments and the impairment of mortgage-servicing assets of ASB;

· changes in ASB’s loan portfolio credit profile and asset quality which may increase or decrease the required level of allowance for loan losses and charge-offs;

· changes in ASB’s deposit cost or mix which may have an adverse impact on ASB’s cost of funds;

· the final outcome of tax positions taken by HEI, HECO, ASB and their subsidiaries;

· 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

· other risks or uncertainties described elsewhere in this report and in other reports (e.g., “Item 1A. Risk Factors” in the Company’s Annual Report on Form 10-K) previously and subsequently filed by HEI and/or HECO 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, HECO, ASB and their subsidiaries undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

13 0.10 0.15 0.20 0.25 0.30 0.35 0.40 Energy Cost ($/kWh) Dec 2011**Wind Solar Forecasted ~ 2030*** Biomass Energy costs subject to volatile oil prices Renewables: long-term fixed price contracts with predetermined escalators Dec 2010* Range of HECO Companies fossil fuel energy cost Range of contracted renewable energy cost* Oil price for LSFO of $83/bbl** Oil price assumption for LSFO of $132/bbl*** Oil price assumption for LSFO of $180/bbl Renewable Energy is Cost Competitive in Hawaii 14 Decoupling Components*Benefits and Details of Mechanisms* Sales decoupling via a revenue balancing account (RBA) Predictable revenue stream •Net revenues fixed at the level approved in the last rate case •Revenues are no longer linked to KWH sales/electricity usage Revenue adjustment mechanism for O&M expenses (O&M RAM) Annual escalation of revenues to recover general “inflation” of O&M expenses between rate cases •Annual indexed adjustments: •Labor exp: labor exp approved in rates (excluding merit employees) x union contract escl. rate less 0.76% productivity factor •Non-labor exp: non-labor exp approved in rates x GDPPI Revenue adjustment mechanism for plant additions (Rate Base RAM) Annual escalation of revenues for plant additions between rate cases •Annual adjustment for plant additions, associated rate base items and depreciation expense •Rate base RAM = rate base additions x RORB .Projects > $2.5M: based on PUC approved amt. .Projects < $2.5M: based on 5-yr historical avg. •Change in depreciation expense New Improved Regulatory Model* Details of mechanisms, calculations and implementation at HECO Oahu included in the appendix .Effective for HECO Oahu and recently approved for HELCO .MECO implementation pending PUC’s allowed ROE decision Existing Balancing Accounts, Trackers and/or Surcharges Energy Cost Adjustment Clause (ECAC): Fuel & Energy-Related Purchased Power; Purchased Power Adjustment Clause (PPAC); Pension & OPEB Trackers; DSM Surcharge; and Renewable Energy Infrastructure Surcharge. 7

0% 20% 40% 60% 80% 100% HECO HELCO MECO Improving ROE Consolidated Book ROE: 7.3% Allowed vs. Actual ROACE Year Ended December 31, 2011* Based on PUC decisions in effect on December 31, 2011** Calculated using GAAP net income divided by average common equity, simple average method (a) Allowed ROE reflects decoupling at HECO (b) Allowed ROE will be reduced to 10.00% at HELCO when the rates from the final D&O dated February 8, 2012 become effective(c)Allowed ROE is expected to be lower at MECO with the implementation of decoupling HELCO’s ROE includes ~100bps related to fuel efficiency savings of which some or all may not continue when the heat rate deadband under decoupling and final 2010 test year rates are implemented. Book**6.4% 9.7% 7.7% Allowed* 10.00% (a) 10.50% (b) 10.50% (c) ROE Goal for HECO Oahu (under existing mechanisms): 8.5% for the full year 2012 Appendix includes additional details of the decoupling mechanisms and implementation Actual ROACE as a % of Allowed 16 Utility 2012 Agenda .Major regulatory priority items: 1. Decoupling implementation for MECO 2. MECO 2012 rate case 3. Resolution of regulatory audits* .Continue work with PUC and others on timely recovery of costs: .Five month lag in rate case interim decisions .Five month lag in revenue adjustment mechanisms .Recovery of software projects .Align operations with new decoupling business model .Achieve HECO Oahu’s ROE goal of 8.5% *PUC ordered regulatory audits on the reasonableness of costs incurred for Campbell Industrial Park (CIP) combustion turbine No. 1 (CT-1) project, Customer Information System project and HECO’s East Oahu Transmission Project (EOTP) 8

Rate Case Schedule HELCO 2010 Test Year HECO 2011 Test Year 2010 2011 2012 2013 2014 Nov 2010 –Interim D&O $6.0M***;ROE 10.5%; Final D&O –Filed revised Rev Req. Feb. 2012 July 2011 –Interim D&O $53.2M; ROE 10%; Final D&O –No statutory deadline HELCO 2013 Test Year MECO 2012 Test Year* MECO 2010 Test Year* July 2010 –Interim D&O $10.3M**; ROE 10.5%; Final D&O –No statutory deadline HECO 2014 Test Year Requested –$27.5M Expected Interim –June 2012 To be filed in mid-2012 To be filed in 2013*The next opportunity for MECO to receive decoupling implementation is either its final 2010 D&O or its next rate case interim decision. **In January 2011, the PUC approved the adjustment from $10.3M to $8.5M to account for the final rates in the MECO 2007 test year rate case. ***In January 2011, the PUC approved the adjustment from $6.0M to $5.2M to incorporate the bargaining unit benefit adjustments that went into effect on January 1, 2012. 18 300 400 600 800 900 - 100 200 300 400 500 600 700 800 900 1,000 2012 2013 2014 2015 2016 Capex in millions ~7-9% rate base growth (5-yr CAGR) Growth in Capital Expenditures* As We Invest in Clean Energy & Reliability Forecast as of December 12, 2011. This forecast is only updated annually. * Gross capital expenditures excluding contributions in aid of construction** For the purposes of this forecast, more than 80% of these project expenditures are assumed in 2015 to 2016, but could change over time 5-Year Capital Expenditures Forecast* .Routine system capital and other: ~$1.2B .Significant items that could change over time: $1.4B -$1.8B .New generation (subject to competitive bidding): $600M to $800M, more than 80% assumed in 2015- 2016 and primarily at HECO .Environmental compliance: $500M to $600M** .Fuel infrastructure: $250M to $300M** .Interisland wind shore-side facilities: $70M to $100M**

21 Bank Agenda .Prudently grow the franchise while further diversifying our asset mix and maintaining our efficient cost structure .Focus on strong profitability metrics as a high performing community bank .2012 targets*: .ROA of 1.15% to 1.20% .Low to mid-single digit loan growth .NIM ~4% .Efficiency ratio in mid-50s .Pretax preprovision income of $100M -$105M *Targets assume no other regulatory changes or impacts from the Durbin Amendment or significant changes in the interest rate environment. 22 1.26 0.84 1.09 1.17 1.20 108 145 146 57 64 57 60 4.16 3.81 3.94 3.04ASBPeers11Peer group includes publicly traded banks and thrifts between $3.5B and $8B in total assets 2 Subset of peer group for 10 high performing banks 3 Peer data based upon core return on average assets which excludes nonrecurring items Note: Quarterly information is annualized. Source for peer data: SNL Financial (4Q11 data based upon data available as of February 29, 2012) High Performing Peers2 Bank of Hawaii .4Q11 Profitability metrics better or in line with the performance of our high performing peers Bank Agenda: Maintain Status as High Performing Community Bank ASB 4Q11 Peers 4Q11 ASB 4Q11 Peers 4Q11 ASB 4Q11 Peers 4Q11 Return on Assets3 (%) Efficiency Ratio (%) Net Interest Margin (%) Noninterest Expense ($) Pretax Preprovision Income ($) ASB Target ASB 4Q11 ASB 4Q11 ~4% mid-50s $110-$120M Target Target Target Target Target

23 Quality Balance Sheet Compared to Industry Peers .Overall loan-to-deposit ratio of 90% .96% of ASB loans funded with low-cost core deposits 9/30/11 (%) 12/31/11 (%) Peer Banks1 ASB Avg yield on earning assets 4Q11:4.44% Avg cost of funds 4Q11:0.29% Median yield on earning assets 3Q11: 4.63% Median cost of funds 3Q11: 0.83% Other liabilities 7 Loans 741 Peer group based on publicly traded banks and thrifts between $3.5B and $8B in total assets. Source for peer data: SNL Financial (3Q11 data based upon data available as of February 29, 2012) Core Deposits 72 Certificates of Deposit 11 Other Liab. 7 Equity 10 Loans 75 Other 10 Investment Securities 15 Core Deposits 53 Certificates of Deposit 22 Other Liabilities 14 Equity 11 Loans 63 Other 14 Investment Securities 23 24 Consumer HELOC Commercial Markets Commercial Real Estate Commercial Construction ASB Asset Quality: Lower Risk Loan Mix .Predominate exposure to lower risk residential mortgages Total loans December 31, 2011 -$3.7B2 1% $42M 9% $332M1 15% $536M 2%, $93M Residential Land Loans 1%, $45M* Residential Construction 1%, $3M 19% $717M 1 Includes approximately $84 million of owner-occupied commercial real estate 2 Before deferred fees, discounts and allowance for loan losses Residential 1-4 Family 52% Oahu $1,200 Neighbor Islands 650* Mainland 77* $1,927M *Primary risks in three isolated areas

27 Nonperforming Assets Ratio Low Compared to Peers 0.49% 0.52% 0.46% 0.45% 1.49% 1.23%1.28%1.30% 1.57% 0.44% 0% 1% 2% 3% 4% 5% 4Q10 1Q11 2Q11 3Q11 4Q11 All Other ASB Loans Residential Lot Loans Peers (1)High Performing Peers (2) $17.5 $18.9 $16.6 $16.3 $58.1 $55.0 $44.6 $46.7 $45.3 $16.9 4Q10 1Q11 2Q11 3Q11 4Q11 Percentages represent regulatory nonperforming assets to regulatory end of period loans and real estate owned. Dollars are in millions at the end of the period. 1 Peer group based on publicly traded banks and thrifts between $3.5B and $8B in total assets. See appendix. 2 Subset of peer group for 10 high performing banks. See appendix. Source for peer data: SNL Financial (based upon data available as of February 29, 2012) Percentages Dollars 1.82% $65.6 1.69% 1.77% $62.8 $61.5 1.94% $71.6 2.01% $74.4 ($M) 280.72% 0.49% 0.45% 0.48% 0.54% 0.0% 0.7% 1.4% 4Q10 1Q11 2Q11 3Q11 4Q11 ASB $6.3 $4.3 $4.1 $4.9 $4.4 $0.0 $5.0 $10.0 4Q10 1Q11 2Q11 3Q11 4Q11 2011 Net Loan Charge-offs Decline Annualized quarterly net loan charge-offs ratio reflected as a percentage of average loans held during the period. Charge-off dollars are in millions. 1 Peer group based on publicly traded banks and thrifts between $3.5B and $8B in total assets. See appendix. 2 Subset of peer group for 10 high performing banks. See appendix. Source for peer data: SNL Financial (based upon data available as of February 29, 2012) Percentages Dollars High Performing Peers (2) Peers (1) ($M)

29 .NIM to decline but remain at ~4% .Low-interest rate environment to persist .Expect low to mid-single digit loan growth .Shift to shorter duration, adjustable rate products to improve interest rate risk Bank Summary of Key Earnings Drivers in 2012 Net Interest Income Provision for loan losses .Focus on expanding fee based products and services .Gains on sales will depend on interest rates and loan origination volumes .~$1M lower interchange revenue .Estimate approximately $13M -$16M in 2012 .Assumes continued modest improvement in the economy Noninterest Expense .Approximately $145M in 2011 Expect net income to be 3% to 5% lower than 2011, however, low- cost funding base, reduced cost structure and lower risk profile should continue to benefit our relative performance to the industry Noninterest Income 30 HEI: A Compelling Investment Above Average Dividend Yield Reduced Risk and Volatility Attractive Earnings Growth .5.0% HEI dividend yield above average EEI companies dividend yield of 4.1% (as of 02/29/12) .HEI has historically paid an above average yield and has continuously paid a dividend for 110 years .Strong utility regulatory framework supported by state’s broader clean energy public policy .New utility regulatory model expected to improve earned ROE .Opportunity for utility rate base growth of ~7% to 9% CAGR over 5 years A unique combination of: .Bank targeting modest loan growth and shift in mix to shorter duration, adjustable rate assets; lower credit costs with improving economy .Bank’s simple business model with a low risk profile, low cost deposit base and efficient operations provide for less volatility and higher profitability

A1 32 .Decoupling for Oahu: .RBA effective March 1, 2011 .RAM effective June 1, 2011 .HECO Oahu 2011 Test Year (TY) Interim Decision and Order, effective July 26, 2011 .Filed MECO 2012 TY rate case .Initiated programs approved by PUC .Electric vehicle incentive rates .Feed-in-tariff Tier 3 .Contracted 146 MW of renewables in 2011: wind, solar and geothermal Utility 2011 Strategic Progress New Regulatory Model Rate Cases Clean Energy Significant Progress on Clean Energy Agreement -- Commitments and Regulatory Elements Clean Energy Commitments Status Status 1. "Big Wind" and implementation studies v 1. Decoupling with trackers v 2. Renewables v 2. Commercial energy efficiency DSM v 3. Solar Plus v 3. AMI v 4. Net energy metering v 4. Smart grid v 5. Biofuels v 5. Firming/backup power v 6. No new fossil fuel plants v 6. DG investments v 7. Retirements v 7. Energy cost adjustment clause (the PPAC) v 8. Feed-in tariffs v 8. Infrastructure support v 9. System Benefit Fund v 9. Clean Energy Infrastructure Surcharge v = RPS at 40% = New Regulatory Compact v Key steps completed or substantially completed v Commitments made v In progress Additional Elements of New Regulatory Compact

A2 Existing RE, 10.2% Expiration of IPP Contract 0.5%. New NEM/FIT/SIA 2.3%. New RE Approved by PUC But Not in Operation, 4.2% New RE Contracts Submitted to PUC for Approval 0.1%. New RE Projects Under Negotiations 2.7%. New Biofuel Contracts, 1.2%. 5% 6% 7% 8% 9% 10% 11% 12% 13% 14% 15% 16% 17% 18% 19% 20% 21% 22% 23% 24% 25% RPS (%) Projected Renewable Energy (RE) Biomass NEM/FIT/SIA Waste-to-Energy PV Wind Geothermal Biofuel Utility: On Track to Achieve 2015 RPS *Represents the estimated 2015 RPS contribution of existing RE projects based on 2015 projected sales Net Energy Metering (NEM) / Feed-in-Tariff (FIT) / Standard Interconnection Agreement (SIA) * 2015 Goal of 15% 35 Decoupling Summary (Hawaii PUC Docket number: 2008-0274) 2. Revenue adjustment mechanism (RAM) for expenses .Annually adjusts revenues for indexed changes in Base Expenses .Base expenses = expense levels in the last approved rate case (interim or final), adjusted for annual indexed increases, and excluding expenses covered by a separate tracking mechanism 1 and labor expense for merit employees .Union labor escalation rate = rate per the union labor agreement less 0.76% productivity factor .Non-labor escalation rate = consensus estimated annual change in GDPPI per the Blue Chip Economic Indicators published each February .O&M in excess of the last rate case level and/or the indexed increases, is not covered by the RAM .Annually, request adjustment by 3/31 and adjusted rates commence on 6/1 for 12 month period, if not suspended 1. Sales decoupling via a revenue balancing account (RBA) .Delinks utility revenues from electricity usage .GAAP revenue = revenue approved in the last rate case (interim or final) .Recorded revenues adjusted monthly in the RBA .Target (decoupling) revenues will be allocated as follows: 1Q: 23.46%; 2Q: 24.75%; 3Q: 26.49%; 4Q: 25.30% .On a cash basis, RBA trued-up in rates annually in June of the following year Components 1 Includes fuel, purchased power, DSM, pension, other post employment benefits, approved projects under the clean energy infrastructure surcharge and the purchased power adjustment clause.

36 Components 3. RAM for rate base .Annual adjustment for plant additions, associated rate base items and depreciation expense .Major Capital Projects (> $2.5M): average annual amount based on prior year ending balance (at project amounts not to exceed amounts approved by the PUC) and projected ending balance for the current year (based on approved projects scheduled to be in service by Sep 30th of the current year, at amounts approved by the PUC) .Baseline Capital Projects (<$2.5M): average annual amount based on the prior year ending balance (actual) and projected ending balance for the current year (based on simple average of preceding 5 years) .Offset by avg balances for accumulated depreciation, contributions in aid of construction and plant related deferred income taxes .Recovery of incremental depreciation and contributions in aid of construction amortization related to prior year rate base changes .Annually, request adjustment by 3/31 and adjusted rates commence on 6/1 for 12 month period, if not suspended Decoupling – Summary (cont.) (Hawaii PUC Docket number: 2008-0274) • Non-labor O&M increases > GDPPI • Non-union labor exp increases • Costs for large capital projects > PUC approved estimate • Costs for base-level capital projects > 5-year historical average, until following year • Investments other than plant (e.g., software projects, fuel inventory) Examples of items not covered in mechanisms: 37 93 85 94 99 143 189 38 39 35 32 39 46 28 38 33 29 30 51 16 19 289 81 34 52 - 50 100 150 200 250 300 350 400 450 500 2007 Actual 2008 Actual 2009 Actual 2010 Actual 2011 Actual 2012 Forecast HECO Baseline HELCO Baseline MECO Baseline Major Projects Plant Additions – Baseline by Co. & Consolidated Major Projects 5-year (2007 – 2011) historical average baseline projects: HECO: $103 HELCO: $ 37 MECO: $ 31 Total: $171 Major Projects = PUC approved projects > $2.5M

38 HECO Oahu Rate Relief and Decoupling Considerations: 2012 to 2014 HECO 2012 2013 2014 Rate Case Considerations 2011 & 2014 test year rate cases PUC issued TY 2011 Interim D&O on July 22, 2011 .ROACE: 10.0% with decoupling and other cost-recovery mechanisms .File 2014 request .PUC TY 2014 Interim D&O Sales decoupling .July 26, 2011 to May 31, 2012: adjusted net revenue true-up to 2011 interim level (plus RAMs effective June 1, 2012) .Rates adjusted to collect/refund EOY 2011 RBA balance .Revenues adjusted for true-up to 2011 interim/final level plus RAMs .Rates adjusted to collect/refund EOY 2012 RBA balance .Revenues adjusted for true-up to 2011 interim/final level plus RAMs until interim D&O issued .Revenues adjusted for true-up to 2014 interim level .Rates adjusted to collect/refund EOY 2013 RBA balance O&M RAM .Labor: BU Labor O&M and payroll tax ($56M) approved for RAM in 2011 rate case x 2012 union contract 2.5% less 0.76% productivity factor x revenue tax gross up (1.0975) .Non-labor: O&M ($139M) level approved for RAM in 2011 rate case x Feb 2012 GDPPI consensus forecast x revenue tax gross up (1.0975) .No O&M RAM from January 1, 2012 – May 31, 2012 .Labor: BU Labor O&M and payroll tax ($56M) approved for RAM in 2011 rate case x ((2012 union contract 2.5% less 0.76% productivity factor) + (2013 union contract 3.0% less 0.76% productivity factor)) x revenue tax gross up (1.0975) .Non-labor: O&M ($139M) level approved for RAM in 2011 rate case x (Feb 2012 GDPPI consensus forecast + Feb 2013 GDPPI consensus forecast)) x revenue tax gross up (1.0975) .Labor: BU Labor O&M and payroll tax ($56M) approved for RAM in 2011 rate case x ((2012 union contract 2.5% less 0.76% productivity factor) + (2013 union contract 3.0% less 0.76% productivity factor ) + (2014 union contract subject to negotiation less 0.76% productivity factor)) x revenue tax gross up (1.0975) .Non-labor: O&M ($139M) level approved for RAM in 2011 rate case x (Feb 2012 GDPPI consensus forecast + Feb 2013 GDPPI consensus forecast + Feb 2014 GDPPI consensus forecast)) x revenue tax gross up (1.0975) .No O&M RAM from interim 2014 D&O – May 31, 2015 Rate base RAM .Total Oahu rate base growth forecasted: ~5% CAGR for 2012 .Baseline plant additions based on 5-year historical average: see Plant Additions slide for an indication of the historical baseline plant additions thru 2011 .No Rate Base RAM from January 1, 2012 – May 31, 2012 Same considerations as 2012 .Same considerations as 2012 .No Rate Base RAM from 2014 interim D&O – May 31, 2015 Existing Balancing Accounts, Trackers and/or Surcharges ECAC: Fuel & Energy-Related Purchased Power; Pension & OPEB Trackers; DSM Surcharge; Renewable Energy Infrastructure Surcharge and Purchased Power Adjustment Clause. 39 HECO: Adjustment Mechanisms .Sales Decoupling .Revenue Adjustment Mechanisms for O&M and rate base .Energy Cost Adjustment Clause: Fuel and energy-related purchased power .Purchased power adjustment clause .Pension & OPEB trackers .DSM surcharge .Renewable energy infrastructure surcharge

40 Public Utilities Commission of the State of Hawaii – Commissioner Biographies Hermina Morita, Chair .Began serving as Chair on March 15, 2011 .1st term to expire on June 30, 2014 .Prior to appointment, was a member of the State House of Representatives since 1997, representing Kauai, and most recently serving as chair of the Energy and Environmental Protection Committee .Kauai Police Commission, 1993-1996 .Kauai County Planning Commission, 1990-1993 .Attended George Washington University .Attended University of Hawaii John E. Cole* .Began serving on the Commission in July 2006 .1st term ends June 30, 2012 .Prior to appointment, was Executive Director of the Division of Consumer Advocacy, Department of Commerce and Consumer Affairs from May 2004 through June 2006 .Policy Analyst with the Office of the Governor .Staff Attorney for the Division of Consumer Advocacy .Staff Attorney for the Office of Information Practices .Attorney for the Hawaii House of Representatives Majority Leaders Ed Case and Marcus Oshiro .University of Hawaii at Manoa (BS, Biology, Cum laude) .Washington University School of Law in St. Louis, Missouri (JD) Michael E. Champley .Appointed as commissioner on interim basis on September 15, 2011 for a term to expire on June 30, 2016 .Appointment is subject to confirmation by the State Senate .Most recently, was a Maui-based energy consultant focused on clean energy resource integration in Hawaii .Prior work experience includes senior executive positions with DTE Energy, including Senior Vice President-Regulatory Affairs and Senior Vice President-Power Supply .University of Dayton (BS, Electrical Engineering) .Indiana University (MBA, Finance and Public Utility Economics and Regulation) * Lorraine Akibahas been nominated by Governor Abercrombie to succeed John E. Cole when his term ends in June 2012, pending confirmation by the Hawaii State Senate. HECO Rate Case: 2011 Test Year (Hawaii PUC Docket number: 2010-0080) Application (7/30/10) Interim D&O (7/22/11) Base Request New Programs $74M (4.3% increase) $40M (2.3% increase) $53.2M(2) (3.1% increase) Return on average common equity 10.75% with mechanisms 10.00% with mechanisms Common equity capitalization (%) 56.3% 56.3% Return on average rate base 8.54% 8.11% Average rate base amount(1) $1.569B $1.354B KWH sales (GWH) 7,470 7,470 (1) Current effective rates are based on the Final D&O in HECO’s 2009 test year rate case. Average rate base in that D&O was $1.25B. (2) Including the impact of $15M (0.9%) in annual revenues which were being recovered through the decoupling Revenue Adjustment Mechanism. Pending Commission’s decision to (1) reduce the interim increase granted by a net reduction of $0.5 million per the Joint Motion to Adjust Interim D&O (filed 11/30/11) and (2) increase of interim by $5 million per the Settlement Agreement relating to the East Oahu Transmission Project (EOTP) (filed 2/3/12). Upcoming Dates • No statutory deadline for ruling on motions and final decision Existing Balancing Accounts, Trackers and/or Surcharges Decoupling Revenue Balancing Account/Revenue Adjustment Mechanism; ECAC: Fuel & Purchased Energy; Pension & OPEB Trackers; DSM Surcharge; Renewable Energy Infrastructure Surcharge and Purchased Power Adjustment Clause.

MECO Rate Case: 2012 Test Year (Hawaii PUC Docket number: 2011-0092) Application (7/22/11) Base Request $27.5M(1) (6.7% increase) Return on average common equity 11% with mechanisms Common equity capitalization (%) 56.85% Return on average rate base 8.72% Average rate base amount(2) $393M KWH sales (GWH)1,201.8 (1) Increases consist of: • Return on rate base $ 3.0 M • O&M $19.5 M • Other, net $ 5.0 M (2) Current effective rates are based on MECO’s 2010 test year adjusted interim rate case D&O. Average rate base in that D&O was $387M. Upcoming Dates • March 2012 Discovery phase complete (CA’s direct testimonies and MECO’s rebuttal testimonies due 2/10/12 and 3/14/12) •April 2012 Possible submission of Joint Settlement Letter •May 2012 Evidentiary hearing • June 2012 Statutory deadline for interim decision and order 43 MECO Rate Case: 2010 Test Year (Hawaii PUC Docket number: 2009-0163) Application (09/30/09) Interim (07/27/10) Adj Interim (1/5/11) Amount requested $28.2M (9.7% increase) (1) $10.3M (3.3% increase) (1) $8.5M (2.7% increase) (2) Return on average common equity 10.75% 10.50% 10.50% Common equity capitalization (%) 56.9% 56.9% 56.9% Return on average rate base 8.57% 8.43% 8.43% Average rate base amount $390M $387M $387M KWH sales (GWH) 1,131.0 1,204.2 1,204.2 (1) Current effective rates are based on the Interim D&O in MECO’s 2007 test year rate case. Average rate base in that D&O was $383M. (2) Current effective rates are based on Final D&O in MECO’s 2007 test year rate case. Average rate base in that D&O was $383M. Upcoming Dates No statutory deadline for final decision Existing Balancing Accounts, Trackers and/or Surcharges ECAC: Fuel & Purchased Energy; Pension & OPEB Trackers; DSM Surcharge; Renewable Energy Infrastructure Surcharge.

44 HELCO Rate Case: 2010 Test Year (Hawaii PUC Docket number: 2009-0164) Application (12/9/09) Interim D&O (11/3/10) Adj Interim (1/1/12)(3) Final (2/8/12)(4) Amount requested $20.9M (6% increase)(1) $6.0M (1.7% increase)(2) $5.2M (1.5% increase)(2) $4.5M (1.3% increase)(2) Return on average common equity 10.75% with mechanisms 11% without 10.5% without mechanisms 10.5% without mechanisms 10.00% with mechanisms Common equity capitalization (%) 55.9% 55.9% 55.9% 55.9% Return on rate base 8.73% 8.59% 8.59% 8.31% Average rate base amount $487M(1) $465M(2) $465M(2) $465M(2) KWH sales (GWH) 1,122.6 1,122.6 1,122.6 1,122.6 (1) Current effective rates are based on the Interim D&O in HELCO’s 2006 TY rate case. Average rate base in that D&O was $357M. (2) Current effective rates are based on the Final rates in HELCO’s 2006 TY rate case. Average rate base in that D&O was $357M. (3) In January 2011, the PUC approved the adjustment from $6.0M to $5.2M to incorporate the bargaining unit benefit adjustments that went into effect on January 1, 2012. (4) Decision and Order No. 30168 directed HELCO to file as soon as reasonably practicable its revised results of operations and tariff sheets based on the newly approved depreciation rates, the ROE of 10.00% and other provisions of the D&O. On February 21, 2012, HELCO filed its revised results of operations and tariff sheets which are subject to PUC approval. Existing Balancing Accounts, Trackers and/or Surcharges ECAC: Fuel & Purchased Energy; Pension & OPEB Trackers; DSM Surcharge; Renewable Energy Infrastructure Surcharge. 45 19 13 (7) 25 26 15 (7) 34 (10) 0 10 20 30 40 Utility Bank Hold. Co. & Other Consol. $ in millions 4Q10 4Q11 77 58 (22) 114 100 60 (22) 138 (50) 0 50 100 150 Utility Bank Hold. Co. & Other Consol. $ in millions 2010 2011 Annual EPS* HECO ASB Cons 2011 $1.04 $0.62 $1.44 2010 $0.82 $0.62 $1.21 Full Year and 4th Quarter Net Income and EPS * Diluted 4Q EPS* HECO ASB Cons 2011 $0.27 $0.16 $0.36 2010 $0.20 $0.14 $0.26 Full Year 4th Quarter

46 19 77 26 100 0 40 80 120 4Q Annual $ in millions 2010 2011 2011 Utility & Bank Financial Highlights Utility Net Income 15 13 58 60 15 0 50 100 4Q 3Q Annual $ in millions 2010 2011 Bank Net Income Key bank earnings drivers fav/(unfav) ($ in millions) 4Q11 vs 3Q11 4Q11 vs 4Q10 2011 vs 2010 Net interest income -- -- ($3) Provision for loan losses -- $3 $4 Noninterest income -- -- ($4) Noninterest expense and other -- ($1) $4 Key utility earnings drivers favorable/(unfavorable) ($ in millions) 4Q11 vs 4Q10 2011 vs 2010 Revenues for rate relief, including Oahu decoupling $7 $27 HECO heat rate deadband and fuel efficiency savings -- ($4) HELCO/MECO fuel efficiency savings $1 $6 HELCO/MECO KWH sales ($1) ($1) O&M $9 -- Tax Related Items ($6) ($6) Transmission project settlement ($6) ($6) Depreciation $1 $4 47 0 50 100 150 200 250 300 350 400 HECO HELCO MECO Consolidated 2010* 2011* +4% -4% flat -12% Utility Operation and Maintenance Expenses By Company O&M, excluding DSM HECO HELCO MECO Consolidated 2010 252 58 65 375 2011 261 56 57 374 2012 Budget** 264 59 73 396 in $millions * Reflects O&M excluding DSM ** Forecast as of December 12, 2011; MECO’s increase in 2012 is for costs to safely and reliably integrate existing and future renewable energy resources into the Company’s three isolated, island electrical grids.

48 HEI Capital Structure and Financing * Based upon December 2011 forecast ** HECO’s credit agreement extension is subject to PUC approval .Strong capital structure with 52% consolidated equity to capitalization as of 12/31/11 .Based on our current assumptions, we do not expect to require additional equity other than DRIP thru 2012 .Utility has authorization to issue $170M of new debt and refinance $311M of existing debt .HEI and HECO amended and extended their combined $300M line of credit facilities to December 5, 2016** .HEI consolidated estimated pension contribution of $104M in 2012 and bonus depreciation tax cash benefits of $45M in 2012 External dividends 120 HEI investments in HECO 44 MTN maturities 7 HC int, exp & other 22 HECO dividends to HEI 73 ASB dividends to HEI 45 DRIP 44 ST Borrowings 31 0 50 100 150 200 Uses of Capital Sources of Capital $ in millions 2012 Holding Co. Sources & Uses* 49 Hawaii Economic Forecast Year-over-year percent change unless noted 2011 2012 2013 2014 Real state GDP 1.2 2.3 3.3 3.7 Real personal income 0.5 1.8 2.8 3.0 Unemployment (%) 6.3 6.2 5.5 4.9 Payroll jobs 1.2 1.8 2.3 2.1 Visitor arrivals 3.5 4.1 2.4 1.9 U.S. visitor arrivals 2.3 1.1 1.7 1.5 Japanese visitor arrivals (5.3) 7.3 2.2 1.8 Other visitor arrivals 17.8 11.9 4.8 3.2 Source: University of Hawaii Economic Research Organization (UHERO) February 10, 2012 report. Figures for 2012-2014 are forecasts. Except for visitor and labor market data, figures for 2011 are UHERO estimates.