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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION Washington, D. C. 20549

FORM 10-K

[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2011

OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

Commission

File Number Registrant; State of Incorporation; Address; and Telephone Number I.R.S. Employer

Identification No.

1-8503 HAWAIIAN ELECTRIC INDUSTRIES, INC.

, a Hawaii corporation
900 Richards Street, Honolulu, Hawaii 96813 Telephone (808) 543-5662 99-0208097

1-4955 HAWAIIAN ELECTRIC COMPANY, INC. , a Hawaii corporation
900 Richards Street, Honolulu, Hawaii 96813 Telephone (808) 543-7771 99-0040500

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

Securities registered pursuant to Section 12(g) of the Act:

Registrant Title of each class

Hawaiian Electric Industries, Inc. None Hawaiian Electric Company, Inc. Cumulative Preferred Stock

Indicate by check mark if Registrant Hawaiian Electric Industr ies, Inc. is a well-known seasoned issuer, as defined in Rule 405 of the

Securities Act. Yes X No

Indicate by check mark if Registrant Hawaiian Electric Com pany, Inc. is a well-known seasoned issuer, as defined in Rule 405 of the

Securities Act. Yes No X

Indicate by check mark if Registrant Hawaiian Electric Industries, Inc. is not required to file reports pursuant to Section 13 or Section 15(d) of

the Act. Yes No X

Indicate by check mark if Registrant Hawaiian Electric Company, Inc. is not required to file reports pursuant to Section 13 or Section 15(d) of

the Act. Yes No X

Indicate by check mark whether Registrant Hawaiian Electric Industries, Inc. (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No

Indicate by check mark whether Registrant Hawaiian Electric Company, Inc. (1) has filed all reports required to be filed by Sec tion 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was requi red to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No

Indicate by check mark whether Registrant Hawaiian Electric Industries, Inc. has submitted electronically and posted on its cor porate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Ye s X No

Indicate by check mark whether Registrant Hawaiian Electric Company, Inc. has submitted electronically and posted on its corpor ate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Ye s X No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and w ill not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Pa rt III of this Form 10-K or any amendment to this Form 10-K. [ ] Registrant Title of each class Name of each exchange on which registered Hawaiian Electric Industries, Inc. Common Stock, Without Par Value New York Stock Exchange Hawaiian Electric Company, Inc. Guarantee with respect to 6.50% Cumulative Quarterly Income Preferred Securities Series 2004 (QUIPS SM ) of HECO Capital Trust III New York Stock ExchangeIndicate by check mark whether Registrant Hawaiian Electric Indu stries, Inc. is a large accelerated filer, an accelerated filer, a nonaccelerated filer or a smaller reporting company. See definitio ns of “large accelerated filer,” “accelerated filer” and “smalle r reporting company” in Rule 12b-2 of the Exchange Act. Large accelerated filer X Accelerated filer Non-accelerated filer (Do not ch eck if a smaller reporting company) Smaller reporting company __

Indicate by check mark whether Registrant Hawaiian Electric Company, Inc. is a large accelerated filer, an accelerated filer, anonaccelerated filer or a smaller reporting company. See definitio ns of “large accelerated filer,” “accelerated filer” and “smalle r reporting company” in Rule 12b-2 of the Exchange Act. Large accelerated filer Accelerated filer Non-accelerated filer X (Do not ch eck if a smaller reporting company) Smaller reporting company __

Indicate by check mark whether Registrant Hawaiian Electric I ndustries, Inc. is a shell company (as defined in Rule 12b-2 of th e Exchange Act). Yes No X

Indicate by check mark whether Registrant Hawaiian Electric Co mpany, Inc. is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes No X

DOCUMENTS INCORPORATED BY REFERENCE

HECO’s Exhibit 99.2, consisting of:

HECO’s Consolidated Se lected Financial Data—Part II

HECO’s Management’s Discussion and Analysis of Financia l Condition and Results of O perations—Parts I and II

HECO’s Quantitative and Q ualitative Disclosures about Market Risk— Parts I and II

HECO’s Consolidated 2011 Financia l Statements—Parts I, II, III and IV

Selected sections of Proxy Statem ent of HEI for the 2012 Annual Meet ing of Shareholders to be filed—

Part III

This combined Form 10-K represents separate filings by Hawaiian Electric Industr ies, Inc. and Hawaiian Electric Company, Inc. Information c ontained herein relating to any indi vidual registrant is filed by each registrant on its own behalf. HECO makes no representati ons as to any information not relating to it or its

subsidiaries. Aggregate market valueof the voting and nonvoting common equity held by non-affiliates of

the registrants as of Number of shares of common stock outstanding of the registrants as of

June 30, 2011 June 30, 2011 February 8, 2012

Hawaiian Electric Industries, Inc. (HEI) $2,306,231,095 95,853,329 96,152,702 (Without par value) (Without par value)

Hawaiian Electric Company, Inc. (HECO) None 13,830,823 ($6 2/3 par value) 14,233,723 ($6 2/3 par value)i TABLE OF CONTENTS Page

Glossary of Terms ............................................................................................................ ....................................................................... ii Forward-Looking Statements .................................................................................................... ................................................................ v

PART I

Item 1. Business .............................................................................................................. .......................................................... 1

Item 1A. Risk Factors ........................................................................................................ ......................................................... 26

Item 1B. Unresolved Staff Comments ........................................................................................... ............................................. 36 Item 2. Properties ............................................................................................................ .......................................................... 36 Item 3. Legal Proceedings ..................................................................................................... ................................................... 37 Item 4. Mine Safety Disclosures ............................................................................................... ................................................ 37 Executive Officers of the Registrant (HEI) .................................................................................... .......................................................... 37

PART II

Item 5. Market for Registrants’ Common Equity, Related Stock holder Matters and Issuer Purchases of Equity Securities .... 39

Item 6. Selected Financial Data ............................................................................................... ................................................. 40 Item 7. Management’s Discussion and Analysis of Fi nancial Condition and Results of Operations ................................. ....... 41

Item 7A. Quantitative and Qualitative Disclosures about Market Risk ........................................................... ............................. 82 Item 8. Financial Statements and Supplementary Data ........................................................................... ................................. 85 Item 9. Change in and Disagreements with Accountants on Accounting and Financial Disclosure ................................... .... 146

Item 9A. Controls and Procedures .............................................................................................. .............................................. 146

Item 9B. Other Information .................................................................................................... .................................................... 147

PART III

Item 10. Directors, Executive Officers and Corporate Governance ............................................................... ........................... 148 Item 11. Executive Compensation ............................................................................................... ............................................. 155 Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters .................... 18 2 Item 13. Certain Relationships and Relate d Transactions, and Director Independence ............................................ .............. 184 Item 14. Principal Accounting Fees and Services ............................................................................... ...................................... 186

PART IV

Item 15. Exhibits and Financ ial Statement Schedules ........................................................................... ................................... 187 Reports of Independent Registered Public Accounting Firm - HEI ................................................................ ....................................... 188 Reports of Independent Registered Public Accounting Firm - HECO ............................................................... .................................... 190

Index to Exhibits ............................................................................................................. ....................................................................... 196 Signatures .................................................................................................................... ......................................................................... 196ii GLOSSARY OF TERMS

Defined below are certain te rms used in this report:

Terms Definitions

2005 Act Public Utility Holding Company Act of 2005

ABO Accumulated benefit obligations

AES Hawaii AES Hawaii, Inc.

AFUDC Allowance for funds used during construction

AOCI Accumulated other comprehensive income (loss)

AOS Adequacy of supply

APBO Accumulated postretirement benefit obligation

ASB American Savings Bank, F.S.B., a wholly-owned subsidiary of American Savings Holdings, Inc.

ASC Accounting Standards Codification

ASU Accounting Standards Update

ASHI American Savings Holdings, Inc., a wholly-owned subsidia ry of Hawaiian Electric Industries, Inc. and the parent company of American Savings Bank, F.S.B.

BIF Bank Insurance Fund

Btu British thermal unit

CAA Clean Air Act

CERCLA Comprehensive Environmental Response, Compensation and Liability Act

CESP Clean Energy Scenario Planning

Chevron Chevron Products Company, a fuel oil supplier

CHP Combined heat and power

CIP Campbell Industrial Park

CIS Customer Information System Company When used in Hawaiian Electric Industries, Inc. secti ons, “Company” refers to Hawaiian Electric Industries, Inc. and its direct and indirect subsidiaries, including, without limitation, Hawaiian Electric Company, Inc. and its subsidiaries (listed under HECO); American Savings Holdings, Inc. and its subsidiary, American Savings Bank, F.S.B.; HEI Properties, Inc.; Hawaiian Electric Industries Capital Trust II and Hawaiian Electric Industries Capital Trust III (inactive finan cing entities); and The Old Oahu Tug Service, Inc. (formerly Hawaiian Tug & Barge Corp.). When used in Hawaiian Electric Company, Inc. secti ons, “Company” refers to Hawaiian Electric Company,

Inc. and its direct subsidiaries.

Consumer Advocate Division of Consumer Advocacy, Department of Co mmerce and Consumer Affairs of the State of Hawaii

CT-1 Combustion turbine No. 1

D&O Decision and order

DBF State of Hawaii Department of Budget and Finance

DG Distributed generation

DOD Department of Defense – federal

Dodd-Frank Act Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010

DOH Department of Health of the State of Hawaii

DRIP HEI Dividend Reinvestment and Stock Purchase Plan

DSM Demand-side management

ECAC Energy cost adjustment clauses

EIP 2010 Executive Incentive Plan, as amended Energy Agreement Agreement dated October 20, 2008 and signed by the Governor of the State of Hawaii, the State of Hawaii Department of Business, Economic Development and Tourism, the Division of Consumer Advocacy of the Department of Commerce and Consumer Affairs, and HECO, for itself and on behalf of its electric utility subsidiaries, committing to actions to develop renewable energy and reduce dependence on fossil fuels in support of the HCEI

EOTP East Oahu Transmission Project

EPA Environmental Protection Agency - federal

ERISA Employee Retirement Income Security Act of 1974, as amendediii GLOSSARY OF TERMS (continued)

Terms Definitions

ERL Environmental Response Law of the State of Hawaii

FASB Financial Accounting Standards Board

FDIC Federal Deposit Insurance Corporation

FDICIA Federal Deposit Insurance Corporation Improvement Act of 1991

federal U.S. Government

FERC Federal Energy Regulatory Commission

FHLB Federal Home Loan Bank

FHLMC Federal Home Loan Mortgage Corporation

FICO Financing Corporation

FNMA Federal National Mortgage Association

FRB Federal Reserve Board

GAAP U.S. generally accepted accounting principles

GHG Greenhouse gas

GNMA Government National Mortgage Association

Gramm Act Gramm-Leach-Bliley Act of 1999

HCEI Hawaii Clean Energy Initiative

HC&S Hawaiian Commercial & Sugar Company , a division of A&B-Hawaii, Inc.

HECO Hawaiian Electric Company, Inc., an electric utility subsid iary of Hawaiian Electric Industries, Inc. and parent company of Hawaii Electric Light Company, Inc., Maui Electric Company, Limited, HECO Capital Trust III (unconsolidated subsidiary), Renewable Hawa ii, Inc. and Uluwehiokama Biofuels Corp.

HECO’s Consolidated

Financial Statements Hawaiian Electric Company, Inc.’s Consolidated Financia l Statements, which are incorporated into Parts I, II, III and IV of this Form 10-K by reference to HECO Exhibit 99.2

HECO’s MD&A Hawaiian Electric Company, Inc.’s Management’s Di scussion and Analysis of Financial Condition and Results of Operations, which is incorporated into Part I, Item 1 and Part II, Item 7 of this Form 10-K by

reference to HECO Exhibit 99.2

HEI Hawaiian Electric Industries, Inc., direct parent co mpany of Hawaiian Electric Company, Inc., American Savings Holdings, Inc., HEI Properties, Inc., Hawaii an Electric Industries Capital Trust II, Hawaiian Electric Industries Capital Trust III and The Old Oahu Tug Service, Inc. (formerly Hawaiian Tug & Barge Corp.). HEI 2012 Proxy

Statement Selected sections of Hawaiian Electric Industries, In c.’s 2012 Proxy Statement to be filed after the date of this Form 10-K, which are incorporated into this Form 10-K by reference

HEI’s Consolidated

Financial Statements Hawaiian Electric Industries, Inc.’s Consolidated Financ ial Statements, including notes, in Item 8 of this

Form 10-K

HEI’s MD&A Hawaiian Electric Industries, Inc.’s Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this Form 10-K

HEIII HEI Investments, Inc. (formerly HEI Investment Corp.) (dissolved in 2008), a direct subsidiary of Hawaiian Electric Industries, Inc. since January 2007 and former ly a wholly-owned subsidiary of HEI Power Corp.

HEIPI HEI Properties, Inc., a wholly-owned subsidiary of Hawaiian Electric Industries, Inc.

HEIRSP Hawaiian Electric Industries Retirement Savings Plan

HELCO Hawaii Electric Light Company, Inc., an electric utilit y subsidiary of Hawaiian Electric Company, Inc.

HEP Hamakua Energy Partners, L.P., formerly known as Encogen Hawaii, L.P.

HITI Hawaiian Interisland Towing, Inc.

HTB Hawaiian Tug & Barge Corp. On November 10, 1999, HT B sold substantially all of its operating assets and the stock of Young Brothers, Limited, and change d its name to The Old Oahu Tug Services, Inc.

IPP Independent power producer

IRP Integrated resource plan

IRR Interest rate risk

Kalaeloa Kalaeloa Partners, L.P.

kV Kilovolt

KWH Kilowatthour

LSFO Low sulfur fuel oil

LTIP Long-term incentive planiv GLOSSARY OF TERMS (continued)

Terms Definitions

MBtu Million British thermal unit

MD&A Management’s Discussion and Analysis of Financ ial Condition and Results of Operations

MECO Maui Electric Company, Limited, an electric utilit y subsidiary of Hawaiian Electric Company, Inc. Moody’s Moody’s Investors Service’s

MSFO Medium sulfur fuel oil

MW Megawatt/s (as applicable)

NA Not applicable

NAAQS National Ambient Air Quality Standard

NM Not meaningful

NPBC Net periodic benefits costs

NQSO Nonqualified stock options

O&M Operation and maintenance

OCC Office of the Comptroller of the Currency

OPA Federal Oil Pollution Act of 1990

OPEB Postretirement benefits other than pensions

OTS Office of Thrift Supervision, Department of Treasury

OTTI Other-than-temporary impairment

PBO Projected benefit obligation

PCB Polychlorinated biphenyls

PECS Pacific Energy Conservation Services, Inc., a wholly-ow ned subsidiary of Hawaiian Electric Industries, Inc.

PGV Puna Geothermal Venture

PPA Power purchase agreement

PPAC Purchased power adjustment clause

PSD Prevention of Significant Deterioration

PUC Public Utilities Commission of the State of Hawaii

PURPA Public Utility Regulatory Policies Act of 1978

QF Qualifying Facility under the Public Utility Regulatory Policies Act of 1978

QTL Qualified Thrift Lender

RAM Revenue adjustment mechanism

RBA Revenue balancing account

RCRA Resource Conservation and Recovery Act of 1976

REG Renewable Energy Group Marketing & Logistics Group LLC Registrant Each of Hawaiian Electric Industries, Inc. and Hawaiian Electric Company, Inc.

RHI Renewable Hawaii, Inc., a wholly owned subsidiary of Hawaiian Electric Company, Inc.

ROACE Return on average common equity

RORB Return on rate base

RPS Renewable portfolio standards

S&P Standard & Poor’s

SAIF Savings Association Insurance Fund

SAR Stock appreciation right

SEC Securities and Exchange Commission

See Means the referenced material is incorporated by refer ence to HECO Exhibit 99.2 as if fully set forth herein (or means refer to the referenced section in this document or the referenced document)

SOIP 1987 Stock Option and Incentive Plan, as amended

ST Steam turbine

state State of Hawaii

Tesoro Tesoro Hawaii Corporation dba BHP Petroleum Am ericas Refining Inc., a fuel oil supplier

TOOTS The Old Oahu Tug Service, Inc., a wholly-owned subs idiary of Hawaiian Electric Industries, Inc.

UBC Uluwehiokama Biofuels Corp., a non-regulated subsid iary of Hawaiian Electric Company, Inc.

UST Underground storage tank

VIE Variable interest entityv Forward-Looking Statements

This report and other presentations made by Hawaiian Electric I ndustries, Inc. (HEI) and Hawaiian Electric Company, Inc. (HECO) and their subsidiaries contain “forward-looking statements,” which incl ude statements that are predictive in nature, depend upon or refer to future events or conditions, and usually include words such as “expects,” “anticipates,” “int ends,” “plans,” “believes,” “predicts,” “ estimates” or similar expressions. In addition, any statements concerning fu ture financial performance, ongoing business strategies or prospe cts or possible future actions are also forward-looking statements. Forward-looking statements are based on current expectations and p rojections 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 industrie s 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 caus e actual results to differ materially from those described in forwardlooking statements and from historical results include, but are not limited to, the following:

 international, national and local economic conditions, includ ing the state of the Hawaii tourism, defense and construction industries, the strength or weakness of t he Hawaii and continental U.S. real estate markets (including the fair value and/or th e 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), decisio ns concerning the extent of the presenc e of the federal government and military in Hawaii, the implications and potential impacts of U.S. and fo reign 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 o f governmental regimes in North Africa and the Middle East, terro rist acts, the war on terroris m, continuing U.S. presence in Afghanistan and potential conflict or crisis with North Korea or Iran);

 weather and natural disasters (e.g., hurricanes, earthquakes, ts unamis, 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 obt ain commercial paper and other short-term and long-term debt financing (including lines of credit) and to access capital ma rkets 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 re tirement plan assets and securities available for sale;

 changes in laws, regulations, market conditions and other factor s 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 electr ic 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 st ate, independent power producers (I PPs) 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 implementat ion of the HCEI on future costs of electricity);

 capacity and supply constraints or difficultie s, especially if generating units (utility -owned or IPP-owned) fail or measures s uch as demand-side management (DSM), distributed generation (DG), co mbined 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 generati on 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 e lectric utilities of their energy cost adjustment clauses (ECACs);

 the impact of fuel price volatility on customer satisf action and political and regulatory support for the utilities;vi  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 renew able energy generation and the operational impacts of adding

intermittent sources of renewabl e 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, periodicall y, 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 uti lity plants) and incidents at data processing centers they use, to the extent not prevented by intrusion detection and prevention system s, anti-virus software, firewalls and other general informatio n technology controls;

 federal, state, county and international governmental and regulat ory 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 la ws and regulations, the regul ation of greenhouse gas (GHG) emissions, governmental fees and assessments (such as Feder al 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 (incl uding the risks of delays in the timing of decisions, adverse changes in final decisions from interim decisions and the disallow ance of project costs as a result of adverse regulatory audit reports or otherwise);

 decisions by the PUC and by other agencies and courts on l and 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 regulati ons 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 rela tionships (i.e., concentrations of large loans and/or cre dit 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. a ccounting 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 secu rities of HEI and HECO and the results of financing efforts;

 faster than expected loan prepayments that can cause an acce leration 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 whic h may increase or decrease the required level of allowance for loan losses and charge-offs;

 changes in ASB’s deposit cost or mix which ma y 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 ar e uninsured (e.g., damages to the utilities’ transmission and distribution system and losses from business interruption) or unde rinsured (e.g., losses not covered as a result of insurance deductibles or other exclusions or exceeding policy limits); and

 other risks or uncertainties described elsew here in this report (e.g., Item 1A. Risk Fact ors) and in other r eports previously a nd 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 repor t, presentation or filing in which they are made. Except to t he extent required by the federal securities laws, HEI, HECO, ASB and thei r subsidiaries undertake no obligation to publicly update or re vise any forward-looking statements, whether as a result of new information, future events or otherwise.1 

### PART I

ITEM 1. BUSINESS

HEI Consolidated

HEI and subsidiaries and lines of business. HEI was incorporated in 1981 un der the laws of the State of Hawaii and is a holding company with its principa l subsidiaries engaged in electric utility and banking businesses operating primarily in t he State of Hawaii. HEI’s predecesso r, HECO, was incorporated under the laws of the Kingdom of Hawaii (now the State of Hawaii) on October 13, 1891. As a re sult of a 1983 corporate reorganization, HECO became an HEI subsidiary and common shareholders of HECO became common

shareholders of HEI. HECO and its operating utility subsidiaries, Hawa ii Electric Light Company, Inc. (HELCO) and Maui Electric Company, Limited (MECO), are regulated electri c public utilities. HECO also owns all the common securities of HECO Capital Trust III (a Delaware statutory trust), which wa s formed to effect the issuance of $50 million of cumulative quarterly income preferred securities in 200 4, for the benefit of HECO, HELCO and MECO. In December 2002, HECO formed a subsidiary, Renewable Hawaii, Inc., to invest in renewable energy projects, but it has made no invest ments and currently is inactive. In September 2007, HECO formed another subsidiary, Uluwehiokama Biofuels Corp. (UBC), to invest in a biodiesel refining plant to be built on the island of Maui, which project has been terminated.
Besides HECO and its subsidiaries, HEI also curr ently owns directly or indirectly the following subsidiaries: American Savings Holdings, Inc. (ASH I) (a holding company) and its subsidiary, ASB; HEI Properties, Inc. (HEIPI); Hawaiian Electric Industries Capital Trusts II and III (both formed in 1997 to be available for trust securities financings); and The Old Oahu Tug Service, Inc. (TOOTS). ASB, acquired by HEI in 1988, is one of the largest financ ial institutions in the St ate of Hawaii with assets
of $4.9 billion as of December 31, 2011. HEIPI, whose predecessor company was formed in Febr uary 1998, holds venture capital investments with a carrying value of $0.6 million as of December 31, 2011. TOOTS administers certain employee and retiree-rela ted benefit programs and monitors matters related to its predecessor’s former maritime freight transportation operations. For additional information about the Company require d by this item, see HEI’s “Management’s Discussion and Analysis of Financial Condition and Results of Operations” (HEI ’s MD&A), HEI’s “Quantitative and

Qualitative Disclosures about Ma rket Risk” and HEI’s Consolidated Financial Statements, and also see HECO’s “Management’s Discussion and Anal ysis of Financial Condition and Re sults of Operations” (HECO’s MD&A) and HECO’s “Quantitative and Q ualitative Disclosures About Mark et Risk” and HECO’s Consolidated Financial Statements, which are incorporat ed by reference to HECO Exhibit 99.2. The Company’s website address is www.hei.com. The information on the Company’s website is not incorporated by reference in this annual report on Form 10-K unless, and exc ept to the extent, specifically incorporated herein by reference. HEI and HECO currently make available free of charge through this website their annual reports on Form 10-K, quar terly reports on Form 10-Q, cu rrent reports on Form 8-K and all amendments to those reports (since 1994) as soon as reasonably practicable after such material is electronically filed with, or furnis hed to, the SEC. HEI and HECO intend to continue to use HEI’s website as a means of disclosing additional information. Such discl osures will be included on HEI’s website in the Investor Relations section. Accordingly, invest ors should routinely monitor such porti ons of HEI’s website, in addition to following HEI’s, HECO’s and ASB’s press releases, SEC filings and public conference calls and webcasts. Investors may also wish to refer to the PUC website at dms.puc.hawaii.gov/dms in order to review documents filed with and issued by the PUC. No information at t he PUC website is incorporat ed herein by reference.

Commitments and contingencies . See “HEI Consolidated—Liquidity and capital resources –Selected contractual obligations and commitments” in HEI’s MD&A, HECO’s “Commitments and contingencies” below

and Note 4 of HEI’s “Notes to Consolidated Financ ial Statements.”2 Regulation. HEI and HECO are each holding companies within the meaning of the Public Utility Holding Company Act of 2005 and implementi ng regulations (2005 Act). The 2005 Ac t requires holding companies and their subsidiaries to grant the Federal Energy Regulatory Commission (FERC) access to books and records relating to FERC’s jurisdictional rates. FERC granted HE I and HECO a waiver from its record retention, accounting and reporting require ments, effective May 2006. HEI is subject to an agreement entered into with the PUC (the PUC Agreement) which, among other things, requires HEI to provide the PUC with peri odic financial information and other reports concerning intercompany transactions and other matter s. It also prohibits the electric utilities from loaning funds to HEI or its nonutility subsidiaries and from redeeming common sto ck of the electric utility subsidiaries without PUC approval. Further, the PUC could limit the ability of the el ectric utility subsidiaries to pay dividends on their

common stock. See “Restrictions on dividends and other di stributions” and “Electric utility—Regulation” below. HEI and ASHI are subject to Federal Reserve B oard (FRB) registration, supervision and reporting requirements as savings and loan hol ding companies. As a result of the enactment of the Dodd-Frank Act, supervision and regulation of HEI and ASHI, as thrift hol ding companies, moved to the FRB, and supervision and regulation of ASB, as a f ederally chartered savings bank, moved to the Office of the Comptroller of the Currency (OCC) in July 2011. In the event the OCC has reasonable cause to believe that any activity of HEI

or ASHI constitutes a serious risk to the financia l safety, soundness or stability of ASB, the OCC is authorized to impose certain restricti ons on HEI, ASHI and/or any of their s ubsidiaries. Possible restrictions include precluding or limiting: (i) the payment of dividends by ASB; (ii) transactions between ASB, HEI or ASHI, and their subsidiaries or affiliates; and (iii) any ac tivities of ASB that might expose ASB to the liabilities

of HEI and/or ASHI and their other affiliates. See “Restrictions on dividends and other distributions” below. Bank regulations generally prohibit savings and loan holding companies and their nonthrift subsidiaries from engaging in activities other than those which are specifically enum erated in the regulations. However, the unitary savings and loan holding company relationship among HEI, ASHI and ASB is “grandfathered” under the Gramm-Leach-Bliley Act of 1999 (Gramm Act) so that HEI and its subsidiaries will be able to continue to engage in their current activities so long as ASB satisfies the qualified thrift lender (QTL) test discussed under “Bank—Regulation—Qualified thrift lender test.” ASB met the QTL test at all times during
2011; however, the failure of ASB to sati sfy the QTL test in the future coul d result in a need for HEI to divest ASB. HEI is also affected by provisions of the Dodd-Frank Act relating to corporate governance and executive compensation, including provisions requiri ng shareholder “say on pay” and “say on pay frequency” votes, mandating additional disclosures concerning executive compensation and compensation consultants and advisors, further restricting pr oxy voting by brokers in the absence of instructions and permitting the SEC to adopt rules in its discretion requiring public companies under specified conditions to include shareholder nominees in management’s pr oxy solicitation materials. See “Bank—Legislation and regulation”

in HEI’s MD&A for a discussion of the effe cts of the Dodd-Frank Act on HEI and ASB.

Restrictions on dividends and other distributions. HEI is a legal entity separate and distinct from its various subsidiaries. As a holding company with no signific ant operations of its own, HEI’s principal sources of

funds are dividends or other distribut ions from its operating subsidiaries, borrowings and sales of equity. The rights of HEI and, consequently , its creditors and shareholders, to participat e in any distribution of the assets of any of its subsidiaries are subject to the prior clai ms of the creditors and pref erred shareholders of such subsidiary, except to the extent that claims of HEI in its capacity as a credito r are recognized as primary.

The abilities of certain of HEI’s s ubsidiaries to pay dividends or make ot her distributions to HEI are subject to contractual and regulatory restri ctions. Under the PUC Agreement, in the event that the consolidated common stock equity of the electric utility subsidiaries falls below 35% of the total capi talization of the electric utilities (including the current maturiti es of long-term debt, but excluding short-term borrowings), the electric utility subsidiaries would, absent PUC approval, be restri cted in their payment of cash dividends to 80% of the earnings available for the payment of dividends in the current fiscal year and preceding five years, less the amount of dividends paid during that period. The PUC Agreement also pr ovides that the foregoing dividend restriction shall not be construed as relinquishing any right the PUC may have to review the dividend policies of the electric utility subsidiaries. As of December 31, 2011, the cons olidated common stock equity of HEI’s electric utility subsidiaries was 56% of their total capitalization (as calculated for purposes of the PUC3 Agreement). As of December 31, 2011, HECO and its subsidiaries had co mmon stock equity of $1.4 billion of which approximately $588 million was not available fo r transfer to HEI without regulatory approval. The ability of ASB to make capital distributions to HEI and other affiliates is restricted under federal law. Subject to a limited exception for stock redemptions t hat do not result in any decrease in ASB’s capital and would improve ASB’s financial condition, ASB is prohi bited from declaring any dividends, making any other capital distributions, or paying a management fee to a controlling person if, follo wing the distribution or payment, ASB would be deemed to be undercapitalized, significantly undercapitalized or critically undercapitalized. See “Bank—Regul ation—Prompt corrective action.” All c apital distributions are subject to a prior indication of no objection by the OCC and FRB. Also see Note 13 to HEI’s Consolidated Financial

Statements. HEI and its subsidiaries are also subject to debt co venants, preferred stock resolutions and the terms of guarantees that could limit their respective abilities to pay dividends. The Company does not expect that the regulatory and contractual restrictions applicable to HEI and/or its subsidiaries will significantly affect the operations of HEI or its ability to pay dividends on its common stock.

Environmental regulation . HEI and its subsidiaries are subject to federal and state statutes and governmental regulations pertaining to water quality, air quality and other environmental factors. See the “Environmental regulation” discussions in the “Electric utility” and “Bank” sections below.

Securities ratings. See the Standard & Poor’s (S&P) and Moody’s Investors Service’s (Moody’s) ratings of HEI’s and HECO’s securities and discussion under “Liquidi ty and capital resources” (both “HEI Consolidated” and “Electric utility”) in HEI’s MD&A. These ratings reflect only the view, at the time the ratings are issued, of the applicable rating agency from whom an explanation of the significance of such ratings may be obtained. There is no assurance that any such credit rating will remain in effect for any given per iod of time or that such rating will not be lowered, suspended or withdrawn entirely by the applicable rating agency if, in such rating agency’s judgment, circumstances so warrant. Any such lo wering, suspension or withdrawal of any rating may have an adverse effect on the market price or marketab ility of HEI’s and/or HECO’s securities, which could increase the cost of capital of HEI and HECO. Neither HEI nor HECO management can predict future rating agency actions or their effect s on the future cost of capital of HEI or HECO. Revenue bonds are issued by the Department of Budget and Finance of the State of Hawaii for the benefit
of HECO and its subsidiaries, but the source of their repayment are the uns ecured obligations of HECO and its subsidiaries under loan agreements and notes issued to the Department, including HECO’s guarantees of its subsidiaries’ obligations. The paym ent of principal and interest due on revenue bonds currently outstanding and issued prior to 2009 are insured, but the ratings of several of these in surers have declined to ratings below HECO ratings—see “Electric Utility—Liquidity and capital resources” in HEI’s MD&A.

Employees. The Company had full-time employees as follows:

December 31 2011 2010 2009 2008 2007

HEI 40 34 34 41 42
HECO and its subsidiaries 2,518 2,317 2,297 2,203 2,145
ASB and its subsidiaries 1,096 1,075 1,119 1,313 1,330

Other subsidiaries – – 3 3 3

3,654 3,426 3,453 3,560 3,520

The employees of HEI and its direct and indirect s ubsidiaries, other than the electric utilities, are not covered by any collective bargaini ng agreement. A substantial number of employees of HECO and its subsidiaries are covered by collective bargaining agr eements. See “Collective bargaining agreements” in

Note 3 to HEI’s Consolidated Financial Statements.

Properties. HEI leases office space from nonaffiliated lessors in downtown Honolulu under leases that expire in March 2016. HEI also subleases office space in a downtown Honolulu buildi ng leased by HECO under a lease that expires in November 2021, with an option to extend to November 2024. See the discussions under “Electric Utility” and “Bank” below for a description of properties owned by HEI subsidiaries.4 Electric utility

HECO and subsidiaries and service areas. HECO, HELCO and MECO are re gulated operating electric public utilities engaged in the production, purchase, transmission, distributi on and sale of electricity on the
islands of Oahu; Hawaii; and Maui, Lanai and Moloka i, respectively. HECO acquired MECO in 1968 and
HELCO in 1970. In 2011, the electric utilities’ revenues and net income amounted to approximately 92% and 72%, respectively, of HEI’s consolidated revenues and net income, compared to approximately 89% and 67% in 2010, and approximately 88% and 96% in 2009, respectively.
The islands of Oahu, Hawaii, Maui, Lanai and Mo lokai have a combined population estimated at 1.2 million, or approximately 95% of the total population of the State of Hawaii, and comprise a service area of 5,766 square miles. The principal communities served include Honolulu (on Oahu), Hilo and Kona (on Hawaii) and Wailuku and Kahului (on Maui). The service areas also include numerous suburban communities, resorts, U.S. Armed Forces installations and agricultural oper ations. The state has granted HECO, HELCO and MECO
nonexclusive franchises, which authoriz e the utilities to construct, operate and maintain facilities over and under public streets and sidewalks. Each of these franchises will continue in effect for an indefinite period of time until forfeited, altered, amended or repealed.
For additional information about HECO, see HECO ’s MD&A, HECO’s “Quant itative and Qualitative

Disclosures about Market Risk” and HECO ’s Consolidated Financial Statements.

Sales of electricity.

Years ended December 31 2011 2010 2009

Customer Electric sales Customer Elec tric sales Customer Electric sales (dollars in thousands) accounts* revenues accounts* revenues accounts* revenues
HECO 296,800 $2,103,859 296,422 $1,645,328 295,282 $1,379,208
HELCO 81,199 443,189 80,695 371,746 79,813 342,982
MECO 68,230 417,451 67,739 343,562 67,489 296,433
446,229 $2,964,499 444,856 $2,360,636 442,584 $2,018,623

* As of December 31.
Seasonality. Kilowatthour (KWH) sales of HECO and its subs idiaries follow a seasonal pattern, but they do not experience extreme seasonal variations due to extreme weather variations experienced by some

electric utilities on the U. S. mainland. KWH sales in Hawaii tend to increase in the warmer, more humid months, probably as a result of in creased demand for air conditioning.

Significant customers. HECO and its subsidiaries derived approximately 11%, 10% and 10% of their operating revenues in 2011, 2010 and 2009, respectively, fr om the sale of electricity to various federal government agencies. Under the Energy Policy Act of 2005, the Energy Independence and Security Act of 2007 and/or executive orders: (1) federal agencies must establish energy cons ervation goals for federally funded programs, (2) goals were set to reduce federal agencies’ energy consumption by 3% per y ear up to 30% by fiscal year 2015 relative to fiscal year 2003, and (3) renewable energy g oals were established for electricity consumed by federal agencies. HECO continues to work with various federal agencies to implement measures that will help them achieve their energy reducti on and renewable ener gy objectives.

Energy Agreement, energy efficiency and decoupling. On October 20, 2008, the Governor, the Hawaii Department of Business Economic Development and T ourism, the Consumer Advocate and the utilities entered into an Energy Agreement pursuant to which t hey agreed to undertake a number of initiatives to help accomplish the objectives of the Hawaii Clean Energy Initiative (HCEI) established under a memorandum of understanding between the State of Hawaii and U.S. Department of Energy. T he primary objective of the HCEI and Energy Agreement is to reduce Hawaii’s dependence on imported fuels through substantial increases in the use of renewable energy and im plementation of new programs int ended to secure greater energy efficiency and conservation. See Note 3 of HEI’s Cons olidated Financial Statements. One of the initiatives under the Energy Agreement was adv anced when, in 2009, the state legi slature enacted Act 155, which gave the PUC the authority to establish an Energy Efficiency Portfolio St andard (EEPS) goal of 4,300 GWH of electricity use reductions by 2030. The PUC issued a decision and order (D&O) on January 3, 2012 approving5 a framework for EEPS that set 2008 as the initial base year for evaluati on and linearly allocated the 2030 goal to interim incremental reduction goals of 1,375 GW H by 2015 and 975 GWH by each of the years 2020, 2025 and 2030. These goals may be revised through goal evaluations scheduled every five years or as the result of recommendations by an EEPS technical working group (T WG) for consideration by the PUC. The interim and final reduction goals will be alloca ted among contributing entities by t he EEPS TWG. The PUC may establish penalties in the future. Another of the initiatives was advanced when the PUC appr oved the implementation of revenue decoupling for HECO and HELCO under which HE CO (beginning in 2011) and HELCO (to begin later in 2012) are allowed to recover PUC-approved revenue requirements that are not based on the amount of electricity sold. Both the EEPS and the implementatio n of revenue decoupling could have an impact on sales. However, neither HEI nor HECO management can predic t with certainty the im pact of these or other governmental mandates, the HCEI or the Energy Agreement on HEI’s or HECO ’s future results of operations, financial condition or liquidity.6 Selected consolidated electri c utility operating statistics.

Years ended December 31 2011 2010 2009 2008 2007

KWH sales (millions)
Residential 2,769.7 2,830.0 2,893.3 2,924.7 3,035.5
Commercial 3,203.8 3,185.0 3,221.7 3,326.3 3,340.6 Large light and power 3,503.4 3,512.8 3,524.5 3,632.9 3,690.2

Other 50.0 50.8 50.2 52.3 51.8

9,526.9 9,578.6 9,689.7 9,936.2 10,118.1

KWH net generated and purchased (millions) Net generated 6,022.2 6,053.6 6,117.6 6,261.8 6,478.6
Purchased 4,009.7 4,062.8 4,119.8 4,248.2 4,228.0

10,031.9 10,116.4 10,237.4 10,510.0 10,706.6

Losses and system uses (%) 4.8 5.1 5.1 5.2 5.3

Energy supply (December 31) Net generating capability—MW 1 1,787 1,785 1,815 1,687 1,685 Firm purchased capability—MW 540 540 532 540 538

2,327 2,325 2,347 2,227 2,223

Net peak demand—MW 2 1,530 1,562 1,618 1,590 1,635 Btu per net KWH generated 10,609 10,617 10,753 10,700 10,807 Average fuel oil cost per Mbtu (cents) 1,986.7 1,404.8 1,026.4 1,840.0 1,108.2

Customer accounts (December 31)
Residential 390,133 388,307 385,886 383,042 381,964
Commercial 53,904 54,374 54,527 55,243 55,869 Large light and power 567 548 558 543 554
Other 1,625 1,627 1,613 1,583 1,510

446,229 444,856 442,584 440,411 439,897

Electric revenues (thousands)
Residential $ 946,653 $ 781,467 $ 690,656 $ 935,061 $ 713,241
Commercial 1,024,725 814,109 694,087 973,048 714,218 Large light and power 976,949 752,056 623,159 921,321 652,298
Other 16,172 13,004 10,721 15,069 10,791
$2,964,499 $2,360,636 $2,018,623 $2,844,499 $2,090,548

Average revenue per KWH sold (cents) 31.12 24.65 20.83 28.63 20.66

Residential 34.18 27.61 23.87 31.97 23.50

Commercial 31.99 25.56 21.54 29.25 21.38 Large light and power 27.89 21.41 17.68 25.36 17.68

Other 32.37 25.63 21.36 28.81 20.81

Residential statistics Average annual use per customer account (KWH) 7,117 7,317 7,523 7,640 7,996 Average annual revenue per customer account $2,433 $2,021 $1,796 $2,443 $1,879 Average number of customer accounts 389,160 386,767 384,600 382,821 379,621

1 The reduction in net generating capability in 2010 was attributabl e to the removal of distributed generation units at substati ons.

2 Sum of the net peak demands on all islands served, noncoincident and nonintegrated.7 Generation statistics. The following table contains certain generati on statistics as of, and for the year ended, December 31, 2011. The net generating and firm purchased capability availabl e for operation at any given time may be more or less than shown because of capability re strictions or temporary outages for inspection, maintenance, repairs or unforeseen circumstances.

Island of

OahuHECO Island of

HawaiiHELCO Island of

MauiMECO Island of

LanaiMECO Island of

MolokaiMECO Total

Net generating and firm purchased capability (MW) as of December 31, 2011 1
Conventional oil-fired steam units 1,106.8 63.8 35.9 – – 1,206.5

Diesel – 30.8 96.8 10.1 9.6 147.3 Combustion turbines (peaking units) 214.8 – – – – 214.8

Other combustion turbines – 46.3 – – 2.2 48.5 Combined-cycle unit – 56.2 113.6 – – 169.8 Firm contract power 2 434.0 90.0 16.0 – – 540.0

1,755.6 287.1 262.3 10.1 11.8 2,326.9

Net peak demand (MW) 1,141.0 189.2 189.9 4.6 5.7 1,530.4 3 Reserve margin 55.8% 51.7% 38.1% 120.0% 107.8% 56.1%

Annual load factor 76.0% 71.6% 71.6% 64.8% 67.4% 74.8% KWH net generated and purchased (millions) 7,593.8 1,186.6 1,191.8 26.1 33.6 10,031.9

1 HECO units at normal ratings; MECO and HELCO units at reserve ratings.

2 Nonutility generators— HECO: 208 MW (Kalaeloa Partners, L.P., oil-fired), 180 MW (AES Hawaii, Inc., coal-fired) and 46 MW (HPower, refuse-fired); HELCO: 30 MW (Puna Geothermal Vent ure, geothermal) and 60 MW (Hamakua Energy Partners, L.P., oil-fired); MECO: 16 MW (Hawaiian Commercial & Sugar Company, primarily bagasse-fired).

3 Noncoincident and nonintegrated.

Generating reliability and reserve margin. HECO serves the island of Oahu and HELCO serves the island of Hawaii. MECO has three separat e electrical systems—one each on the islands of Maui, Molokai and Lanai. HECO, HELCO and MECO have isolated electrical systems that are not currently interconnected to each other or to any other electrical grid and, thus, each mainta ins a higher level of reserve generation than is typically carried by interconnected mainland U.S. utilities, which are able to share reserve capacity. These higher levels of reserve margins are required to meet peak el ectric demands, to provide for scheduled maintenance of generating units (including the units operated by IPPs re lied upon for firm capacity) and to allow for the forced outage of the largest generat ing unit in the system. See “Adequacy of supply” in HEI’s MD&A under “Electric utility.”

Nonutility generation. The Company has supported state and fe deral energy policies which encourage the development of renewable energy source s that reduce the use of fuel o il as well as the development of qualifying facilities. The Company’s renewable energy source s and potential sources range from wind, solar, photovoltaic, geothermal, wave and hydroelectric pow er to energy produced by the burning of bagasse (sugarcane waste), municipal waste and other biofuels. The rate schedules of HECO contain purchased power adjustment clauses that allow HECO to recover purchase power expenses through a surcharge mechanism. In addition to the firm capacity PPAs described below, the electric utilities also purchase energy on an asavailable basis directly from nonutility generators and through its Feed-In Tariff and net metering programs from renewable energy sources. The PUC has allowed rate recovery for the firm capacity and purchased energy costs for the electric utilities’ approved firm capacity and as-available energy PPAs.

HECO firm capacity PPAs. HECO currently has three major PPAs that provide a total of 434 MW of firm capacity, representing 25% of HECO’s total net generating and firm purchased capacity on Oahu as of
December 31, 2011. In March 1988, HE CO entered into a PPA with AES Bar bers Point, Inc. (now known as AES Hawaii, Inc. (AES Hawaii)), a Hawaii-based, indirect subsidiary of The AES Corporation. The agreement with AES Hawaii, as amended, provides that, for a period of 30 years beginning September 1992, HECO will purchase 180 megawatts (MW) of firm capacity. The AES Hawaii 180 MW coal-fired cogeneration plant utilizes8 a “clean coal” technology and is designed to sell suffici ent steam to be a “Qualifyi ng Facility” (QF) under the Public Utility Regulatory Po licies Act of 1978 (PURPA). In October 1988, HECO entered into an agreement wi th Kalaeloa Partners, L. P. (Kalaeloa), a limited partnership, which, through affiliates, contracted to design, build, operate and maintain a QF. The agreement with Kalaeloa, as amended, provided that HECO would purchase 180 MW of firm c apacity for a period of 25 years beginning in May 1991 and terminating in May 2016. T he Kalaeloa facility is a combined-cycle operation, consisting of two oil-fired combustion turbines burning low sulfur fuel oil (LSFO) and a steam turbine that

utilizes waste heat from the combustion turbines. Following two additional amendments, effective in 2005, Kalaeloa currently supplies HECO with 208 MW of firm capacity. In 2011, HECO fi led an application with the PUC seeking a declaratory order that HECO is exempt from the rules under the PUC’s Competitive Bidding
Framework, or in the alternative that HECO be granted a waiver from t he rules, to renegotiate the agreement in anticipation of its expiration. The PUC has not issued a declaratory order, but HECO has initiated the process of renegotiating t he agreement with Kalaeloa pendi ng the PUC’s decision.

HECO also entered into a PPA in March 1986 and a fi rm capacity amendment in April 1991 with the City and County of Honolulu with respect to a refuse-fired pl ant (HPower). The HPower facility currently supplies HECO with 46 MW of firm capacity. Under the amend ment, HECO will purchase fi rm capacity until mid-2015. HECO is currently in negotiations with the City and Co unty of Honolulu for a PPA (exempt from rules under the PUC’s Competitive Bidding Framework) to purchase a total of 73 MW of firm capacity for a term of 20 years.

HELCO and MECO firm capacity PPAs. As of December 31, 2011, HELCO has PPAs for 98 MW (of which 90 MW are currently available) and MECO has a PPA for 16 MW (inc luding 4 MW of system protection) of firm capacity. HELCO has a 35-year PPA with Puna Geothermal Vent ure (PGV) for 30 MW of firm capacity from its geothermal steam facility, which will expire on De cember 31, 2027. In Febr uary 2011, HELCO and PGV amended the current PPA for the pricing on a portion of the energy payments and entered into a new PPA for HELCO to acquire an additional 8 MW of firm, dispatc hable capacity from the facilit y. Both the amendment and the new PPA were approved by the PUC on December 30, 2011. In October 1997, HELCO entered into an agreement with Encogen, which has been succeeded by Hamakua Energy Partners, L. P. (HEP). The agreement requires HELCO to purchase up to 60 MW (net) of firm capacity for a period of 30 y ears, expiring on December 31, 203 0. The dual-train combined-cycle DTCC facility, which primarily bur ns naphtha, consists of two oil-fired com bustion turbines and a steam turbine that

utilizes waste heat from the combustion turbines. MECO has a PPA with Hawaiian Commercial & Sugar Co mpany (HC&S) for 16 MW of firm capacity. The HC&S generating units primarily burn bag asse (sugar cane waste) along with secondary fuels of diesel oil or coal. The PPA runs through December 31, 2014, and from year to year thereafter, subjec t to termination on or after December 31, 2014 on not less than two years’ prior written notice by either party.

Fuel oil usage and supply. The rate schedules of the Company’s el ectric utility subsidiaries include ECACs under which electric rates (and consequently the revenues of the electric utility subsidiaries generally) are adjusted for changes in the weighted-average price pai d for fuel oil and cert ain components of purchased power, and the relative amounts of company-generated pow er and purchased power. See discussion of rates and issues relating to the ECAC below under “Rates,” and “Electric utility—Certain factors that may affect future results and financial condition—Regulation of electric utility rates” and “Electric utility–Material estimates and critical accounting policie s–Revenues” in HEI’s MD&A. HECO’s steam generating units burn LSFO. HECO’s combustion turbine peaking units burn diesel fuel (diesel) and B99 grade biodiesel (biodi esel). HECO’s CIP CT-1 is being operated exclusively on biodiesel. A HECO steam unit has successfully completed a co-firing project to test burn mixt ures of LSFO and crude palm

oil. MECO’s and HELCO’s steam generating units burn m edium sulfur fuel oil (MSFO) and HELCO’s and

MECO’s Maui and Molokai combustion turbine and diesel engine generating units bur n diesel and biodiesel. MECO’s Lanai diesel engine generating units burn high- and ultra-low-sulfur grades of diesel. A MECO diesel generating unit has successfully complet ed a biodiesel test fire project.9 See the fuel oil commitments information set forth in the “Fuel contracts” section in Note 3 to HEI’s

Consolidated Financial Statements. The following table sets forth the average cost of fuel oil used by HECO, HELCO and MECO to generate electricity in the years 2011, 2010 and 2009:

HECO HELCO MECO Consolidated
$/Barrel ¢/MBtu $/Barrel ¢/MBtu $/ Barrel ¢/MBtu $/Barrel ¢/MBtu

2011 122.94 1,949.6 118.09 1,934.1 129.58 2,178.3 123.63 1,986.7
2010 85.49 1,352.1 89.33 1,460.4 95.17 1,595.8 87.62 1,404.8

2009 60.90 966.5 68.28 1,109.0 73.54 1,231.9 63.91 1,026.4

The average per-unit cost of f uel oil consumed to generate electri city for HECO, HELCO and MECO reflects a different volume mix of fuel types and grades as follows:

HECO HELCO MECO

LSFO Diesel/Biodiesel MSFO Diesel MSFO Diesel/Biodiesel

2011 99% 1% 56% 44% 22% 78%

2010 99 1 58 42 24 76

2009 98 2 67 33 25 75

In general, MSFO is the least costly fuel, biodiesel and diesel are the most ex pensive fuels and the price of LSFO falls in-between on a per-barrel basis. In 2011, the prices of all petro leum fuels trended strongly higher through the spring and were generally stable ther eafter. In 2011, the pr ices of LSFO, MSFO and diesel increased by approximately 40%, 40% and 30%, respectively. The per-unit price of biodiesel increased steadily with about a 42% increase in 2011.
In December 2000, HELCO and MECO executed contra cts of private carriage with Hawaiian Interisland Towing, Inc. (HITI) for the employ ment of a double-hull tank barge for t he shipment of MSFO and diesel supplies from their fuel suppliers’ facilities on Oahu to stor age locations on the islands of Hawaii and Maui, respectively, commencing January 1, 2002. The c ontracts have been extended through December 31, 2016. In July 2011, the carriage contracts were assigned to Kirby Corporation (Kirby), which provides refined petroleum and other products for marine transportation, distribution and logistics services in the U.S. domestic marine transportation industry. Kirby never takes title to the fuel oil or diesel f uel, but does have custody and control while the fuel is in

transit from Oahu. If there were an oil spill in transit, Kirby is generally contractually obligated to indemnify HELCO and/or MECO for resulting cl ean-up costs, fines and damages. Kirby maintains liability insurance coverage for an amount in excess of $1 billion for oil spill related damage. State law provides a cap of $700 million on liability for releases of heavy fuel oil transported interisland by tank barge. In the event of a release, HELCO and/or MECO may be responsible for any clean-up, damages, and/or fines that Kirby and its

insurance carrier do not cover. The prices that HECO, HELCO and MECO pay for purchased energy from nonutility generators are generally linked to the price of oil. The AES Hawaii energy prices vary primarily with an inflation index. The energy prices for Kalaeloa, which purchases LSFO from Tesoro Hawaii Corporation (Tesoro), vary primarily with world LSFO prices. The HPower, HC&S and PGV energy prices are based on the electric utilities’ respective PUC-filed short-run avoide d energy cost rates (which vary with their respective composite fuel costs), subject to minimum floor rates specified in their approved PPAs . HEP energy prices vary primarily with

HELCO’s diesel costs.

The utilities estimate that 73% of the net energy they will generat e and purchase in 2012 will be generated from the burning of fossil fuel oil. HECO generally maintains an average syst em fuel inventory level equivalent to 47 days of forward consumption. HELCO and MECO generally maintain an average system fuel inventory level equivalent to approximately one month’s supply of both MSFO and diesel. The PPAs with AES Hawaii and HEP require that they maintain ce rtain minimum fuel inventory levels.10 Rates. HECO, HELCO and MECO are subject to the regulatory jurisdiction of the PUC with respect to rates, issuance of securities, accounting and cert ain other matters. See “Regulation” below.

Rate schedules of HECO and its subsidiaries c ontain ECACs and rate schedules of HECO contain purchased power adjustment clauses (PPACs). HELCO’s rate schedules will contain PPACs when the final rates from the 2010 test year rate case become effective. Under current law and practices, specific and separate PUC approval is not requir ed for each rate change pursuant to automatic rate adjustment clauses previously approved by the PUC. All other rate increa ses require the prior approval of the PUC after public and contested case hearings. PURPA requir es the PUC to periodically review the ECACs of electric and gas utilities
in the state, and such clauses, as well as the rate s charged by the utilities generally, are subject to change. See “Electric utility–Most recent rate proceedings, “Ele ctric utility–Certain factors that may affect future results and financial condition–Regulation of electric ut ility rates” and “Electric utility–Material estimates and critical accounting policies–Revenues” in HEI’s MD &A and “Interim increases” and “Major projects” under “Commitments and contingencies” in Note 3 to HEI’s Consolidated Fi nancial Statements.

Public Utilities Commission and Division of Consumer Advocacy of the Department of Commerce and

Consumer Affairs of the State of Hawaii. Hermina Morita is the Chairman of the PUC (for a term that will expire in June 2014) and was formerly a State Repr esentative. The other commissioners are Michael E. Champley (for a term that will expire in June 2016, subject to confirmation by the State Senate), who previously was a senior energy consultant and a senior executive with DTE Energy, and John E. Cole (for a term that will expire in June 2012), who previously wa s the Executive Director of the Division of Consumer Advocacy.

The Executive Director of the Divisi on of Consumer Advocacy is Jeffrey T. Ono, an attorney previously in private practice.

Competition. See “Electric utility–Certain factors that may affect futu re results and financial condition– Competition” in HEI’s MD&A.

Electric and magnetic fields. The generation, transmission and use of electricity produces low-frequency (50Hz-60Hz) electrical and magnetic fields (EMF). While EMF has been classified as a possible human carcinogen by more than one public health organizati on and remains the subject of ongoing studies and evaluations, no definite causal relationship between EMF and health risks has been clearly demonstrated to

date and there are no federal standards in the U.S. limiting occupational or residential exposure to 50Hz-60Hz EMF. HECO and its subsidiaries are continuing to m onitor the ongoing research and continue to participate in utility industry funded studies on EMF and, where technica lly feasible and economically reasonable, continue to pursue a policy of prudent avoidance in the design and installation of new tr ansmission and distribution facilities. Management cannot predict the impact, if any, the EMF issue may have on HECO, HELCO and

MECO in the future.

Global climate change and gr eenhouse gas emissions reduction. The Company shares the concerns of many regarding the potential effects of global wa rming and the human contributions to this phenomenon, including burning of fossil fuels for electricity pr oduction, transportation, manufacturing and agricultural activities, as well as deforestation. Recognizing that effectively addressi ng global warming requires commitment by the private sector, all levels of government, and the pub lic, the Company is committed to taking direct action to mitigate greenhouse gas emission s from its operations. See “Environmental regulation– Global climate change and greenhouse gas emissions reduction” under “Co mmitments and contingencies” in

Note 3 to HEI’s Consolidated Financial Statements.

Legislation. See “Electric utility–Legislati on and regulation” in HEI’s MD&A.

Commitments and contingencies . See “Selected contractual obli gations and commitments” in HECO’s MD&A and “Electric utility–Certain fact ors that may affect future resu lts and financial condition–Other regulatory and permitting contingencies” in HEI’s MD&A , Item 1A. Risk Factors, and Note 3 to HEI’s

Consolidated Financial Statements for a discussion of important co mmitments and contingencies.11 Regulation. The PUC regulates the rates, issuance of securi ties, accounting and certai n other aspects of the operations of HECO and its electric utility subsidiari es. See the previous discussion under “Rates” and the discussions under “Electric utility–Re sults of operations–Most recent ra te proceedings” and “Electric utility– Certain factors that may affect future results and financial condition–Regulation of electric utility rates” in HEI’s

MD&A. Any adverse decision or policy made or adopted by the PUC, or any prol onged delay in rendering a
decision, could have a material adverse effect on consolidated HECO’s and the Company’s results of operations, financial condition or liquidity. On October 20, 2008, HECO signed an Energy Agreem ent (see “Hawaii Clean E nergy Initiative” under “Commitments and contingencies” in Note 3 to HEI’s Consolidated Financial Statem ents) setting forth goals, objectives and actions with the purpose of decreasing Hawaii’s dep endence on imported fossil fuels through

substantial increases in the us e of renewable energy and implement ation of new programs intended to secure greater energy efficiency and conservation. As a result of the Energy Agreement, numerous PUC proceedings have been initiated, many of which have been completed, as described elsewhere in this report. In 2009, the State Legislature amended Hawaii’s RPS law to require electric utilities (either individually or on a consolidated basis) to meet an RPS of 10% , 15%, 25% and 40% by De cember 31, 2010, 2015, 2020 and 2030, respectively. Energy savings resulting from ener gy efficiency programs will not count toward the RPS after 2014 (only electrical generation using rene wable energy as a source will count). The amended

RPS law is consistent with the co mmitment in the Energy Agreement. Certain transactions between HEI’s electric public utility subsidiaries (HECO, HELCO and MECO) and HEI and affiliated interests (as defined by statute) are subjec t to regulation by the PUC. All contracts of $300,000 or more in a calendar year for management, supervisory, c onstruction, engineering, a ccounting, legal, financial
and similar services and for the sale, lease or trans fer of property between a public utility and affiliated
interests must be filed with the PUC to be effective, and the PUC may issue cease and desist orders if such

contracts are not filed. All such “affilia ted contracts” for capital expenditures (except for real property) must be accompanied by comparative price quotations from tw o nonaffiliates, unless the qu otations cannot be obtained without substantial expense. Moreov er, all transfers of $300,000 or more of real property between a public utility and affiliated interests require the prior approval of the PUC and proof that the transfer is in the best interest of the public utility and its customers. If the PUC, in its discretion, determines that an affiliated contract is unreasonable or otherwise contrary to the public intere st, the utility must either re vise the contract or risk disallowance of payments under the c ontract for rate-making purposes. In rate-making proceedings, a utility must also prove the reasonableness of payments made to affiliated interests under any affiliated contract of $300,000 or more by clear and convincing evidence.
In December 1996, the PUC issued an order in a docket that had been opened to review the relationship

between HEI and HECO and the effects of that relationship on the operati ons of HECO. The order adopted the report of the consultant the PUC had retained and ordered HECO to continue to provide the PUC with periodic status reports on its compliance with the PUC Agr eement (pursuant to which HEI became the holding company of HECO). HECO files such status reports annually. In the order, the PUC also required HECO, HELCO and MECO to present a comprehensive analysis of the impact that the hol ding company structure and investments in nonutility subsidiaries have on a case-by- case basis on the cost of capital to each utility in future rate cases and remove any su ch effects from the cost of capi tal. HECO, HELCO and MECO have made presentations in their subsequent rate cases to support their positions that there was no evidence that would modify the PUC’s finding that HECO’s access to capita l did not suffer as a result of HEI’s involvement in nonutility activities and that HEI’s di versification did not permanently rais e or lower the cost of capital incorporated into the rates paid by HECO’s utility customers. HECO and its electric utility subsidiaries are not subject to regulation by the FERC under the Federal Power Act, except under Sections 210 through 212 (added by Title II of PURPA and amended by the Energy Policy Act of 1992), which permit the FERC to order electric utilities to interconnect with qualifying cogenerators and small power producers, and to wheel power to other electric utilities. Title I of PURPA, which relates to retail regulatory policies for electric utilitie s, and Title VII of the Energy Policy Act of 1992, which12 addresses transmission access, also apply to HECO and its electric utility subsidiaries. HECO and its electric utility subsidiaries are also required to file various operational reports with the FERC. Because they are located in the State of Hawaii, HECO and its subsidiaries are exempt by statute from limitations set forth in the Powerpl ant and Industrial Fuel Use Act of 1978 on the use of petroleum as a primary

energy source. See also “HEI–Regulation” above.

Environmental regulation . HECO, HELCO and MECO, like other utilities, are subject to periodic inspections by federal, state and, in some cases, local environmental regulator y agencies, including agencies responsible for the regulation of water quality, air quality, haz ardous and other waste, and hazardous materials. These inspections may result in the identific ation of items needing correc tive or other action. When the corrective or other necessary action is taken, no fu rther regulatory action is expec ted. Except as otherwise disclosed in this report (see “Certain factors that may affect future resu lts and financial condition–

Environmental matters” for HEI Consolidated, the Electric utility and the Bank sections in HEI’s MD&A and
Note 3 to HEI’s Consolidated Financial Statements, wh ich are incorporated herein by reference), the Company believes that each subsidiary has appropriately res ponded to environmental conditions requiring action and
that, as a result of such actions, such environmental conditions will not have a mate rial adverse effect on the Company or HECO.

Water quality controls. The generating stations, substations and other utility facilities operate under federal and state water quality regulations and permits , including but not limited to the Clean Water Act National Pollution Discharge Eliminat ion System (governing poi nt source discharges, including wastewater and storm water discharges), Underground Injection Contro l (regulating disposal of wastewater into the subsurface), the Spill Prevention, Control and Counter measure (SPCC) program, t he Oil Pollution Act of 1990 (OPA), and other regulations associated with discharge s of oil and other substances to surface water. OPA governs actual or threatened oil releases and est ablishes strict and joint and several liability for responsible parties for (1) oil remova l costs incurred by the federal gove rnment or the state, and (2) damages

to natural resources and real or personal property, as well as compens ation for certain economic damages. Responsible parties include vessel owners and operators of on-shore facilities. OPA imposes fines and jail terms ranging in severity depending on how the release was caused.
In 2011 and 2012 to date, HECO, HELCO and MECO did not experience any significant petroleum releases. The Company believes that each subsidiary’s costs of responding to petroleum releases to date will not have a

material adverse effect on the res pective subsidiary or the Company. EPA regulations under OPA also require certain fac ilities that use or store petroleum to prepare and implement SPCC Plans in order to prevent releases of petroleum to navigable wa ters of the U.S. The

determination of whether SPCC Plan requirements are applicable to a facility depends on the amount of petroleum stored at the fac ility and whether a release of petroleum coul d reach waters of the U.S. The HECO, HELCO, and MECO facilities that are subject to SPCC Plan requirements, including most power plants, base yards, and certain substations, are in compliance with SPCC Plan requirements. As required by section 316(b) of the Clean Water Act, proposed regulations gov erning protection of aquatic organisms in cooling water intake structures at three of HECO’s power plants were issued by the EPA. The EPA is scheduled to issue the final rule by July 27, 2012. Depending on the ultimate regulations adopted by the EPA, the cost of compliance could be significant.

Air quality controls. The generating stations of the utility subsidiaries operate under air pollution control permits issued by the Department of Health of the State of Hawaii (DOH) and, in a limited number of cases, by the EPA. The entire elec tric utility industry has been affected by the 1990 amendments to the Clean Air Act (CAA), changes to the National Ambient Ai r Quality Standard (NAAQS) for ozone, adoption of a NAAQS for fine particulate matter, and the EPA’s 1-hour NAAQS for ni trogen dioxide and sulfur dioxide (adopted in 2010). On December 21, 2011, the EPA issued the final rule establishing the EPA’s National

Emission Standards for Hazardous Air Pollutants for fo ssil-fuel fired steam electrical generating units (see “Environmental regulation” in Note 3 to HEI’s “N otes to Consolidated Financial Statements”).13 The EPA has also required HELCO (for its Hill Powe r Plant) and MECO (for its Kahului Power Plant) to develop evaluations of emission controls for generating units at those plants that the EPA believes contribute to Regional Haze. Under the terms of a consent dec ree, the EPA has committed to issue proposed rules, known as a Federal Implementation Plan (FIP), for the State of Hawaii by mid-May 2012 and a final FIP by mid-September 2012. Depending on final FIP, the co st of compliance for HELCO and MECO could be significant. The CAA amendments of 1990, among ot her things, established a federal operating permits program (in Hawaii known as the Covered Source Permit pr ogram) and greatly expanded the hazardous air pollutant program. The more stringent NAAQS will affect new or modified generating units requiring a permit to construct under the Prevention of Significant Deterior ation (PSD) program and the controls necessary to

meet the NAAQS. CAA operating permits (Title V permits) have been issued for all affected generating units.

Hazardous waste and toxic substances controls. The operations of the el ectric utility and former freight transportation subsidiaries of HEI are subject to EPA regulations that impl ement provisions of the Resource Conservation and Recovery Act (RCRA ), the Superfund Amendment s and Reauthorization Act (SARA) and the Toxic Substances Control Act (TSCA). RCRA underground storage tank (UST) regulations requi re all facilities with USTs used for storing petroleum products to comply with leak detection, sp ill prevention and new tank st andard retrofit requirements.
All HECO, HELCO and MECO USTs cu rrently meet these standards. The Emergency Planning and Community Right-to-Know Act under SARA Title III requires HECO, HELCO and MECO to report potentially hazardous chemicals present in their facilities in order to provide the public with information so that emergency procedures can be established to protect t he public in the event of hazardous chemical releases. All HECO, HELCO and MECO facilities are in compliance with applicable annual reporting requirements to t he State Emergency Planning Commissi on, the Local Emergency Planning Committee and local fire departments. Since January 1, 1998, the steam electric industry category has been subject to Toxics Release Inventory (TRI) reporting re quirements. All HECO, HELCO and MECO facilities are in compliance with TRI reporting requirements. The TSCA regulations specify procedures for t he handling and disposal of polychlorinated biphenyls (PCB), a compound found in some transformer and capacitor dielectric fluids. The TSCA regulations also apply to responses to releases of PCB to t he environment. HECO, HELCO and MECO have instituted procedures to monitor compliance with these regulat ions and have implemented a program to identify and replace PCB transformers and capacit ors in their systems. Management believes that all HECO, HELCO and MECO facilities are currently in compliance with PC B regulations. In April 2010, the EPA issued an Advance Notice of Proposed Rule Making announcing it s intent to reassess PCB regulations. Hawaii’s Environmental Response Law, as amended (ERL ), governs releases of hazardous substances, including oil, to the environment in areas within the state’s jurisdiction . Responsible parties under the ERL are jointly, severally and strictly liable for a release of a hazardous substance. Responsible parties include owners or operators of a facility where a hazar dous substance is located and any person who at the time of disposal of the hazardous substance owned or operated any facility at which such hazardous substance was disposed. HECO, HELCO and MECO periodically identify leaking petroleum-contai ning equipment such as USTs, piping and transformers. In a few instances, small amounts of PCBs have been id entified in the leaking equipment. Each subsidiary reports releases from su ch equipment when and as required by applicable law and addresses impacts due to the releases in comp liance with applicable r egulatory requirements.

Research and development. HECO and its subsidiaries expensed approximately $4.3 m illion, $4.0 million and $4.4 million in 2011, 2010 and 2009, respectively, fo r research and developm ent (R&D). In 2011, 2010
and 2009, the electric utilities’ contributions to t he Electric Power Research Institute accounted for approximately half of the R&D expenses. There were al so utility expenditures in 2011, 2010 and 2009 related to new technologies, biofuels, energy storage, electric and hybrid plug in vehicles and other renewables (e.g., wind and solar power integration and solar resource evaluation).14 Properties.

HECO owns and operates four gener ating plants on the island of Oahu at Honolulu, Waiau, Kahe and Campbell Industrial Park (CIP). These plants have an aggregate net generating capabilit y of 1,321.6 MW as of December 31, 2011. The four plant s are situated on HECO-owned land hav ing a combined area of 535 acres and one 3.5-acre parcel of land under a lease expiring Dece mber 31, 2018. In addition, HECO owns a total of
132 acres of land on which substations, transformer vaults, distribution baseyards and the Kalaeloa cogeneration facility are located. HECO owns buildings and approx imately 11.6 acres of land located in Honolulu which houses its operating, engineering and in formation services departments and a war ehousing center. It also leases an office building and certain office space in Honolulu. The lease for the office buildin g expires in November 2021, with an option to extend through November 2024. Leases for certain office and warehouse spaces expire on various dates from December 31, 2012 through June 30, 2021 with options to extend to various dates through
November 30, 2022.

HECO owns land at CIP used to situate central f uel storage facilities adjacent to its CIP combustion turbine No. 1 (CT-1) generating unit facility with an aggregate usable capacity of 786, 632 barrels of fuel, which land is included in the power plant acreage above. HECO also has fuel st orage facilities at each of its plant sites with a combined usable capacity of 869,093 barrels , as well as underground fuel pipelines that transport

fuel from HECO’s central fuel stor age at CIP to fuel storage facilities at HECO’s generating stations at Waiau and Kahe. HECO also owns a fuel storag e facility at Iwilei, which receives fuel trucked from the central storage facility, with a combined usable capacity of 76,735 bar rels, and an under-ground pipeline that transports fuel

from that site to its Honolulu generating station.

HELCO owns and operates five generating plants on the is land of Hawaii, two at Hilo and one at each of Waimea, Keahole and Puna, along with distributed gener ators at substation sites. These plants have an aggregate net generating capabilit y of 197.1 MW as of December 31, 2011 (excluding several small run-ofriver hydro units). The plants are situated on HELCO-owned land having a combined area of approximately 44 acres. The distributed generators are located within HE LCO-owned substation sites having a combined area of approximately 4 acres. HELCO also owns fuel storage facilities at these sites with a total maximum usable capacity of 66,387 barrels of bunker oil, and 83,819 barrels of diesel. There are an additional 17,600
barrels of diesel and 22,770 barrels of bunker oil st orage capacity for HELCO-owned fuel off-site at Chevron Products Company (Chevron)-owned term inalling facilities. HELCO pays a storage fee to Chevron and has no other interest in the property, tan ks or other infrastructure situated on Chevron’s property. HELCO also owns 6 acres of land in Kona, which is used for a basey ard, and one acre of land in Hilo, which houses its accounting, customer services and administrative offi ces. HELCO also leases 3.7 acres of land for its baseyard in Hilo under a lease expiring in 2030. In addi tion, HELCO owns a total of approximately 100 acres of land, and leases a total of approximately 8.5 acre s of land, on which hydro facilities, substations and switching stations, microwave facilities, and transmission lines are located. The deeds to the sites located in
Hilo contain certain restrictions, but t he restrictions do not materially interfer e with the use of the sites for public utility purposes.

MECO owns and operates two generating pl ants on the island of Maui, at Kahului and Maalaea, with an aggregate net generating capabilit y of 246.3 MW as of December 31, 2011. The plants are situated on MECOowned land having a combined area of 28.6 acres. MECO al so owns fuel oil storage facilities at these sites with a total maximum usable capacity of 176,355 barrels of fuel. MECO owns two 1 MW stand-by diesel generators and a 6,000 gallon fuel storage tank located in Hana. MECO owns 65.7 acres of undeveloped land at Waena. Most of this Waena land is used for agric ultural purposes by the fo rmer landowner under an amended license agreement, which is effective on a month- to-month basis, but terminable by either party upon 30 days written notice until the area is required for development by MECO fo r utility purposes, or until July 31,
2013, whichever occurs first. MECO’s administrative offices and engineering and di stribution departments are located on 9.1 acres of

MECO-owned land in Kahului.15 MECO also owns and operates smaller distribut ion systems, generation system s (with an aggregate net capability of 21.9 MW as of December 31, 2011) and fuel storage facilities on the islands of Lanai and Molokai, primarily on land owned by MECO.

Other properties. The utilities own overhead transmission and distribution lines, underground cables, poles (some jointly) and metal high voltage towers. El ectric lines are located over or under public and nonpublic properties. Lines are added wh en needed to serve increased loads and/or for reliability reasons. In some design districts on Oahu, lines must be placed underground. Under Hawaii law, the PUC generally must determine whether new 46 kilovolt (kV) , 69 kV or 138 kV lines can be c onstructed overhead or must be placed underground.

See “HECO and subsidiaries and service areas” above for a discussion of the nonexclusive franchises of

HECO and subsidiaries. Most of t he leases, easements and licenses for HECO’s, HELCO’s and MECO’s lines

have been recorded.

See “Generation statistics” above and “Limited insurance” in HEI’s MD&A for a further discussion of some of the electric utility properties.

Bank

General. ASB was granted a federal savings bank char ter in January 1987. Prior to that time, ASB had operated since 1925 as the Hawaii division of American Sa vings & Loan Association of Salt Lake City, Utah.
As of December 31, 2011, ASB was one of the largest financial institutions in the State of Hawaii based on total assets of $4.9 billion and deposits of $4.1 billi on. In 2011, ASB’s revenues and net income amounted to approximately 8% and 43% of HEI’s consolidated revenues and net income, respectively, compared to approximately 11% and 51% in 2010 and approximat ely 12% and 26% in 2009, respectively. At the time of HEI’s acquisition of ASB in 1988, HEI agreed with the OTS’ predecessor regulatory agency that ASB’s regulatory capital would be maintained at a level of at least 6% of ASB’s total liabilities, or at such greater amount as may be r equired from time to time by regulation. Under the agreement, HEI’s obligation to contribute additional capital to ensure that ASB would hav e the capital level required by the OTS was limited to a maximum aggregate amount of appr oximately $65.1 million. As of Dece mber 31, 2011, as a result of certain HEI contributions of capital to ASB, HEI’ s maximum obligation under the agreement to contribute additional capital has been reduced to approximately $28. 3 million. ASB is subject to OCC regulations on

dividends and other distributions and ASB must rece ive a letter of non-objec tion from the OCC and FRB before it can declare and pay a dividend to HEI. ASB’s earnings depend primarily on its net interest income—the difference between the interest income earned on earning assets (loans receivable and investm ent and mortgage-related securities) and the interest expense incurred on costing liabilities (deposit liabilities and other borrowings, including advances from the Federal Home Loan Bank (FHLB) of Seattle and secu rities sold under agreement s to repurchase). Other factors affecting ASB’s operating results include its prov ision for loan losses, fee income, other noninterest income (including gains and losses on sales of l oans, securities and notes and other-than-temporary impairments of securities) and noninterest expenses.
For additional information about ASB, see the secti ons under “Bank” in HEI’s MD&A, HEI’s “Quantitative

and Qualitative Disclosures about Market Risk” and No te 4 to HEI’s Consolidated Financial Statements

. The following table sets forth selected data for ASB (average balances calculated using the average daily balances):

Years ended December 31 2011 2010 2009 Common equity to assets ratio Average common equity divided by average total assets 10.24% 10.34% 9.38%

Return on assets Net income for common stock divided by average total assets 1.23 1.20 0.43 Return on common equity

Net income for common stock divided by average common equity 11.99 11.62 4.54 Tangible efficiency ratio

Total noninterest expense, less amortization of intangibles, divided

by net interest income and noninterest income 57 56 7216 All of the foregoing ratios and retu rns for 2009 were adversely affected by losses related to the sale of the private-issue mortgage-related securities portfolio and other-than-temporary impa irment charges on ASB’s securities portfolio, and for 2010 and 2011 were positivel y affected by the reduction in 2009 in ASB’s common equity, earning assets and costing liabilities.

Asset/liability management. See HEI’s “Quantitative and Qualitat ive Disclosures about Market Risk.”

Consolidated average balance sheet and interest income and interest expense. See “Bank—Results of operations—Average balance sheet and net interest margin” in HEI’s MD&A. The following table shows the effect on net interest income of (1) changes in interest rates (change in weighted-average interest rate multiplied by prior y ear average balance) and (2) changes in volume (change in average balance multiplied by prior period weighted-average interest rate). Any remaining change is allocated to the above two categories on a prorata basis.

(in thousands) 2011 vs. 2010 2010 vs. 2009
Increase (decrease) due to Rate Volume Total Rate Volume Total

Income from earning assets

Investment and mortgage-related securities $ (1,817) $ 1,439 $ (378) $ (9,847) $ (2,184) $(12,031) Loans receivable, net (9,552) (1,155) (10,707) (1,700) (20,946) (22,646) (11,369) 284 (11,085) (11,547) (23,130) (34,677) Expense from costing liabilities

Deposit liabilities 3,674 2,039 5,713 12,588 6,762 19,350 Other borrowings 66 101 167 (1,113) 4,957 3,844

3,740 2,140 5,880 11,475 11,719 23,194 Net interest income $ (7,629) $ 2,424 $(5,205) $ (72) $(11,411) $(11,483)

See “Bank—Results of operations” in HEI’s MD&A for an explanation of significant changes in earning assets and costing liabilities.

Noninterest income. In addition to net interest income, ASB has various sources of noninterest income, including fee income from credit and debit cards and fe e income from deposit liabilities and other financial products and services. See “Bank—Results of operations” in HEI’s MD&A for an explanation of significant changes in noninterest income.

Lending activities.

General. The following table sets forth the compositio n of ASB’s loans receivable held for investment:

December 31 2011 2010 2009 2008 2007

(dollars in thousands) Balance % of

total Balance % of

total Balance % of

total Balance % of

total Balance % of

total

Real estate loans: 1 Residential 1-4 family $1,926,774 52.2 $2,087,813 58.9 $2,332,763 62.9 $2,812,177 66.5 $2,901,420 70.1
Commercial real estate 331,931 9.0 300,689 8.5 255,716 6.9 243,109 5.8 252,831 6.1 Home equity line of credit 535,481 14.5 416,453 11.7 326,896 8.8 271,780 6.4 194,549 4.7
Residential land 45,392 1.2 65,599 1.8 96,515 2.6 126,963 3.0 159,114 3.8
Commercial construction 41,950 1.1 38,079 1.1 68,174 1.9 71,579 1.7 34,184 0.8
Residential construction 3,327 0.1 5,602 0.2 16,705 0.5 34,768 0.8 55,867 1.4
Total real estate loans, net 2,884,855 78.1 2,914,235 82.2 3,096,769 83.6 3,560,376 84.2 3,597,965 86.9

Commercial loans 716,427 19.4 551,683 15.5 545,622 14.7 597,234 14.1 471,576 11.4
Consumer loans 93,253 2.5 80,138 2.3 64,360 1.7 72,524 1.7 71,440 1.7

3,694,535 100.0 3,546,056 100.0 3,706,751 100.0 4,230,134 100.0 4,140,981 100.0 Less: Deferred fees and discounts (13,811) (15,530) (19,494) (24,631) (26,192)

A llowance for loan losses (37,906) (40,646) (41,679) (35,798) (30,211)

Total loans, net $3,642,818 $3,489,880 $3,645,578 $4,169,705 $4,084,578

Total loans as a % of assets 74.2% 72.8% 73.8% 76.7% 59.5%

1 Includes renegotiated loans.

The increase in the loans receivable balance in 2011 was primarily due to growth in commercial markets and home equity lines of credit loans as ASB targeted these portfolios because of their shorter duration and variable rates. Offsetting these loan portfolio increases was a decrease in the residential loan portfolio due to17 lower production and ASB’s decision to sell a portion of the residential loan producti on. The decrease in the loans receivable balance in 2010 and 2009 was primarily due to ASB’s decision to sell substantially all of its residential loan production in 2009 and the first nine months of 2010. The increase in loans receivable in 2008 was primarily due to growth in home equity li nes of credit and commercial markets loans. The following table summarizes ASB’s loans receivable held for investment, including undisbursed commercial real estate construction and development loan funds, based upon contractually scheduled principal payments and expected prepayments allocated to the indicated maturity categories:

December 31 2011 2010

Due In 1 year

or less After 1 year through 5 years After 5 years Total In 1 year

or less After 1 year through 5 years After 5 years Total (in millions)
Residential loans - Fixed $440 $ 965 $ 450 $1,855 $486 $ 981 $ 540 $2,007 Residential loans - Adjustable 37 32 3 72 37 38 5 80

477 997 453 1,927 523 1,019 545 2,087

Commercial real estate loans-Fixed 13 54 15 82 9 56 24 89 Commercial real estate loans-Adjustable 56 113 123 292 46 115 89 250

69 167 138 374 55 171 113 339

Consumer loans – Fixed 51 62 1 114 52 70 3 125 Consumer loans – Adjustable 49 85 431 565 44 92 309 445

100 147 432 679 96 162 312 570

Commercial loans – Fixed 48 116 26 190 33 71 14 118 Commercial loans – Adjustable 212 268 46 526 207 193 34 434

260 384 72 716 240 264 48 552

Total loans - Fixed 552 1,197 492 2,241 580 1,178 581 2,339 Total loans - Adjustable 354 498 603 1,455 334 438 437 1,209
$906 $1,695 $1,095 $3,696 $914 $1,616 $1,018 $3,548

The decrease in fixed rate residential loans was due to repayments in the portfolio and the sale of fixed rate loans in the secondary market.

Origination, purchase and sale of loans. Generally, residential and commercial real estate loans originated by ASB are collater alized by real estate located in Hawaii. For additional information, including information concerning the geographic distribution of ASB’s mortgage-related securities portfolio and the geographic concentration of credit risk, see Note 14 to HEI’s Consolidated Financial Statements. The demand for loans is primarily dependent on the Hawaii real esta te market, business conditi ons, interest rates and loan refinancing activity.

Residential mortgage lending. ASB’s general policy is to require private mortgage insurance when the loan-to-value ratio of the property exceeds 80% of th e lower of the appraised va lue or purchase price at origination. For nonowner-occupied residential properties , the loan-to-value ratio may not exceed 80% of the lower of the appraised value or purchase price at origination.

Construction and development lending. ASB provides both fixed- and adjustable-rate loans for the

construction of one-to-four unit resi dential and commercial properties. Constr uction loan projects are typically

short term in nature. Constructi on and development financing generally in volves a higher degree of credit risk than long-term financing on improved, occupied real es tate. Accordingly, construction and development loans are generally priced higher than loans collateralized by completed stru ctures. ASB’s underwriting, monitoring and disbursement practices with respect to construc tion and development financing are designed to ensure sufficient funds are available to complete constr uction projects. See “Loan portfolio risk elements” and “Multifamily residential and commercia l real estate lending” below.

Multifamily residential and commerc ial real estate lending. ASB provides permanent financing and construction and development financing collateralized by multifamily residential proper ties (including apartment buildings) and collateralized by commercial and industri al properties (including office buildings, shopping18 centers and warehouses) for its own portfolio as well as for participation with other lenders. Commercial real estate lending typically involves long lead times to or iginate and fund. As a result, production results can vary significantly from period to period.

Consumer lending. ASB offers a variety of secured and unsecur ed consumer loans. Loans collateralized by deposits are limited to 90% of t he available account balance. ASB o ffers home equity lines of credit, secured and unsecured VISA cards, checking account overdraft protection and other general purpose

consumer loans.

Commercial lending. ASB provides both secured and unsecured co mmercial loans to business entities. This lending activity is part of ASB’s strategic transfo rmation to a full-service community bank and is designed to diversify ASB’s asset structure, shorten maturities, improve rate sensitivity of the loan portfolio and attract commercial checking deposits.

Loan origination fee and servicing income. In addition to interest earned on loans, ASB receives income from servicing loans, for late payments and from other related services. Servicing fees are received on loans originated and subsequently sold by ASB where ASB acts as collection agent on behalf of third-party purchasers. ASB generally charges the borrower at loan settlem ent a loan origination f ee of 1% of the amount

borrowed. See “Loans receivable” in Note 1 to HEI’s Consolidated Financial Statements.

Loan portfolio risk elements. When a borrower fails to make a r equired payment on a loan and does not cure the delinquency promptly, the loan is classified as delinquent. If delinquencie s are not cured promptly, ASB normally commences a collection action, including fo reclosure proceedings in the case of secured loans. In a foreclosure action, the property collateralizing the delinquent debt is sold at a public auction in which ASB may participate as a bidder to protect its interest. If ASB is the successful bidder, the property is classified as

real estate owned until it is sold. As of December 31, 2011, December 31, 2010 and December 31, 2009, ASB had $7.3 million, $4.3 million and $4.0 million, respectively, of real esta te acquired in settlement of loans. In addition to delinquent loans, other significant l ending risk elements include: (1) loans which accrue interest and are 90 days or more past due as to princi pal or interest, (2) loans accounted for on a nonaccrual basis (nonaccrual loans), and (3) loans on which various c oncessions are made with re spect to interest rate, maturity, or other terms due to the inability of the borrowe r to service the obligation under the original terms of the agreement (troubled debt restructur ed loans). ASB loans that were 90 days or more past due on which interest was being accrued as of December 31, 2011, 2010, 2009, 2008 and 2007 were immaterial or nil. The following table sets forth certain information with respect to nonaccrual and troubled debt restructured loans:19 December 31 2011 2010 2009 2008 2007 (dollars in thousands)

Nonaccrual loans—

Real estate

Residential 1-4 family $28,298 $36,420 $31,848 $ 7,468 $1,027
Commercial real estate 3,436 – 344 – – Home equity line of credit 2,258 1,659 2,755 759 464

Residential land 14,535 15,479 25,164 7,652 89

Residential construction – – 326 326 –
Total real estate loans 48,527 53,558 60,437 16,205 1,580

Consumer loans 281 341 715 523 342
Commercial loans 17,946 4,956 4,171 2,766 1,273
Total nonaccrual loans $66,754 $58,855 $65,323 $19,494 $3,195

Nonaccrual loans to end of period loans 1.8% 1.7% 1.8% 0.5% 0.1%

Troubled debt restructured loans not included above—

Real estate

Residential 1-4 family $ 5,029 $ 5,150 $ 1,986 $1,913 $2,536
Commercial real estate – 1,963 513 – –
Residential land 24,828 27,689 15,665 2,125 –
Total real estate loans 29,857 34,802 18,164 4,038 2,536
Commercial loans 15,386 4,035 2,904 4,612 571
Total troubled debt restructured loans $45,243 $38,837 $21,068 $8,650 $3,107

Nonaccrual and troubled debt restructured loans to end of period loans 3.1% 2.8% 2.3% 0.7% 0.2%

ASB realized $6.3 million, $3.6 million and $2.0 million of intere st income on nonaccrual and troubled debt restructured loans in 2011, 2010 and 2009, respectively . If these loans would have earned interest in accordance with their original contractual term s ASB would have realized $9.9 million, $3.8 million and $2.9 million in 2011, 2010 and 2009, respectively. In 2011, nonaccrual loans increased by $7.9 million due to certain commercial loans that were current as to principal and interest payments but were cla ssified and placed on nonaccrual status. The increase in

troubled debt restructured loans was due to two comme rcial loans that were renegotiated. In 2010, nonaccrual loans decreased by $6.5 million due to a decr ease in residential land loans that were 90+ days delinquent and the renegotiation of certain residential land loans that had been on nonaccrual status. In 2009, nonaccrual loans increased by $45.8 million primar ily due to an increase in residential 1-4 family and residential land loans 90+ days delinquent. In 2008, nonaccrual loans increased by $16.3 million due to higher residential loan delinquencies and the reclassi fication of certain commercial loans due to their weakening credit quality. In 2007, nonaccrual loans increased by $0.8 million when compared to 2006 due to higher delinquencies in the resi dential and consumer loan portfolios.20 Allowance for loan losses. See “Allowance for loan losses” in Note 1 to HEI’s Consolidated Financial

Statements. The following table presents the changes in the allowance for loan losses:

(dollars in thousands) 2011 2010 2009 2008 2007

Allowance for loan losses, January 1 $40,646 $41,679 $35,798 $30,211 $31,228

Provision for loan losses 15,009 20,894 32,000 10,334 5,700

Charge-offs Residential 1-4 family 5,528 6,142 3,129 51 – Home equity line of credit 1,439 2,517 2,331 21 89
Residential land 4,071 6,487 4,217 282 –
Total real estate loans 11,038 15,146 9,677 354 89
Commercial loans 5,335 6,261 14,853 3,447 6,301
Consumer loans 3,117 3,408 2,436 1,825 1,334 Total charge-offs 19,490 24,815 26,966 5,626 7,724

Recoveries Residential 1-4 family 110 744 151 46 68 Home equity line of credit 25 63 – – 4

Residential land 170 63 – – –

Total real estate loans 305 870 151 46 72
Commercial loans 869 1,537 404 548 623

Consumer loans 567 481 292 285 312
Total recoveries 1,741 2,888 847 879 1,007

Allowance for loan losses, December 31 $37,906 $40,646 $41,679 $35,798 $30,211

Ratio of allowance for loan losses, December 31, to end of period loans 1.03% 1.15% 1.12% 0.84% 0.73%

Ratio of provision for loan losses during the year to average loans outstanding 0.42% 0.58% 0.81% 0.25% 0.15%

Ratio of net charge-offs during the year to average loans outstanding 0.49% 0.61% 0.66% 0.11% 0.17%

The following table sets forth the allocation of ASB’ s allowance for loan losses and the percentage of loans in each category to total loans:

December 31 2011 2010 2009 2008 2007

(dollars in thousands) Balance % of

total Balance % of

total Balance % of

total Balance % of

total Balance % of

total

Real estate Residential 1-4 family $ 6,500 52.2 $ 6,497 58.9 $ 5,522 62.5 $ 4,024 66.2 $ 3,906 69.8
Commercial real estate 1,688 9.0 1,474 8.5 861 6.9 2,229 5.7 2,760 6.1 Home equity line of credit 4,354 14.5 4,269 11.7 4,679 8.8 548 6.4 412 4.7
Residential land 3,795 1.2 6,411 1.8 4,252 2.6 1,953 3.0 256 3.9
Commercial construction 1,888 1.1 1,714 1.1 3,068 1.8 1,748 1.7 1,483 0.8

Residential construction 4 0.1 7 0.2 19 0.5 88 0.8 68 1.3

Total real estate loans, net 18,229 78.1 20,372 82.2 18,401 83.1 10,590 83.8 8,885 86.6

Commercial loans 14,867 19.4 16,015 15.5 19,498 14.6 22,294 14.0 18,820 11.4
Consumer loans 3,806 2.5 3,325 2.3 2,590 2.3 2,190 2.2 2,167 2.0

36,902 100.0 39,712 100.0 40,489 100.0 35,074 100.0 29,872 100.0

Unallocated 1,004 934 1,190 724 339

Total allowance for

loan losses $37,906 $40,646 $41,679 $35,798 $30,211

In 2011, ASB’s allowance for loan losses decreased by $2.7 million from 2010 due to a lower historical loss ratio for the commercial markets portfolio and the decline of the residential land portfolio, which was a higher risk and had a higher historical loss ratio assi gned to it. Partly offsetting these decreases was an21 increase in the allowance for loan losses for the comm ercial real estate portfolios due to a higher average loan balance. The levels of delinquencies and losse s in 2011 declined from a year ago. ASB’s 2011 provision for loan losses was $15.0 million, or a decrease of $5.9 million from the pr ior year’s provision for loan losses. Although the economy had gradually recover ed during the year and businesses have stabilized, the housing market remained stagnant. The outlook for the Hawaii economy is a continued gradual recovery through 2012.
In 2010, ASB’s allowance for loan losses decreased by $1.0 million from 2009 due to lower residential, commercial and commercial construction average loan balances , partly offset by increases in the historical loss ratios for residential first mortgage and land loan s. Although ASB’s loan qualit y improved in 2010, there were still signs of financial stress in the Hawaii and U. S. mainland markets. The slowdown in the economy, both nationally and locally, resulted in ASB experi encing higher levels of loan delinquencies and losses, which were concentrated in the vacant land portfo lio and on the neighbor islands. ASB’s 2010 provision for
loan losses was $20.9 million. While a mild recove ry began in 2010 as the global economic recovery began to take hold, many challenges remained.
In 2009, ASB’s allowance for loan losses increased by $5.9 million from 2008 as a result of higher residential 1-4 family, residential la nd and home equity lines of credit delinquencies and increases in the historical loss ratios for these loan types. ASB’s lo an quality weakened in 2009, although not to the same level of decline in loan quality seen in many mainl and U.S. markets. The slow down in the economy, both nationally and locally, had caused increased levels of fi nancial stress on ASB’s customers, resulting in higher levels of loan delinquencies and losses. ASB’s 2009 provision for loan losses was $32 million, which included a provision for loan loss on a comme rcial loan that was subsequently sold.

Investment activities. Currently, ASB’s investment portfolio consis ts of mortgage-related securities, stock of the FHLB of Seattle, federal agency obligations and municipal bonds. ASB owns mortgage-related securities issued by the Federal National Mortgage Associat ion (FNMA), Federal Home Loan Mortgage Corporation (FHLMC) and Government National Mortgage Associati on (GNMA) and federal agency obligations issued by the FNMA and FHLMC. The weighted-average yield on investments during 2011, 2010 and 2009 was 2.01%, 2.18% and 3.67%, respectively. ASB did not maintain a portfolio of securities held for trading during 2010,

2009 and 2008.
As of December 31 in each of 2011, 2010 and 2009, ASB’s investment in stock of the FHLB of Seattle
amounted to $97.8 million. The amount that ASB is required to invest in FHLB of Seattle stock is determined by regulatory requirements and ASB’s in vestment is in excess of that requirement. See “FHLB of Seattle stock” in HEI’s MD&A. Also, see “Regulat ion–Federal Home Loan Bank System” below. With the sale of the private-issue mortgage-related securities in 2009, ASB does not have any exposure to securities backed by subprime mortgages. See “Investm ent and mortgage-related securities” in Note 4 to

HEI’s Consolidated Financial Statements for a discussi on of other-than-temporarily impaired securities. The following table summarizes ASB’s investment portfolio (e xcluding stock of the FH LB of Seattle, which has no contractual maturity), as of December 31, 2011, based upon contractually scheduled principal payments and expected prepayments allocated to the indicated maturity categories:

Due In 1 year

or less After 1 year through 5 years After 5 years through 10 years After 10 years Total (dollars in millions)

Federal agency obligations $ 80 $128 $10 $ – $218 Mortgage-related securities - FNMA,

FHLMC and GNMA 108 180 35 6 329 Municipal bonds – 9 42 – 51
$188 $317 $87 $ 6 $598

Weighted average yield 2.23% 2.13% 2.70% 2.35%22 Deposits and other sources of funds.

General. Deposits traditionally have been the principal sour ce of ASB’s funds for use in lending, meeting liquidity requirements and making investments. ASB also derives funds from the receipt of interest and principal on outstanding loans receivable and mortgage-re lated securities, borrowings from the FHLB of Seattle, securities sold under agreements to repurch ase and other sources. ASB borrows on a short-term basis to compensate for seasonal or other reductions in deposit flows. ASB also may borrow on a longer-term basis to support expanded lending or investment activities . Advances from the FHLB and securities sold under agreements to repurchase continue to be a source of funds, but they are a higher cost source than deposits.

Deposits. ASB’s deposits are obtained primarily from residents of Hawaii. Net deposit inflow or outflow, measured as the year-over-year difference in y ear-end deposits, was an inflow of $95 million in 2011 compared to outflows of $83 million in 2010 and $121 million in 2009. The following table illustrates the distribution of ASB’s average deposits and average daily rates by type of deposit. Average balances have been calculat ed using the average daily balances.

Years ended December 31 2011 2010 2009

(dollars in thousands) Average

balance % of

total deposits Weighted

average rate % Average

balance % of

total deposits Weighted

average rate % Average

balance % of

total deposits Weighted

average rate %

Savings $1,672,033 41.5% 0.11% $1,608,650 40.2% 0.14% $1,504,758 36.5% 0.33% Checking 1,510,848 37.5 0.01 1,392,698 34.8 0.02 1,292,516 31.4 0.06 Money market 250,682 6.2 0.26 232,809 5.8 0.38 180,967 4.4 0.49
Certificate 598,360 14.8 1.07 768,991 19.2 1.46 1,140,997 27.7 2.40 Total deposits $4,031,923 100.0% 0.22% $4,003,148 100.0% 0.37% $4,119,238 100.0% 0.83%

As of December 31, 2011, ASB had $119.2 million in certificate accounts of $100,000 or more, maturing

as follows:

(in thousands) Amount
Three months or less $ 24,295 Greater than three months through six months 13,080 Greater than six months through twelve months 34,163
Greater than twelve months 47,704
$119,242

This compares with $152.5 million in such certificate accounts in 2010.

Deposit-insurance premiums and regulatory developments . For a discussion of changes to the deposit insurance system, premiums and Financing Cor poration (FICO) assessments, see “Regulation– Deposit insurance coverage” below.

Other borrowings. See “Other borrowings” in Note 4 to HE I’s Consolidated Financial Statements. ASB may obtain advances from the FHLB of Seattle provided that certain st andards related to creditworthiness have been met. Advances are collateralized by a bl anket pledge of certain notes held by ASB and the mortgages securing them. To the ext ent that advances exceed the amount of mortgage loan co llateral pledged
to the FHLB of Seattle, the excess must be covered by qualified marketable securities held under the control of

and at the FHLB of Seattle or at an approved third-party custodian. FHLB advances generally are available to

meet seasonal and other withdrawals of deposit accounts, to expand lending an d to assist in the effort to improve asset and liability management. FHLB advances are made pursuant to several different credit programs offered from time to ti me by the FHLB of Seattle. The decrease in other borrowings in 2011 compared to 2010 was primarily due to the payoff of a maturing FHLB advance, partially offset by an increase in retail repurchase agreements. The decrease in other borrowings in 2010 compared to 2009 was primarily due to a decrease in retail repurchase agreements.

Competition. See “Bank—Executive overview and strategy” and “Bank—Certain factors that may affect

future results and financial conditi on—Competition” in HEI’s MD&A.23 Competition for deposits comes prim arily from other savings institut ions, commercial banks, credit unions, money market and mutual funds and other investment al ternatives. As of Decem ber 31, 2011, there were 9 financial institutions insured by the FDIC in the State of Hawaii, of which 2 were thrifts and 7 were commercial
banks, and numerous credit unions

. Additional competition for deposits comes from various types of corporate and government borrowers, including insurance companies. Competition for origination of first mortgage loans comes primarily from mortgage banking and brokerage firm s, commercial banks, other savings institutions, insurance companies and real es tate investment trusts.

Regulation. ASB, a federally chartered savings bank, and it s holding companies had been subject to the regulatory supervision of the OTS, which regulatory jurisdiction was transferred to the OCC and FRB, respectively, in July 2011, and, in certain respects , the FDIC. See “HEI–Regula tion” above and “Bank–Certain factors that may affect future re sults and financial conditi on–Regulation” in HEI’s MD&A. In addition, ASB must comply with FRB reserve requirements.

Deposit insurance coverage. The Federal Deposit Insurance Act, as amended, and regulations promulgated by the FDIC, govern insu rance coverage of deposit accounts. In July 2010, the Dodd-Frank Act permanently raised the current st andard maximum deposit insurance am ount to $250,000. Generally, the amount of all deposits held by a depositor in the same capacity (even if held in separate accounts) is aggregated for purposes of appl ying the insurance limit. See “Federal Deposit Insurance Cor poration restoration plan” in Note 4 to HEI’s Consolidated Financial Statements for a discussion of FDIC deposit insuranc e assessment rates, the prepayment of estimated assessments for the fourth quarter of 2009 and for all of 2010, 2011 and 2012 and changes to the assessment rates and base. FICO will continue to impose an assessm ent on deposits to service the interest on FICO bond obligations. ASB’s annual FICO a ssessment is 0.66 cents per $100 of deposits as of December 31, 2011.

Federal thrift charter. See “Bank–Certain factors that may a ffect future results and financial condition— Regulation—Unitary savings and loan holding company” in HEI’s MD&A, including the discussion of previously proposed legislation that w ould abolish the charter.

Recent legislation and issuances. See “Bank

– Legislation and regulation” in HEI’s MD&A.

Capital requirements . The OCC has set three capital standar ds for financial institutions. As of December 31, 2011, ASB was in compliance with all of the minimum standards with a core capital ratio of 9.0% (compared to a 4.0% requirement ), a tangible capital ratio of 9.0% (compared to a 1.5% requirement) and total risk-based capital ratio of 12.9% (based on risk-based capital of $474.9 million, $180.8 million in excess of the 8.0% requirement). The OCC requires that financial institutions with a composite rating of “1” under the Uniform Financial Institution Rating System (i.e., CAME LS rating system) must maintain core capital in an amount equal to at least 3% of adjusted total assets. All other institutions must maintain a minimum core capital of 4% of adjusted total assets, and higher capital ratios may be requir ed if warranted by particular circumstances. As of December 31, 2011, ASB met the applicable minimum core capital requirement. Other capital standards based on an international fra mework have been adopted for institutions that are much larger in size than ASB or that have substantia l foreign exposures. ASB is not currently required to be, and has elected not to be, gov erned by these other standards.

Affiliate transactions . Significant restrictions apply to certai n transactions between ASB and its affiliates, including HEI and its direct and indirect subsidiaries. For example, ASB is prohibited from making any loan or other extension of credit to an entity affiliated with ASB unless the affiliate is engaged exclusively in activities which the FRB has determined to be permissible for bank holding companies. There are also various other restrictions which apply to certain transactions between ASB and certain executive officers, directors and insiders of ASB. ASB is also barred from making a purchas e of or any investment in securities issued by an affiliate, other than with respect to shares of a subsidiary of ASB.

Financial Derivatives and Interest Rate Risk. ASB is subject to OCC rules relating to derivatives activities, such as interest rate swaps. Currently ASB does not us e interest rate swaps to manage interest rate risk24 (IRR), but may do so in the future. Generally speaking, the OCC rules permit financial institutions to engage in transactions involving financial derivatives to the extent these transactions are otherwise authorized under applicable law and are safe and sound. The rules require ASB to have certain internal procedures for handling financial derivative transactions, including in volvement of the ASB Board of Directors. With the transfer of the regulatory jurisdiction fr om the OTS to the OCC, ASB has adopted terminology and IRR assessment, measurement and management practice s consistent with OCC guidelines. Management believes ASB’s IRR processes are aligned with the Interagency Advisory on Inte rest Rate Risk Management and appropriate with earnings and capital levels, balance sheet complexity, business model and risk tolerance

. Liquidity. OCC regulations require ASB to maintain sufficient liquidity to ensure safe and sound operations. ASB’s principal sources of liquidity are cu stomer deposits, borrowings, the maturity and repayment of portfolio loans and securities and the sale of loans into secondary market channels. ASB’s principal sources of borrowings are advances from the FHLB of Sea ttle and securities sold under agreements to repurchase from broker/dealers. ASB is approved by the FHLB of S eattle to borrow an amount of up to 35% of assets to the extent it provides qualifying collat eral and holds sufficient FHLB of Seattl e stock. As of December 31, 2011, ASB’s unused FHLB of Seattle borrowing capacity was approximately $1.1 billion. ASB utilizes growth in deposits, advances from the FHLB of Seattle and securi ties sold under agreements to repurchase to fund maturing and withdrawable deposits, repay maturing borrowings, fund existing and future loans and make

investments. As of December 31, 2011, ASB had loan commitments, undi sbursed loan funds and unused lines
and letters of credit of $1.3 billion. Management believes ASB’s current s ources of funds will enable it to meet these obligations while maintaining liquidity at satisfactory levels.

Supervision. Pursuant to the Federal Deposit Insuranc e Corporation Improvement Act of 1991 (the FDICIA), the federal banking agencie s promulgated regulations which appl y to the operations of ASB and its holding companies. Such regulations address, for example, standards fo r safety and soundness, real estate lending, accounting and reporting, transactions with affiliates and loans to insiders.

Prompt corrective action. The FDICIA establishes a statutory framew ork that is triggered by the capital

level of a financial institution and s ubjects it to progressively more stringent restrictions and supervision as capital levels decline. The OCC rules im plement the system of prompt correcti ve action. In particular, the rules define the relevant capital measures for the cat egories of “well capitaliz ed”, “adequately capitalized”, “undercapitalized”, “significantly undercapita lized” and “critically undercapitalized.”

A financial institution that is “undercapitalized” or “significantly undercapitalized” is subject to additional mandatory supervisory actions and a number of discretionar y actions if the OCC determines that any of the actions is necessary to resolve the problems of the a ssociation at the least possi ble long-term cost to the Deposit Insurance Fund. A financial in stitution that is “critically und ercapitalized” must be placed in conservatorship or receivership within 90 days, unles s the OCC and the FDIC concur that other action would be more appropriate. As of December 31, 2011, ASB was “well-capitalized.”

Interest rates. FDIC regulations restrict the ability of financial institutions that are u ndercapitalized to offer interest rates on deposits that are signi ficantly higher than the rates offered by competing institutions. As of December 31, 2011, ASB was “well capitalized” and thus not subject to these intere st rate restrictions.

Qualified thrift lender test. In order to satisfy the QTL test, ASB mu st maintain 65% of its assets in “qualified thrift investments” on a mont hly average basis in 9 out of the prev ious 12 months. Failure to satisfy the QTL test would subject ASB to various penalties, in cluding limitations on its activities, and would also bring into operation restrictions on the activities that may be engaged in by HEI, ASHI and their other subsidiaries, which could effectively result in the required divestiture of ASB. At all times during 2011, ASB was in compliance with the QTL test. As of December 31, 2011, 76% of ASB’s portfolio assets were “qualified

thrift investments.” See “HEI Consolidated–Regulation.”

Federal Home Loan Bank System. ASB is a member of the FHLB Syst em, which consists of 12 regional FHLBs, and ASB’s regional bank is the FHLB of Seattle. The FHLB System provides a central credit facility for member institutions. Historically, the FHLBs have serv ed as the central liquidity facilities for savings25 associations and sources of long-term funds for financ ing housing. At such time as an advance is made to ASB or renewed, it must be collateralized by collateral fr om one of the following categor ies: (1) fully disbursed, whole first mortgages on improved residential property, or securities representing a whole interest in such mortgages; (2) securities issued, insured or guaranteed by the U.S. Government or any agency thereof; (3) FHLB deposits; and (4) other real estate-related colla teral that has a readily ascertainable value and with respect to which a security interest can be perfected. The aggregate amount of outstanding advances collateralized by such other real estate-related collateral may not exceed 30% of ASB’s capital. As mandated by the Gramm Act, the Federal Hous ing Finance Board (Board) regulations require each FHLB to maintain a minimum total capital leverage rati o of 5% of total assets and include risk-based capital standards requiring each FHLB to maintain permanent c apital in an amount sufficient to meet credit risk and
market risk. In June 2001, the FHLB of Seattle formul ated a capital plan to meet these new minimum capital standards, which plan was approved by the Board. The capi tal plan requires ASB to own capital stock in the FHLB of Seattle in an amount equal to the total of 4% of the FHLB of Seattle’s advances to ASB plus the greater of (i) 5% of the out standing balance of loans sold to the FHLB of Seattle by ASB or (ii) 0.5% of ASB’s mortgage loans and pass through securities. As of Dece mber 31, 2011, ASB was r equired under the capital plan to own capital stock in the FHLB of Seattle in the amount of $14 million and owned capital stock in the
amount of $98 million, or $84 million in excess of the requirement. Under the capital plan, stock in the FHLB of Seattle can be required to be redeemed at the option of ASB, but the FHLB of Seattle may require up to a 5- year notice of redemption. This 5- year notice period has an adverse but immaterial effect on ASB’s liquidity.

See “FHLB of Seattle stock” in HEI’s MD&A section fo r recent developments regarding the FHLB of Seattle.

Community Reinvestment. The Community Reinvestment Act (CRA) requires financial institutions to help meet the credit needs of their communities, including lo w- and moderate-income areas, consistent with safe and sound lending practices. T he OCC will consider ASB’s CRA record in evaluating an application for a new deposit facility, including the establishment of a branch, the relocation of a branch or office, or the acquisition

of an interest in another bank. ASB current ly holds an “outstanding” CRA rating.

Other laws. ASB is subject to federal and state consumer pr otection laws which affect lending activities, such as the Truth in Lending Act, the Truth in Savings Act, the Equal Credit Opportuni ty Act, the Real Estate Settlement Procedures Act, the Home Mortgage Disclosur e Act and several federal and state financial privacy acts intended to protect consumers’ personal informat ion and prevent identity thef t, such as the Gramm Act and the Fair and Accurate Transactions Act. ASB is also subj ect to federal laws regulating certain of its lending practices, such as the Flood Disaster Protection Act, and laws requiring reports to regulators of certain customer transactions, such as the Currency and Fore ign Transactions Reporting Act and the International Money Laundering Abatement and Anti-Terrorist Financing Act. ASB’s relationship with LPL Financial LLP is also governed by regulations adopt ed by the FRB under the Gramm Act, which regulate “networking” relationships under which a financial institution refers cu stomers to a broker-dealer for securities services and employees of the financial institution are permitted to receive a nominal fee for the referrals. These laws may provide for substantial penalties in t he event of noncompliance. ASB believes that it currently is in compliance with these laws and regulations in all material respects.

Proposed legislation. See the discussion of proposed legislation in “Bank

– Legislation and regulation” in

HEI’s MD&A.

Environmental regulation . ASB may be subject to the provisions of Comprehensive Environmental Response, Compensation and Liabil ity Act (CERCLA), Hawaii Environmental Response Law (ERL) and regulations promulgated thereunder, which impose liability for environmental cleanup costs on certain categories of responsible parties. CERCLA and ERL exem pt persons whose ownership in a facility is held primarily to protect a security interest, provided that they do not participate in t he management of the facility. Although there may be some risk of liability for ASB for environmental cleanup costs in the event ASB forecloses on, and becomes the owner of, property with environmental problems, t he Company believes the26 risk is not as great for ASB as it may be for other depository instituti ons that have a larger portfolio of

commercial loans.

Properties. ASB owns or leases several office buildings in downtown Honolulu and owns land and an operations center in the Mililani Te chnology Park on the island of Oahu. The following table sets forth the number of bank branches owned and leased by ASB by island:

Number of branches

December 31, 2011 Owned Leased Total

Oahu 6 33 39

Maui 3 4 7

Kauai 2 2 4

Hawaii 2 4 6

Molokai

– 1 1

13 44 57

As of December 31, 2011, the net book value (NBV) of branches and office facilities is $40 million ($31 million NBV of the land and im provements for the branches and office facilities owned by ASB and $9 million represents the NBV of ASB’s leasehold improvements). The leases expire on various dates through July 2033, but many of the leas es have extension provisions.
As of December 31, 2011, ASB ow ned 119 automated teller machines.

ITEM 1A. RISK FACTORS

The businesses of HEI and its subsidiaries involve nume rous risks which, if realized, could have a material and adverse effect on the Company’s financial statements. For additional information for certain risk factors

enumerated below and other risks of t he Company and its operations, s ee “Forward-Looking Statements”
above and HEI’s MD&A, HEI’s “Quantitative and Qualit ative Disclosures about Market Risk”, HEI’s

Consolidated Financial Statem ents, HECO’s MD&A, HECO’s “Quantitat ive and Qualitative Disclosures About

Market Risk” and HECO’s Consol idated Financial Statements.

Holding Company and Company-Wide Risks.

HEI is a holding company that derives its income fr om its operating subsidiari es and depends on the ability of those subsidiaries to pay dividends or make other dis tributions to HEI and on its own ability to raise capital. HEI is a legal entity separate and dist inct from its various subsidiaries. As a holding company with no significant operations of its own, HEI’s cash flows and consequent ability to service its obligations and pay dividends on its common stock is dependent upon its receip t of dividends or other distributions from its operating subsidiaries and its ability to issue common st ock or other equity securi ties and to incur additional debt. The ability of HEI’s subsidiaries to pay dividends or make other distributions to HEI, in turn, is subject to the risks associated with their operations and to cont ractual and regulatory rest rictions, including:

 the provisions of an HEI agreement with the PUC, which could limit the ability of HEI’s principal electric public utility subsidiary, HECO, to pay divi dends to HEI in the event that the consolidated common stock equity of the electric public utility subs idiaries falls below 35% of total capitalization
of the electric utilities;

 the provisions of an HEI agreement entered into wi th federal bank regulator s in connection with its acquisition of its bank subsidiary, ASB, which requi re HEI to contribute additional capital to ASB (up to a maximum amount of additional capital of $28.3 million as of December 31, 2011) upon request of the regulators in order to maintain ASB’s regulatory c apital at the level required by regulation;

 the minimum capital and capital distribution regulat ions of the OCC that are applicable to ASB;

 the receipt of a letter from t he OCC and FRB stating it has no objection to the payment of any dividend ASB proposes to dec lare and pay to HEI; and

 the provisions of preferred stock resolutions and debt instruments of HEI and its subsidiaries.27 The Company is subject to risks associated with the Hawaii economy (in the aggregate and on an individual island basis), volatile U.S. capital markets and changes in the interest rate and credit market environment that have and/or could result in higher re tirement benefit plan funding requirement s, declines in electric utility KWH sales, declines in ASB’s interest rate margins and in vestment values, higher delinquencies and charge-offs in ASB’s loan portfolio and restrictions on the ability of HEI or its subsidiaries to borrow money or issue securities. The two largest components of Hawaii’s economy are t ourism and the federal government (including the military). Because the core businesses of HEI’s subsidiari es are providing local public electric utility services (through HECO and its subsidiaries) and banking services (through ASB) in Hawaii, the Company’s operating results are significantly influenced by Hawaii’s economy, which in turn is influenced by economic conditions in the mainland U.S. (particularly Califor nia) and Asia (particularly Japan) as a result of the impact of those conditions on tourism, by the impact of interest rates on the construction and real estate industries and by the impact of world conditions (e.g., U.S. presence in Afgh anistan) on federal government spending in Hawaii. For example, the turmoil in the financial markets and dec lines in the national and gl obal economies had a negative effect on the Hawaii economy in 2009. In 2009, declines in the Hawaii, U.S. and Asian economies in turn led to declines in KWH sales (which continued into 2010 and 2011), an increase in uncollect ed billings of HECO and its subsidiaries, higher delinquencies in ASB’s loan portfolio and other adver se effects on HEI’s businesses. If S&P or Moody’s were to downgrade HEI’s or HECO’s long-term debt ratings because of past adverse
effects, or if future events were to adversely affect the availability of capital to the Company, HEI’s and HECO’s ability to borrow and raise capital could be constrained and their future borrowing costs would likely increase with resulting reductions in HEI’s c onsolidated net income in future per iods. Further, if HEI’s or HECO’s commercial paper ratings were to be downgraded, HEI and HECO might not be able to sell commercial paper and might be required to draw on more expensive bank lines of credit or to defer capi tal or other expenditures. Changes in the U.S. capital markets can also hav e significant effects on the Company. For example, pension funding requirements are affect ed by the market performance of the assets in the master pension trust maintained for pension plans, and by the discount rate used to estimate the service and interest cost components of net periodic pension cost and value obli gations. The electric utilities’ pension tracking mechanisms help moderate pension expens e; however, the significant decli ne in 2008 in the value of the Company’s defined benefit pension plan assets resulted in a substantial gap betwe en the projected benefit obligations under the plans and the value of plan asse ts, resulting in increases in funding requirements. Because the earnings of ASB depend primarily on net intere st income, interest rate risk is a significant risk of ASB’s operations. HEI and its electric utility subsidiaries are also exposed to interest rate risk primarily due to their periodic borrowing requirements, the discount rate used to determine pension funding requirements and the possible effect of interest rate s on the electric utilities’ rates of re turn. Interest rates are sensitive to many factors, including general ec onomic conditions and the policies of government and regulat ory authorities. HEI cannot predict future changes in in terest rates, nor be certain that in terest rate risk management strategies it or its subsidiaries have implemented will be successful in managing in terest rate risk. Interest rate risk also represents a market risk factor affecting the fair value of ASB’s investment securities. Increases and decreases in prevailing in terest rates generally translate into decreases and increases in the fair values of those instruments, respectively. Disruptions in the credit markets, a liquidity crisis in the banking industry or increased levels of resi dential mortgage delinquencies and defaults may result in decreases in the fair value of ASB’s investment securities and an impai rment that is other-than-te mporary, requiring ASB to

write down its investment securities. As of December 31, 2011, 90% of ASB’s investment securities were securities and obligations issued by a federal agency or government sponsored enti ty that have an implicit guarantee from the U.S. government.28 HEI and HECO and their subsidiaries may incur hi gher retirement benefits expenses and have and will likely continue to recognize substantia l liabilities for retirement benefits. Retirement benefits expenses and cash funding requirements could increase in future years depending on numerous factors, including the performance of the U.S. equity mark ets, trends in interest rates and heal th care costs, plan amendments, new laws relating to pension funding and changes in accoun ting principles. For the electric utilities, however, retirement benefits expenses, as adjusted by the pension and postretirement benef its other than pensions (OPEB) tracking mechanisms, have been an allo wable expense for rate-making purposes.

The Company is subject to the risks associated with the geographic concentration of its businesses and current

lack of interconnections that could result in service interr uptions at the electric utilit ies or higher default rates on loans held by ASB. The business of HECO and its electric utility s ubsidiaries is concentrated on the individual islands they serve in the State of Hawaii. Their operations are more vulnerable to se rvice interruptions than are many U.S. mainland utilitie s because none of the systems of HECO and its subsidiaries are interconnected with the systems on the other islands they serve. Because of this lack of interconnections, it is necessary to maintain higher generation reserve margins than are typica l for U.S. mainland utilities to help ensure reliable service. Service interruptions, including in particular extended interruptions that could result from a natur al disaster or terrorist activity, could adversely impact the KWH sales of some or all of the electric utility subsidiaries. Substantially all of ASB’s consum er loan customers are Hawaii resi dents. A significant portion of the

commercial loan customers are located in Hawaii. While a majority of customers are on Oahu, ASB also has customers on the neighbor islands (w hose economies have been weaker than Oahu during the recent economic downturn). Substantially all of the r eal estate underlying ASB’s residential and commercial real estate loans are located in Hawaii. These assets may be subject to a great er risk of default than other comparable assets held by financial institutions with other geographi c concentrations in the event of adv erse economic, political or business developments or natural disasters affecting Hawaii and the ability of ASB’s custom ers to make payments of principal and interest on their loans.

Increasing competition and technological advances co uld cause HEI’s businesses to lose customers or render their operations obsolete. The banking industry in Hawaii, and certain aspects of the electric utility industry, are competitive. The su ccess of HEI’s subsidiaries in m eeting competition and responding to technological advances will continue to have a direct impact on HEI’s consolidated financial performance. For example:

 ASB, one of the largest financial instit utions in the state, is in dire ct competition for deposits and loans not only with two larger institutions that have subs tantial capital, technology and marketing resources,

but also with smaller Hawaii inst itutions and other U.S. institutions, including credit unions, mutual funds, mortgage brokers, finance companies and investment banking firms. Larger financial institutions may have greater access to capital at lower costs, which could impair ASB’s ability to compete effectively. Significant advances in te chnology could render the operations of ASB less competitive or obsolete.

 HECO and its subsidiaries face co mpetition from IPPs and customer self-generati on, with or without cogeneration. With the exception of certain ident ified projects, the utilit ies are required to use competitive bidding to acquire a future generation re source unless the PUC finds competitive bidding to be unsuitable. The PUC set policies for DG interconnection agreements and standby rates, and

established conditions under which electric utilitie s can provide DG services on customer-owned sites as a regulated service. The electric utilities cannot predict the future impact of competition from IPPs and customer self-generation, or the rate at which technological developments facilitating non-utility generation of electricity will occur.

 New technological developments, such as the co mmercial development of ener gy storage, may render the operations of HEI’s electric utility s ubsidiaries less competitive or outdated.29 The Company may be subject to information tec hnology system failures, net work disruptions and breaches in data security that could adverse ly affect its businesses and reputation. The Company is subject to cyber security risks and the potential for cyber incident s, including potential incidents at ASB branches and at the HECO, HELCO and MECO plants and the related electr icity transmission and dist ribution infrastructure, and incidents at data processing center s they use, to the extent not prevented by intrusion detection and prevention systems, anti-virus softw are, firewalls and other general info rmation technology controls. ASB and HECO are highly dependent on their ability to process, on a daily basis, a large number of transactions. ASB and the utilities rely heavily on numerous data processing systems. If any of these systems fails to operate properly or becomes disabled even for a brief period of time, the Company could suffer financial loss, business disruptions, liability to customers, regulatory intervention or damage to its reputation. The utilities and ASB have disaster recovery plans in plac e to protect their businesses against natural disasters, security breaches, military or terrorist actions, power or communication failures or similar ev ents. The disaster recovery plans, however, may not be successful in preventing the loss of customer data, service interruptions, disruptions to operations or damage to important facilities.

HEI’s businesses could suffer losses that are uninsur ed due to a lack of affor dable insurance coverage, unavailability of insurance coverage or limitations on the insurance coverage the Company does have. In the ordinary course of business, HEI and it s subsidiaries purchase insurance co verages (e.g., property and liability coverages) to protect against loss of, or damage to, th eir properties and against claims made by third parties and employees for property damage or per sonal injuries. However, the protection provided by such insurance is limited in significant respects and, in some instanc es, there is no coverage. Ce rtain of the insurance has

substantial deductibles or has limits on the maximu m amounts that may be recove red. For example, the electric utilities’ overhead and underground transmissi on and distribution systems (with the exception of substation buildings and contents) have a replacement value roughly esti mated at $5 billion and are not insured against loss or damage bec ause the amount of transmission and distribution system insurance available is limited and the premiums are cost prohibiti ve. Similarly, the electr ic utilities have no business interruption insurance as the premiums for such insu rance would be cost prohibitive, particularly since the

utilities are not interconnected to other systems. If a hurricane or other uni nsured catastrophic natural disaster
were to occur, and if the PUC were not to allow the affected electric utilities to recover from ratepayers

restoration costs and revenues lost from business inte rruption, the lost revenues and repair expenses could result in a significant decrease in HEI’s consolidated ne t income or in significant net losses for the affected periods. ASB generally does not obtain credit enhancements, su ch as mortgagor bankruptcy insurance, but does require standard hazard and hurricane insurance and may require flood insurance for certain properties. ASB is subject to the risks of borrower defaults and bankruptci es, special hazard losses not covered by the required insurance and the insurance company’s inabili ty to pay claims on existing policies.

Increased federal and state environment al regulation will require an in creasing commitment of resources

and funds and could result in construction dela ys or penalties and fines for non-compliance. HEI and its subsidiaries are subject to federal and state environmental laws and regulations relating to air quality, water quality, waste management, natural resources and health and safety, which regulate the operation of existing facilities, the construction and operation of new fa cilities and the proper cleanup and disposal of hazardous waste and toxic substances. Compliance with these lega l requirements requires HEI’s utility subsidiaries to commit significant resources and funds toward environm ental monitoring, installation of pollution control equipment and payment of em ission fees. These laws and regulations, am ong other things, require that certain environmental permits be obtained in order to construct or operate certain facilities, and obtaining such permits can entail significant expense and caus e substantial construction delays. Al so, these laws and regulations may
be amended from time to time, incl uding amendments that increase the burden and expense of compliance. For example, emission and/or discharge limits may be tightened, more extensive permitting requirements may be imposed and additional substances may become regulated. In addition, si gnificant regulatory uncertainty exists regarding the impact of federal or state greenhouse gas emission limits and reductions.30 If HEI or its subsidiaries fail to comply with environmental laws and r egulations, even if caused by factors beyond their control, that failure may result in civil or criminal penalties and fines.

Adverse tax rulings or developments could result in significant increases in tax payments and/or

expense. Governmental taxing authorities could challen ge a tax return position taken by HEI or its subsidiaries and, if the taxing aut horities prevail, HEI’s consolidated tax payments and/or expense, including applicable penalties and interest, could increase significantly.

The Company could be subject to the risk of unins ured losses in excess of its accruals for litigation

matters. HEI and its subsidiaries are involved in routine litigation in the ordi nary course of their businesses, most of which is covered by insurance (subject to policy limits and deductibles). However, other litigation may arise that is not rout ine or involves claims that may not be covered by insurance. Because of the uncertainties associated with litigation, there is a risk that litigation agai nst HEI or its subsidiaries, even if vigorously defended, could result in costs of defense and judgment or settlement amounts not covered by

insurance and in excess of reserves establish ed in HEI’s consolidated financial statements.

Changes in accounting principles and estimates c ould affect the reported amounts of the Company’s assets and liabilities or revenues and expenses. HEI’s consolidated financial statements are prepared in accordance with accounting principles generally accept ed in the U.S. Changes in these principles, or changes in the Company’s application of existi ng accounting principles, could materially affect the financial statement presentation of HEI’s or the electric utilities’ conso lidated results of operations and/or financial condition. Further, in preparing the consolidat ed financial statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities, t he disclosure of contingent assets and liabilities and the reported amounts of revenues and expenses. Actual results could differ significantly from

those estimates. Material estimates that are particularly susceptible to significant change include the amounts reported for investment and mortgage-related securi ties; property, plant and equipment; pension and other postretirement benefit obligations; contingencies and litigat ion; income taxes; regulatory assets and liabilities; electric utility revenues; and allowance for loan losses.

HECO and its subsidiaries’ financia l statements reflect assets and co sts based on cost-based rate-making regulations. Continued accounting in this manner requires that cert ain criteria relating to the recoverability of such costs through rates be met. If events or circumst ances should change so that the criteria are no longer
satisfied, the electric utilities’ regulatory assets (amounting to $669 m illion as of December 31, 2011) may need to be charged to expense, which could result in signifi cant reductions in the electric utilities’ net income, and the electric utilities’ regulatory liabilities (amounting to $315 million as of December 31, 2011) may need to be refunded to ratepayers immediately. Changes in accounting principles can also impact HE I’s consolidated financial st atements. For example, if management determines that a PPA re quires the consolidation of the I PP in HECO’s consolidated financial
statements, the consolidat ion could have a material effect on HECO’s and HEI’s consolidated financial statements, including the recogniti on of a significant amount of a ssets and liabilities and, if such a consolidated IPP were operating at a loss and had insuffici ent equity, the potential recognition of such losses. Also, if management determines that a PPA requires the classification of the agreement as a capital lease, a

material effect on HEI’s consolidated balance sheet may result, including t he recognition of significant capital assets and lease obligations.31 Electric Utility Risks.

Actions of the PUC are outside the control of the el ectric utility subsidiaries and could result in inadequate or untimely rate increases, in rate reductions or ref unds or in unanticipated delays, expenses or writedowns in connection with the construction of new projects. The rates the electric utilities are allowed to charge for their services and the timeliness of permitted rate increases are among the most import ant items influencing the electric utilities’ results of operations, financial co ndition and liquidity. The PUC has broad discretion over the

rates that the electric utilities char ge their customers. The electric util ities currently have rate cases pending before the PUC. In addition, as part of the decoupling me chanism that the electric utilities have or will be implementing, each of the electric utilit ies will alternately file a rate case once every three years. Any adverse decision by the PUC concerning the level or method of determining electric utility rates, the items and amounts that may be included in rate base, the returns on equi ty or rate base found to be reasonable, the potential consequences of exceeding or not meeting such return s, or any prolonged delay in rendering a decision in a rate or other proceeding, could have a material adverse effect on HECO’s consoli dated results of operations, financial condition and liquidity. To improve the timing and certainty of the recovery of their costs, the electric utilities have proposed and received approval of various cost recovery mechanism s including an ECAC, and more recently a decoupling mechanism, a PPAC, and a renewable energy infrastructure program surcharge. The electric utilities could be required to refund to their customers, with inte rest, revenues that have been or may be received under interim rate orders in their rate case proceedings, integrated resource plan cost recovery dockets and other proceedings, if and to the extent they exceed the amounts allowed in final orders. Many public utility projects require PUC approval and various permits (e.g., environmental and land use permits) from other governmental agencie s. Difficulties in obtaining, or the inability to obtain, the necessary approvals or permits, or any adverse decision or polic y made or adopted, or any prolonged delay in rendering a decision, by an agency with respec t to such approvals and permits, can result in significantly increased project costs or even cancellation of projects. For example, HECO’s East Oahu Transmission Project encountered substantial opposition an d consequent delay, increased cost s and a subsequent partial write-off of costs in the fourth quarter of 2011. In the event a project does not proc eed, or if the PUC disallows cost recovery for all or part of a projec t, project costs may need to be written o ff in amounts that could result in significant reductions in HECO ’s consolidated net income.

Energy cost adjustment clauses. The rate schedules of each of HEI’s electric utilities include ECACs under which electric rates charged to customers are automatically adjusted for changes in the weightedaverage price paid for fuel oil and certain component s of purchased power, and the relative amounts of company-generated power and purchased power. The Energy Agreement confirms the intent of the parties that the exis ting ECACs will continue, but subject to periodic review by the PUC. The Energy Agreement al so provides that as part of the review, the PUC may

examine whether there are renewable energy projects from which the utilities should have, but did not, purchase energy or whether alternat ive fuel purchase strategies were appropriately used or not used.
In the recent rate cases, the PUC has allowed the current ECAC to continue. However, a change in, or the
elimination of, the ECAC could have a materi al adverse effect on the electric utilities.

Electric utility operations are significa ntly influenced by weather conditions. The electric utilities’ results of operations can be affected by the weat her. Weather conditions, particularly temperature and humidity, directly influence the demand for electricity. In addition, severe weather and natural disasters, such as hurricanes, earthquakes, tsunamis and lightning storms, which may becom e more severe or frequent as a result of global warming, can cause outages and property damage and require the utilities to incur significant additional expenses that may not be recoverable.32 Electric utility operations de pend heavily on third-party suppliers of fuel and purchased power. The electric utilities rely on fuel oil suppliers and shippers and IPPs to deliver fuel oil and power, respectively, in accordance with contractual agreement s. Approximately 76% of the net energy generat ed or purchased by the electric utilities in 2011 was generated from the burning of fossil fuel oil, and pur chases of power by the electric utilities provided about 40% of their total net energy generated and purchased fo r the same period. Failure or delay by oil suppliers and shippers to provide fuel pursuant to existing contracts, or failure by a major IPP to deliver the firm capacity anticipated in its PPA, could disrupt the ability of the electric utilities to deliver electricity and require the electric utilities to incur additional expenses to meet the needs of their customers that may not be recoverable. In addi tion, as these contractual agreements end, the electric utilities may not be able to purchase fuel and power on terms equivalent to the current contractual agr eements. Further, as the use of biofuels in generating units increases, the same risks will exist with suppliers of biofuels.

Electric utility generating facilities are subject to operational risks that could result in unscheduled plant outages, unanticipated and/or increased operation and maintenance expenses and increased power purchase

costs. Operation of electric generating facilities involves certain risks which can adversely affect energy output and efficiency levels. Included among these risks are fa cility shutdowns or power interruptions due to insufficient generation or a breakdown or failure of equipment or proce sses or interruptions in fuel supply, inability to negotiate satisfactory collective bargaining agreements when existing agr eements expire or other labor disputes, inability to comply with regulatory or per mit requirements, disruptions in delivery of electricity, operator error and catastrophic events such as earthquakes , tsunamis, hurricanes, fires, explosions, floods or other similar occurrences affecting the electric utilities’ generating fac ilities or transmission and distribution systems. The utilities have taken a number of steps to mitigate the risk of outages, including securing additional purchased power, adding new utility gener ation, adding distributed generation and encouraging energy conservation. The costs of supplying energy to meet high demand and maintenance costs required to sustain high availability of aging generation units have been increasing and the trend of cost increases is not likely to ease, putting pressure on earnings to the extent timely cost recovery is not achieved.

The electric utilities may be adversely affected by new legislation. Congress and the Ha waii Legislature periodically consider legislation that could have uncerta in or negative effects on the electric utilities and their customers. The Hawaii Legislature has adopted a number of measur es that will significantly affect the electric
utilities, as described below.

Renewable Portfolio Standards law . In 2009, Hawaii’s RPS law was amended to require electric
utilities to meet an RPS of 10%, 15%, 25% and 40% by December 31, 2010, 2015, 2020 and 2030, respectively. Energy savings resulting from energy ef ficiency programs will not count toward the RPS after 2014. The utilities are committed to achieving t hese goals and met the 2010 RPS; however, due to the exclusion of energy savings in calculating RPS a fter 2014 and risks such as potential delays in IPPs being able to deliver contracted renewable energy, it is possi ble the electric utilities may not attain the required renewable percentages in the future, and management cannot predict the futu re consequences of failure to do so (including potential penalties to be assessed by the PUC). On December 19, 2008, the PUC approved a penalty of $20 for every MWh that an electric utility is deficient under Hawaii’s RPS law. The PUC noted, however, that this penalty may be reduced, in the PUC’s discretion, due to events or circumstances that are outside an electric utility’s reasonable control, to the extent the event or circumstance could not be reasonably
foreseen and ameliorated, as described in the RPS law and in an RPS framework. In addition, the PUC ordered that the utilities will be prohibited from recovering any RPS penalty costs through rates.33 Renewable energy. In 2007, a measure was passed by the Hawaii legislature st ating that the PUC may consider the need for increased renewable energy in rendering decisions on utility matters. Due to this measure, it is possible that, if energy from a renewable source were more expensive than energy from fossil fuel, the PUC may still approve the purchase of energy fr om the renewable source, re sulting in higher costs.

Global climate change and greenhous e gas emissions reduction . National and international concern about climate change and the contributio n of greenhouse gas (GHG) emissions to global warming have led to action by the state of Hawaii and federal legislativ e and regulatory proposals to reduce GHG emissions. In July 2007, Act 234, which requires a statewide reduction of GHG emissi ons by January 1, 2020 to

levels at or below the statewide GHG emi ssion levels in 1990, became law in Hawaii. In recent years, several approaches to GHG emission reduction (including “cap and trade”) have been either introduced or discussed in Congress; however, no legislation has yet been enacted. In response to the 2007 U.S. Supreme Court decision in Massachusetts v. EPA, which ruled that the EPA has the authority to regulate GHG em issions from motor vehicles under the CAA, the EPA has accelerated rulemaking addressing GHG emissions from both mobile and stationary s ources. On Septem ber 22, 2009, the EPA issued the Final Mandatory Reporting of Greenhouse Gases Rule. The rule, which applies to HECO, HELCO and MECO, requires that sources above certain threshold levels m onitor GHG emissions.
On June 3, 2010, the EPA’s final “Prevention of Significant Deterioration (PSD) and Title V Greenhouse Gas (GHG) Tailoring Rule” (GHG Tailoring Rule) was pub lished. It creates a new emissions threshold for GHG emissions from new and existing facilities. The utilities are evaluating the impact of the GHG Tailoring Rule and a three-year permit deferral for biomass-fired and other biogenic sources on t he utilities’ operations.

At this time, it is not possible to predict with cert ainty the impact on the utilities of the foregoing legislation or legislation that now is, or may in the future be, proposed.

The electric utilities may be subject to increased operational challenges and their results of operations, financial condition and liquidity may be adversely impacted in meeting t he commitments and objectives of the HCEI Energy Agreement. On October 20, 2008, the Gove rnor of the State of Ha waii, the State of Hawaii Department of Business, Economic Development and T ourism, the Division of Co nsumer Advocacy of the State of Hawaii Department of Comm erce and Consumer Affairs and the elec tric utilities (collectively, the parties), signed an Energy Agreement setting forth t he goals and objectives of the HCEI and the related commitments of the parties. The Energy Agreement requires the parties to pursue a wide range of actions with the purpose of decreasing the Stat e of Hawaii’s dependence on import ed fossil fuels through substantial increases in the use of renewable energy and implem entation of new programs in tended to secure greater energy efficiency and conservation. The far-reaching nature of the Energy Agreement, in cluding the extent of r enewable energy commitments, presents new increased risks to the Company. Am ong such risks are: (1) the dependence on third party suppliers of renewable purchased energy, which if the utilities are unsuccessf ul in negotiating purchased power agreements with such IPPs or if a major IPP fails to deliver t he anticipated capacity in its purchased power agreement, could impact the utilities’ achievem ent of its commitments under the Energy Agreement and/or the utilities’ ability to deliver re liable service; (2) delays in acquiri ng or unavailability of non-fossil fuel supplies for renewable generation; (3) the impact of intermittent power to the electrical grid and reliability of service if appropriate supporting infras tructure is not installed or does not operate effectively; (4) the likelihood that the utilities may need to make subs tantial investments in related infr astructure, which could result in increased borrowings and, therefore, ma terially impact the financial condition and liquidity of the utilities; and (5) the commitment to support a variet y of initiatives, which, if approv ed by the PUC, may have a material impact on the results of operations and financial c ondition of the utilities depending on their design and implementation. Programs in clude, but are not limited to, decoupling revenues from sales; implementing feedin tariffs to encourage development of renewable energy; removing the system-wide caps on net energy metering (but studying distribut ed generation interconnections on a per-circuit basis); and developing an Energy Efficiency Portfolio Standard. Management cannot predict the ultimate im pact or outcome of the implementation of these or other HCEI programs on the results of o perations, financial condition and liquidity

of the electric utilities.34 Bank Risks.

Fluctuations in interest rates could result in lowe r net interest income, impair ASB’s ability to originate new loans or impair the ability of ASB’s adjustable-rate borrowers to make increased payments. Interest rate risk is a significant risk of ASB’s operations. ASB’s net interest in come consists primarily of interest income received on fixed-rate and adjustable-rate loans, mortgage-related securities and investments and interest expense consisting primarily of interest paid on deposits and other borrowings. Interest ra te risk arises when earning

assets mature or when their interest rates change in a time frame different fr om that of the co sting liabilities. Changes in market interest rates, including changes in the relationship between short-term and long-term

market interest rates or between different interest rate indices, can impact ASB’s net interest margin. Although ASB pursues an asset-liability management stra tegy designed to mitigate its risk from changes in
market interest rates, unfavorable movements in intere st rates could result in lower net interest income. Residential 1-4 family fixed-rate mortgage loans comprised about 50% of ASB’s loan portfolio as of December 31, 2011 and do not re-price with movements in interest rates. ASB continues to face a challenging interest rate environment. The persistent, low level of interest rates and excess liquidity in the financial system have impacted the new loan production rates and made it challenging to find investments with adequate riskadjusted returns, which resulted in a negative impac t on ASB’s asset yields and net interest margin. The potential for compression of ASB’s margin when interest rates rise is an ongoing concern.

Increases in market interest rates could have an adverse impact on ASB’s cost of funds. Higher market interest rates could lead to higher interest rates paid on deposits and other borrowings. Significant increases in market interest rates, or the perc eption that an increase may occur, could adversely affect ASB’s ability to originate new loans and grow. An increase in market in terest rates, especially a sudden increase, could also adversely affect the ability of ASB’s adjustable-rate borro wers to meet their higher payment obligations. If this occurred, it could cause an increase in nonperformi ng assets and charge-offs. Conversely, a decrease in interest rates or a mismatching of ma turities of interest sensitive financial instruments could result in an acceleration in the prepayment of loans and mortgage-rela ted securities and impact ASB’s ability to reinvest its liquidity in similar yielding assets. Historically low interest rates in 2009, 2010 and 2011 resulted in high refinancings, which reduced the level of future interest income.

ASB’s operations are affected by many disparate factors, some of which are beyond its control, that could result in lower net interest income or decreased demand for its products and services. ASB’s results of operations depend primarily on the leve l of interest income generated by ASB’s earning assets in excess of the interest expense on its costing liabilities and the supply of and demand for its products and services (i.e., loans and deposits). ASB’s net income may also be adverse ly affected by various other factors, such as:

 local and other economic and political conditions t hat could result in declines in employment and
real estate values, which in turn could adverse ly affect the ability of borrowers to make loan payments and the ability of ASB to recover the fu ll amounts owing to it under defaulted loans;

 the ability of borrowers to obtain insurance and the ability of ASB to place insurance where borrowers fail to do so, particularly in the event of catastrophic damage to collateral securing loans made by ASB;

 faster than expected loan prepaym ents that can cause an accelera tion of the amortization of premiums on loans and investments and the impairm ent of mortgage servicing assets of ASB;

 changes in ASB’s loan portfolio credit profiles and as set quality, which may increase or decrease the required level of allo wance for loan losses;

 technological disruptions affe cting ASB’s operations or financ ial or operational difficulties experienced by any outside vendor on whom ASB relies to provide key components of its business operations, such as business processi ng, network access or internet connections;

 the impact of potential legislative and regulatory changes affecting capital requirements and increasing oversight of, and reporting by, banks in response to the recent financial crisis and
federal bailout of financial institutions;

 legislative changes regulating the assessment of ov erdraft, interchange and credit card fees, which will have a negative impact on noninterest income;35  public opinion about ASB and financial institutions in general, which, if negative, could impact the public’s trust and confidence in ASB and adversely affe ct ASB’s ability to attract and retain customers and expose ASB to adverse legal and regulatory consequences;

 increases in operating costs, in flation and other factor s, that exceed increas es in ASB’ s net
interest, fee and other income; and

 the ability of ASB to maintain or increase the level of deposits, ASB’s lowest costing funds.

Banking and related regulations could result in signi ficant restrictions being imposed on ASB’s business or in a requirement that HEI divest ASB. ASB is subject to examination and comprehensive regulation by the Department of Treasury, the OCC and the FDIC, and is subject to reserve requirements established by the

Board of Governors of the Federal Reserve System. In addition, the FRB is responsible for regulating ASB’s holding companies, HEI and ASHI. The r egulatory authorities have ex tensive discretion in connection with their supervisory and enforcement activities and examinatio n policies to address not only ASB’s compliance with applicable banking laws and regulat ions, but also capital adequacy, asset quality, management ability and performance, earnings, liquidity and various other factors. Under certain circumstances, including any determinat ion that ASB’s relationship with HEI results in an unsafe and unsound banking practice, these regulatory authorities have the author ity to restrict the ability of

ASB to transfer assets and to make distributions to it s shareholders (including payment of dividends to HEI), or they could seek to require HEI to sever its relationship with or divest its ownership of ASB. Payment by ASB of dividends to HEI may also be restricted by the OCC and FRB under its prompt corrective action regulations or its capital distribution regulations if ASB’ s capital position deteriorates. In order to maintain its status as a QTL, ASB is required to maintain at least 65% of its assets in “qualified thrift investments. ” Institutions that fail to maintain QTL status are subject to various penalties, incl uding limitations on their activities. In ASB’s case, the

activities of HEI and HEI’s other subsidiaries would also be subject to restrictions, and a failure or inability to comply with those restrictions could effectively result in the required divestiture of ASB. Federal legislation has also been proposed in the past that could result in a r equired divestiture of ASB. In the event of a required divestiture, federal law substantially limits the ty pes of entities that could potentially acquire ASB.

Recent legislative and regulator y initiatives could have an adverse effect on ASB’s business. The DoddFrank Act, which became law in July 2010, is expected to have a substantial impact on the financial services industry. The Dodd-Frank Act establishes a framewor k through which regulatory reform will be written and changes to statutes, regulations or regulatory policies could affect ASB in substantial and unpredictable ways. A major component of the Dodd-Frank Act is the creation of the Consum er Financial Protection Bureau that has the responsibility for setting and enforcing clear, cons istent rules relating to consumer financial products and services and has the authority to prohibit practices it finds to be unfair, deceptive or abusive. Compliance with any such directives could have adverse effects on ASB’s revenues or operating costs. Failure to comply with laws, regulations or policies could result in sanc tions by regulatory agencies, ci vil money penalties and/or reputation damage, which could have a material adverse effect on ASB’s business, results of operations, financial condition and liquidity.

A large percentage of ASB’s loans and securities are co llateralized by real estate, and adverse changes in the real estate market and/or general economic conditions may result in loan losses and adversely affect the Company’s profitability. As of December 31, 2011 appr oximately 78% of ASB’s loan portfolio was comprised of loans primarily collateralized by real estate, most of which was conc entrated in the State of Hawaii. ASB’s HELOC (home equity line of credit) portfolio grew by 29% during 2011 and now comprises 19% of total real estate loans. ASB’s financial results may be adversely affected by changes in prevailing economic conditions, either nationally or in the state of Hawaii, including decreases in real estate values, adverse employment conditions, the monetary and fiscal pol icies of the federal and state government and other significant external

events. A deterioration of the economic environment in Hawaii, including a ma terial decline in the real estate
market, further declines in home resales, or a material external shock, may significantly impair the value of ASB’s collateral and ASB’s ability to sell the collateral upon foreclosure. In the event of a default, amounts received upon sale of the collateral may be insufficient to recover outstanding principal and interest. Adverse changes in the economy may also have a negative effect on the ability of borrowers to make timely36 repayments of their loans. In addition, if poor economic conditions result in decreased demand for real estate loans, ASB’s profits may decrease if alternative investments earn less income than real estate loans.

ASB’s strategy to expand its commercial and commercial r eal estate lending activities may result in higher service costs and greater credit risk than residential lending activities due to the unique characteristics of these

markets. ASB has been aggressively pursuing a strategy that includes expanding its commercial and commercial real estate lines of business. These types of loans generally entail higher underwriting and other service costs and present greater credit risks than traditional residential mortgages. Generally, both commercial and commercial real esta te loans have shorter terms to maturity and earn higher spreads than residential mortgage loans. Only the a ssets of the business typically secure commercial loans. In such cases, upon default, any collateral repo ssessed may not be sufficient to repay the outstanding loan balance. In addition, loan collections are dependent on the borrower’s contin uing financial stability and, thus, are more likely to be affected by current ec onomic conditions and adverse business developments. ASB has grown its national syndicated lending portfoli o where ASB is a participant in credit facilities agented by established and reputable national lenders. Management select ively chooses each deal based on

conservative credit criteria to ensure a high quality, well diversified portfolio. Commercial real estate properties tend to be unique a nd are more difficult to value than residential real estate properties. Commercial real estate loans may not be fully amortizing, meani ng that they may have a significant principal balance or “balloon” payment due at maturity. In addition, commercial real estate properties, particularly industrial and warehouse properties, ar e generally subject to relatively greater environmental risks than noncommercial properties and to the corresponding burdens and costs of compliance with environmental laws and regulations. Also, there may be costs and delays involved in enforcing rights of a property owner against tenants in default under the terms of leases with respect to commercial properties. For example, a tenant may seek the protec tion of bankruptcy laws, which could resu lt in termination of the tenant’s

lease.

In addition to the inherent risks of commercial and co mmercial real estate lending described above, the expansion of these new lines of business present exec ution risks, including the ability of ASB to attract personnel experienced in underwriting such loans and t he ability of ASB to appropriately evaluate credit risk associated with such loans in determining the adequacy of its allowance for loan losses.

ITEM 1B. UNRESOLVED STAFF COMMENTS

HEI: None.

HECO: Not applicable.

ITEM 2. PROPERTIES

HEI and HECO: See the “Properties” sections under “HEI,” “E lectric utility” and “Bank” in Item 1. Business

above.37 ITEM 3. LEGAL PROCEEDINGS

HEI and HECO: HEI subsidiaries (including HECO and its subs idiaries and ASB) may be involved in ordinary routine PUC proceedings, environmental proceedings and/or litigatio n incidental to their respective businesses. See the descriptions of legal proceedings (including judicial proceedings and proceedings before

the PUC and environmental and other adm inistrative agencies) in “Item 1. Business,” in HEI’s MD&A and in

the Notes 3 and 4 to HEI’s Consolidated Financial Stat ements. Management believes that, other than these proceedings, the likelihood that HEI or its subsidiaries would incur ma terial losses or writ e-offs in excess of insurance coverage and loss reserves recorded on HEI’ s consolidated balance sheet from lawsuits or other proceedings currently pending or threatened is remo te. Nevertheless, the outcomes of litigation and administrative proceedings are necessarily uncertain and ther e is a risk that the outcom e of such matters could

have a material adverse effect on the fi nancial position, results of operations or liquidity of HEI or one or more of its subsidiaries for a par ticular period in the future.

ITEM 4. MINE SAFETY DISCLOSURES

HEI and HECO: Not applicable.

EXECUTIVE OFFICERS OF THE REGISTRANT (HEI)

The executive officers of HEI are listed below. Messrs. Rosenblum and Wacker are officers of HEI
subsidiaries rather than of HEI, but are deemed to be executive offi cers of HEI under SEC Rule 3b-7 promulgated under the 1934 Exchange Act. HEI executive offi cers serve from the date of their initial appointment until the annual m eeting of the HEI Board (or applicable HE I subsidiary board of directors) at which officers are appointed, and thereafter are appoint ed for one-year terms or until their successors have been duly appointed and qualified or until their earlier resignation or remova l. HEI executive officers may also

hold offices with HEI subsidiaries and affiliates in addition to their current positions listed below.38 Name Age Business experience for last 5 years and prior positions with the Company

Constance H. Lau 59 HEI President and Chief Executive Officer since 5/06
HEI Director, 6/01 to 12/04 and since 5/06

HECO Chairman of the Board since 5/06

ASB Chairman of the Board since 5/06

 ASB Chairman of the Board, 11/10 to present

 ASB Chairman of the Board and Chief Executive Officer, 2/08 to 11/10

 ASB Chairman of the Board, President and Chief Executive Officer, 5/06 to 1/08

 ASB President and Chief Executive Officer and Director, 6/01 to 5/06

 ASB Senior Executive Vice President and Chief Operating Officer and Director,

12/99 to 5/01

 HEI Treasurer, 4/89 to 10/99

 HEI Power Corp. Financial Vice President and Treasurer, 5/97 to 8/99

 HECO Treasurer and HEI Assistant Treasurer, 12/87 to 4/89

 HECO Assistant Corporate Counsel, 9/84 to 12/87

James A. Ajello 58 HEI Executive Vice Presiden t, Chief Financial Officer and Treasurer since 5/11

 HEI Senior Financial Vice President, Treasur er and Chief Financial Officer, 1/09 to

5/11

 Prior to joining the Company: Reliant Energy, Inc. Senior Vice President-Business Development, 8/06 to 1/09, and Reliant Energy, Inc. Senior Vice President and General Manager of Commercial & Industrial Marketing, 1/04 to 8/06

Chester A.

Richardson 63 HEI Executive Vice President, G eneral Counsel, Secretary and Chief

Administrative Officer since 5/11

 HEI Senior Vice President, General Couns el, Secretary and Chief Administrative Officer, 9/09 to 5/11

 HEI Senior Vice President, General Counsel and Chief Administrative Officer, 12/08

to 9/09

 HEI Vice President, General Counsel, 8/07 to 12/08

 Prior to joining the Company: Alliant Energy Corp. Deputy General Counsel, 9/03 to

7/07

Richard M.

Rosenblum 61 HECO President and Chief Executive Officer since 1/09

HECO Director since 2/09

 Prior to joining the Company: Southern California Edison Company Senior Vice President of Generation and Chief Nuclear Officer, 11/05 until his retirement in

5/08

Richard F. Wacker 49 ASB President and Chief Executive Officer since 11/10

ASB Director since 11/10

 Prior to joining the Company: Korea Exchange Bank, Chairman, 4/09 to 11/10; Korea Exchange Bank, Chairman and Chief Executive Officer, 4/07 to 3/09; and Korea Exchange Bank, Chief Executive Officer, 1/05 to 3/07

There are no family relationships between any HEI ex ecutive officer and any other HEI executive officer or any HEI director or director nominee. There are no arrangements or under standings between any HEI executive officer and any other person pursuant to which such executive officer was selected.39 PART II

ITEM 5. MARKET FOR REGISTRANTS’ COMMON EQUITY, RELATED STOCKHOLDER

MATTERS AND ISSUER PURCHAS ES OF EQUITY SECURITIES

HEI: Certain of the information required by this item is incorporated herein by refer ence to Note 13, “Regulatory restrictions on net assets” and Note 16, “Quarterly in formation (unaudited)” to HEI’s Consolidated Financial

Statements and Item 6 “Selected Financial Data” and “Item 12. Equity compensation plan information” of this

Form 10-K. Certain restrictions on dividends and other distributions of HEI are described in this report under “Item 1. Business—HEI—Regulation—Restrictions on divi dends and other distributi ons” and that description is incorporated herein by reference. HEI’s common st ock is traded on the New York Stock Exchange and the

total number of holders of record of HEI common stock (i.e., registered shareholders) as of February 8, 2012,

was 9,386. Purchases of HEI common shares were made during the fourth quarter to satisfy the requirements of certain plans as follows:

ISSUER PURCHASES OF EQUITY SECURITIES

Period* (a)

Total Number of

Shares

Purchased ** (b) Average

Price Paid per Share ** (c)

Total Number of

Shares Purchased as Part of Publicly

Announced Plans or Programs (d) Maximum Number (or Approximate Dollar Value) of

Shares that May Yet Be

Purchased Under the Plans or Programs
October 1 to 31, 2011 60,134 $25.24 – NA
November 1 to 30, 2011 52,738 25.72 – NA
December 1 to 31, 2011 305,580 25.99 – NA
418,452 $25.85 – NA

NA Not applicable. * Trades (total number of shares purchased) are refl ected in the month in which the order is placed.
** The purchases were made to satisfy the requirements of the DRIP, the Hawaiian Electric Industries Retirement Savings Plan (HEIRSP) and the ASB 401(k) Plan for shares pur chased for cash or by the reinvestment of dividends by participants under those plans and none of the purchases were made under publicly announced repurchase plans or programs. Average prices per share are calculated exclusive of any commissions payable to the brok ers making the purchases for the DRIP, the HEIRSP and the ASB 401(k) Plan. Of the shares listed in column (a) all of the 60,134 shares, 46,728 of the 52,738 and 265,880 of the 305,580 share s were purchased for the DRIP, 5,100 of the 52,738 and 35,100 of the 305,580 shares were purchased for the HEIRSP and the remainder were purchased for the ASB 401(k) Plan. The repurchased shares were issued for the accounts of the participants under registration statements registering the shares issued under these plans.

HECO: Since a corporate restructuring on July 1, 1983, all the common stock of HECO has been held solely by its parent, HEI, and is not publicly traded. A ccordingly, information required with respect to “Market information” and “holders” is not applicable to HECO. The dividends declared and paid on HECO’s common stock for the quarters of 2011 and 2010 were as

follows:

Quarters ended 2011 2010
March 31 $17,639,622 $15,149,485
June 30 17,639, 622 11,738,025 September 30 17, 639,622 11,472,370
December 31 17, 639,622 10,409,120

Also, see “Liquidity and capital resources” in HEI’s MD&A. See the discussion of regulatory and ot her restrictions on dividends or ot her distributions in “Restrictions

on dividends and other distributions” under “HEI–Regulation” in Item 1. Business and in Note 13 to HEI’s

Consolidated Financial Statements.40 ITEM 6. SELECTED FINANCIAL DATA

HEI:

Hawaiian Electric Industries, Inc. and Subsidiaries

Years ended December 31 2011 2010 2009 2008 2007 (dollars in thousands, except per share amounts)

Results of operations
Revenues $ 3,242,335 $ 2,664,982 $ 2,309,590 $ 3,218,920 $ 2,536,418
Net income for common stock $ 138,230 $ 113,535 $ 83,011 $ 90,278 $ 84,779 Basic earnings per common share $ 1.45 $ 1.22 $ 0.91 $ 1.07 $ 1.03 Diluted earnings per common share $ 1.44 $ 1.21 $ 0.91 $ 1.07 $ 1.03 Return on average common equity 9.2% 7.8% 5.9% 6.8% 7.2%

Financial position *
Total assets $ 9,592,731 $ 9,085,344 $ 8,925,002 $ 9,295,082 $ 10,293,916 Deposit liabilities 4,070,032 3,975,372 4,058,760 4,180,175 4,347,260 Other bank borrowings 233,229 237,319 297,628 680,973 1,810,669 Long-term debt, net 1,340,070 1,364,942 1,364,815 1,211,501 1,242,099

Preferred stock of subsidiaries – not subject to mandatory redemption 34,293 34,293 34,293 34,293 34,293 Common stock equity 1,531,949 1,483,637 1,441,648 1,389,454 1,275,427

Common stock Book value per common share * $ 15.95 $ 15.67 $ 15.58 $ 15.35 $ 15.29 Market price per common share High 26.79 24.99 22.73 29.75 27.49

Low 20.59 18.63 12.09 20.95 20.25

December 31 26.48 22.79 20.90 22.14 22.77 Dividends per common share 1.24 1.24 1.24 1.24 1.24

Dividend payout ratio 86% 102% 137% 116% 120% Market price to book value per common share * 166% 145% 134% 144% 149% Price earnings ratio ** 18.3x 18.7x 23.0x 20.7x 22.1x Common shares outstanding (thousands) * 96,038 94,691 92,521 90,516 83,432 Weighted-average 95,510 93,421 91,396 84,631 82,215
Shareholders *** 32,004 32,624 33,302 33,588 34,281 Employees * 3,654 3,426 3,453 3,560 3,520

*

**

*** A t December 31. Calculated using December 31 market price per common share divided by basic earnings per common share. The principal trading market for HEI’s common stock is the New York Stock Exchange (NYSE). At December 31. Registered shareholders plus participants in the HEI Dividend Reinvestment and Stock Purchase Plan who are not registered shareholders. As of February 8, 2012, HEI had 31,965 registered shareholders and participants. See “Commitments and contingencies” in Note 3 of HEI’s “Notes to Consolidated Financial Statements” and “Management’s Dis cussion and Analysis of Financial Condition and Results of Operations” for discussions of certain contingencies that could adversely affect future results of operations and factors that affected reported results of operations. On December 8, 2008, HEI completed the issuance and sale of 5 million shares of HEI’s common stock (without par value) u nder an omnibus shelf registration statement. The net proceeds from the sale amounted to approximately $110 million and were primarily used to repay HEI’s outstanding short-term debt and to make loans to HECO (principally to permit HECO to repay its short-term debt). For 2011, 2010, 2009, 2008 and 2007, under the two-class method of computing basic earnings per share, distributed earnin gs were $1.24 per share each year and undistributed earnings (loss) were $0.21, $(0.02), $(0.33), $(0.17) and $(0.21) per share, respectively, fo r both unvested restricted stock awards and unrestricted common stock. For 2011, 2010, 2009, 2008 and 2007, under the two-class method of compu ting diluted earnings per share, distributed earnings were $1.24 per share each year and undistributed earnings (loss) were $0.20, $(0.03), $(0.33), $(0.17) and $(0.21) per share, respectively, for both unvested restricted stock awards and unrestricted common stock.

HECO: The information required by this item is incorporated herein by reference to “Selected Financial Data” on page 4 of HECO Exhibit 99.2.41 ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND

RESULTS OF OPERATIONS

HEI:

The following discussion should be read in conjunction with Hawaiian Electric I ndustries, Inc.’s (HEI’s) consolidated financial statements and accompanying note s. The general discussion of HEI’s consolidated results should be read in conjunction with the segment discussions of the electric utilities and the bank that

follow.

HEI Consolidated

Executive overview and strategy. HEI is a holding company that operates subsidiaries (collectively, the Company), principally in Hawaii’s el ectric utility and banking sectors. HEI’ s strategy is to build fundamental earnings and profitability of its electric utilities and bank in a cont rolled risk manner to support its current dividend and improve operating and capital effici ency in order to build shareholder value. HEI, through its electric utility subsidiaries (Hawaiian Electric Company, Inc. (HECO) and its subsidiaries, Hawaii Electric Light Company, Inc. (HELCO) and Maui El ectric Company, Limited (MECO)), provides the only electric public utility service to approximately 95% of Hawaii ’s population. HEI also provides a wide array of banking and other financial services to consumers and businesses through its bank subsidiary, American Savings Bank, F.S.B. (ASB), one of Hawaii’s largest financial institutions based on

total assets. In 2008, the Company initiated aggr essive strategies to set both th e utilities and ASB on a new course – the utilities entered into an agreement with the State to create a clean energy future for Hawaii and ASB set new performance standards. In 2011, the Company conti nued to make major progress on these strategies (see segment discussions below). Together, HEI’s unique co mbination of electric utilities and a bank continues to provide the Company with a strong balance sheet and the financial resources to invest in the strategic growth of its subsidiaries while providi ng an attractive divide nd for investors.
In 2011, net income for HEI common stock was $138 million, compared to $114 million in 2010. Basic earnings per share were $1.45 per share in 2011, up 19% from $1.22 per share in 2010 due to higher earnings for the electric utility and bank segments, partly offset by sli ghtly higher losses for the “other” segment and the effects of t he higher weighted average number of shares outstanding. Electric utility net income for common stock in 2011 of $100 million increased 31 % from the prior year due primarily to higher interim and final rate increas es and decoupling revenue adjustments. Key to results for 2012 will be the impacts of actions taken under t he Hawaii Clean Energy Initia tive (HCEI) and Energy Agreement, including the steps taken toward the int egration of new generation from a variety of renewable energy sources into the utility syst ems, and managing O&M expenses to the levels included in rates. ASB’s earnings in 2011 of $60 milli on increased $1 million over prior y ear net income due primarily to lower provision for loan losses and noninterest expenses, partly offset by lower net interest and noninterest

income. ASB’s future financial results will continue to be impacted by the intere st rate environment, the quality of ASB’s loan portfolio, and the ongoing resu lts of the performance improvement project. HEI’s “other” segment had a net loss in 2011 of $22 million, comparable to t he net loss in 2010. HEI’s consolidated effective tax rate was 35% in 2011 compar ed to 37% in 2010. The decrease in the effective tax rate was due primarily to additional low income housin g credits and tax-free income from municipal bonds
and bank-owned life insurance at ASB, and a favorable IR S appeals settlement related to foreign losses at

HEI in 2011.

Shareholder dividends are declar ed and paid quarterly by HEI at the discretion of HEI’s Board of Directors. HEI and its predecessor company, HECO, have paid dividends continuously since 1901. The dividend has been stable at $1.24 per share annually since 1998. The i ndicated dividend yield as of December 31, 2011 was 4.7%. The dividend payout rati os based on net income for common stock for 2011, 2010 and 2009 were 86%, 102% and 137%, respectively. The HEI Board of Directors considers many factors in determining the dividend quarterly, includi ng but not limited to the Company’s results of operations, the long-term prospects for the Company, and current and expected future economic conditions.42 HEI’s subsidiaries from time to time consider various strategies designed to enhance their competitive positions and to maximize shareholder value. These stra tegies may include the formation of new subsidiaries or the acquisition or disposition of businesses. The Company may from time to ti me be engaged in preliminary discussions, either internally or with third parties , regarding potential transacti ons. Management cannot predict whether any of these strategies or transactions will be carried out or, if so, whether they will be successfully implemented.

Economic conditions.

Note: The statistical data in this section is from public th ird-party sources (e.g., Department of Business, Economic Developm ent and Tourism (DBEDT); University of Hawaii Economic Research Or ganization (UHERO); U.S. Bureau of Labor Statistics; Blue Chip Economic Indicators; U.S. Energy Information Administration; Hawaii Tourism Authority (HTA); Honolulu Board of REALTORS®; Bureau of Economic Analysis and national and local newspapers).

Hawaii’s tourism industry, a signifi cant driver of Hawaii’s economy, ma intained a positive growth trend in 2011. State visitor arrivals grew by 3.8% in 2011 over 2010. State visitor expenditures continued to grow, increasing by 15.6% in 2011 over 2010. Hotel occupancies and room rate s remain higher year-over-year. The

outlook for the visitor indus try remains positive with the Hawaii Tour ism Authority expecting a 3.8% increase in airline seat capacity in the first quarter of 2012, with growth in international flights offset by a slight decline in U.S. mainland capacity. Hawaii’s unemployment rate was 6.6% in December 2011, higher than the 6.3% in December 2010, but lower than the national unemployment ra te of 8.5% in December 2011. Hawa ii’s unemployment rate has slowly

worsened since June 2011 while the nati onal unemployment rate improved to the lowest level since early 2009. Hawaii jobs continued to grow year-over-year through December 2011, but not enough to improve the unemployment rate. Single family residential home sales on Oahu decreased 14.1% in December 2011 compared to December 2010, and 2011 sales were lower than 2010 by 2.7%. Median prices were slightly higher in December 2011, but for the full year 201 1 median prices were 3% lower than 2010. The price of a barrel of West Texas Intermediat e (WTI) crude oil reached $113. 93 on April 29, 2011, its highest level since 2008, but declined somewhat to aver age $99 per barrel in December 2011. However, while mainland WTI U.S. prices have declined from the peak in April 2011, Hawaii’s petroleum product prices, which reflect supply and demand in the Asia-Pacific region and the price of crude oil on in ternational markets, have remained high, owing in part to the disruption occa sioned by the tragic earthquake and tsunami in Japan in March 2011. The dramatic reduction in nuclear pr oduction has increased regional demand for oil and the utilities’ oil prices have remained consistently high for most of 2011. The Federal Open Market Committee (F OMC) held the federal funds rate target at 0 to 0.25 percent on January 25, 2012, citing low rates of resource utilization and a subdued outlook for inflation. The FOMC also expects the low federal funds rate to continue th rough late 2014 based on the current economic outlook and continued its program announced in S eptember 2011 to extend the average maturity of the System Open Market Account portfolio to suppor t a stronger economic recovery. Overall, Hawaii’s economy is expected to see onl y modest growth in 2012 and 2013 with local economic growth supported by only moderate improvement in the U.S. economy and impeded by some apparent slowing in global economies.

Recent tax developments. The Tax Relief, Unemployment Insura nce Reauthorization and Job Creation Act (the 2010 Act) enacted at the end of 2010 contained major tax provisions which continue to impact the Company. Specifically the 50% and 100% bonus depreciation provisions for certain property result in an estimated net increase in federal tax depreciation of $153 million for 2011 and $128 m illion for 2012, primarily

attributable to the utilities. In additi on, the 2010 Act provided for a 2% reduction in the Social Security tax on employees and self-employed individuals for 2011. Th e Temporary Payroll Tax Cu t Continuation Act of 2011 extended this 2% reduction through February 29, 2012. In December 2011, the Internal Revenue Service (I RS) issued temporary regulations, which provide a framework for determining whether expenditures are deductible as repai rs. Although label ed “temporary,”43 these regulations have the binding effe ct of final regulations and are e ffective January 1, 2012. The IRS is expected to issue additional revenue procedures contai ning transitional rules and guidance. The Company will analyze these regulations and any subsequently issued guidance for their impacts and for the opportunities they present for 2012 and future years.

Results of operations.

(dollars in millions, except per share amounts) 2011 % change 2010 % change 2009

Revenues $ 3,242 22 $ 2,665 15 $ 2,310 Operating income 290 13 256 37 188

Net income for common stock 138 22 114 37 83

Net income (loss) by segment: Electric utility $ 100 31 $ 77 (4) $ 79

Bank 60 2 58 169 22 Other (22) NM (21) NM (18)

Net income for common stock $ 138 22 $ 114 37 $ 83

Basic earnings per share $ 1.45 19 $ 1.22 34 $ 0.91
Diluted earnings per share $ 1.44 19 $ 1.21 33 $ 0.91
Dividends per share $ 1.24 – $ 1.24 – $ 1.24 Weighted-average number of common shares outstanding (millions) 95.5 2 93.4 2 91.4 Dividend payout ratio 86% 102% 137%

NM Not meaningful.

See “Executive overview and strategy” above and the “Other segment,” “E lectric utility” and “Bank”

sections below for discussions of results of operations.

Retirement benefits . The Company’s reported costs of providing reti rement benefits are dependent upon numerous factors resulting from actual plan experi ence and assumptions about future experience. For example, retirement benefits costs are impacted by actual employee demographics (including age and compensation levels), the level of contributions to the plans, plus earnings and realized and unrealized gains and losses on plan assets, and changes made to the provis ions of the plans. During 2011, for example, the qualified retirement plan for employees of HEI and HECO was changed for employees hired on or after May 1, 2011. Those employees will receive lower benefit accruals, different early retirement reduction factors and no automatic cost of living increases. The change is ex pected to decrease ongoing co sts through a reduction in service cost. (See Note 9 of HEI’s “Notes to C onsolidated Financial Statem ents.”) Costs may also be significantly affected by changes in key actuarial assu mptions, including the expected return on plan assets and the discount rate. The Company’s accounting for retirement benefits under the plans in which the employees of HECO and its subsidiaries participate is al so adjusted to account for the impact of decisions by

the Public Utilities Commission of the State of Ha waii (PUC). Changes in obligat ions associated with the factors noted above may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remain ing average service period of plan participants. The assumptions used by management in making ben efit and funding calculations are based on current economic conditions. Changes in economic conditions will impact the underlying assumptions in determining retirement benefits costs on a prospective basis. For 2011, the Company’s retire ment benefit plans’ assets gener ated a loss of 1.3%, including investment management fees, resulting in net losses and unrealized losses of $7 million, compared to net earnings and unrealized gains of $145 million for 2010 and net earnings and unrealized gains of $186 million

for 2009. The market value of t he retirement benefit plans’ assets for both December 31, 2011 and 2010
was $983 million. The Company intends to make contributions to t he qualified retirement plan for HEI and HECO equal to the calculated net periodic pension cost for the y ear. However, if the mini mum required contribution determined under the Employee Retirement Income Security Act of 1974 (ERISA), as amended by the
Pension Protection Act of 2006, for t he year is greater than the net periodic pension cost, then the Company44 will contribute the minimum required contribution and the utilities’ difference bet ween the minimum required contribution and the net periodic pension cost will increa se their regulatory asset. In the next rate case, the regulatory asset will be amortized over five years and used to reduce the cash funding requirement based on net periodic pension cost. The regulatory asset ma y not be applied against the ERISA minimum required

contribution. The ERISA minimum required contribution is expect ed to be higher than the net periodic pension cost for
2012 and 2013. Therefore, the “Pension Protection Act minimum required contribution” will be the basis of the cash funding for 2012 and 2013 as shown in the following table and constitutes “forward-looking statements”:

(in millions) 2012 2013

Pension Protection Act estimated minimum required contribution:
Based on plan assets as of December 31, 2011

Consolidated HECO $102 $87

Consolidated HEI 104 89

The Company’s Pension Protection Act minimum required contribution in 2012 is estimated to increase to $104 million primarily due to the decrease in the effective interest rate. The estimated subsequent decrease in 2013 to $89 million is primarily due to assumed asset growth outpacing assumed liability growth. Actual results, however, could di ffer substantially from these estimates. Based on various assumptions in Note 9 of HEI’ s “Notes to Consolidat ed Financial Statements” and assuming no further changes in retirement benefit plan pr ovisions, information regar ding consolidated HEI’s,

consolidated HECO’s and ASB’s retirem ent benefits was, or is estimated to be, as follows, and constitutes “forward-looking statements”:

AOCI balance, net of tax
benefits, related to retirement benefits liability Retirement benefits expense,

net of tax benefits Retirement benefits paid and plan expenses

December 31 Years ended December 31 Years ended December 31

(in millions) 2011 2010 (Estimated)

2012 2011 2010 2009 2011 2010 2009

Consolidated HEI $28 $(15) $23 $22 $24 $21 $66 $64 $61

Consolidated HECO – 1 21 21 24 19 61 60 57 ASB 19 (10) – – (1)

– 3 3 3

Sensitivities of the projec ted benefit obligation (PBO) and a ccumulated postretirement benefit obligation (APBO) as of December 31, 2011, associ ated with a change in certain actuarial assumptions,

were as follows and constitute “forward-looking statements.”

Baseline assumptions: 5.19% discount rate for pension benefits; 4.90% discount rate for other benefits; 7.75% asset return rate; 8.5% medical trend rate for 2012, grading down to 5% for 2019 and thereafter; 5% dental trend rate; and 4% vision

trend rate.

The impact on 2012 net income for common stock for changes in actuarial assumptions should be immaterial based on the adoption by the electric ut ilities of pension and postret irement benefits other than pensions (OPEB) tracking mechanisms approved by the PUC. See Note 9 of HEI’s “Notes to Consolidated

Financial Statements” for further retirement benefits information.

Actuarial assumption Change in assumption in basis points Impact on

PBO or APBO (dollars in millions)

Pension benefits Discount rate +/– 50 $(85)/$94

Other benefits Discount rate +/– 50 (12)/13 Health care cost trend rate +/– 100 4/(5)45 Other segment.

(dollars in millions) 2011 % change 2010 % change 2009

Revenues 1 $ (1) NM $ – NM $ – Operating loss (17) NM (15) NM (14) Net loss (22) NM (22) NM (18)

1 Including writedowns of and net gains and losses from investments.
NM Not meaningful.

The “other” business segment includes results of the stand-alone corporat e operations of HEI and American Savings Holdings, Inc. ( ASHI), both holding companies; HEI Prope rties, Inc. (HEIPI), a company holding passive, venture capital inve stments (venture capital investm ents valued at $0.6 million as of December 31, 2011); and The Old Oahu Tug Service, In c. (TOOTS), a maritime freight transportation company that ceased operations in 1999, HEI Investm ents, Inc. (HEIII), a company previously holding investments in leveraged leases but whose wind-down was substantia lly completed during 2009; Pacific Energy Conservation Services, Inc. (PECS), a con tract services company which provided windfarm operational and maintenance services to an affiliated el ectric utility until the windf arm was dismantled in the fourth quarter of 2010 and dissolved in the second quarter of 2011; as well as eliminations of intercompany

transactions. HEI corporate-level operating, general and administrative expenses we re $15 million in 2011 compared to $13 million in each of 2010 and 2009. In 2011, expens e increased primarily due to the accrual of
$3 million of contributions to be made to the HEI Charitable Foundat ion in 2012. In 2010, expenses increased slightly primarily due to higher compensation expense, partly offset by lower retirement benefit expense and an accrual in 2009 to di smantle a windfarm in 2010. The “other” segment’s interest expenses were $22 million in 2011, $20 m illion in 2010 and $18 million in 2009. In 2011 and 2010, financing costs were higher due in part to the recognition of the ineffective portion of the change in fair value of the forward starting swaps. Also in 2010, there was a higher level of borrowings. The “other” segment’s income tax benef its were $17 million in 2011, $13 million in 2010 and
$14 million in 2009. The increase in income tax benefits in 2011 was primarily due to higher operating losses, higher interest expense and a favorable se ttlement in 2011 in an IRS appeal related to the character (ordinary versus capital) of a foreign loss, and the write-off in 2010 of a deferred tax asset due to the expiration of a capital loss carryforward period.

Effects of inflation. U.S. inflation, as measur ed by the U.S. Consumer Price Index (CPI), averaged 3.2% in 2011, 1.6% in 2010 and (0.4%) in 2009. Hawaii inflation, as measured by the Honolulu CPI, was 2.1% in 2010 and 0.5% in 2009. The Department of Business, Economic Development and Tourism estimates average

Honolulu CPI to have been 3.3% in 2011 and forecasts it to be 2.8% for 2012. Inflation continues to have an impact on HEI’s oper ations. Inflation increases operating costs and the replacement cost of assets. Subsidia ries with significant physical asse ts, such as the electric utilities, replace assets at much higher costs and must r equest and obtain rate increases to maintain adequate earnings. In the past, the PUC has granted rate increases in part to cover increases in construction costs and operating expenses due to inflation.

Recent accounting pronouncements. See “Recent accounting pronouncements and interpretations” in

Note 1 of HEI’s “Notes to C onsolidated Financia l Statements.”46 Liquidity and capital resources.

Selected contractual oblig ations and commitments. Information about payment s under the specified contractual obligations and comme rcial commitments was as follows:

December 31, 2011 Payments due by period

(in millions) Total Less than 1 year 1-3

years 3-5

years More than 5 years Contractual obligations Deposit liabilities 1 $ 4,070 $ 3,851 $ 124 $ 83 $ 12 Other bank borrowings 233 133 – 50 50 Long-term debt 1,341 65 161 75 1,040 Interest on certificates of deposit, other bank borrowings and long-term debt 1,047 80 146 129 692 Operating leases, service bureau contract and maintenance agreements 101 23 33 22 23 Open purchase order obligations 2 141 97 26 18 – Fuel oil purchase obligations (estimate based on December 31, 2011 fuel oil prices) 1,806 1,033 773

– – Power purchase obligations–minimum fixed capacity charges 1,163 121 238 208 596 Liabilities for uncertain tax positions 6 5 1 – – Total (estimated) $ 9,908 $ 5,408 $1,502 $585 $2,413

1 Deposits that have no maturity are included in the “Less than 1 year” column, however, they may have a duration longer than one year.

2 Includes contractual obligations and commitments for capital expenditures and expense amounts.

December 31, 2011 Total (in millions)

Other commercial commitments to ASB customers Loan commitments (primarily expiring in 2012) $ 24 Loans in process 72
Unused lines and letters of credit 1,243

Total $ 1,339

The tables above do not include other categories of obligations and commitm ents, such as deferred taxes, trade payables, amounts that will become payab le in future periods under collective bargaining and other employment agreements and empl oyee benefit plans, obligations t hat may arise under indemnities provided to purchasers of discont inued operations and potent ial refunds of amounts collected under interim decision and orders (D&Os) of the PUC. As of December 31, 2011, the fair value of the assets held in trusts to satisfy the obligations of the Company’s retirem ent benefit plans did not exceed the retirement benefit plans’ benefit obligation. Minimum funding requirements for retireme nt benefit plans have not been included
in the tables above; however, see “Retirement benefits” above for estima ted minimum required contributions

for 2012 and 2013.

See Note 3 of HEI’s “Notes to Consolidated Financ ial Statements” for a discu ssion of fuel and power purchase commitments. The Company believes that its ability to generate ca sh, both internally from electric utility and banking operations and externally from issuances of equity and debt securities, commercial paper and bank borrowings, is adequate to maintain sufficient liquidity to fund its contractual obligations and commercial commitments, its forecasted capital expenditures and investments, its expect ed retirement benefit plan contributions and other cash require ments in the foreseeable future. The Company’s total assets were $9.6 billion as of December 31, 2011 and $9.1 billion as of
December 31, 2010.47 The consolidated capital structure of HEI (excluding deposit liabilities and other bank borrowings) was as

follows:

December 31 2011 2010 (dollars in millions)

Short-term borrowings—other than bank $ 69 2% $ 25 1% Long-term debt, net—other than bank 1,340 45 1,365 47

Preferred stock of subsidiaries 34 1 34 1 Common stock equity 1,532 52 1,484 51
$2,975 100% $2,908 100%

HEI’s short-term borrowings and HEI’s li ne of credit facility were as follows:

Year ended
December 31, 2011

(in millions) Average

balance End-of-period

balance December 31,

2010

Short-term borrowings 1 Commercial paper $ 14 $ 69 $ 25

Line of credit draws – – – Undrawn capacity under HEI’s line of credi t facility (expiring December 5, 2016) 125 125 125

1 This table does not include HECO’s separate commercial paper issuances and line of credit facilities and draws, which are disclosed below under “Electric utility—Financial Condition—Liqui dity and capital resources. At February 8, 2012, HEI’s outstanding commercial paper balance was $67 million and its line of credit facility was undrawn. The maximum amount of HEI’s short-term borrowings in 2011 was $77 million.

HEI utilizes short-term debt, typically commerc ial paper, to support normal operations, to refinance commercial paper, to retire long-term debt, to pay dividends and for other temporary requirements. HEI also periodically makes short-term loans to HECO to meet HECO’s cash requirements, including the funding of loans by HECO to HELCO and MECO, but no such sho rt-term loans to HECO were outstanding as of December 31, 2011. HEI periodically utilizes long-term debt, historically consisting of medium-term notes
and other unsecured indebtedness, to fund investments in and loans to its subsidiaries to support their capital improvement or other requi rements, to repay long-term and s hort-term indebtedness and for other corporate purposes. In November 2011, HEI filed an om nibus registration statement to re gister an indeterminate amount of debt and equity securities. Under Securities and Exch ange Commission (SEC) regulations, this registration statement expires on November 4, 2014. On March 24, 2011, HEI issued $125 million of Senior Notes via a private placement ($75 million of 4.41%
notes due March 24, 2016 and $50 millio n of 5.67% notes due March 24, 2021). HEI used part of the net proceeds from the issuance of the Senior Notes to pay down commercial paper (originally issued to refinance
$50 million of 4.23% medium-term not es that matured on March 15, 2011) and ultimately used the remaining proceeds to refinance part of the $100 million of 6.141 % medium-term notes that matured on August 15, 2011. The Note Agreement contains cust omary representation and warranties, affirmative and negative covenants, and events of default (the occurrence of which may resu lt in some or all of the notes then outstanding becoming immediately due and payable) and provisions r equiring the maintenance by HEI of certain financial ratios generally consistent with those in HEI’s revolving noncollateralized cr edit agreement, expiring on December 5, 2016. For example, it is an event of default if HEI fails to maintain a nonconsolidated “Capitalization Ratio” (funded debt) of 50% or less (ratio of 19% as of Dece mber 31, 2011, as calculated under the agreement) or “Consolidated Net Worth” of at l east $975 million (Net Worth of $1.6 billion as of December 31, 2011, as calculated under the agreement). T he Note Agreement also r equires that HEI offer to prepay the Notes upon a change of control or certain di spositions of assets (as defined in the Note Agreement). HEI has a line of credit facility of $125 million. S ee Note 7 of HEI’s “Notes to Consolidated Financial Statements.” The credit agreem ent, amended in December 2011, contains pr ovisions for revised pricing in the event of a ratings change. For example, a ratings dow ngrade of HEI’s Issuer Rati ng (e.g., from BBB/Baa2 to48 BBB-/Baa3 by Standard & Poor’s (S&P) and Moody’s Investors Service (Moody’s), respectively) would result in a commitment fee increase of 5 basis points and an inte rest rate increase of 25 basis points on any drawn
amounts. On the other hand, a ra tings upgrade (e.g., from BBB/Baa2 to BBB+/Baa1 by S&P or Moody’s, respectively) would result in a commi tment fee decrease of 2.5 basis points and an interest rate decrease of 25 basis points on any drawn amounts. T he agreement contains customary condi tions which must be met in order to draw on it, including compliance with its covenants (such as covenants preventing its subsidiaries from entering into agreements that restrict th e ability of the subsidiaries to pay dividends to, or to repay borrowings from, HEI). In addition to cu stomary defaults, HEI’s failure to mainta in its financial ratios, as defined in its agreement, or meet other requirements may result in an event of default. For example, under its agreement, it

is an event of default if HEI fails to maintain a nonc onsolidated “Capitalization Ra tio” (funded debt) of 50% or less (ratio of 19% as of December 31, 2011, as ca lculated under the agreement) and “Consolidated Net Worth” of at least $975 million (Net Wort h of $1.6 billion as of December 31, 2011, as calculated under the agreement), or if HEI no longer owns HECO. In addition to their impact on pricing under HEI’s credit agreement, the rating of HEI’s commercial paper and debt securities could significantly impact the ab ility of HEI to sell its commercial paper and issue debt

securities and/or the cost of such debt. The rating agencies use a combination of qualitative measures (i.e., assessment of business risk that incorporates an anal ysis of the qualitative factors such as management, competitive positioning, operations, markets and regulation) as well as quantitative measures (e.g., cash flow, debt, interest coverage and liquidity ratios) in determining the ratings of HEI securities. On August 1, 2011, Moody’s maintained HEI’s long-term and short-term (commercial paper) ra tings and stable outlook, indicating that the ratings reflect the relative ly stable earnings and cash flow hist orically provided by its vertically integrated utility businesses and banki ng operation. The stable rating outlook factors in Moody’s belief that (1) the decoupling mechanism will reduce regulatory lag and better match cost recovery of expenses and capital investment such that HECO’s consolidated RO E will approach authorized returns over time and (2) the expectation that profitability initiati ves at ASB will produce fairly predict able earnings enabling ASB to provide regular dividends to HEI without jeopardizing the bank’s strong capital position. Moody’s indicated the rating could be downgraded if the PUC does not follow through with the regulatory trans formation contemplated under the HCEI, including all elements of the decoupling me chanism or if HEI’s cash flow to debt declined to below 15% (20% last twelve months as of March 31, 2011 – latest reported by Moody’s) and its cash flow coverage of interest fell below 3.3 times (5.0 times last twelve months as of Ma rch 31, 2011 – latest reported by Moody’s) on a sustainable basis. On November 18, 2011, S&P maintained HEI’s long-term and corporate credit rating of “BBB-”, short-term (c ommercial paper) rating of “A-3”, st able outlook and “aggressive” financial profile. The stable outlook reflects S&P’s view that des pite anticipated weaker cash flow metrics in 2012 and 2013, the consolidated credit profile will remain consis tent with the HEI “BBB-” ratings and the expectation that any financial profile improvements from decoupling approved this year for HECO will be gradual. S&P indicated the rating could come under pressure if rate case disallowances are significant enough to drive HEI’s funds from operations (FFO) to tota l debt to less than 10% and FFO intere st coverage to less than 3 times, and/or if leverage exceeds 60% fully adjusted on a consistent basis. As of February 8, 2012, the S&P and Moody’s ratings of HEI securities were as follows:
S&P Moody’s

Commercial paper A-3 P-2

Senior unsecured debt BBB- Baa2
The above ratings reflect only the view, at the time the rati ngs are issued, of the applicable rating agency, from whom an explanation of the significance of such ratings may be obtained. Such ratings are not recommendations to buy, sell or hold any securities; such ratings may be subject to revision or withdr awal at any time by the rating agencies; and each rating should be evaluated independently of any other rating.

Management believes that, if HEI’s commercial paper ratings were to be downgraded, or if credit markets for commercial paper with HEI’s ratings or in general were to tighten, it could be more difficult and/or expensive for HEI to sell commercial paper or HEI might not be able to sell commercial paper in the

future. Such limitations could cause HEI to draw on its syndicated credit facilit y instead, and the costs of such borrowings could increase under the terms of t he credit agreement as a resu lt of any such ratings49 downgrades. Similarly, if HEI’s long- term debt ratings were to be downgr aded, it could be more difficult and/or expensive for HEI to issue long-term debt. Such limitations and/or increas ed costs could materially adversely affect the results of operations, financial condition and liquidity of HEI and its subsidiaries. Issuances of common stock through the Hawaiian Electric Industries, Inc. Dividend Reinvestment and Stock Purchase Plan (DRIP), Hawaiian Electric Indus tries Retirement Savings Plan (HEIRSP) and the ASB 401(k) Plan (which was split off fr om HEIRSP in 2009) provided new c apital of $24 million (approximately 1.0 million shares) in 2011, $43 million (approxim ately 1.9 million shares) in 2010 and $32 million (approximately 2.0 milli on shares) in 2009. From April 16, 2009 through September 3, 2009 and from August 18, 2011 to December 31, 2011, HEI satisfied t he share purchase requirement s of the DRIP, HEIRSP and ASB 401(k) Plan through open market purchases of its common stock rather than new issuances. Operating activities provided net cash of $250 million in 2011, $341 million in 2010 and $269 million in 2009. Investing activities provided (used) net cash of $(327) million in 2011, $(279) million in 2010 and
$458 million in 2009. In 2011, net cash used in invest ing activities was primarily due to purchases of investment and mortgage-related securities, HECO’s cons olidated capital expenditure s (net of contributions in aid of construction) and a net increase in loans hel d for investment, partly offs et by the repayments of, and the proceeds from sales of, investment and mortgage -related securities. Financing activities provided (used) net cash of $16 million in 2011, $(235) million in 2010 and $(406) million in 2009. In 2011, net cash provided by financing activities included net increas es in deposits and short-term borrowings and proceeds from the issuance of common stock under HEI plans, offs et by the net decrease in long-term debt and other bank borrowings and the payment of common and pr eferred stock dividends. Other than capital contributions from their parent company, intercom pany services (and related intercompany payables and receivables), HECO’s periodic short-term borrowings from HEI (and related interest) and the payment of dividends to HEI, the electric utility and bank segments are largely autonomous in their operating, investing and financing activities. (See the electric utility and bank segments’ discussions of their cash flows in their respective “Financial condition–Liquidity and capital resources” sections below.) During 2011, HECO and ASB paid cash dividends to HEI of $71 million and $58 million, respectively. A portion of the net assets of HECO and ASB is not available for transfer to HEI in the form of dividends, loans or advances without regulatory approval . One of the conditions to the PUC’s approval of the merger and corporate restruct uring of HECO and HEI requires that HECO maintain a consolidated common equity to total capitalization ratio of not less than 35% (actual ratio of 56% at December 31, 2011), and restricts HECO from making distributi ons to HEI to the extent it would result in that ratio being less than 35%. In the absence of an unexpected material adverse change in the financial condition of the electric
utilities or ASB, such restrictions ar e not expected to significantly affect the operations of HEI, its ability to pay dividends on its common stock or it s ability to meet its debt or other cash obligations. See Note 13 of

HEI’s “Notes to Consolidated Financial Statements.”

Forecasted HEI consolidated “net cash used in inve sting activities” (excluding “investing” cash flows from ASB) for 2012 through 2014 consists primarily of the net capital expenditures of HECO and its subsidiaries. In addition to the funds required for the electric utilities’ construc tion programs (see “Electric utility–Liquidity and capital resources”), approxim ately $157 million will be required during 2012 through 2014 to repay maturing HEI medium-term notes, which are expected to be repaid with the proceeds from the issuance of commercial paper, bank borrowings, ot her medium- or long-te rm debt, common stock issued under Company plans and/or dividends from s ubsidiaries. In addition, HECO special purpose revenue bonds (SPRBs) totaling $69 million will be maturing during 2012 through 2014 and are expected to be repaid with proceeds from issuances of long-term debt. Additional debt and/ or equity financing may be utilized to invest in the utilities and bank, pay down commercial paper or other short-term borrowings or may be required to fund unanticipated expenditures not included in the 2012 through 2014 forecast, such

as increases in the costs of or an acceleration of t he construction of capital pr ojects of the utilities, unanticipated utility capital expenditure s that may be required by the HCE I or new environmental laws and regulations, unbudgeted acquisitions or in vestments in new businesses, signi ficant increases in retirement benefit funding requirements and higher ta x payments that would result if certain tax positions taken by the Company do not prevail or if taxes are increased by f ederal or state legislation. In addition, existing debt50 may be refinanced prior to maturity (potentially at mo re favorable rates) with additional debt or equity financing (or both). As further explained in “Retirem ent benefits” above and Notes 1 and 9 of HEI’s “Notes to Consolidated Financial Statements,” the Company maintains pens ion and other postretirem ent benefit plans. The Company was required to make contributions of $72.9 million for 2011 and $19.1 million for 2010, but was not required to make any contributions for 2009 to the qualified pension plans to meet minimum funding requirements pursuant to ERISA, including changes promulgated by t he Pension Protection Act of 2006. The Company also made additional voluntary contributions to t hese plans in 2011, 2010 and 2009.

Contributions to the reti rement benefit plans totaled $75 million in 2011 (comprised of $73 million by the utilities, $2 million by HEI and nil by ASB), $32 milli on in 2010 and $25 million in 2009 and are expected to total $107 million in 2012 ($104 milli on by the utilities, $3 million by HE I and nil by ASB). In addition, the Company paid directly $2 million of benefits in each of 2011 and 2010 and $1 million in 2009 and expects to pay $2 million of benefits in 2012. Depending on the perfo rmance of the assets held in the plans’ trusts
and numerous other factors, additional contributions may be required in t he future to meet the minimum funding requirements of ERISA or to pay benefits to plan participants. The Company believes it will have adequate cash flow or access to capital resources to support any necessary funding requirements.

Off-balance sheet arrangements. Although the Company has off-bal ance sheet arrangements, management

has determined that it has no off-bal ance sheet arrangements that either have, or are reasonably likely to have, a current or future effect on the Company’s finan cial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital ex penditures or capital resources that are material to investors, including the following types of off-balance sheet arrangements: (1) obligations under guarantee contracts, (2) retained or contingent interests in assets transferred to an unconsolidated entity or similar arrangements that serve as credit, liquidity or mark et risk support to that entity for such assets, (3) obligations under deriv ative instruments, and (4) obligations under a material variable interest held by the Company in an unconsolidated entity that provides financing, liquidity, market risk or credit risk support to the Company, or engages in leasing, hedging or research and develop ment services with the Company.

Certain factors that may affect future results and financial condition. The Company’s results of operations and financial condition can be affected by nume rous factors, many of which are beyond its control and could cause future results of operations to differ ma terially from historical results. The following is a

discussion of certain of these factors. Also see “For ward-Looking Statements” above and “Certain factors that may affect future results and financial condition” in eac h of the electric utility and bank segment discussions

below.

Economic conditions, U.S. capital market s and credit and interest rate environment. Because the core businesses of HEI’s subsidiaries are providing local electric public utility services and banking services in Hawaii, the Company’s operating result s are significantly influenced by Hawaii’s economy, which in turn is influenced by economic conditions in the mainland U. S. (particularly California) and Asia (particularly Japan) as a result of the impact of those conditions on t ourism, by the impact of inte rest rates, particularly on the construction and real estate industries, and by the impact of world conditi ons on federal government spending in Hawaii. The two largest components of Hawaii’s economy are tourism and the federal government (including the military).
Declines in the Hawaii, U.S. and Asian economies in recent years led to declines in KWH sales, delinquencies in ASB’s loan portfolio and other adverse effects on HEI’s businesses. If S&P or Moody’s were to further downgrade HEI’s or HECO’s debt ratings, or if future events were to adversely affect the availability of capital to t he Company, HEI’s and HECO’s ability to borrow and raise capital could be constrained and their future borrowing costs would likely increase. Changes in the U.S. capital markets can also hav e significant effects on the Company. For example, pension funding requirements are affe cted by the market performance of the assets in the master pension trust, and by the discount rate used to estimate t he service and interest cost components of net periodic51 pension cost and value obligations. The electric ut ilities’ pension tracking mechanisms help moderate pension expense; however, a decline in the value of the Company’s defined benefit pension plan assets may increase the unfunded status of t he Company’s pension plans and result in increases in future funding requirements. Because the earnings of ASB depend primarily on net inte rest income, interest rate risk is a significant risk of ASB’s operations. HEI and its electric utility subs idiaries are also exposed to interest rate risk primarily due to their periodic borro wing requirements, the discount rate used to determine pension funding requirements and the possible effect of interest rates on the electric ut ilities’ rates of return and overall economic activity. Interest rates are sensitive to many factors, including general economic conditions and the policies of government and regulatory authorities. HE I cannot predict future c hanges in interest rates, nor be certain that interest rate risk management strategi es it or its subsidiaries have implemented will be successful in managing in terest rate risk. Changes in interest rates and credit spreads also affect the fair value of ASB’s investment securities. In 2009, the credit markets experienced significant disruptions, liquidity on many financial instruments declined and residential mortgage delinquencies and defaults incr eased. These disruptions negatively impacted the fair value of ASB’s investment portfolio in 2009. Ho wever, with the fourth quarter 2009 sale of ASB’s remaining private-issue mortgage-related securities por tfolio and substantial residential loan production in 2009 and 2010, the Company’s exposure to credi t and interest rate risks have been reduced.

Limited insurance. In the ordinary course of business, t he Company purchases insurance coverages (e.g., property and liability coverages) to protect itself against loss of or damage to its properties and against claims made by third-parties and employees for pr operty damage or personal in juries. However, the protection provided by such insurance is limited in si gnificant respects and, in some instances, the Company has no coverage. HECO, HELCO and MECO’s transmi ssion and distribution systems (excluding substation buildings and contents) have a replacement val ue roughly estimated at $5 billion and are uninsured. Similarly, HECO, HELCO and MECO have no business interruption insurance. If a hurricane or other uninsured catastrophic natural disaster were to occur, and if the PUC were not to allow the utilities to recover from ratepayers restoration costs and revenues lost from busine ss interruption, their results of operations, financial condition and liquidity could be materially adversely impacted. Certain of the Company’s insurance has substantial “deductibles ” or has limits on the ma ximum amounts that may be

recovered. Insurers also have exclusions or limitati ons of coverage for claims related to certain perils including, but not limited to, mold and terrorism. If a series of losses occurred, such as from a series of lawsuits in the ordinary course of business each of which were subject to an insurance deductible amount,

or if the maximum limit of the av ailable insurance were substantiall y exceeded, the Company could incur

uninsured losses in amounts that would have a materi al adverse effect on the Company’s results of operations, financial condition and liquidity.

Environmental matters. HEI and its subsidiaries are subject to environmental laws and regulations that regulate the operation of existing facilities, the cons truction and operation of new facilities and the proper cleanup and disposal of hazardous waste and toxic s ubstances. These laws and regulations, among other things, may require that certain environmental permits be obtained and maintained as a condition to constructing or operating certain facilities. Obtaini ng such permits can entail significant expense and cause substantial construction delays. Also, these laws and regulations may be amended from time to time, including amendments that increase the burden and expense of compliance.

Material estimates and critical accounting policies. In preparing financial statements, management is required to make estimates and assumptions that affe ct the reported am ounts of assets and liabilities, the disclosure of contingent assets and liabilities and t he reported amounts of rev enues and expenses. Actual results could differ significantly from those estimates. Material estimates that are particularly susceptib le to significant change include the amounts reported for investment and mortgage-related securities ; property, plant and equipm ent; pension and other postretirement benefit obligations; contingencies and litigation; inco me taxes; regulatory assets and liabilities; electric utility revenues; and allowance for loan losses. Management considers an accounting52 estimate to be material if it requi res assumptions to be made that were uncertain at the time the estimate was made and changes in the assumptions selected could have a material impact on the estimate and on the Company’s results of oper ations or financial condition.
In accordance with SEC Release No. 33-8040, “Caut ionary Advice Regarding Disclosure About Critical Accounting Policies,” management has ident ified accounting policies it believes to be the most critical to the Company’s financial statements—that is, management believes that the policies discussed below are both the most important to the portra yal of the Company’s results of operations and financial condition, and currently require management’s most difficult, subjecti ve or complex judgments. The policies affecting both of the Company’s two principal segments are discuss ed below and the policies affecting just one segment are discussed in the respective segment’s section of “Material estimates and crit ical accounting policies.” Management has reviewed the material estimates and cr itical accounting policies with the HEI Audit Committee and, as applicable, the HECO Audit Committee. For additional discussion of the Company’s accounti ng policies, see Note 1 of HEI’s “Notes to

Consolidated Financial Statements” and for additional discussion of material estimates and critical accounting policies, see the electric utility and bank segment discussions below under the same heading.

Pension and other postretir ement benefits obligations. For a discussion of material estimates related to pension and other postretirement benef its (collectively, retirement benefits), including costs, major assumptions, plan assets, other factors affecting cost s, accumulated other comp rehensive income (loss) (AOCI) charges and sensitivity analyses, see “Retirem ent benefits” in “Consolidat ed—Results of operations”

above and Notes 1 and 9 of HEI’s “Notes to Consolidated Fi nancial Statements.”

Contingencies and litigation . The Company is subject to proceedings (including PUC proceedings), lawsuits and other claims. Management assesses the like lihood of any adverse judgm ents in or outcomes of these matters as well as potential ranges of probabl e losses, including costs of investigation. A

determination of the amount of rese rves required, if any, for these contingencies is based on an analysis of each individual case or proceeding often with the a ssistance of outside counsel. The required reserves may change in the future due to new developments in each matter or changes in approach in dealing with these matters, such as a change in settlement strategy. In general, environmental contaminat ion treatment costs are charged to expense, unless it is probable

that the PUC would allow such costs to be recovered through future rates, in which case such costs would be capitalized as regulatory assets. Also, environmental costs are capita lized if the costs extend the life, increase the capacity, or improve the safety or effici ency of property; the costs mi tigate or prevent future
environmental contamination; or the costs are incurred in pr eparing the property for sale.

Income taxes . Deferred income tax assets and liabilities are established for the temporary differences between the financial reporting bases and the tax bases of the Company’s assets and liabilities using tax rates expected to be in effect when such deferred tax assets or liabilities ar e realized or settled. The

ultimate realization of deferred ta x assets is dependent upon t he generation of future taxable income during the periods in which those tempor ary differences become deductible. Management evaluates its potential exposures fro m tax positions taken that have or could be challenged by taxing authorities. T hese potential exposures result because taxing authorities may take positions that differ from those taken by management in the interpre tation and application of statutes, regulations and rules. Management considers the possibility of al ternative outcomes based upon past experience, previous actions by taxing authorities (e.g., actions taken in other jurisdictions) and advice from its tax advisors. Management believes that the Company’s provision fo r tax contingencies is reasonable.
However, the ultimate resolution of tax treatments disputed by governmental authorities may adversely affect the Company’s current and deferred income tax amounts.53 Following are discussions of the electric utility and bank segments. Additional segment information is shown in Note 2 of HEI’s “Notes to Consolidated Financial Statements.” The discussion concerning Hawaiian Electric Company, Inc. should be read in conjunction with its consolidated financial statements and accompanying notes.

Electric utility

Executive overview and strategy. The electric utilities’ strategic focus has been to meet Hawaii’s growing energy needs through a combination of diverse ac tivities—modernizing and add ing needed infrastructure through capital investment, placing emphasis on ener gy efficiency and conservation, pursuing renewable energy generation (including the use of biofuels) and ta king the necessary steps to secure regulatory support for their plans. Reliability projects remain a priority for HECO and its subsidiaries. HECO has completed construction of a new generating unit that uses biodie sel fuel and has completed the firs t phase and is currently constructing the remaining phase of the East Oahu Transmission Pr oject (EOTP)—a needed alternative route to move power from the west side of Oahu to load centers on the east side. HECO and its subsidiaries have been taking actions intended to protect Hawaii’s island ecology and reduce greenhouse gas (GHG) emissions, while continuing toprovide reliable power to customers. A threepronged strategy supports attainment of the requirements and goals of the State of Hawaii Renewable Portfolio Standards (RPS), the Hawaii Global Warm ing Solutions Act of 2007 and the HCEI by: (1) the “greening” of existing assets, (2) the expansion of renewable energy generation and (3) the acceleration of energy efficiency and load management programs.

Utility strategic progress. In 2011, the utilities continued to make si gnificant progress in implementing their clean energy strategies and the PUC iss ued several important regul atory decisions, all of which are key steps to support Hawaii’s efforts to reduce its dependence on oil. Included in the PUC decisions were a number of interim and final rate case decisions (see table in “M ost recent rate proceeding s” below). Additional PUC

decisions are needed that will allow the utilities to re cover their increasing expenditures for clean energy and reliability on a more timely basis.

Regulatory . With PUC approval, HECO implemented decoupling on March 1, 2011. Decoupling is a new regulatory model that is intended to fa cilitate meeting the State’s goals to transition to a clean energy economy and achieve an aggressive renewable po rtfolio standard. The decoupling m odel implemented in Hawaii delinks revenues from sales and includes annual revenue adjust ments for O&M expenses and rate base additions. The decoupling mechanism has three components: (1) a sales decoupling component via a revenue balancing account (RBA), (2) a revenue escalation component via a revenue adjustment mechanism (RAM) and (3) an earnings sharing mechanism, which would provide for a r eduction of rates between rate cases in the event the utility exceeds the return on average common equity (R OACE) allowed in its most recent rate case. Decoupling provides for more timely cost recovery and earning on investments. In the second half of 2011, decoupling has resulted in an improvement in HECO’s under-earning situation that has ex isted over the last several years. Prior to and during the transition to decoupling, however, the utilities’ returns have been well

below PUC-allowed returns. In F ebruary 2012, HELCO received the final D&O in its 2010 rate case, which approved decoupling. Decoupling will be implemented for HELCO when the final rates in its 2010 rate case

become effective. Under decoupling, the most significant drivers for improving earnings are:

1. spending within PUC approved amounts for major projects and completing projects on schedule;

2. managing O&M expenses relative to authorized O& M adjustments, especially during periods of increasing demand; and

3. rate case outcomes that cove r O&M requirements and rate base items not included in the RAMs.

Effective March 1, 2011, as part of the decoupl ing implementation, HECO established the RBA and started recording the difference between target rev enues from its HECO 2009 rate case and actual revenues. Beginning June 1, 2011, HECO began accruing and co llecting 2011 RAM revenues of $15 million annually, or $1.3 million per month, which was superseded on July 26, 2011 by the implementation of interim rates in HECO’s 2011 general rate case (see “Most recent rate proceedings” bel ow). Under the decoupling tariff54 order, in future non-general rate ca se years, HECO will accrue and co llect 7/12ths of the annual RAM adjusted revenues in one year and the remaining 5/12t hs in the following year. HECO had expected to be able to accrue RAM-adjusted revenues fr om January 1 of each RAM period. Also critical to improving earn ings are HECO’s 2011 rate case, decoupling implementation for MECO and the outcome of the regulatory audits to be conducted on certain major projects . See “Major projects” in Note 3

to HEI’s “Notes to Consolidated Financial Statements” for a discussion of the regul atory audits ordered by the

PUC. The HECO 2011 rate case interim D&O reset target revenues, O&M expenses and rate base for the decoupling mechanisms until a final D&O is issued. Future earnings growth is also dependent on rate bas e growth. The utilities’ five-year 2012-2016 forecast reflects net capital expenditures of $3.0 billi on and a compounded annual rate base growth rate of approximately 7% to 9%. Many of t he major initiatives within this fo recast are expected to be completed beyond the 5-year period. Major initiatives which comp rise approximately 40% of the 5-year plan include projects relating to: (1) environmental compliance; (2) fuel infrastructure investments; (3) new generation; and (4) infrastructure investments to integrate renewables into the system. Estimates for these initiatives could change with time, based on external factors such as th e timing and technical require ments for environmental compliance.

Actual and PUC-allowed returns were as follows:

% Return on rate base (RORB)* ROACE**
Year ended December 31, 2011 HECO HELCO MECO HECO HELCO MECO Utility returns 6.83 8.78 7.07 6.4 9.7 7.7

PUC-allowed returns 8.11 8.59 8.43 10.0 10.5 10.5

Difference (1.28) 0.19 (1.36) (3.6) (0.8) (2.8)

* Based on recorded operating income and average rate base, both adjusted for items not included in determining electric rates. ** Recorded net income divided by average common equity for 2011.

Only HECO implemented decoupling in 2011. HECO’s 2011 rate-making method ROACE (as expected to be calculated for the earnings sharing mechanism under decoupling) was 8.03%, compared to HECO’s PUCallowed ROACE of 10.0% and actual ROACE of 6.4%.

Results of operations. (dollars in millions, except per barrel amounts) 2011 % change 2010 % change 2009

Revenues 1 $ 2,979 25 $ 2,382 17 $ 2,035 Expenses
Fuel oil 1,265 41 900 34 672 Purchased power 690 26 549 10 500 Other operation 257 2 251 1 249 Maintenance 121 (5) 127 19 108

Other 431 14 377 11 337 Operating income 215 21 178 5 170 Allowance for funds used during construction 8 (1) 9 (51) 17

Net income for common stock 100 31 77 (4) 79 Return on average common equity 7.3% 5.8% 6.4% Average fuel oil cost per barrel 1 $ 123.63 41 $ 87.62 37 $ 63.91 Kilowatthour sales (millions) 2

9,527 (1) 9,579 (1) 9,690 Cooling degree days (Oahu) 4,954 6 4,661 (3) 4,815 Number of employees (at December 31) 2,518 9 2,317 1 2,297

1 The rate schedules of the electric utilities currently contain energy cost adjustment clauses (ECACs) through which

changes in fuel oil prices and certain components of purchased energy costs are passed on to customers.

2 KWH sales for 2011 and 2010 were lower when compared to the prior year due largely to cooler, less humid weather and

continued conservation efforts by customers.55  2011 vs. 2010 Increase (decrease) (in millions)

$597 Revenues. Increase largely due to: $567 Higher fuel prices

26 Rate increases granted to HECO for the 2011 and 2009 test years and 2009 test year refund 10 Interim rate increases granted to HELCO ($6 milli on) and MECO ($4 million) for the 2010 test year 10 Decoupling revenue adjustments net of sales impacts at HECO

2 Rate base RAM and O&M RAM at HECO (4) Heat rate deadband and lower fuel efficiency at HECO

9 Fuel related revenues at HELCO and fuel efficiency savings at HELCO and MECO (6) Lower KWH sales at HELCO and MECO (3) Purchase power adjustment clause (PPAC) adjustment at HECO (10) Interest income due to a federal tax settlement in 2010

365 Fuel oil expense. Increase largely due to higher fuel cost s, partly offset by less KWHs generated

141 Purchased power expense. Increase largely due to higher purchased energy costs, partly offset by less KWHs purchased

6 “Other operation” expense . Increase largely due to: 6 Higher transmission and distribution expense, which in cludes costs related to the Asia-Pacific Economic Cooperation (APEC) forum held in Honolulu 6 Higher bad debt expenses (5) Regulatory change for the capitalization of administrative costs, which lowered administrative and general expenses

(6) Maintenance expense . Decrease largely due to: (11) Lower overhaul costs at HELCO and MECO

4 Higher overhaul and station maintenance at HECO 2 Higher vegetation management

54 Other expenses . Increase largely due to: 54 Higher taxes, other than income taxes, primarily resulting from higher revenues

9 Partial writedown of the East Oahu Transmissi on Project Phase 1 costs in December 2011 (7) Decrease in depreciation expense resulting from lower depreciation rates implemented in conjunction with the most recent interim D&Os

37 Operating income. Increase largely due to the interim rate increases for HECO, HELCO and MECO, decoupling revenue adjustments net of sales impacts at HECO and lower depreciation expense, partly offset by the impact of higher other expenses (see above) and lower interest

income due to a tax settlement in 2010.

23 Net income for common stock. Increase largely due to:

20 Interim and final rate increases

7 Decoupling revenue adjustments (including ra te base RAM and O&M RAM) net of sales impacts at HECO (4) Heat rate deadband and lower fuel efficiency at HECO 6 Fuel efficiency savings at HELCO and MECO (6) Partial writedown of the East Oahu Transmission Project Phase 1 costs (6) Interest income due to a federal tax settlement in 2010 (1) Lower KWH sales at HELCO and MECO net of energy cost savings 4 Lower depreciation expense56  2010 vs. 2009 Increase (decrease) (in millions)

$347 Revenues. Increase largely due to: $326 Higher fuel prices

43 Interim rate increase granted to HECO for the 2009 test year

4 Interim rate increase granted to MECO for the 2010 test year (22) Lower KWH sales (20) Lower demand-side management program recovery revenues

10 Interest income due to a federal tax settlement

228 Fuel oil expense. Increase largely due to higher fuel cost s, partly offset by less KWHs generated and improved operating unit efficiency

49 Purchased power expense. Increase largely due to higher purchased energy costs, partly offset by less KWHs purchased.

2 “Other operation” expense . Increase largely due to: 17 Higher administrative and general expenses, in cluding higher employee benefits expense due to higher retirement benefit expense ($7 million) 6 Higher production and transmission and distribution expense to maintain reliable operations (17) Lower DSM program expenses

(5) Bad debt expenses

19 Maintenance expenses . Increase largely due to: 13 Increased production maintenance expenses, in cluding generating unit overhauls ($9 million) 2 Full year operation of CT-1 2 Higher maintenance on boiler plant equipment 7 Higher transmission and distribution expenses due to increased levels of work to address aging infrastructure

40 Other expenses . Increase largely due to: 30 Higher taxes, other than income taxes, primarily resulting from higher revenues

5 Higher depreciation expenses due to 2009 plant additions

8 Operating income. Increase largely due to the interim rate increases and higher interest income due to a tax settlement, partly offset by the impact of lower KWH sales and higher O&M and depreciation expenses

(2) Net income for common stock. Decrease largely due to: (23) Higher O&M spending (excluding demand-side m anagement (DSM) program expenses) to maintain system reliability (6) Lower KWH sales (8) Lower allowance for funds us ed during construction (AFUDC)

27 Interim rate increases

6 Interest income due to a federal tax settlement57 Most recent rate proceedings . The electric utilities initiate PUC pr oceedings from time to time to request electric rate increases to cover rising operating costs and the cost of plant and equipment, including the cost of new capital projects to maintain and improve service re liability. The PUC may grant an interim increase within 10 to 11 months following the filing of an application, but there is no guarantee of such an interim increase and
interim amounts collected are refundable, with interest, to the extent they exceed the amount approved in the PUC’s final D&O. The timing and amount of any final incr ease is determined at the di scretion of the PUC. The adoption of revenue, expense, rate base and cost of capital amounts (including the ROACE and RORB) for purposes of an interim rate increase does not commit the PUC to accept any such amounts in its final D&O. The following table summarizes certain details of each ut ility’s most recent rate cases, including the details of the increases requested, whether the utility and the Consumer Advoca te reached a settlement that they proposed to the PUC, and the details of increases gr anted in interim and final PUC D&Os or whether an interim or final PUC D&O remains pending.58 Test year Date (applied/implemented) Amount % over

rates in

effect ROACE (%) RORB (%) Rate

base Common equity

% Stipulated agreement

reached with

Consumer

Advocate Reflects decoupling (dollars in millions)

HECO

2007 Request 12/22/06 $99.6 7.1 11.25 8.92 $1,214 55.10 Yes No

Interim increase 10/22/07 70.0 5.0 10.70 8.62 1,158 55.10 No Interim increase (adjusted) 6/20/08 77.9 5.6 10.70 8.62 1,158 55.10 No

Final increase 3/1/11 77.5 5.5 10.70 8.62 1,158 55.10 No

2009
Request 1 7/3/08 $97.0 5.2 11.25 8.81 $1,408 54.30 Yes No Interim increase (1st) 8/3/09 61.1 4.7 10.50 8.45 1,169 55.81 No Interim increase (2 nd , plus 1st) 2/20/10 73.8 5.7 10.50 8.45 1,251 55.81 No

Final increase 2 3/1/11 66.4 5.1 10.00 8.16 1,250 55.81 Yes

2011 3 Request 7/30/10 $113.5 6.6 10.75 8.54 $1,569 56.29 Yes Yes

Interim increase 7/26/11 53.2 3.1 10.00 8.11 1,354 56.29 Yes Final increase Pending

HELCO

2006 Request 5/5/06 $29.9 9.2 11.25 8.65 $369 50.83 Yes No

Interim increase 4/5/07 24.6 7.6 10.70 8.33 357 51.19 No

Final increase 4 1/14/11 24.6 7.6 10.70 8.33 357 51.19 No

2010 Request 5 12/9/09 $20.9 6.0 10.75 8.73 $487 55.91 Yes Yes

Interim increase 1/14/11 6.0 1.7 10.50 8.59 465 55.91 No Interim increase (adjusted) 1/1/12 5.2 1.5 10.50 8.59 465 55.91 No

Final increase 5 10.00 8.31 55.91 Yes

MECO

2007 Request 2/23/07 $19.0 5.3 11.25 8.98 $386 54.89 Yes No

Interim increase 12/21/07 13.2 3.7 10.70 8.67 383 54.89 No

Final increase 1/12/11 13.2 3.7 10.70 8.67 383 54.89 No

2010 6 Request 9/30/09 $28.2 9.7 10.75 8.57 $390 56.86 Yes Yes

Interim increase 8/1/10 10.3 3.3 10.50 8.43 387 56.86 No Interim increase (adjusted) 1/12/11 8.5 2.7 10.50 8.43 387 56.86 No Final increase Pending

2012
Request 7 7/22/11 $27.5 6.7 11.00 8.72 $393 56.85 Yes

Note: The “Request Date” reflects the application filing date fo r the rate proceeding. All other line items reflect the effect ive dates of the revised schedules and tariffs as a result of PUC-approved increases.

1 In April 2009, HECO reduced this rate increase request by $6.2 million because a new Customer Information System would not be placed in service as originally

planned (see Note 3 of HEI’s “Notes to Consolidated Financial Statements”).

2 Because the final increase was $7.4 millio n less in annual revenues, HECO refunded $2.1 million to customers (including intere st) in February 2011.

3 HECO filed a request with the PUC for a general rate increase of $113.5 million, ba sed on a 2011 test year and without the the n estimated impacts of the implementation of decoupling as proposed in the PUC’s separate decoupling proce eding and depreciation rates and methodology as proposed by HECO in a separate depreciation proceeding. Including t he estimated effects of the implementation of decoupling at the time, the effective revenue request was $94.0 million, or 5.4%. HECO’s request was primarily to pay for ma jor capital projects and higher O&M costs to maintain and improv e service reliability and to recover the costs for several proposed programs to help reduce Hawaii’s dependen ce on imported oil, and to further in crease reliability and fuel security.
The $53.2 million interim increase includes $15 million in ann ual revenues already being reco vered through the decoupling RAM

.

4 Final D&O appealed by a participant in th e rate case proceeding. The appeal is pending, but has not affected implementation o f the rate increase.

5 HELCO’s request was primarily to cover investments for system upgrade projects, two major transmission line upgrades and incr easing O&M expenses. On February 8, 2012, the PUC issued a final D&O, which reflected the approval of decoupling and cost -recovery mechanisms. Implemen tation of final rates is subject to PUC review and approv al. See discussion below.

6 MECO's interim increase, effective August 1, 2010, was based on a stipulated agreement reached wi th the Consumer Advocate and temporary approval of new depreciation rates and methodology in a separ ate depreciation proceeding. The adjustment to this increase, effective January 12 , 2011, reflects the final rates from MECO's 2007 test year rate case. On February 13, 2012, the PUC issued an order instructing ME CO and the Consumer Advocate to submit a revised stipulated agreement by March 15, 2012 to prov ide them the opportunity to incorporat e the applicable rulings and decisions in D &Os issued in related proceedings since the first stipulation was filed, in cluding the final decoupling D&O, the final D& Os in the MECO 2007, HECO 2009, and HELC O 2010 test year rate cases59 (including the findings related to ROACE wi th the implementation of decoupling), the in terim D&O in the HECO 2011 test year rat e case and the final D&O in MECO's depreciation proceeding.

7 MECO’s request is required to pay for O&M expenses and additi onal investments in plant and equi pment required to maintain and improve system reliability and to cover the increased costs to support the integration of more re newable energy generation. The r equest is for an increase over r ates currently in effect. MECO's electric rates currently in effect include the $8.5 million annual interim rate increase granted in the 2010 test year rate cas e, which is subject to a final D&O and subject to refund with interest if the final D&O provides for a lesser increase. The Consumer Advocate filed its direct testimo ny in February 2012 and proposed an increase of $9.6 million, based on a ROACE of 9%, a RORB of 7.59% and an average rate base of $397 million.

HECO 2011 test year rate case . On July 22, 2011, the PUC issued an interim D&O in HECO’s 2011 test year rate case, effective July 26, 2011, granting a tota l annual interim increase of $53.2 million, or 3.1%, or an increase of $38.2 million in annual revenues, or 2.2%, net of the $15 million of revenues currently being recovered through the decoupling Reve nue Adjustment Mechanism (RAM). The interim increase is based on, and is substantially the same as, the increase proposed in the settlem ent agreement executed and filed on July 5, 2011 by HECO, the Consumer Advocate and the Department of Defense (the parties in the proceeding). The interim increase reflects the new depr eciation rates and methods approved by the PUC in a separate proceeding, which will result in a $2 million decrease in depreciation expense effective with interim

rates to the end of 2011. The PUC di d not approve the portion of the settlem ent agreement to a llow deferral of certain costs amounting to approximat ely $3.2 million for 2011 (including costs related to project management for the interisland wind project and undersea cable system sourcing). HECO filed a motion for clarification and/or partial reconsideration of the interim D&O’s findi ngs and conclusions on the defe rral of these costs. On November 30, 2011, the parties filed a joint motion to ad just the interim increase gr anted to $52.7 million, a net reduction of $0.5 million, to be effective January 1, 2012. As part of the settlement agreement regarding EOTP Phase 1 costs, the parties filed a joint motion to increas e the interim increase that became effective on July 26, 2011 by $5 million, to be effective March 1, 2012, based on the additional re venue requirements reflecting all remaining EOTP Phase 1 costs not previously included in rates or agreed to be wri tten off and offset by the
amounts included in the November 30, 2011 motion. Management cannot predict the timing, or the ultimate
outcome, of the orders on the motions and a final D&O in this rate case. See “Major projects” in Note 3 to HEI’s “Notes to Consolidated Financial Statements” for a discussion of the deferral of project costs in the interim D&O.

HELCO 2010 test year rate case . On February 8, 2012, the PUC issued a final D&O in HELCO’s 2010 test year rate case, which allows HELCO to implement the decoupling mechanism. In the final D&O, the

ROACE of 10.00% and RORB of 8. 31% reflect the PUC’s approval of decoupling and other cost-recovery

mechanisms that the PUC concluded will cumulatively lower HELCO’s business risk. The PUC also approved the PPAC, which is also intended to lower financial risk of recovery of such expenses. The final D&O accepts HELCO’s proposed austerity adjustment to reduce expens es by $0.4 million in lieu of the PUC’s downward adjustments to the labor costs and employ ee benefits included in the interim D&O. HELCO will file final revenue requirements, which wi ll reflect the slightly lower depreciation rates and methodology approved in a separate deprec iation proceeding. The heat rates (b y fuel type) that establish the fuel efficiency targets will reflec t the current complement of HELC O units, and the heat rate deadband will be implemented with the effective date of the final rates in this proc eeding. HELCO expects the final annual revenue requirements may be slightly lowe r than the interim increase currently in effect due to factors such as the lower depreciation rates and the lower ROACE. HE LCO will also implement decoupling, including the RAM, and begin tracking the target revenues and actual recorded revenues via the revenue balancing account as established by the decoupling proc eeding D&O when the final rates in this proceeding become effective.

Clean energy strategy . The utilities’ policy is to support effort s to increase renewable energy in Hawaii. The utilities believe their actions will help stabilize cu stomer bills over time as they become less dependent on costly and price-volatile fossil fuel. The utilities’ clean energy strategy will also allo w them to meet Hawaii’s RPS law, which requires electric utilities to meet an RPS of 10%, 15%, 25% and 40% by December 31, 2010, 2015, 2020 and 2030, respectively. HECO met the 10% RPS for 2010 with a consolidated RPS of 20.7%, including savings from energy efficiency programs and solar water heating (or 9.5% without DSM energy savings). Energy savings resulting from DSM energy efficiency programs and solar water heating will not count

toward the RPS after 2014. The utilities believe they are on track to meet the 2015 RPS.60 Recent developments in the utilities’ clean energy strategy include:

 In January 2011, HELCO signed a 20-year contract, subject to PUC approval, with Aina Koa PonoKa’u LLC to supply 16 million gallons of biodiesel per year with initial c onsumption to begin by 2015. In September 2011, however, the P UC denied the utilities’ requested appr oval of the contract citing the higher cost of the biofuel ov er the cost of petroleum diesel. HECO, on behalf of HELCO, is negotiating changes to the original contract with AKP with the intent of submitting a new contract to the PUC for its approval.

 In February 2011, HECO successfully demonstrated that Unit 3 at its Kahe Power Plant could be powered using up to 100% of biofuel.

 In February 2011, HELCO executed a purchase power agreement (PPA) amendment with Puna Geothermal Venture (PGV) for t he purchase of energy and capacit y from an 8 megawatts (MW) expansion of PGV’s geothermal energy plant on the island of Hawaii.

 In February 2011, the PUC opened dockets related to MECO’s and HECO’s plans to proceed with competitive bidding processes to acquire up to approximately 50 MW and 300 MW, respectively, of new, renewable firm dispatchable capacity generation resources, with the in itial increments expected to come on line in the 2015 and 2016 timeframes, respectively.

 In 2008, HECO issued an Oahu Renewable Ener gy Request for Proposals (2008 RFP) for combined renewable energy projects up to 100 MW . In 2011, HECO executed a PPA with Kalaeloa Solar Two for a 5 MW PV project and a PPA with Kawailoa Wind, LLC for a 69 MW wind project.

 Included in the bids received in response to the 2008 RFP were proposals for two large scale neighbor island wind projects that would produc e energy to be imported from Lanai and Molokai to Oahu via a yet-to-be-built undersea transmission c able system. HECO is negotiating with one of the project developers for a 200 MW wind farm to be built on Lanai. The other proposal did not advance after missing a key PUC deadline. Further, in July 2011, the PUC directed HECO to prepare a draft RFP for 200 MW or more of renewable energy for the island of Oahu from generation on any of the
Hawaiian islands. In October 2011, HECO filed a draft RFP with the PUC.

 In July 2011, HECO signed a 3-year contract, subj ect to PUC approval, with Pacific Biodiesel to supply at least 250,000 gallons of locally produc ed biodiesel for a new 8 MW standby generation facility at the Honolulu Airport that will be owned by the State and operated by HECO, targeted for operation in 2012.

 In August 2011, HECO signed a 20-year contract, s ubject to PUC approval, with Hawaii BioEnergy to supply 10 million gallons per year of biocrude at Kahe Power Plant with initial consumption to begin as early as 2015.

 In August 2011, HECO signed a Pilot Contract, subj ect to PUC approval, with Phycal Hawaii R&D, LLC for a single delivery of 100,000 to 150,000 gallons of biocrude at Kahe Power Plant to conduct testing in 2014.

 In October 2011, HECO signed a 3- year contract, subject to PUC approval, with REG to supply 3 million to 7 million gallons of biodi esel per year for CIP CT-1. If ap proved, this contract will be in effect upon expiration of the current biodiesel supply contract with REG that expires in July 2012.

 In August 2011, MECO successfully demonstrated that its reciprocal diesel engines at Maalaea Power Plant can be powered using 100% biofuel.61 Other regulatory matters. In addition to the items below, also see “Hawaii Clean Energy Initiative” and “Major projects” in Note 3 of HEI’s “N otes to Consolidated Financial Statements.”

Adequacy of supply.

HECO . In February 2011, HECO fil ed its 2011 Adequacy of Supply (A OS) letter, which indicated that based on its May 2010 sales and peak forecast , HECO’s generation capacity for 2011 to 2015 is sufficiently large to meet all reasonably expected dem ands for service and provide reasonable reserves for emergencies. The letter reported that, beginning in 2016, HECO anticipates that based on expected increasing demand it will begin experiencing reserve c apacity shortfalls if no more firm generating capacity is added to the system. Also, four existing generating uni ts may be retired within the next 10 years because of their age or more stringent environmental regulat ions. HECO estimates it will need approximately 300 MW of new, firm generating capacity to replace the capacity that would be lost with the retirement of these four units and to accommodate load growth.

HELCO . In January 2012, HELCO filed its 2012 AOS letter, which indicated that HELCO’s generation capacity through 2015 is sufficiently large to meet all reasonably expected demands for service and provide reasonable reserves for emergencies. In January 2012, HELCO added 8 MW of renewable capacity from Puna Geothermal V enture. HELCO is currently negot iating with one independent power producer (IPP) to supply additional firm renewable gen erating capacity to the HELCO grid. Should this additional firm renewable facility come on line within the next three years as anticipated, HELCO will not have a need for additional firm capacity in the fores eeable future. HELCO, how ever, may choose to add additional renewable generating capacity to replac e existing nonrenewable gener ation. In January 2012, HELCO announced plans to request that the PUC open a docket for a Geothermal Request for Proposals.

MECO . In January 2011, MECO filed its 2011 AOS lette r, which indicated that MECO’s generation capacity through 2014 is sufficient to meet the fo recasted demands on the islands of Maui, Lanai and
Molokai, but also stated that addi tional increments of firm capacity will be needed on Maui in 2015 and 2018 should a major IPP cease providing capacity and energy to MECO after Decemb er 31, 2014. Also, in January 2011, MECO filed a request to open a new docket related to ME CO’s plan to proceed with a competitive bidding process to acquire up to approx imately 50 MW of new, renewable firm dispatchable capacity generation resources on the island of Maui, with the initial increment ex pected to come on line in

the 2015 timeframe.

HECO and MECO 2012 AOS letters . HECO and MECO have each requested from the PUC an extension of time for filing its respective 2012 AOS le tter until March 2012. The additi onal time is required to assess the impact on HECO’s and MECO’s forecasts of the sales and peak load impact targets set in the EEPS framework adopted by the PUC in January 2012. T hese revised forecasts may reduce HECO’s and

MECO’s estimates of future fi rm generating capacity requirements.

Collective bargaining agreements. See “Collective bargaining agreements” in Note 3 of HEI’s “Notes to

Consolidated Financ ial Statements.”

Legislation and regulation. Congress and the Hawaii legislature periodi cally consider legislation that could have positive or negative effects on the utilities and their customers. Also s ee “Hawaii Clean Energy Initiative” and “Environmental regulation” in Note 3 of HEI’s “N otes to Consolidated Financial Statements” and “Recent tax developments” above.

Renewable energy. In 2007, a Hawaii law was enacted that stated that the PUC may consider the need for increased renewable energy in render ing decisions on utility matters. Due to this measure, it is possible that, if energy from a renewable source were more ex pensive than energy from fossil fuel, the PUC may still approve the purchase of energy from the renewable source. In 2008, a Hawaii law was enacted to promote and encourage the use of solar thermal energy. This measure requires the installation of solar thermal wa ter heaters in residences constructed after January 1,
2010, but allows for limited variances in cases w here installation of solar water heating is deemed inappropriate. The measure establishes standards for quality and performance of such systems. Also in62 2008, a Hawaii law was enacted that is intended to facili tate the permitting of lar ger (200 MW or greater) renewable energy projects. The Energy Agreement incl udes several undertakings by the utilities to integrate solar energy into the electric grid. In 2009, a bill became Hawaii law (Act 185) that aut horizes preferential rates to agricultural energy producers selling electricity to utilities. This will help support the long-term development of locally grown biofuel crops, cultivating potential local renewable fuel sources for the utilities. In addition, pursuant to Act 50 (also adopted in 2009), avoided cost is no longer a cons ideration in determining a just and reasonable rate for non-fossil fuel generated electricity. This will allo w the utilities to negotiate purchased power prices for renewable energy that have the potential to be more stable and less costly than current pricing tied to

avoided cost.
In 2011, a Hawaii law was enacted that gives the PUC the author ity to allow those electric utilities that aggregate their renewable portfolios to achieve the RPS (e.g., HECO, HE LCO and MECO) to distribute the costs and expenses of renewable energy projects among those utilities. The bill al so allows the PUC to establish a surcharge for such costs and expenses without a rate case filing. Also passed in 2011, Act 10 provides for continued inclusion of customer-sited, grid-connected renewable ene rgy generation in the RPS calculations after 2015. This is the current practice in calculating RPS levels, which provides electric utility ratepayers with a clear value from a program such as net energy metering.

Biofuels. In 2007, a Hawaii law was enacted with the stated purpose of encouraging further production

and use of biofuels in Hawaii. It established that biofuel processing facilities in Hawaii are a permitted use in designated agricultural districts and established a progr am with the Hawaii Department of Agriculture to encourage the production in Hawaii of energy f eedstock (i.e., raw materials for biofuels). In 2008, a Hawaii law was enacted that encourages the development of biof uels by authorizing the

Hawaii Board of Land and Natural Reso urces to lease public lands to growers or produc ers of plant and animal material used for the production of biofuels. The utilities have agreed in the Energy Agreement to test the use of biofuels in their generating units and, if economically feasible, to connec t them to the use of biofuels. For its part, the State agrees to support this testing and conversion by expediting all necessary approvals and permitting.

For additional discussion of environment al legislation and regulations, s ee “Environmental regulation” in

Note 3 of HEI’s “Notes to Consolidat ed Financial Statements.” At this time, it is not possible to predict with certainty the impact of the foregoing le gislation or legislation that is, or may in the future be, proposed.

Commitments and contingencies. See “Commitments and contingencies” in Note 3 of HEI’s “Notes to

Consolidated Financ ial Statements.”

Recent accounting pronouncements. See “Recent accounting pronouncements and interpretations” in

Note 1 of HEI’s “Notes to C onsolidated Financia l Statements.”

Liquidity and capital resources. Management believes that HECO’s abili ty, and that of its subsidiaries, to generate cash, both internally from operations and exter nally from issuances of equity and debt securities, commercial paper and lines of credit, is adequate to maintain sufficient liquidity to fund their respective capital expenditures and investments and to cover debt, retire ment benefits and other cash requirements in the

foreseeable future. HECO’s consolidated capital structure was as follows:

December 31 2011 2010 (dollars in millions)

Short-term borrowings $ – –% $ – –% Long-term debt, net 1,058 43 1,058 44

Preferred stock 34 1 34 1 Common stock equity 1,406 56 1,338 55
$2,498 100% $2,430 100%63 HECO’s short-term borrowings (other than from HE LCO and MECO), HECO’s line of credit facility, the principal amount of SPRBs that have been authorized by the Hawaii legisl ature for future issuance by the State of Hawaii Department of Budget and Finance (D BF) for the benefit of the utilities and the principal amount of unsecured taxable obligations approved by the PUC were as follows:

Year ended
December 31, 2011

(in millions) Average

balance End-of-period

balance December 31,

2010

Short-term borrowings 1 Commercial paper $ 2 $ – $ –

Line of credit draws – – – Borrowings from HEI – – –

Undrawn capacity under line of credit facility (

expiring December 5, 2016) 175 175 175

Special purpose revenue bonds authorized for issuance 2007 legislative authorization (expiring June 30, 2012)
HECO $170 $170

HELCO 55 55

MECO 25 25

Total special purpose revenue bonds available for issuance $250 $250

Unsecured taxable obligations approved by the PUC
for issuance on or before December 31, 2012
HECO $150

HELCO 10

MECO 10

Total unsecured taxable obligations available for issuance in 2012 $170

1 The maximum amount of external short-term borrowings in 2011 was $21 million. At December 31, 2011, HECO had $46 million and $19 million of short-term borrowings from HELCO and MECO, respectively, which borrowings are eliminated in consolidation. At February 8, 2012, HECO had no outstanding co mmercial paper, its line of credit facility was undrawn, it had n o borrowings from HEI and it had borrowings of $41 m illion and $9 million from HELCO and MECO, respectively.

HECO utilizes short-term debt, typically commerc ial paper, to support normal operations, to refinance short-term debt and for other temporar y requirements. HECO also borrows short-term from HEI for itself and on behalf of HELCO and MECO, and HECO may borrow from or loan to HELCO and MECO short-term. The intercompany borrowings among the utilities, but not the borrowings from HEI, are eliminated in the

consolidation of HECO’s financial st atements. HECO and its subsidiaries periodically utilize long-term debt, historically borrowings of the proceeds of SPRBs i ssued by the DBF to finance the utilities’ capital improvement projects, or to repay short-term borro wings used to finance such projects. The PUC must approve issuances, if any, of equity and long-term debt securities by HECO, HELCO and MECO. HECO has a line of credit facility of $175 million. S ee Note 7 of HEI’s “Notes to Consolidated Financial Statements.” The credit agreem ent, amended in December 2011, contains pr ovisions for revised pricing in the event of a ratings change. For example, a ratings dow ngrade of HECO’s long-term rating (e.g., from BBB/Baa2 to BBB-/Baa3 by S&P and Moody’s, respectively) would resu lt in a commitment fee in crease of 5 basis points and an interest rate increase of 25 basis points on any drawn amounts. On the ot her hand, a ratings upgrade (e.g., from BBB/Baa2 to BBB+/Baa1 by S&P or Moody’s, respectively) would result in a commitment fee decrease of 2.5 basis points and an interest rate dec rease of 25 basis points on any drawn amounts. The agreement contains customary conditions that must be met in order to dr aw on it, including compliance with several covenants (such as covenants preventing its subsidiaries from ent ering into agreements that restrict the ability of the subsidiaries to pay dividends to, or to repay borrowings from, HE CO, and restricting its ability as well as the ability of any of its subsidiaries to guarantee additional indebtedness of the subsidiaries if such additional debt would cause the subsidiary’s “Consolidat ed Subsidiary Funded Debt to Capitalization Ratio” to exceed 65% (ratio of 42% for HELCO and for MECO as of December 31, 2011, as calculated under the agreement)). In addition to customary defaul ts, HECO’s failure to maintain its financial ratios, as defined in its agreement, or meet other requirements may result in an event of default. For example, under its agreement, it64 is an event of default if HECO fails to maintain a “Cons olidated Capitalization Ratio” (equity) of at least 35% (ratio of 56% as of December 31, 2011, as calculated under the agreement), or if HECO is no longer owned by

HEI. In addition to their impact on pricing under HECO’s credit agreement, the ratings of HECO’s commercial paper and debt securities could significantly impact th e ability of HECO to sell its commercial paper and issue

debt securities and/or the cost of such debt. The ra ting agencies use a combinatio n of qualitative measures (e.g., assessment of business risk that incorporat es an analysis of the qualitative factors such as management, competitive positioning, op erations, markets and regulation) as well as quantitative measures (e.g., cash flow, debt, interest cove rage and liquidity ratios) in determining the ratings of HECO securities. On August 1, 2011, Moody’s maintained HECO’s long-term and short-term (commercial paper) ratings and stable outlook, indicating that the ratings factor in the anticipated cash flow stability of this vertically integrated utility, the long-term benefits of a more predictable regulatory fr amework being introduced, and a conservative financial management. Moody’s indicated the rating c ould be downgraded if the Ha waii PUC does not follow through with the regulatory transfo rmation contemplated under the HCEI, including all elements of the decoupling mechanism or if the utilities’ cash flow to debt declined to below 17% (22% last twelve months as of March 31, 2011 – latest reported by Moody’s) on a sust ainable basis and its cash flow coverage of interest fell below 3.5 times (5.2 times last twelve months as of March 31, 2011 – latest reported by Moody’s). On
November 21, 2011, S&P maintained it s long-term ratings for HECO, HE LCO and MECO of “BBB-” and stable
outlook. In addition, S&P maintained its “A-3” shor t-term rating and “aggressive ” financial profile on HECO. S&P indicated that although HECO’s consolidated credit profile has the potential to gradually improve through HECO’s decoupling and recently approved automatic ra te adjustment mechanisms, the utilities had yet to make meaningful strides in closing the signific ant gap between their actual and authorized ROACE. As of February 8, 2012, the S&P and Moody’s ratings of HECO securities were as follows:
S&P Moody’s

Commercial paper A-3 P-2 Special purpose revenue bonds-insured

(principal amount noted in parentheses, senior unsecured, insured as follows): Ambac Assurance Corporation ($0.2 billion) BBB-* Baa1* Financial Guaranty Insurance Company ($0.3 billion) BBB-* Baa1* MBIA Insurance Corporation ($0.3 billion) BBB** Baa1** Syncora Guarantee Inc. (formerly XL Capi tal Assurance Inc.) ($0.1 billion) BBB-* Baa1* Special purpose revenue bonds – uninsured ($150 million) BBB- Baa1 HECO-obligated preferred securities of trust subsidiary BB Baa2 Cumulative preferred stock (selected series) Not rated Baa3

The above ratings reflect only the view, at the time the rati ngs are issued, of the applicable rating agency, from whom an explanation of the significance of such ratings may be obtained. Such ratings are not recommendations to buy, sell or hold any securities; such ratings may be subject to revision or withdraw al at any time by the rating agencies; and each rating should be evaluated independently of any other rating.
* Rating corresponds to HECO’s rating (senior unsecured debt rating by S&P or issuer rating by Moody’s) because, as a result of rating agency actions to lower or withdraw the ratings of these bond insurers after the bonds were issued, HECO’s current ratin gs are either higher than the current rating of the applicable bond insurer or the bond insurer is not rated.
** Following MBIA Insurance Corporation’s (MBIA’s) announced restructuring in February 2009, the revenue bonds issued for the benefit of HECO and its subsidiaries and insured by MBIA have been reinsured by MBIA Insurance Corp. of Illinois (MBIA Illinois ), whose name was subsequently changed to National Public Finance Guarantee Corp. (National). The financial strength rating of National by S&P is BBB. Moody’s ratings on securities that are guaranteed or “wrapped” by a financial guarantor are generally maintained at a l evel equal to the higher of the rating of the guarantor (if rated at the investment grade level) or the published underlying rating. The i nsurance financial strength rating of National by Moody’s is Baa2, which is lower than Moody’s issuer rating for HECO.

Management believes that, if HECO ’s commercial paper ratings were to be downgraded or if credit

markets were to further ti ghten, it could be more difficult and/or expensive to sell commercial paper or secure other short-term borrowings. Similarl y, management believes that if HECO’s long-term credit ratings were to be downgraded, or if credit markets furt her tighten, it could be more difficu lt and/or expensive for DBF and/or the Company to sell SPRBs and other debt securities, respective ly, for the benefit of the utilities in the future. Such

limitations and/or increased costs coul d materially adversely affect the re sults of operations, financial condition and liquidity of HECO and its subsidiaries.65 The PUC must approve issuances, if any, of equity and long-term debt securi ties by HECO, HELCO and MECO. Revenue bonds are issued by the DBF to finance capital improvement projects of HECO and its
subsidiaries, but the source of thei r repayment is the unsecured obligat ions of HECO and its subsidiaries under loan agreements and notes issued to the DBF, including HECO’s guarantees of its subsidiaries’ obligations. The payment of principal and interest due on SPRBs currently outstanding and issued prior to 2009 are insured either by Ambac Assurance Corporation, Financ ial Guaranty Insurance Company, MBIA (which bonds have been reinsured by National Public Finance Guarantee Corp.) or Syncora Guarantee Inc. (which bonds have been reinsured by Syncora Capital Assurance Inc.). The insured outstanding revenue bonds were initially issued with S&P and Moody’s rati ngs of AAA and Aaa, respectively, based on the ratings at the time of issuance of the applic able bond insurer. Beginning in 2008, however, ratings of the insurers (or their predecessors) were downgraded and/or withdrawn by S&P and Moody’s, resulting in a downgrade of the bond ratings of all of the bonds as shown in the rati ngs table above. The $150 million of SPRBs sold by the DBF for the benefit of HECO and HELCO on July 30, 2009, were sold without bond insurance. Management believes that if HECO’s long-term credit ratings were to be downgraded, or if credit markets further tighten, it could be more difficult and/or expensive to sell bonds in the future. On November 15, 2010, the PUC approved the request of HECO, HELCO and MECO for the sale of each utility’s common stock over a five -year period from 2010 through 2014 (HECO’s sale to HEI of up to
$210 million and HELCO and MECO’s sales to HECO of up to $43 million and $15 million, respectively), and the purchase of the HELCO and MECO common stock by HECO. In Dece mber 2010, HELCO and MECO sold $23 million and $3 million, respectively, of their comm on stock to HECO, and HECO sold $4 million of its
common stock to HEI. In December 2011, HECO so ld $40 million of its common stock to HEI.
On November 1, 2011, the P UC authorized HECO, HELCO and MECO to issue up to $150 million, $10 million and $10 million, respectively, in one or more registered public offerings or private placements of unsecured obligations bearing taxable interest on or before December 31, 2012. If sold, the proceeds are expected to be used to fund capital expenditures (inc luding repaying short-term indebtedness incurred to fund capital expenditures) and to repay $57.5 million of outst anding SPRBs at their maturity in 2012. The PUC also approved the use of the expedited approval procedure for the approval of additional taxable debt to be issued by HECO, HELCO and MECO during the period 2013 through 2015, subject to certain conditions.
On December 22, 2011, the PUC authorized HECO , HELCO and MECO to issue up to $217 million, $34 million and $60 million, respectively, in one or more registered public offerings and/ or private placements of unsecured taxable debt obligations an d/or refunding SPRBs through Dece mber 31, 2012 to refinance certain series of outstanding SPRBs. The PUC also approved t he use of the expedited appr oval procedure for the approval of additional refinancings by HECO, HELC O and MECO during the period 2013 through 2015, subject

to certain conditions. Operating activities provided $161 million in net ca sh during 2011. Investing activities used net cash of $202 million, primarily for capital expendi tures, net of contributions in aid of construction. Financing activities used net cash of $33 million for the payment of commo n and preferred stock divid ends of $73 million, partly offset by $40 million net proceeds fr om issuance of common stock. For the five-year period 2012 through 2016, the utilities fo recast $3.0 billion of net capital expenditures, approximately 38% of which is for transmission and di stribution projects and 13% for generation projects, 10% for general plant and other projects, with the rema ining 39% anticipated for major initiatives (including environmental compliance and infrastructure investment s for fuel and to integr ate renewables into the system), which could change with time based upon ex ternal factors, includ ing timing and technical requirements for environmental compliance. HECO’s cons olidated cash flows from operating activities (net income for common stock, adjusted for non-cash income and expense items such as depreciation, amortization and deferred taxes), after the payment of common stock and prefer red stock dividends, are currently not expected to provide sufficient cash to cover the forecasted net capital expenditures. Debt and equity financing are expected to be requi red to fund this estimated shortfall as well as to refinance maturing revenue bonds ($57.5 million in 2012 and $11.4 million in 2014) and to fund any unanticipated expenditures not included in the 2012 through 2016 forecast, such as increases in the costs or acceleration of the66 construction of capital projects, unbudgeted acquisitions or investments in new businesses and significant increases in retirement benefit funding requirements. Proceeds from the issuances of debt and equity, ca sh flows from operating activities, temporary increases in short-term borrowings and existing cash and cash equivalents are expected to provide the
forecasted $300 million needed for the net capital expenditures in 2012. For 2012, net capital expenditures include approximately $189 million for transmission and distribution projects, approximately $66 million for generation projects and approximatel y $45 million for general plant and ot her projects. Consolidated net capital expenditures for HECO and subsidiari es for 2011, 2010 and 2009 were $249 million, $173 million and $288 million, respectively. Management periodically reviews capital expenditure estimates and the timing of construction projects. These estimates may change significantly as a result of many considerations, including changes in economic conditions, changes in forecasts of KWH sa les and peak load, the availability of purchased power and changes in expectations concerning the constructi on and ownership of future generation units, the availability of generating sites and tr ansmission and distribution corridors, the need for fuel infrastructure investments, the ability to obtain adequate and timely rate increases, escalation in construction costs, commitments under the Energy Agreem ent, the effects of opposition to proposed construction projects and requirements of environmental and other regulatory and permitting authorities. For a discussion of funding for the electric utilities’ retirement benefits plans, see Note 1 and Note 9 of

HEI’s “Notes to Consolidated Financial Statements” and “Retirement benefits” abov e. The electric utilities were required to make contributions of $71 milli on for 2011 and $19 million for 2010, but not required to make any contributions for 2009 to the qualified pens ion plans to meet minimum funding requirements pursuant to ERISA, including c hanges promulgated by the Pension Protection Act of 2006. The electric utilities made additional voluntary c ontributions in 2011, 2010 and 2009. Contri butions by the electric utilities to the retirement benefit plans for 2011, 2010 and 200 9 totaled $73 million, $31 million and $24 million, respectively, and are expected to total $104 million in 2012. In addition, the electric utilities paid directly $1 million of benefits in 2011, $2 million of benefits in 2010, less t han $1 million of benefits in 2009 and expect to pay less than $1 million of benefits in 2012. Depending on the perfo rmance of the assets held in the plans’ trusts and numerous other factors, additional c ontributions may be required in the future to meet the minimum funding requirements of ERISA or to pay benefits to plan par ticipants. The electric utilities believe they will have adequate cash flow or access to capital resources to support any necessary funding requirements.

Certain factors that may affect future results and financial condition . Also see “Forward-Looking

Statements” and “Certain factors t hat may affect fu ture results and financial condition” for Consolidated HEI

above.

HCEI Energy Agreement. HECO, for itself and its subsidiaries, entered into the Energy Agreement on October 20, 2008. See “Hawaii Clean Energy Initiative” in Note 3 of HEI’s “Notes to Consolidated Financial

Statements.” The far-reaching nature of the Energy Agreement, in cluding the extent of r enewable energy commitments, present new increased risks to the Company. Among such risks are: (1) the dependence on third-party suppliers of renewable purchased energy, which if the utilities are unsuccessf ul in negotiating purchased power agreements with such IPPs or if a major IPP fails to deliver t he anticipated capacity in its purchased power agreement, could impact the utilities’ achievem ent of their commitments under the Energy Agreement and/or the utilities’ ability to deliver re liable service; (2) delays in acquiri ng or unavailability of non-fossil fuel supplies for renewable generation; (3) the impact of intermittent power to the electrical grid and reliability of service if appropriate supporting infrastructure is not in stalled or does not operate effe ctively; (4) the likelihood that the utilities may need to make subs tantial investments in related infr astructure, which could result in increased borrowings and materially impact the financial condition and liquidity of the utilities; and (5) the commitment to support a variety of in itiatives, which, if approved by the PUC, may have a material impact on the results of operations and financia l condition of the utilities depending on their design and implementation.
These initiatives include, but are not limited to, decoupling revenues from sa les; implementing feed-in tariffs to67 encourage development of renewable en ergy; removing the system-wide c aps on net energy metering (but studying DG interconnections on a per-circuit basis); a nd developing an Energy Efficiency Portfolio Standard. Management cannot predict the ultimate impact or outco me of the implementation of these or other HCEI programs on the results of operat ions, financial condition and liquidi ty of the electric utilities.

Regulation of electr ic utility rates. The rates the electric utilities are al lowed to charge for their services, and the timeliness of permitted rate increases, are among t he most important items in fluencing their results of operations, financial condition and liquidity. The PUC has br oad discretion over the rates the electric utilities charge and other matters. Any adverse decision by the PUC concerning the level or method of determining electric utility rates, the items and amounts permitted to be included in rate base, the authorized returns on equity or rate base found to be reas onable, the potential cons equences of exceeding or not meeting such returns, or any prolonged delay in rendering a decision in a rate or other proceedi ng could have a material adverse effect on the Company’s and HECO’s consol idated results of operations, financial condition and liquidity. Upon a showing of probable entitlement, the PUC is required to issue an interim D&O in a rate case

within 10 months from the date of f iling a completed application if the evi dentiary hearing is completed (subject to extension for 30 days if the evidentiary hearing is not completed). There is no time limit for rendering a final D&O. Interim rate increases are subject to refund with interest, pending the final outcome of the case. Management cannot predict when the final D&Os in pe nding or future rate cases will be rendered or the amount of any interim or final ra te increase that may be granted.

Fuel oil and purchased power. The electric utilities rely on fuel oil suppliers and IPPs to deliver fuel oil and power, respectively. See “Fuel contracts” and “Power purchase agreements” in Note 3 of HEI’s “Notes to

Consolidated Financial Statements.” The Company estimates that 73% of the net energy generated and purchased by HECO and its subsidiaries in 2012 will be generated from the burning of fossil fuel oil. Purchased KWHs provided approximately 40% of th e total net energy generated and purchased in 2011, 2010

and 2009. Failure or delay by the electric utilities’ oil supp liers and shippers to provide fuel pursuant to existing supply contracts, or failure by a major IPP to deliver the firm capacity anticipated in its PPA, could interrupt the ability of the electric utilities to deliver electricity, thereby materia lly adversely affecting the Company’s results of operations and financial condition. HECO ge nerally maintains an averag e system fuel inventory level equivalent to 35 days of forw ard consumption. HELCO and MECO gener ally maintain an inventory level equivalent to one month’s supply of bot h medium sulfur fuel oil and diesel fuel. Some, but not all, of the electric utilities’ PPAs require that the IPPs maintain minimum fuel in ventory levels and all of the firm capacity PPAs include provisions imposing substantial penalties fo r failure to produce the firm capacity anticipated by those agreements.

Other operation and maintenance expenses. Other O&M expenses were essentially flat in 2011 and increased 6% and 3% for 2010 and 2009, respectively, w hen compared to the prior year (0%, 12% and 7% respectively, excluding DSM program expense). O& M expenses for the year 2012 are expected to be approximately 6% higher than 2011 as the el ectric utilities expect to incur cost s to facilitate the safe, reliable integration of more renewables to the separate isl and systems. Transmission and distribution expenses are also expected to increase consistent with the new asset management initiatives to modernize the infrastructure. The timing and amount of expenses can va ry as circumstances change. For example, recent overhauls have been more expensive than in the past due to the larger scope of work necessary to maintain aging equipment. Also, the cost of overhauls can be hi gher than originally planned after full assessments of the repair work are performed. HECO’s implementatio n of decoupling mechanisms has mitigated some of the negative net income impact of rising other O&M expenses.68 Other regulatory and permi tting contingencies. Many public utility projec ts require PUC approval and various permits (e.g., environmental and land use permi ts) from other agencies. Delays in obtaining PUC approval or permits can result in increased costs. If a project does not proceed or if the PUC disallows costs of the project, the project costs may need to be writte n off in amounts that could have a material adverse effect on the Company. Two major capi tal improvement utility projects, the Keahole project (consisting of CT4, CT-5 and ST-7) and the East Oahu Transmission Project, encountered opposition and were seriously delayed before being placed in service, with a wr itedown being required for both the Keahole and EOTP projects. See Note 3 of HEI’s “Notes to Consoli dated Financial Statem ents” for a discussion of additional regulatory contingencies.

Competition. Although competition in the generation sect or in Hawaii has been moderated by the scarcity of generation sites, various permitting proc esses and lack of interconnections to other electric
utilities, HECO and its subsidiaries face competition from IPPs and customer self-generation, with or without cogeneration. In October 2003, the PUC opened investigative procee dings on two specific issues (competitive bidding and distributed generation (DG)) to movetoward a more competitive electric industry environment under costbased regulation.

Competitive bidding proceeding. In December 2006, the PUC issu ed a decision that included a final competitive bidding framework, which became effective immediately. The final framework states, among other things, that: (1) a utility is required to use competitive bidding to acquire a fu ture generation resource or a block of generation resources unless the PUC finds bidding to be unsuitable; (2) the fr amework does not apply in

certain situations identified in the fr amework; (3) waivers from competitive bidding for certain circumstances will be considered; (4) the utility is required to select an independent observer from a list approved by the PUC whenever the utility or its affiliate seeks to advance a proj ect proposal (i.e., in competition with those offered by bidders); (5) the utility may consider its own self-bid proposals in response to generation needs identified in its RFP; and (6) for any resource to which competitive bi dding does not apply (due to waiver or exemption), the utility retains its traditional obligation to offer to purchas e capacity and energy from a Q ualifying Facility (QF) at avoided cost upon reasonable terms and c onditions approved by the PUC. Management cannot currently predict t he ultimate effect of the framewor k on the ability of the utilities to acquire or build additional generating capacity in the future. The utilities received approval for wa ivers from the competit ive framework to negotiate modifications to existing PPAs that generate electricity from renewable resources. Also, cert ain renewable energy projects were “grandfathered” from the com petitive bidding process. The PUC can al so grant waivers on its own volition to renewable energy projects that are not exempt from the Co mpetitive Bidding Framework.

Distributed generation proceeding . In January 2006, the PUC issued a D&O indicating that its policy is to promote the development of a mark et structure that assures DG is ava ilable at the lowest feasible cost, DG that is economical and reliable has an opportunity to come to fruition and DG that is not cost-effective does not enter the system. The D&O a ffirmed the ability of the utilities to procure and operate DG for utility purposes at utility sites. The PUC also indicated its desire to promote the devel opment of a competitive

market for customer-sited DG. The D&O allows the utility to provide DG se rvices on a customer-owned site as a regulated service when (1) the DG resolves a legiti mate system need, (2) the DG is the lowest cost alternative to meet that need and (3) it can be shown that, in an open and competitive process acceptable to the PUC, the customer operator was unable to find another entity ready and able to supply the proposed DG service at a price and quality compar able to the utility’s offering.

Environmental matters. The HECO, HELCO and MECO generating stations operate under air pollution control permits issued by the Hawaii Department of H ealth (DOH) and, in a limited number of cases, by the

federal Environmental Protection Agency (EPA). The 2004 Hawaii State Legi slature passed legislation that requires an environmental assessment fo r proposed waste-to-energy facilities, landfills, oil refineries, powergenerating facilities greater than 5 MW and wastewater facilities, exc ept individual wastewater systems. Meeting this requirement result s in increased project costs.69 The 1990 amendments to the Clean Air Act (CAA), ch anges to the National Ambient Air Quality Standard (NAAQS) for ozone, and adoption of a NAAQS for fine particulate matter resulted in substantial changes for the electric utility industry. Further si gnificant impacts may occur under newly adopted rules (e.g., one-hour NAAQS for sulfur dioxide and nitrogen dioxide, control of GHGs under the GHG PSD and Title V Tailoring Rule), under rules deemed applicable to t he utilities’ facilities (e.g., Regional Haze Rule), if currently proposed legislation, rule s and standards are adopted (e.g., GHG emission reduction rules), or if new legislation, rules or standards are adopted in the future. Similarly, soon-to-be issued rules governing cooling water intake may significantly impac t HECO’s steam generati ng facilities on Oahu. See “Environmental regulation” in Note 3 of HEI’ s “Notes to Consolidated Financial Statements.” There can be no assurance that a significant environmental liability will not be incurred by the electric utilities or

that the related costs will be recoverable through rates. Additional environmental complianc e costs are expected to be incurred as a result of the initiatives called for in the Energy Agreement, including permitti ng and siting costs for new facilities and testing and permitting costs related to changi ng to the use of biofuels. Management believes that the recovery through rates of most, if not all, of any costs incurred by HECO and its subsidiaries in complying with environmental requirements would be allo wed by the PUC, but no assurance can be given that this will in fact be the case.

Technological developments. New technological developments (e.g., the commercial development of energy storage, DG and generation fr om renewable sources) may impac t the electric utility’s future competitive position, results of operat ions, financial condition and liquidity.

Material estimates and critical accounting policies. Also see “Material estimates and critical accounting policies” for Consolidated HEI above.

Property, plant and equipment. Property, plant and equipment are repor ted at cost. Self-constructed electric utility plant includes engineer ing, supervision, and administrativ e and general costs, and an allowance for the cost of funds used during the construction per iod. These costs are recorded in construction in progress and are transferred to pr operty, plant and equipment when c onstruction is completed and the facilities are either placed in service or become useful for public utility purposes. Upon the retirement or sale of electric utility plant, no gain or loss is recognized. The cost of the plant retir ed is charged to accumulated depreciation. Amounts collected from cu stomers for cost of removal (expec ted to exceed salvage value in the future) are included in regulatory liabilities. HECO and its subsidiaries evaluate the impact of applying lease accounting standards to their new PPAs, PPA amendments and other arrangement s they enter into. A possible outcome of the evaluation is that an arrangement results in its classification as a capital lease, which could have a material effect on HECO’s consolidated balance sheet if a significant amount of capital assets of t he IPP and lease obligations

needed to be recorded. Management believes that the PUC will allow recove ry of property, plant and equipment in its electric rates. If the PUC does not allow recovery of any such co sts, the electric utility w ould be required to write off

the disallowed costs at that time. See the discussion under “Major projects” in Note 3 of HEI’s “Notes to

Consolidated Financial Statem ents” concerning costs of major projec ts that have not yet been approved for inclusion in the applicable utility’s rate base.

Regulatory assets and liabilities. The electric utilities are regulated by the PUC. In accordance with accounting standards for regulatory operations, the Company ’s financial statements reflect assets, liabilities,

revenues and costs of HECO and its subsidiaries based on current cost-based rate-making regulations. The actions of regulators can affect the timing of rec ognition of revenues, expenses, assets and liabilities. Regulatory liabilities represent amounts collected from cu stomers for costs that are expected to be incurred in the future. Regulatory assets represent incurred costs that have been deferred because their recovery in future customer rate s is probable. As of December 31, 2011, the consolidated regulatory liabilities and regulatory assets of the utilities amounted to $315 m illion and $669 million, respectively, compared to $297 million and $478 million as of December 31, 2010, respectively. Regulatory liabilities and regulatory assets are itemized in Note 3 of HE I’s “Notes to Consolidated Financial Statements.”70 Management continually assesses whet her the regulatory assets are probable of future recovery by considering factors such as changes in the applicable regulatory environment. Because current rates include the recovery of regulatory assets existi ng as of the last rate case and rate s in effect allow the utilities to earn a reasonable rate of return, management believes that the recovery of the regulatory assets as of December 31, 2011 is probable. This determination as sumes continuation of t he current political and regulatory climate in Hawaii, and is subject to change in the future. Management believes HECO and its subsidiaries’ operations currently satisfy the criteria for regulatory accounting. If events or circumstances should change so that those crit eria are no longer satisfied, the electric utilities expect that the r egulatory assets would be charged to expense and the regulatory liabilities would be credited to income or refunded to ratepayers immediately. In the event of unforeseen regulatory actions or other circumstances, however, management believes that a material adverse effect on the Company’s results of operations, financia l condition and liquidity may result if regulatory assets have to be charged to expense or if regulatory liabilities are r equired to be refunded to ratepayers immediately.

Revenues. Electric utility revenues are based on rates authorized by the PUC and include revenues applicable to energy consumed in the accounting period but not yet billed to customer s. As of December 31, 2011, revenues applicable to energy consumed, but not ye t billed to customers, amounted to $138 million. Revenue amounts recorded pursuant to a PUC interim or der are subject to refund, with interest, pending

a final order. The rate schedules of the electric utilities include ECACs under wh ich electric rates are adjusted for changes in the weighted-average price pai d for fuel oil and cert ain components of purchased power, and the relative amounts of company-generated power and purchased power. The rate schedules of

HECO also include a PPAC under which electric rates are more closely aligned with purchase power costs incurred. Management believes that a material adverse effect on the Company’s results of operations, financial condition and liquidity may resu lt if the ECACs or PPAC were lost.

Consolidation of variable interest entities. A business enterprise must evaluate whether it should consolidate a variable interest entity (VIE). The Company evaluates the im pact of applying accounting

standards for consolidation to its rela tionships with IPPs with whom the utilities execute new PPAs or execute amendments of existing PPAs. A possibl e outcome of the analysis is that HECO or its subsidiaries may be found to meet the definition of a prim ary beneficiary of a VIE which finding may result in the consolidation of

the IPP in HECO’s consolid ated financial statements. The consolidation of IPPs could have a material effect

on HECO’s consolidated financ ial statements, including t he recognition of a significant amount of assets and
liabilities, and, if such a consolidated IPP were operating at a loss and had insu fficient equity, the potential recognition of such losses. The utilities do not know how the consolidation of IPPs would be treated for regulatory or credit ratings purposes. See Notes 1 and 5 of HEI’s “Notes to Consolidated Financial

Statements.”71 Bank

Executive overview and strategy. When ASB was acquired by HEI in 1988, it was a traditional thrift with
assets of $1 billion and net income of about $13 m illion. ASB has grown by both acquisition and internal growth, but has been optimizing its balance sheet in recent years as a result of its multi-year performance improvement project, which has resulted in a reducti on in asset size and a concomitant improvement in profitability and capital efficiency. ASB ended 2011 with a ssets of $4.9 billion and ne t income of $60 million, compared to assets of $4.8 billi on as of December 31, 2010 and net in come of $58 million in 2010. ASB improved its interest rate risk by selling substantially all of its salable fixed ra te residential loan production during 2009 and a portion of its fix ed rate residential loan production in 2010 and 2011 into the secondary market. A portion of the excess liquidity was used to pay off other borrowings that were maturing. ASB is a full-service community bank serving both consumer and commercial customers. In order to remain competitive and continue build ing core franchise value, ASB c ontinues to develop and introduce new products and services in order to meet the needs of those markets. Additional ly, the banking industry is constantly changing and ASB is ma king the investments in people and technology necessary to adapt and remain competitive. ASB’s ongoing challenge is to c ontinue to increase revenues and control expenses after the completion of its performance improvement project. The interest rate environment and the quality of ASB’s assets will continue to impact its financial results. ASB continues to face a challenging interest rate environment. The persistent, low level of interest rates and excess liquidity in the financial system have im pacted the new loan production rates and made it challenging to find investments with adequate risk-adjust ed returns, which resulted in a negative impact on ASB’s asset yields and net interest margin. The potent ial for compression of ASB’s ma rgin when interest rates rise is an ongoing concern. As part of its interest rate risk management process, ASB uses simulation analysis to measure net interest income sensitivity to changes in interest rates (see “Quantitative and Qualitativ e Disclosures about Market Risk”). ASB then employs strategies to limit the impact of changes in inte rest rates on net interest income. ASB’s key strategies include:

(1) attracting and retaining low-cost, core deposit s, particularly those in non-interest bearing
transaction accounts; (2) reducing the overall exposure to fixed-rate residential mortgage loans and diversifying the loan portfolio with higher-spread, shorter-maturity loans or variable-rate loans such as commercial,
commercial real estate and consumer loans; (3) managing costing liabilities to optimize cost of funds and manage interest rate sensitivity; and (4) focusing new investments on shorter dur ation or variable rate securities.

Although ASB’s loan quality improved in 2011, there ar e still signs of financial stress in the Hawaii and mainland markets. The slowdown in the economy, both nationally and locally, had resulted in ASB experiencing higher levels of loan del inquencies and losses, which were concentrated in the residential land portfolio and on the neighbor islands. The residential l and portfolio has declined, which has enabled ASB to release some loan loss reserves on that portfolio. Al though ASB’s provision for loan losses had decreased in 2011 compared to 2010, it is still at an el evated level compared to several years of historically low loan losses and loan loss allowances. While a gradual recovery was experienced in 2011 as the global economic recovery began to take hold, many challenges remain and the outl ook for the Hawaii econom y is for a slow, steady recovery. Consumers and businesses are expected to recover slowly in 2012 as gradual improvement in measures such as job growth, unemployment and real personal income are expec ted. Continued financial stress on ASB’s customers may result in higher levels of loan delinquencies and losses.72 Results of operations.

(dollars in millions) 2011 % change 2010 % change 2009

Revenues $ 264 (6) $ 283 3 $ 275 Net interest income 185 (3) 190 (6) 201 Operating income 92 (1) 93 192 32

Net income 60 2 58 169 22 Return on average common equity 1 12.0% 3 11.6% 156 4.5%
Earning assets

Average balance 1 $ 4,490 - $ 4,492 (6) $ 4,804
Weighted-average yield 4.45% (5) 4.68% (8) 5.10%

Costing liabilities

Average balance 1 $ 3,362 (2) $ 3,445 (9) $ 3,801
Weighted-average rate 0.43% (27) 0.59% (49) 1.15% Net interest margin 2 4.12% (3) 4.23% 1 4.19%

1 Calculated using the average daily balances.

2 Defined as net interest income as a percentage of average earning assets.

 2011 vs. 2010 Increase (decrease) (in millions)

$ (5) Net interest income before provision for loan losses. Decrease largely due to lower yields on earning assets, partly offset by lower funding costs. ASB’s 2011 average loan portfolio balance was $27 million higher than the 2010 average loan portfolio balance as the average commercial markets and home equity lines of credit loan balances increased by $106 million and $98 million, respectively. ASB targeted these loan types because of their shorter duration and variable rates. Offsetting these loan portfolio increases was a decrease in the average residential loan portfolio balance of $181 million due to lower production and ASB’s decision to sell a portion of the residential loan production. The average investment and mortgage-related securities portfolio balance increased by $71 million as ASB purchased se curities with its excess liquidity. Average deposit balances for 2011 increased by $29 million compared to 2010 balances due to an increase in core deposits of $199 million, partly offset by a decrease in term certificates of $171 million. The other borrowings average balance decreased by $18 million due to lower retail repurchase agreements. Net interest margin decreased primar ily due to lower yields on new loan production as

a result of the low interest rate environment.

(6) Provision for loan loss. Decrease primarily due to lower loan loss reserves for the commercial markets portfolio as a result of lower historical loss ratios in 2011 and lower loan loss reserves for the residential land portfolio due to the contraction of the portfolio. ASB’s nonaccrual and renegotiated loans represented 3.1%, 2.8% and 2.3% of total outstanding loans as of December 31, 2011, 2010 and 2009, respectively.

(7) Noninterest income. Decrease largely due to: $ (8) Lower fee income on deposits as a re sult of new overdraft fee legislation

(6) Noninterest expense. Decrease largely due to: (5) Lower data processing expense due to lower service bureau expenses with the system conversion

in mid-2010

2 Net income. Increase largely due to: 4 Lower provision for loan losses 3 Lower noninterest expense 2 Lower taxes primarily due to additional low in come housing credits and tax-free income from municipal bonds and bank-owned life insurance (3) Lower net interest income before provision for loan losses (4) Lower noninterest income73  2010 vs. 2009 Increase (decrease) (in millions)

$(11) Net interest income before provision for loan losses. Decrease largely due to lower balances and yields on earning assets, partly offset by lower funding costs. ASB’s average interest earning assets and loan portfolio balances decreased by $312 million and $347 million, respectively, primarily due to the sale of substantial residential loan production in 2009 and 2010. The average commercial market and residential land loan portfolio balances decreased by $42 million and $31 million, respectively, due to repayments in th e portfolios. The average home equity line of credit portfolio balance increased by $74 million due to promotional campaigns in the first half of 2010. The average investment and mortgage-related securi ties portfolio balance decreased by $61 million due to the sale of private-issue mortgage-related securities portfolio in the fourth quarter of 2009. The other investments average balance increased by $97 million due to an increase in liquidity as a result of ASB’s fixed rate mortgage production sales. Average deposit balances for 2010 decreased by $116 million compared to 2009 due to an outflow of time certificates of $372 million as ASB did not aggressively price its time certificate produc ts, partly offset by a $256 million increase in the average core deposit balance as ASB introduced new core deposit products. The other borrowings average balance decreased by $160 million primarily due to the payoff of maturing amounts. Net interest margin increased due to lower funding costs as a result of the outflow of higher costing term certificates and a shift in deposit mix.

(11) Provision for loan loss. Decrease primarily due to a $10 million provision for loan loss in 2009 on a commercial loan that subsequently sold and lower level of nonperforming loans. ASB’s nonaccrual and renegotiated loans represented 2.8%, 2.3% and 0.7% of total loans outstanding as of December 31, 2010, 2009 and 2008, respectively. Net charge-offs for 2010 totaled $21.9 million compared to $26.1 million in 2009. The decrease in net charge-offs was due to a $10 million partial charge-off of a commercial loan in 2009. ASB exper ienced an increase in net charge-offs of 1-4 family and residential land loans in 2010.

43 Noninterest income. Increase largely due to: $ 47 Losses on sale of private-issue mortgage-rela ted securities and other-than-temporary impairment (OTTI) charges in 2009 (4) Lower fee income on deposits as a resu lt of new overdraft fee legislation

(19) Noninterest expense. Decrease largely due to lower compensation, occupancy, data processing, services and equipment expenses as a result of ASB’s performance improvement project, which reduced ASB’s cost structure through improv ed processes and procedures, and improved the efficiency of ASB. In May 2010, ASB completed the conversion to the Fiserv Inc. banking platform system, which reduced service bureau expenses by approximately $0.5 million per month beginning

in June 2010. ASB incurred conversion costs to taling approximately $4.4 million in 2010 to complete the project.

37 Net income. Increase largely due to: 7 Lower provision for loan losses 26 Higher noninterest income 11 Lower noninterest expense (7) Lower net interest income before provision for loan losses

See Note 4 of HEI’s “Notes to Consolidated Fi nancial Statements” for a discussion of guarantees and

further information about ASB.74 Average balance sheet and net interest margin. The following tables set forth average balances, together with
interest and dividend income earned and accrued, and resulting yields and costs for 2011, 2010 and 2009.

2011 2010

(dollars in thousands) Average

balance Interest Average rate (%) Average

balance Interest Average rate (%)

Assets:

Other investments 1 $ 233,909 $ 342 0.15 $ 334,270 $ 621 0.19 Investment and mortgage-related securities 637,123 14,763 2.32 566,126 14,468 2.56

Loans receivable 2 3,618,527 184,485 5.10 3,591,794 195,192 5.43 Total interest-earning assets 3 4,489,559 199,590 4.45 4,492,190 210,281 4.68 Allowance for loan losses (39,263) (39,135) Non-interest-earning assets 423,183 415,986
Total assets $4,873,479 $4,869,041

Liabilities and Shareholder’s Equity: Interest-bearing demand and savings deposits $2,516,606 2,590 0.10 $2,410,118 3,475 0.14
Time certificates 598,360 6,393 1.07 768,991 11,221 1.46 Total interest-bearing deposits 3,114,966 8,983 0.29 3,179,109 14,696 0.46 Other borrowings 247,121 5,486 2.22 266,149 5,653 2.12 Total interest-bearing liabilities 3,362,087 14,469 0.43 3,445,258 20,349 0.59 Non-interest bearing liabilities: Deposits 916,957 824,039
Other 95,363 96,510 Shareholder’s equity 499,072 503,234 Total Liabilities and Shareholder’s Equity $4,873,479 $4,869,041

Net interest income $185,121 $189,932
Net interest margin (%) 4 4.12 4.23

2009

(dollars in thousands) Average

balance Interest Average rate (%)

Assets:

Other investments 1 $ 237,770 $ 329 0.14 Investment and mortgage-related securities 627,365 26,648 4.25

Loans receivable 2 3,938,575 217,838 5.53 Total interest-earning assets 3 4,803,710 244,815 5.10 Allowance for loan losses (42,121) Non-interest-earning assets 352,398
Total assets $5,113,987

Liabilities and Shareholder’s Equity: Interest-bearing demand and savings deposits $2,234,259 6,676 0.30
Time certificates 1,140,997 27,370 2.40 Total interest-bearing deposits 3,375,256 34,046 1.01 Other borrowings 425,947 9,497 2.23 Total interest-bearing liabilities 3,801,203 43,543 1.15 Non-interest bearing liabilities: Deposits 743,982
Other 89,248 Shareholder’s equity 479,554 Total Liabilities and Shareholder’s Equity $5,113,987

Net interest income $201,272
Net interest margin (%) 4 4.19

1 Includes federal funds sold, interest bearing deposits and stock in the Federal Home Loan Bank of Seattle.

2 Includes loan fees of $3.9 million, $6.3 million and $6.9 million for 2011, 2010 and 2009, respectively, together with interest accrued prior to suspension of interest accrual on nonaccrual loans.75 3 Interest income includes taxable equivalent basis adjustments, based upon a federal statutory tax rate of 35%, of $0.5 million
and $0.1 million for 2011 and 2010, respectively

.
4 Defined as net interest income as a percentage of average earning assets.

Earning assets, costing liabilities and other factors . Earnings of ASB depend pr imarily on net interest
income, which is the difference between interest earned on earning assets and interest paid on costing

liabilities. The current inte rest rate environment is impacted by disr uptions in the financial markets and these conditions may have a negative impact on ASB’s net interest margin. Loan originations and mortgage-related securities ar e ASB’s primary sources of earning assets.

Loan portfolio . ASB’s loan volumes and yields are affected by market interest rates, competition, demand for financing, availability of funds and management ’s responses to these factors. See Note 4 of

HEI’s “Notes to Consolidated Financial Statements” for the composition of ASB’s loans receivable. The increase in the total loan portfolio from $3.5 b illion at the end of 2010 to $3. 6 billion at the end of 2011 was primarily due to growth in the commercial market and home equity line of credit loan portfolios, which ASB targeted because of their shorter duration and variable rates.

Loan portfolio risk elements. When a borrower fails to make a required payment on a loan and does not cure the delinquency promptly, the loan is classi fied as delinquent. If delinquencies are not cured promptly, ASB normally commences a collection action, including foreclosure proceedings in the case of secured loans. In a foreclosure action, the property secu ring the delinquent debt is sold at a public auction in which ASB may participate as a bidder to protect its in terest. If ASB is the successful bidder, the property is

classified as real estate owned until it is sold.

See “Allowance for loan losses” in Note 4 of HEI’ s “Notes to Consolidated Financial Statements” for information with respect to nonperforming assets. The level of nonperforming loans reflects the impact of current unemployment levels in Hawaii and the weak economic envir onment globally, nationally and in

Hawaii.

Allowance for loan losses. See “Allowance for loan losses” in Note 4 of HEI’s “Notes to

Consolidated Financial Statements” for the tables which sets forth the a llocation of ASB’s allowance for loan
losses. For 2011, the allowance for loan losses decreased by $2.7 million due to a lower historical loss ratio

used for commercial loans and a decrease in loss reserv es for residential land loans as a result of the contraction of the portfolio. Offsetting these decreases was an increase in the commercial real estate loan loss reserves due to an increase in the outstanding loan balance.

Investment and mortgage-related securities . As of December 31, 2011, ASB’s investment portfolio consisted of 55% mortgage-related securities iss ued by Federal National Mortgage Association (FNMA), Federal Home Loan Mortgage Corporation (FHLMC) or Government National Mort gage Association (GNMA), 35% federal agency obligations and 10% municipal bonds . As of December 31, 2010, ASB’s investment portfolio consisted of 47% mortgage-related securities issued by FNMA, FHLMC or GNMA and 47% federal agency obligations and 6% municipal bonds. Principal and interest on mortgage-related secu rities issued by FNMA, FHLMC and GNMA are guaranteed by the issuer, and the securi ties carry implied AAA ratings. The unrealized gains on ASB’s investment in feder al agency mortgage-backed securities were primarily caused by lower interest rates. The low interest rate environment coupled with tighter spreads on all mortgage

collateralized securities caused the market value of the securities hel d to increase above the carrying book

value. All contractual cash flows of those invest ments are guaranteed by an agency of the U.S. government. See “Investment and mortgage-related securities” in Note 1 for a discussion of securities impairment

assessment. As of December 31, 2011, 2010 and 2009, ASB did not have any private-issue mortgage-related securities. In the fourth quarter of 2009, ASB sold it s PMRS portfolio and had no OTTI as of December 31,

2009.76 Deposits and other borrowings . Deposits continue to be the lar gest source of funds for ASB and are affected by market interest rates, competition and man agement’s responses to these factors. Deposit retention and growth will remain challenging in the current envir onment due to competition fo r deposits and the low level

of short-term interest ra tes. Advances from the FHLB of Sea ttle and securities sold under agreements to repurchase continue to be additional sources of funds. As of December 31, 2011, ASB’s costing liabilities consisted of 95% deposits and 5% other borrowings. As of December 31, 2010, ASB’s costing liabilities consisted of 94% deposits and 6% other borrowings. See Note 4 of HEI’s “Notes to Consolidated Financial Statements” for the compos ition of ASB’s deposit liabilities and other borrowings.

Other factors . Interest rate risk is a si gnificant risk of ASB’s operations and also represents a market risk factor affecting the fair value of ASB’s investment securities. Increases and decreases in prevailing interest rates generally translate into decreases and increases in t he fair value of those instruments, respectively. In addition, changes in credit spreads also impac t the fair values of those instruments.
As of December 31, 2011 and 2010, ASB had unrealized gains, net of taxes, on available-for-sale investments and mortgage-related securiti es (including securities pledged for repurchase agreements) in AOCI of $10 million and $4 million, respecti vely. See “Quantitative and qualitativ e disclosures about market risk.”

Legislation and regulation. ASB is subject to extensive regulatio n, principally by the Office of the Comptroller of the Currency (OCC) and the Federal Deposit Insurance Corpor ation (FDIC). Depending on ASB’s level of regulatory capital and ot her considerations, these regulations could restrict the ability of ASB to compete with other institutions and to pay dividends to its shareholder. See the discussion below under “Liquidity and capital resources.” Also see “Federal Deposit Insurance Corporat ion restoration plan” and “Deposit insurance coverage” in Note 4 of HEI’ s “Notes to Consolidat ed Financial Statements.”

Dodd-Frank Wall Street Reform and Cons umer Protection Act (Dodd-Frank Act). Regulation of the financial services industry, including regulation of HEI and ASB, has changed and will continue to change as a

result of the enactment of the D odd-Frank Act, which became law in Ju ly 2010. Importantly for HEI and ASB, under the Dodd-Frank Act, on July 21, 2011, all of the functions of the Office of Thrift Supervision (OTS)
transferred to the OCC, the FDIC, the Federal Reserve Board (FRB) and the Consumer Financial Protection Bureau. Supervision and regulation of HEI, as a thrift holding company, moved to the FRB, and supervision and regulation of ASB, as a federally chartered savings bank, moved to the OCC. While the laws and regulations applicable to HEI and ASB did not gener ally change—the Home Owners Loan Act and regulations issued thereunder still apply—the applicable laws and regulations are being interpreted, and new and amended regulations may be adopted by the FRB and the O CC. HEI will for the firs t time be subject to minimum consolidated capital requirements, and ASB may be required to be supervised through ASHI, its intermediate holding company. The Dodd-Frank Act require s regulators, at a minimum, to apply to bank and thrift holding companies leverage and risk-based capital standards that are at least as strict as those in effect at the insured depository in stitution level on the date the Act became effective, although there will be a phasein period for meeting these standards. In addition, HEI w ill continue to be required to serve as a source of strength to ASB in the event of its financial distress. The Dodd-Frank Act also imposes new restrictions on the ability of a savings bank to pay dividends s hould it fail to remain a qualified thrift lender. More stringent affiliate transaction rules now apply to ASB in the securities l ending, repurchase agreement and derivatives areas. Standards were raised with respec t to the ability of ASB to merge with or acquire another institution. In reviewing a potential merger or acquisition, t he approving federal agency will need to consider the extent to which the proposed transaction will result in “greater or more concentrated risks to the stability of the U.S. bank ing or financial system.”

The Dodd-Frank Act establishes a Consumer Financia l Protection Bureau (Bureau) that will have authority to prohibit practices it finds to be unfair, deceptive or abusive, and it may also issue rules requiring specified disclosures and the use of new model forms. ASB may al so be subject to new state regulation because of a provision in the Dodd-Frank Act. ASB may also be subject to new state regulation bec ause of a provision in the Dodd-Frank Act that acknowledges that a federal savings ba nk may be subject to state regulation and allows federal law to preempt a state consumer financial law on a “case by case” basis only when (1) the state law would have a77 discriminatory effect on the bank compar ed to that on a bank chartered in that state; (2) the state law prevents or significantly interferes with a bank’s exercise of its power; or (3) the stat e law is preempted by another

federal law. The Dodd-Frank Act also adopts a number of provisi ons that will impact the mortgage industry, including the imposition of new specific duties on the part of mortgage originators (such as ASB) to act in the best

interests of consumers and to take st eps to ensure that consum ers will have the capability to repay loans they may obtain, as well as provisions imposing new di sclosure requirements and requiring appraisal reforms. Regulations are required to be adopted within 18 months after the date that is to be specified by the Secretary of the Treasury for the transfer of cons umer protection power to the Bureau. The “Durbin Amendment” to the Dodd-Frank Act required the FRB to issue rules to ensure that debit card interchange fees are “reasonable and proportional” to the pr ocessing costs incurred. In June 2011, the FRB issued a final rule establishing standards for debit ca rd interchange fees and prohibiting network exclusivity arrangements and routing restrictions. U nder the final rule, effective Oct ober 1, 2011, the maximum permissible interchange fee that an issuer may receive for an el ectronic debit transaction is 21-24 cents, depending on certain components. For 2011, ASB had earned an average of 53 cents per transaction. As specified in the Dodd-Frank Act, these regulations wi ll exempt banks like ASB, that, along wi th their affiliates, have less than $10 billion in assets. However, market pressures c ould cause all banks to observe this limitation. Many of the provisions of the Dodd-Frank Act, as amended, will not become effective until implementing regulations are issued and effective. Thus, management cannot predict the ultimate impact of the Dodd-Frank Act, as amended, on the Company or ASB at this time . Nor can management predict the impact or substance

of other future federal or state legislation or regulati on, or the application thereof.

Overdraft rules. On November 12, 2009, t he Board of Governors of t he Federal Reserve System announced that it amended Regulation E (which implement s the Electronic Fund Transfer Act) to limit the ability of a financial institution to assess an overdraft fee for paying autom ated teller machine or one-time debit
card transactions that overdraw a consumer’s account, unless the consumer affirmat ively consents, or opts in, to the institution’s payment of ov erdrafts for those transactions. These new rules applied on July 1, 2010 for new accounts and on August 15, 2010 for existing accounts. For 2011, these types of overdraft fees were $7.9 million lower compared to 2010.

S.A.F.E. Act. Under the Secure and Fair Enforcement for Mortgage Licensing Act and the final rules issued on July 28, 2010, residential mortgage loan origi nators employed by banks mu st register with the Nationwide Mortgage Lending System and Registry to obtain a unique i dentifier from the Registry, and maintain that registration. The init ial period for this federal registra tion ended July 29, 2011; ASB satisfied its obligations under this act before that deadline.

FHLB of Seattle stock. As of December 31, 2011, ASB’s investment in stock of the FHLB of Seattle of
$97.8 million was carried at cost because it can onl y be redeemed at par. There is a minimum required

investment in such stock based on measurements of A SB’s capital, assets and/or borrowing levels, and ASB’s investment is substantially in excess of that requi rement. The FHLB of Seattle reported net income of
$70.7 million for the nine months ended September 30, 2011 compared to net income of $23.9 million for the nine months ended September 30, 2010. The FHLB of Sea ttle reported retained earnings of $144 million as of September 30, 2011 and was in compliance with all of its regulatory capital requirements. In October 2010, the FHLB of Seattle entered into a Stipul ation and Consent to the Issuance of a Consent Order with the Federal Housing Finance Agency, which requires the FHLB of Seattle to take certain actions related to its business and operations. The Consents provide that, following a stabilization period and once the FHLB of Seattle reaches and maintains certain thresholds, it may redeem or repurchase capi tal stock and begin paying

dividends. ASB does not believe that the Consents will affect the FHLB of Sea ttle’s ability to meet ASB’s liquidity and funding needs. The FHLB of Seattle di d not pay any cash dividends in 2009, 2010 or 2011.

Commitments and contingencies. See Note 4 of HEI’s “Notes to Consolidated Fi nancial Statements.”

Recent accounting pronouncements. See “Recent accounting pronouncements and interpretations” in

Note 1 of HEI’s “Notes to C onsolidated Financia l Statements.”78 Liquidity and capital resources.
December 31 2011 % change 2010 % change (dollars in millions)

Total assets $4,910 2 $4,797 (3) Available-for-sale investment and mortgage-related securities 624 (8) 678 57 Loans receivable held for investment, net 3,643 4 3,490 (4) Deposit liabilities 4,070 2 3,975 (2) Other bank borrowings 233 (2) 237 (20)

As of December 31, 2011, ASB was one of Hawaii’s largest financial institutions based on assets of $4.9 billion and deposits of $4.1 billion. In August 2011, Moody’s affirmed ASB’ s counterparty credit rating of A3 with a “stable” outlook based on ASB’s excellent asset quality indicators, high capital ra tios and healthy liquidity position that is supported by good core deposit funding. In December 2011, S&P affirm ed ASB’s issuer credit ratings of BBB/Stable/A-2 based on strong capital and earnings, moderate risk position, above average f unding and adequate liquidity. These ratings reflect only the view, at the time the ratings are issued, of the applicable rating agency from whom an explanation of the significance of such ratings may be obtained. Such ratings are not recommendations to buy, sell or hold any HEI or HECO se curities; such ratings may be subject to revision or withdrawal at any time by the rating agencies; and eac h rating should be evaluated independently of any other rating. ASB’s principal sources of liquidity are customer deposits, borrowings and the maturity and repayment of portfolio loans and securities. ASB’s deposits as of December 31, 2011 were $95 million higher than December 31, 2010. ASB’s principal sources of borrowi ngs are advances from the FHLB and securities sold under agreements to repurchase from br oker/dealers. As of December 31, 2011, FHLB borrowings totaled $50 million, representing 1.0% of assets. ASB is approved to borrow from the FHLB up to 35% of ASB’s assets to the extent it provides qual ifying collateral and holds sufficient FH LB stock. As of December 31, 2011, ASB’s unused FHLB borrowing capacity was approximately $1. 1 billion. As of December 31, 2011, securities sold under agreements to repurchase to taled $183 million, representing 3.7% of assets. ASB utilizes deposits,

advances from the FHLB and securities sold under agreements to repurchase to fund maturing and withdrawable deposits, repay maturi ng borrowings, fund existing and future loans and purchase investment and mortgage-related securities. As of December 31, 2011, ASB had commitments to borrowers for
undisbursed loan funds, loan commitments and unused lines and letters of credit of $1.3 billion, including
$3 million to lend additional funds to borrowers w hose loan terms have been modified in troubled debt restructurings. Management believes ASB’ s current sources of funds will enabl e it to meet these obligations while maintaining liquidity at satisfactory levels. As of December 31, 2011 and 2010, ASB had $66.8 million and $58.9 million of loans on nonaccrual status, respectively, or 1.8% and 1. 7% of net loans outstanding, respec tively. As of December 31, 2011 and 2010, ASB had $7.3 million and $4.3 million, respectively, of real esta te acquired in settlement of loans. In 2011, operating activities provided cash of $101 m illion. Net cash of $120 million was used by investing activities primarily due to purchases of investment and mortgage-related securities, a net increase in loans held for investment and capital expenditures, partly offs et by repayments of inve stment and mortgage-related securities and proceeds from the sa le of mortgage-related securities and real estate. Financing activities provided net cash of $32 million due to a net increase in deposits, partly offset by a decrease in other borrowings and the payment of common stock dividends. ASB believes that maintaining a satisfactory regul atory capital position provides a basis for public confidence, affords protection to depositors, helps to ensure continued access to capital markets on favorable terms and provides a foundation for growth. FDIC regulati ons restrict the ability of financial institutions that are not well-capitalized to compete on the same terms as well-capitalized institutions, such as by offering interest rates on deposits that are signi ficantly higher than the rates offered by competing institutions. As of December 31, 2011, ASB was well-capitalized (see “R egulation—Capital requirements” below for ASB’s capital ratios). For a discussion of ASB dividends, see “Common stock equity” in Note 4 of HEI’s “Notes to

Consolidated Financ ial Statements.”79 Certain factors that may affect future results and financial condition. Also see “Forward-Looking

Statements” and “Certain factors t hat may affect fu ture results and financial condition” for Consolidated HEI

above.

Competition. The banking industry in Hawaii is highly co mpetitive. ASB is one of Hawaii’s largest
financial institutions, based on total assets, and is in direct competition for deposits and loans, not only with larger institutions, but also with sm aller institutions that are heavily prom oting their services in certain niche areas, such as providing financial services to small- and medium-sized businesses, and national organizations offering financial services. ASB’s main competitors are banks, savings associations, credit unions, mortgage brokers, finance companies and securiti es brokerage firms. These competitors offer a variety of lending, deposit and investment products to retail and business customers. The primary factors in competing for deposits are interest rates, the quality and range of services offered, marketing, convenience of locations, hours of operati on and perceptions of t he institution’s financial soundness and safety. To meet competition, ASB offe rs a variety of savings and checking accounts at competitive rates, convenient business hours, conv enient branch locations with interbranch deposit and withdrawal privileges at each branch and convenient automated teller machines. ASB also conducts advertising and promotional campaigns. The primary factors in competing for first mortgage an d other loans are interest rates, loan origination fees and the quality and range of lending and other services offered. ASB believes that it is able to compete for such loans primarily through the competitive intere st rates and loan fees it charges, the type of mortgage loan programs it offers and the efficiency and quality of t he services it provides to individual borrowers and the business community. ASB is a full-service community bank serving both consumer and commercial customers and has been diversifying its loan portfolio from single-family home mortgages to higher-s pread, shorter-duration
consumer, commercial and commercial real estate lo ans. The origination of consumer, commercial and

commercial real estate loans involves risks and other c onsiderations different from those associated with originating residential real estate loans. For example, the sources and level of co mpetition may be different and credit risk is generally higher than for mortgage loans. These different risk factors are considered in the underwriting and pricing standards and in the allowance for loan losses established by ASB for its
consumer, commercial and commercial real estate loans.

U.S. capital markets and credit and interest rate environment. Volatility in U.S. capital markets may negatively impact the fair values of investment and mortgage-related securities held by ASB. As of
December 31, 2011, the fair value and carrying value of the investment and mortgage-related securities held by ASB were $0.6 billion. ASB’s strat egic sales of its private-issue mortgage-related securities in the fourth quarter of 2009, substantially all of its salable re sidential loan production dur ing 2009 and a portion of its residential loan production in 2010 and 2011 helped to reduc e its exposure to credit risk and interest rate

risk. Interest rate risk is a signifi cant risk of ASB’s operations. ASB actively manages this risk, including managing the relationship of its interest-sensitive assets to its interest-sensitive liabilities. Persistent low
levels of interest rates, weak loan demand, and excess liquidity in the financial system have made it challenging to find investments with adequate risk-adjusted returns, resulti ng in declining loan balances and an increase in ASB’s liquidity position, with a negative impact on ASB’s asset yields and net interest margin.

If the current interest rate environm ent persists, the potential for compre ssion of ASB’s net interest margin will continue. ASB also manages the credit risk associat ed with its lending and securities portfolios, but a deep and prolonged recession led by a material decline in hous ing prices could materially impair the value of its portfolios. See “Quantitativ e and Qualitative Disclosures about Market Risk” below.

Technological developments. New technological developments (e.g., significant advances in internet banking) may impact ASB’s future competitive position, results of operations and financial condition.

Environmental matters. Prior to extending a loan collateralized by real property, ASB conducts due diligence to assess whether or not the property may present environment al risks and potential cleanup liability. In the event of default and foreclosure of a loan, ASB may become the owner of the mortgaged80 property. For that reason, ASB seeks to avoid lending upon the security of, or acquiring through foreclosure, any property with significant potent ial environmental risks; however, ther e can be no assurance that ASB will successfully avoid all such environmental risks.

Regulation. ASB is subject to examination and compr ehensive regulation by the Department of Treasury, OCC and the FDIC, and is subject to reserve requirements established by the Board of Governors of the Federal Reserve System. Regulation by thes e agencies focuses in lar ge measure on the adequacy of ASB’s capital and the results of per iodic “safety and soundness” examinat ions conducted by the OCC.

Capital requirements . The OCC, which is ASB’s principal regul ator, administers two sets of capital standards—minimum regulatory capital requirements and prompt corrective action requirements. The FDIC also has prompt corrective action capital requirement s. As of December 31, 2011, ASB was in compliance with OCC minimum regulatory capital requirements and was “well-capitalized” within the meaning of OCC prompt corrective action regulations an d FDIC capital regulations, as follows:

 ASB met applicable minimum regulatory capital r equirements (noted in parentheses) as of December 31, 2011 with a tangible capital ratio of 9. 0% (1.5%), a core capita l ratio of 9.0% (4.0%) and a total risk-based capital ratio of 12.9% (8.0%).

 ASB met the capital requirements to be generally considered “well-capitalized” (noted in parentheses) as of December 31, 2011 with a lever age ratio of 9.0% (5.0%), a Tier-1 risk-based capital ratio of 11.9% (6.0%) and a total ri sk-based capital ratio of 12.9% (10.0%). The purpose of the prompt corrective action capital requirements is to establish thresholds for varying degrees of oversight and intervention by regulators. Declines in levels of capital, depending on their severity, will result in increasingly stri ngent mandatory and discreti onary regulatory consequences. Capital levels may decline for any number of reasons, including reduction s that would result if there were losses from operations, deterioration in collateral values or the i nability to dispose of real estate owned (such as by foreclosure). The regulators have subst antial discretion in the corrective actions they might direct and could

include restrictions on dividends and other distribut ions that ASB may make to HEI (through ASHI) and the requirement that ASB develop and implement a plan to restore its capital. Under an agreement with regulators entered into by HEI when it acquired ASB, HEI currently c ould be required to contribute to ASB up to an additional $28.3 million of capital, if necessary, to maintain ASB’s capital position.

Examinations. ASB is subject to periodic “safet y and soundness” examinations and other examinations by the OCC. In conduc ting its examinations, the OCC utilizes the Uniform Financial Institutions Rating System adopted by the Federal Financial Institut ions Examination Council, which system utilizes the “CAMELS” criteria for rating financ ial institutions. The six components in the rating system are: Capital adequacy, Asset quality, Management, Earnings, Liquid ity and Sensitivity to market risk. The OCC examines and rates each CAMELS component. An overall CAMELS rating is also gi ven, after taking into account all of the component ratings . A financial institution may be s ubject to formal regulatory or administrative direction or supervision such as a “memorandum of understandi ng” or a “cease and desist” order following an examination if its CAMELS rating is not satisfactory. An institution is prohibited from disclosing the OCC’s report of its safety and soundnes s examination or the comp onent and overall CAMELS rating to any person or organization not officially connected with the in stitution as an officer, director, employee, attorney, or auditor, except as provided by regulation. The OCC also regularly examines ASB’s information technology practices and its performance under Community Reinvest ment Act measurement

criteria. The Federal Deposit Insurance Act, as amended, addresses the safety and soundness of the deposit insurance system, supervision of depos itory institutions and improvement of accounting standards. Pursuant to this Act, federal banking agencies have promulgated r egulations that affect th e operations of ASB and its holding companies (e.g., standards for safety and soundne ss, real estate lending, accounting and reporting,

transactions with affiliates and loans to insiders). FDIC regulations restrict the ability of financial institutions that fail to meet relevant capital measures to engage in certain activities, such as offering interest rates on deposits that are significantly higher than the ra tes offered by competing institutions. As of December 31, 2011, ASB was “well-capitalized” and thus not subject to these restrictions.81 Qualified Thrift Lender status. ASB is a “qualified thrift lender” (QTL ) under its federal thrift charter and, in order to maintain this status, ASB is required to main tain at least 65% of its assets in “qualified thrift investments,” which include housing-related loans (inc luding mortgage-related securities) as well as certain
small business loans, education loans, loans made thr ough credit card accounts and a basket (not exceeding 20% of total assets) of other consumer loans and other asse ts. Institutions that fail to maintain QTL status are subject to various penalties, including limitations on their activities. In ASB’s case, the activities of HEI, ASHI and HEI’s other subsidiaries would also be subject to rest rictions if ASB failed to main tain its QTL status, and a failure or inability to comply with those restrictions coul d effectively result in the r equired divestiture of ASB. As of December 31, 2011, approximat ely 76% of ASB’s assets were qualified thrift investments.

Unitary savings and loan holding company . The Gramm-Leach-Bliley Act of 1999 (Gramm Act) permitted banks, insurance companies and investment firms to compete directly against each other, thereby allowing “one-stop shopping” for an arra y of financial services. Although t he Gramm Act further restricted the creation of so-called “unitary savings and loan hol ding companies” (i.e., compani es such as HEI whose subsidiaries include one or more savings associations and one or more nonfinancial subsidiaries), the unitary savings and loan holding company relationship am ong HEI, ASHI and ASB is “grandfathered” under the

Gramm Act so that HEI and its subsidiaries will be able to continue to engage in their current activities so long

as ASB maintains its QTL status. Under the Gramm Ac t, any proposed sale of ASB would have to satisfy applicable statutory and regulatory r equirements and potential acquirers of ASB would most likely be limited to companies that are already qualifie d as, or capable of qualifying as, either a traditional savings and loan association holding company or a bank holding company, or as one of the newly authorized financial holding companies permitted under the Gramm Act. There have been legislative proposals in the past which would operate to eliminate the thrift charter or the grandfathered status of HEI as a unitary thrift holding company and effectively require the divestiture of ASB.

Material estimates and critical accounting policies. Also see “Material estimates and critical accounting policies” for Consolidated HEI above.

Investment and mortgage-related securities. ASB owns federal agency obligations and mortgage-related securities issued by the FNMA, GNMA and FHLMC a nd municipal bonds, all of which are classified as available-for-sale and reported at fair value, with unrealized gains and losses excluded from earnings and reported in AOCI.

ASB views the determination of whet her an investment security is te mporarily or other -than-temporarily impaired as a critical accounting policy since the estima te is susceptible to significant change from period to period because it requires management to make signifi cant judgments, assumptions and estimates in the preparation of its consoli dated financial statements. See “Investment and mortgage-related securities” in Note 1 of HEI’s “Notes to Consolidated Financial

Statements” for a discussion of secu rities impairment assessment and othe r-than-temporary impaired securities. Prices for investments and mortgage-related securities are provided by an independent third party pricing service and are based on observable inputs, including historical trading levels or sector yields, using marketbased valuation techniques. The price of these securities is generally based on observable inputs, which includes market liquidity, credit cons iderations of the underly ing collateral, the levels of interest rates, expectations of prepayments and defaults , limited investor base, market se ctor concerns and overall market psychology. To validate the accuracy and completeness of security pricing, a separate third party pricing service is used on a quarterly basis to compare prices t hat were received from the initial third party pricing service. If the pricing differential between the two pricing sources exc eeds an established threshold, the security price will be re-evaluated by sending a re -pricing request to both indepen dent third party pricing services, to another third party vendor, or to an independent broker to determine the most accurate price based on all observable inputs found in the ma rket place. The third party price se lected will be based on the value that

best reflects the data and observable characteristics of the security

. As of December 31, 2011, ASB had investment and mortgage-related securities issued by FHLMC, GNMA and FNMA valued at $0.6 billion.82 Allowance for loan losses. See Note 1 of HEI’s “Notes to Cons olidated Financial St atements” and the discussion above under “Earning assets, costing liabilit ies and other factors.” As of December 31, 2011,
ASB’s allowance for loan losses was $37.9 million an d ASB had $66.8 million of loans on nonaccrual status, compared to $40.6 million and $58.9 million at December 31, 2010, respectively. In 2011, ASB recorded a provision for loan losses of $15.0 million.

The determination of the allowance for loan losses is sensitive to the credit risk ratings assigned to ASB’s loan portfolio and loss ratios inherent in the ASB l oan portfolio at any given point in time. A sensitivity analysis provides insight regarding the impact that adv erse changes in credit risk ratings may have on ASB’s
allowance for loan losses. At December 31, 2011, in the event that 1% of the homogenous loans move down one delinquency classification (e.g., 1% of the loans in the 0-29 days delinquent category move to the 30-59 days delinquent category, 1% of the loans in the 30-59 days delinquent ca tegory move to the 60-89 days delinquent category and 1% of the loans in t he 60-89 days delinquent category move to the 90+ days delinquent category) and 1% of non- homogenous loans were downgraded one credit risk rating category for each category (e.g., 1% of the loans in the “pass” category moved to the “special mention” category, 1% of the loans in the “special mention” category moved to the “substandard” category, 1% of the loans in the “substandard” category moved to the “doubtful” cat egory and 1% of the loans in the “doubtful” category moved to the “loss” category), the allowance for loan losses would have increased by approximately $0.4 million. The sensitivity analyses do not imply any expectation of future deterioration in ASB loans’ risk ratings and they do not necessarily reflect the nature and extent of future changes in the allowance for loan losses due to the numerous quantitative and qualitative fa ctors considered in deter mining ASB’s allowance for loan losses. The example above is only one of a number of possible scenarios. Although management believes ASB’s allowance for loan losses is adequate, the actual loan losses, provision for loan losses and allowance for loan losses may be materially different if conditions change (e.g., if there is a significant change in t he Hawaii economy or real estate mark et), and material increases in those

amounts could have a material adverse effect on the Company’s results of operations, financial condition and liquidity.

HECO: The information required by this item is set forth in HECO’s MD&A, incorporated herein by reference to page 3

of HECO Exhibit 99.2.

ITEM 7A. QUANTITATIVE AND QUALITAT IVE DISCLOSURES ABO UT MARKET RISK

HEI: The Company manages various market risks in the or dinary course of business, including credit risk and liquidity risk. The Company believes the electric ut ility and the “other” segment’s exposures to these two

risks are not material as of December 31, 2011.

Credit risk for ASB is the risk that borrowers or iss uers of securities will not be able to repay their obligations to the bank. Credit risk associated with ASB’s lending portfolios is controlled through its underwriting standards, loan rating of commercial and commercial real estate loans, on-going monitoring by loan officers, credit review and quality control func tions in these lending areas and adequate allowance for

loan losses. Credit risk associated with the securities portfolio is mitigat ed through investment portfolio limits, experienced staff working with analytical tools, monthly fair value analysis and on-going monitoring and reporting such as investment watch reports and loss s ensitivity analysis. See “A llowance for loan losses”

above. Liquidity risk for ASB is the risk that the bank wi ll not meet its obligations when they become due. Liquidity risk is mitigated by ASB’s asset/liabilit y management process, on- going analytical analysis, monitoring and reporting information such as week ly cash-flow analyses and maintenance of liquidity contingency plans.83 The Company is exposed to some commodity price risk primarily related to the fuel supply and IPP

contracts of the electric utilities. The Company’s commodity price risk is substantially mitigated so long as

the electric utilities have their current ECACs in t heir rate schedules. The Company currently has no hedges against its commodity price risk. The Company curr ently has no exposure to market risk from trading activities nor foreign currency exchange rate risk. The Company considers interest rate risk to be a ve ry significant market risk as it could potentially have a significant effect on the Company’s results of operations, financial conditi on and liquidity, especially as it relates to ASB, but also as it may af fect the discount rate used to determ ine retirement benefit liabilities, the market value of retirement benefit plans’ assets and the el ectric utilities’ allowed rates of return. Interest rate risk can be defined as the exposure of the Company’s ear nings to adverse movements in interest rates.

Bank interest rate risk

The Company’s success is dependent, in part, upon ASB’s ability to manage interest rate risk. ASB’s interest-rate risk profile is strongly influenced by its primary business of making fixed-rate residential mortgage loans and taking in retail deposits. Large mism atches in the amounts or timing between the maturity or repricing of interest sensitive assets or liabilities could adversely affect ASB’s earnings and the

market value of its interest-sensitive assets and liabilitie s in the event of significant changes in the level of interest rates. Many other factors also affect ASB’s exposure to changes in interest rates, such as general economic and financial conditions, customer pref erences, and competition for loans or deposits. ASB’s Asset/Liability Management Committee (A LCO), whose voting members are officers and employees of ASB, is responsible for managing interest rate risk and carrying out the overall asset/liability management objectives and activities of ASB as approved by the ASB Board of Directors. ALCO establishes policies under which management monitors and coordinates ASB’s assets and liabilities.

See Note 4 of HEI’s “Notes to Consolidated Financia l Statements” for a discussi on of the use of rate

lock commitments on loans held for sale and forward sa le contracts to manage some interest rate risk

associated with ASB’s resi dential loan sale program. Management of ASB measures interest-rate risk using simulation analysis with an emphasis on measuring changes in net interest income (NII) and the market value of interest-sensitive assets and

liabilities in different interest-rate environments. The simulation analysis is performed using a dedicated asset/liability management software system enhanc ed with a mortgage prepayment model and a collateralized mortgage obligation database. The simu lation software is capable of generating scenariospecific cash flows for all instruments using the s pecified contractual information for each instrument and product specific prepayment assumptions for mortgage loans and mortgage-related securities. NII sensitivity analysis measures the change in ASB’s tw elve-month, pretax NII in alternate interest rate scenarios. NII sensitivity is measured as the change in NII in the alternate interest-rate scenarios as a percentage of the base case NII. The base case interest -rate scenario is established using the current yield

curve and assumes interest rates remain constant over the next twelve months. The alternate scenarios are created by assuming “rate ramps” or gradual interest changes and accomplished by moving the yield curve in a parallel fashion, over the next twelve month peri od, in increments of +/- 100 basis points. The simulation model forecasts scenario-specific principal and intere st cash flows for the interest-bearing assets and
liabilities, and the NII is calculated for each scenario . Key balance sheet modeling assumptions used in the NII sensitivity analysis include: the size of the balance sheet remains relatively constant over the simulation horizon and maturing assets or liabilities are reinvested in similar instruments in order to maintain the current mix of the balance sheet. In addition, assumptionsare made about the prepayment behavior of mortgagerelated assets, future pricing sp reads for new assets and liabilities, and the speed and magnitude with which deposit rates change in response to changes in the overa ll level of interest rate s. Other NII sensitivity analysis may include scenarios such as yield curve twists or non-static balance sheet changes (such as changes to key balance sheet drivers). For 2011, ASB adopted terminology and interest rate risk (IRR) asse ssment, measurement and management practices consistent with OCC guidelines. The market value or economic capitalization of ASB is now measured as economic value of equity (EVE) repl acing the OTS’ net portfolio value (NPV) ratio and84 sensitivity measures. EVE is a similar measurement conceptually as NPV and r epresents the theoretical market value of ASB’s net worth and is defined as the pr esent value of expected net cash flows from existing assets minus the present value of expected cash flows from existing liabilities plus the present value of expected net cash flows from existing off-balance sheet c ontracts. Key assumptions used in the calculation of ASB’s EVE include the prepayment behavior of loans and in vestments, the possible distribution of future interest rates, pricing spreads for assets and liabilities in the alter nate scenarios and the rate and balance behavior of deposit accounts with indeterminate maturities. EVE is calculated in multiple scenarios. As with the NII simulation, the base case is represented by the cu rrent yield curve. Alter nate scenarios are created by assuming immediate parallel shifts in the yield curve in increments of +/- 100 basis points (bp) up to + 300 bp. The change in EVE is measured as the change in EVE in a given rate scenario from the base case and expressed as a percentage. To gain further insight in to the IRR profile, additional analysis is periodically performed in alternate scenarios includi ng rate shifts of greater magnitude, yield curve twists and changes in key balance sheet drivers. ASB’s interest-rate risk sensitivity measures asof December 31, 2011 and 2010 constitute “forwardlooking statements” and were as follows:

December 31 2011 2010* Change in interest rates Change in NII Change in EVE Change in NII Change in EVE (basis points) Gradual change Instantaneous change Gradual change Instantaneous change +300 0.5% (7.4)% (1.3)% (16.8)% +200 (0.3) (3.8) (1.3) (10.2) +100 (0.4) (1.5) (0.8) (4.3)

Base –

– – – -100 (0.4) (3.5) (0.6) 0.7 * Results for 2010 were restated from NPV ratio sensitivity to change in EVE for comparative purposes.

Management believes that ASB’s interest rate ri sk position as of December 31, 2011 represents a reasonable level of risk. The NII profile under the rising interest rate scenarios is less liability sensitive as of December 31, 2011 compared to December 31, 2010 due to changes in the deposit mix and assumptions. In
the +300 scenario, the increase in NII is due to the effect of rate floors on certain loans in ASB’s portfolio. The

interest income benefit from the rate increases is not fu lly realized in this scenario until the rate on certain

loans exceeds their floors. ASB’s base EVE was approximately $848 million as of December 31, 2011 compared to $700 million as of December 31, 2010 due to the higher relative value of the mortgage portfolio and changes in assumptions about the behavior of core deposits. The change in EVE was less sensitive in the risi ng scenarios as of Decem ber 31, 2011 compared to
December 31, 2010 as the asset mix shifted from longer duration residential loans and investments to
shorter duration consumer and commercial loans, c hanges in core deposit assumptions and the large drop in rates during 2011, which shortened th e duration of mortgage-related assets. The computation of the prospective effects of hypot hetical interest rate changes on the NII sensitivity and the percentage change in EVE is based on numerous assu mptions, including relative levels of market interest rates, loan prepayments, balance changes and pricing strategies, and should not be relied upon as

indicative of actual results. To the extent market conditions and other factors vary from the assumptions used in the simulation analysis, actual results may differ materially from the simulation results. Furthermore, NII sensitivity analysis measures the change in ASB’s tw elve-month, pretax NII in alternate interest rate scenarios, and is intended to help m anagement identify potential exposure s in ASB’s current balance sheet and formulate appropriate strategies for managing intere st rate risk. The simulation does not contemplate any actions that ASB management might undertake in res ponse to changes in interest rates. Further, the changes in NII vary in the twelve-month simulation peri od and are not necessarily evenly distributed over the period. These analyses are for analytical purposes onl y and do not represent management’s views of future
market movements, the level of futu re earnings, or the timing of any c hanges in earnings within the twelve month analysis horizon. The actual impact of changes in interest rates on NII will depend on the magnitude and speed with which rates change, actual changes in ASB’s balance sheet, and management’s responses to the changes in interest rates.85 Other than bank interest rate risk

The Company’s general policy is to manage “other than bank” interest rate risk through use of a combination of short-term debt, long- term debt (currently fixed-rate d ebt) and preferred securities. As of December 31, 2011, management believe s the Company is exposed to “ot her than bank” interest rate risk because of its periodic borrowing requ irements, the impact of interest rates on the discount rate and the market value of plan assets used to determine retirement benefits expenses and obligations (see

“Retirement benefits” in HEI’s MD&A and Note 9 of HEI’s “Notes to Consolidated Financia l Statements”) and the possible effect of interest rates on the electric ut ilities’ allowed rates of re turn (see “Electric utility— Certain factors that may affect futu re results and financial condition—Regul ation of electric utility rates”). Other than these exposures, management believes its exposure to “other t han bank” interest rate risk is not material. The Company’s longer-term debt, in the fo rm of borrowings of proceeds of revenue bonds, registered Medium-Term Notes and privat ely-placed Senior Notes, is at fixed rates (see Note 15 of HEI’s

“Notes to Consolidated Financial Statements” for the fair value of long-term debt, net-other than bank).

HECO: The information required by this it em is set forth in HECO’s Quantit ative and Qualitative Disclosures about Market Risk, incorporated herein by refe rence to page 3 of HECO Exhibit 99.2.

ITEM 8. FINANCIAL STATEM ENTS AND SUPPLEMENTARY DATA

HEI: Index to Consolidated Financial Statements Page

Reports of Independent Registered Public Accounting Firms 86

Consolidated Financial Statements 8886 

### Report of Independent Register ed Public Accounting Firm

To the Board of Directors and Shareholders of
Hawaiian Electric Industries, Inc.:

In our opinion, the accompanying consolidated bal ance sheets as of December 31, 2011 and 2010 and the related consolidated statements of income, changes in s hareholders’ equity and cash flows for each of the two years in the period ended December 31, 2011 present fairly, in all material respects, the financial position of
Hawaiian Electric Industries, In c. and its subsidiaries (the “Com pany”) at December 31, 2011 and 2010 and the results of their operations and their cash flows for each of the two years in t he period ended December 31, 2011 in conformity with accounting principles generally acc epted in the United States of America. Also in our opinion, the Company maintained, in a ll material respects, effective inter nal control over financial reporting as
of December 31, 2011, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial stat ements, for maintaining effective inte rnal control over financial reporting

and for its assessment of the effectiveness of internal control over financial reporting, included in the Annual Report of Management on Internal Control over Fi nancial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial st atements and on the Company’s internal control over financial reporting based on our integr ated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (U nited States). Those standar ds require that we plan and perform the audits to obtain r easonable assurance about whether t he financial statements are free of

material misstatement and whether effe ctive internal control over financ ial reporting was maintained in all material respects. Our audits of the financial statements incl uded examining, on a test basis, evidence supporting the amounts and disclosures in the financial statement s, assessing the accounting principles used and significant estimates made by m anagement, and evaluating the overall fi nancial statement presentation. Our audit of internal control over financial reporting in cluded obtaining an understanding of internal control over financial reporting, assessing the ri sk that a material weakness exists , and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered ne cessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

As discussed in Note 1 to the consolidated financial statements, the Company cha nged the manner in which it

accounts for variable interest entities as of January 1, 2010.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financia l statements for external purposes in accordance with generally accepted accounting princi ples. A company’s internal control over financial reporting includes those policies and pr ocedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transac tions and dispositions of the assets of the company; (ii) provide reasonable assurance t hat transactions are recorded as necessary to permit preparation of financial statements in accordance with generally a ccepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposit ion of the company’s assets that could have a material effect on the

financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effe ctiveness to future periods ar e subject to the risk that controls may become inadequate because of changes in c onditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP Los Angeles, California February 17, 201287 

### Report of Independent Register ed Public Accounting Firm

The Board of Directors and Shareholders
Hawaiian Electric Industries, Inc.:

We have audited the consolidated statements of income, changes in shareholders’ equity, and cash flows
of Hawaiian Electric Industries, Inc. and subsidia ries for the year ended December 31, 2009. These

consolidated financial statement s are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidat ed financial statements based on our audit.

We conducted our audit in accordance with the standar ds of the Public Com pany Accounting Oversight Board (United States). Those standards require t hat we plan and perform the audit to obtain reasonable

assurance about whether the financ ial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the am ounts and disclosures in the financial statements. An audit also includes assessing the accounting principl es used and significant estimates made by management, as well as evaluating the overall fi nancial statement presentation. We believe that our audit provides a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the results of operations and cash flows of Ha waiian Electric Industries, Inc. and subsidiaries for the year ended December 31, 2009, in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP

Honolulu, Hawaii February 19, 201088 

### Consolidated Statements of Income

Hawaiian Electric Industries, Inc. and Subsidiaries

Years ended December 31 2011 2010 2009 (in thousands, except per share amounts)

Revenues Electric utility $ 2,978,690 $ 2,382,366 $ 2,035,009

Bank 264,407 282,693 274,719

Other (762) (77) (138)

3,242,335 2,664,982 2,309,590 Expenses Electric utility 2,763,556 2,203,978 1,865,338

Bank 172,806 190,105 242,955

Other 16,277 14,688 13,633

2,952,639 2,408,771 2,121,926 Operating income (loss) Electric utility 215,134 178,388 169,671

Bank 91,601 92,588 31,764

Other (17,039) (14,765) (13,771)

289,696 256,211 187,664 Interest expense – other than on deposit liabilities and other bank borrowings (82,106) (81,538) (76,330) Allowance for borrowed funds used during construction 2,498 2,558 5,268 Allowance for equity funds used during construction 5,964 6,016 12,222

Income before income taxes 216,052 183,247 128,824
Income taxes 75,932 67,822 43,923

Net income 140,120 115,425 84,901
Preferred stock dividends of subsidiaries 1,890 1,890 1,890

Net income for common stock $ 138,230 $ 113,535 $ 83,011

Basic earnings per common share $ 1.45 $ 1.22 $ 0.91

Diluted earnings per common share $ 1.44 $ 1.21 $ 0.91

Dividends per common share $ 1.24 $ 1.24 $ 1.24

Weighted-average number of common shares outstanding 95,510 93,421 91,396 Dilutive effect of share-based compensation 310 272 120

Adjusted weighted-average shares 95,820 93,693 91,516

The accompanying notes are an integral part of these consolidated financial statements.89 

### Consolidated Balance Sheets

Hawaiian Electric Industries, Inc. and Subsidiaries

December 31 2011 2010 (dollars in thousands)

ASSETS Cash and cash equivalents $ 270,265 $ 330,651
Accounts receivable and unbilled revenues, net 344,322 266,996 Available-for-sale investment and mortgage-related securities 624,331 678,152
Investment in stock of Federal Home Loan Bank of Seattle 97,764 97,764
Loans receivable held for investment, net 3,642,818 3,489,880
Loans held for sale, at lower of cost or fair value 9,601 7,849 Property, plant and equipment, net
Land $ 66,152 $ 66,002 Plant and equipment 5,177,453 5,034,211 Construction in progress 140,717 103,303

5,384,322 5,203,516 Less – accumulated depreciation (2,049,821) 3,334,501 (2,037,598) 3,165,918
Regulatory assets 669,389 478,330
Other 517,550 487,614
Goodwill 82,190 82,190

Total assets $ 9,592,731 $ 9,085,344

LIABILITIES AND SHAREHOLDERS’ EQUITY

Liabilities Accounts payable $ 216,176 $ 202,446 Interest and dividends payable 25,041 27,814 Deposit liabilities 4,070,032 3,975,372 Short-term borrowings—other than bank 68,821 24,923 Other bank borrowings 233,229 237,319 Long-term debt, net—other than bank 1,340,070 1,364,942
Deferred income taxes 354,051 278,958 Regulatory liabilities 315,466 296,797
Contributions in aid of construction 356,203 335,364 Retirement benefits liability 530,410 376,994
Other 516,990 446,485

Total liabilities 8,026,489 7,567,414

Preferred stock of subsidiaries - not subject to mandatory redemption 34,293 34,293

Commitments and contingencies (Notes 3 and 4)

Shareholders’ equity Preferred stock, no par value, authorized 10,000,000 shares;

issued: none

– – Common stock, no par value, authorized 200,000,000 shares; issued and outstanding: 96,038,328 shares and 94,690,932 shares in 2011 and 2010, respectively 1,349,446 1,314,199 Retained earnings 201,640 181,910 Accumulated other comprehensive income (loss), net of taxes Net unrealized gains on securities $ 9,886 $ 3,532 Unrealized losses on derivatives (996) (1,169) Retirement benefit plans (28,027) (19,137) (14,835) (12,472)
Total shareholders’ equity 1,531,949 1,483,637 Total liabilities and shareholders’ equity $ 9,592,731 $ 9,085,344

The accompanying notes are an integral part of these consolidated financial statements.90 Consolidated Statements of Changes in Shareholders’ Equity

Hawaiian Electric Industries , Inc. and Subsidiaries

Common stock Retained A ccumulated

other comprehensive (in thousands, except per share amounts) Shares A mount earnings income (loss) Total

Balance, December 31, 2008 90,516 1,231,629 210,840 (53,015) 1,389,454 Cumulative effect of adoption of a standard on other-than-temporary Impairment recogniti on, net of taxes of $2,497

– – 3,781 (3,781)

– Comprehensive income:

Net income for common stock

– – 83,011

– 83,011 Net unrealized gains on securities: Net unrealized gains on securities aris ing during the period, net of taxes of $8,543

– – – 12,938 12,938 Less: reclassification adjustment for net realized losses included in net income, net of tax benefits of $18,882

– – – 28,596 28,596 Retirement benefit plans: Net transition asset arising duri ng the period, net of taxes of $4,172

– – – 6,549 6,549 Prior service credit arising during the period, net of taxes of $921

– – – 1,446 1,446 Net gains arising during the period, net of taxes of $41,218

– – – 64,547 64,547 Less: amortization of transition obligatio n, prior service credit and net losses recognized during the period in net periodi c benefit cost, net of tax benefits of $6,861

– – – 10,754 10,754 Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes of $48,251

– – – (75,756) (75,756)
Other comprehensive income 49,074 Comprehensive income 132,085

Issuance of common stock: Dividend reinvestment and stock purchase plan 1,714 27,701

– – 27,701 Retirement savings and other plans 291 4,771

– – 4,771 Expenses and other, net

– 1,056

– – 1,056 Common stock dividends ($1.24 per share)

– – (113,419)

– (113,419)

Balance, December 31, 2009 92,521 1,265,157 184,213 (7,722) 1,441,648 Comprehensive income:

Net income for common stock

– – 113,535

– 113,535

Net unrealized losses on securities:

Net unrealized losses on securities arisin g during the period, net of tax benefits of $789

– – – (1,196) (1,196) Derivatives qualified as cash flow hedges: Net unrealized holding losses arising during the period, net of tax benefits of $745 (1,169) (1,169) Retirement benefit plans: Prior service credit arising duri ng the period, net of taxes of $3,001

– – – 4,712 4,712 Net losses arising during the period, net of tax benefits of $28,431

– – – (44,626) (44,626) Less: amortization of transition obligation, prior service credit and net losses recognized during the period in net per iodic benefit cost, net of tax benefits of $2,566

– – – 4,030 4,030 Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of tax benefits of $21,336

– – – 33,499 33,499 Other comprehensive loss (4,750) Comprehensive income 108,785

Issuance of common stock: Dividend reinvestment and stock purchase plan 1,685 37,296

– – 37,296 Retirement savings and other plans 485 8,934

– – 8,934 Expenses and other, net

– 2,812

– – 2,812 Common stock dividends ($1.24 per share)

– – (115,838)

– (115,838)

Balance, December 31, 2010 94,691 1,314,199 181,910 (12,472) 1,483,637 Comprehensive income:

Net income for common stock

– – 138,230

– 138,230 Net unrealized gains on securities: Net unrealized gains on securities aris ing during the period, net of taxes of $4,343

– – – 6,578 6,578 Less: reclassification adjustment fo r net realized gains included in net income,
net of taxes of $148 (224) (224) Derivatives qualified as cash flow hedges: Net unrealized holding losses arising during the period, net of tax benefits of $4

– – – (8) (8) Less: reclassification adjustment to net income , net of tax benefits of $115 181 181 Retirement benefit plans: Prior service credit arising duri ng the period, net of taxes of $4,422

– – – 6,943 6,943 Net losses arising during the period, net of tax benefits of $83,147

– – – (130,191) (130,191) Less: amortization of transition obligation, prior service credit and net losses recognized during the period in net per iodic benefit cost, net of tax benefits of $5,976

– – – 9,364 9,364 Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes of $64,134

– – – 100,692 100,692 Other comprehensive loss (6,665) Comprehensive income 131,565

Issuance of common stock: Dividend reinvestment and stock purchase plan 879 21,217

– – 21,217 Retirement savings and other plans 468 10,318

– – 10,318 Expenses and other, net 3,712

– – 3,712 Common stock dividends ($1.24 per share)

– – (118,500)

– (118,500)

Balance, December 31, 2011 96,038 $1,349,446 $ 201,640 $ (19,137) $1,531,949

As of December 31, 2011, Hawaiian Electric Industries, Inc. (HEI) had reserved a total of 16,900,246 shares of common stock for future issuance under the HEI Dividend Reinvestment and Stock Purchase Plan (DRIP), the Hawaiian Electric Industries Retirem ent Savings Plan (HEIRSP), the 1987 Stock Option and Incentive Plan, the HEI 2011 Nonemployee Director Stock Plan, the American Savings Bank, F.S.B. (ASB) 401(k) Plan and the 2010 Executive Incentive Plan.

The accompanying notes are an integral part of these consolidated financial statements.91 

### Consolidated Statemen ts of Cash Flows

Hawaiian Electric Industries, Inc. and Subsidiaries

Years ended December 31 2011 2010 2009
(in thousands)

Cash flows from operating activities

Net income $ 140,120 $ 115,425 $ 84,901

A djustments to reconcile net income to net cash provided by operating activities Depreciation of property, plant and equipment 148,152 154,523 151,282

Other amortization 19,318 4,605 5,389

Provision for loan losses 15,009 20,894 32,000 Impairment of utility plant 9,215

– – Loans receivable originated and purchased, held for sale (267,656) (360,527) (443,843)

Proceeds from sale of loans receivable, held for sale 273,932 392,406 471,194 Net losses on sale of investment and mortgage-related securities

– – 32,034 Other-than-temporary impairment on available-for-sale mortgage-related securities

– – 15,444 Changes in deferred income taxes 79,444 97,791 12,787 Changes in excess tax benefits from share-based payment arrangements 35 45 310

A llowance for equity funds used during construction (5,964) (6,016) (12,222) Change in cash overdraft (2,688) (141)

– Changes in assets and liabilities Decrease (increase) in accounts receivable and unbilled revenues, net (77,326) (25,880) 59,550 Increase in fuel oil stock (18,843) (74,044) (946) Increase (decrease) in accounts, interest and dividends payable (34,480) 22,410 (12,472) Changes in prepaid and accrued income taxes and utility revenue taxes 73,153 (5,252) (61,977) Contributions to defined benefit pension and other postretirement benefit plans (74,961) (31,792) (25,354) Changes in other assets and liabilities (26,094) 36,270 (39,491)
Net cash provided by operating activities 250,366 340,717 268,586

Cash flows from investing activities

A

vailable-for-sale investment and mortgage-related securities purchased (361,876) (714,552) (297,864) Principal repayments on available-for-sale investment and mortgage-related securities 389,906 465,437 357,233 Proceeds from sale of available-for-sale investment and mortgage-related securities 32,799

– 185,134 Net decrease (increase) in loans held for investment (181,080) 118,892 484,960 Proceeds from sale of real estate acquired in settlement of loans 8,020 5,967 1,555 Capital expenditures (235,116) (182,125) (288,879)
Contributions in aid of construction 23,534 22,555 14,170

Other (2,974) 5,092 1,199 Net cash provided by (used in) investing activities (326,787) (278,734) 457,508

Cash flows from financing activities Net increase (decrease) in deposit liabilities 94,660 (83,388) (121,415) Net increase (decrease) in short-term borrowings with original maturities

of three months or less 43,898 (17,066) 41,989 Net increase (decrease) in retail repurchase agreements 10,910 (60,308) (3,829) Proceeds from other bank borrowings

– – 310,000 Repayments of other bank borrowings (15,000)

– (689,517) Proceeds from issuance of long-term debt 125,000

– 153,186 Repayment of long-term debt (150,000)

– – Changes in excess tax benefits from share-based payment arrangements (35) (45) (310) Net proceeds from issuance of common stock 15,979 22,706 15,329 Common stock dividends (106,812) (93,034) (96,843) Preferred stock dividends of subsidiaries (1,890) (1,890) (1,890) Change in cash overdraft

– – (9,545)

Other (675) (2,229) (2,762) Net cash provided by (used in) financing activities 16,035 (235,254) (405,607)

Net increase (decrease) in cash and cash equivalents (60,386) (173,271) 320,487 Cash and cash equivalents, January 1 330,651 503,922 183,435 Cash and cash equivalents, December 31 $ 270,265 $ 330,651 $ 503,922

The accompanying notes are an integral part of these consolidated financial statements.92 

### Notes to Consolidated Financial Statements

1 • Summary of significant accounting policies

General

Hawaiian Electric Industries, Inc. (HEI) is a hol ding company with direct and indirect subsidiaries principally engaged in electric utility and banking businesses, primarily in the State of Hawaii. HEI’s common stock is traded on the New York Stock Exchange.

Basis of presentation. In preparing the consolid ated financial statem ents, management is required to make estimates and assumptions that affect the reported am ounts of assets and liabilities, the disclosure of contingent assets and liabilities and the reported amount s of revenues and expenses. Actual results could differ significantly from those estimates. Material estimates that are particularly susceptible to significant change incl ude the amounts reported for investment and mortgage-related secu rities; property, plant and equipmen t; pension and other postretirement benefit obligations; contingencies and litigation; income ta xes; regulatory assets and li abilities; electric utility
revenues; and allowance for loan losses.

Consolidation. The consolidated financial statements include t he accounts of HEI and its subsidiaries (collectively, the Company), but exclude subsidiaries which are variable interest entities (VIEs) when the Company is not the primary beneficiary. Investments in companies over which the Company has the ability to exercise significant influence, but not control, are accounted for using the equity method. All material intercompany accounts and transactions hav e been eliminated in consolidation. See Note 5 for information regarding unconsoli dated VIEs. In June 2009, the Financial Accounting Standards Board (FASB) issued a standar d that eliminated exceptions toconsolidating qualifying specialpurpose entities, contained new criter ia for determining the primary benef iciary, and increased the frequency of required reassessments to det ermine whether a company is the primar y beneficiary of a VIE. The Company adopted this standard as of January 1, 2010 and the adoption did not im pact the Company’s financial condition, results of operations or liquidi ty, but did require additional disclosures.

Cash and cash equivalents. The Company considers cash on hand, deposits in banks, deposits with the Federal Home Loan Bank (FHLB) of Seattle, federal funds sold (excess funds that ASB loans to other banks overnight at the federal funds rate), money market ac counts, certificates of depos it, short-term commercial paper of non-affiliates, reverse repurc hase agreements and liquid investments (with original maturities of three months or less) to be ca sh and cash equivalents.

Investment and mortgage-related securities. Debt securities that the Company intends to and has the ability to hold to maturity are cl assified as held-to-maturity securiti es and reported at amortized cost. Marketable equity securities and debt securities that are bought and held principally for the purpose of selling

them in the near term are classified as trading securities and reported at fair value, with unrealized gains and losses included in earnings. Marketable equity securities and debt securities not classified as either held-tomaturity or trading securities are cla ssified as available-for- sale securities and reported at fair value, with unrealized gains, temporary losses and other-than-temporary impairment (OTTI ) not related to credit losses excluded from earnings and reported on a net basis in accumulated other comprehensive income (loss) (AOCI). For securities that are not trading securities, individ ual securities are assessed for impairment at least on a quarterly basis, and more frequently when economic or market conditions warrant. An investment is impaired if the fair value of the security is less than its carrying va lue at the financial statement date. When a security is impaired, the Company determines w hether this impairment is temporar y or other-than-tem porary. If the Company does not expect to recover t he entire amortized cost basis of t he security, an OTTI exists. If the Company intends to sell the security, or will more likely than not be required to sell the security before recovery
of its amortized cost, the OTTI mu st be recognized in earnings. If the Company does not intend to sell the security and it is not more likely than not that the Com pany will be required to sell the security before recovery93 of its amortized cost, the OTTI s hall be separated into the amount repr esenting the credit loss and the amount

related to all other factors. The am ount of OTTI related to the credit lo ss is recognized in earnings while the remaining OTTI is recognized in other comprehens ive income. Once an OTTI has been recognized on a security, the Company accounts for the security as if the security had been purchased on the measurement

date of the OTTI at an am ortized cost basis equal to the previous amortized cost basis less the OTTI recognized in earnings. The difference between the new am ortized cost basis and the cash flows expected to be collected is accreted in accordance with existing applic able guidance as interest income. Any discount or reduced premium recorded for the security will be amorti zed over the remaining life of the security in a prospective manner based on the amount and timing of future estimated cash flows. If upon subsequent evaluation, there is a significant increase in cash flow s expected to be collected or if actual cash flows are significantly greater than cash flows previously expected, such changes shall be accounted for as a prospective adjustment to the accretable yield. The specific identification met hod is used in determining realized gains and losses on the sales of securities. Discounts and premiums on investment securi ties are accreted or amortized over the remaining lives of the securities, adjusted for actual portfolio prepayments, using the in terest method. Discounts and premiums on mortgage-related securities are accreted or amortiz ed over the remaining li ves of the securities, adjusted based on changes in anticipated pr epayments, using the interest method.

Equity method. Investments in up to 50%-owned affiliates over which the Company has the ability to exercise significant influence over the operating and financing policie s and investments in unconsolidated subsidiaries (e.g. HECO Capital Trust III) are account ed for under the equity method, whereby the investment is carried at cost, plus (or minus) the Company’s equity in undistributed earnings (or losses) and minus distributions since acquisition. Equity in earnings or losses is reflected in operating revenues. Equity method

investments are evaluated for other-t han-temporary impairment. Also see “V ariable interest entities” below.

Property, plant and equipment. Property, plant and equipment are report ed at cost. Self-constructed electric utility plant includes engineering, s upervision, administrative and general co sts and an allowance for the cost of funds used during the construction period. These co sts are recorded in constr uction in progress and are transferred to property, plant and equipment when construction is completed and the facilities are either placed in service or become useful for public utility purposes . Costs for betterments that make property, plant or equipment more useful, more efficient, of greater durability or of greater c apacity are also capitalized. Upon the retirement or sale of electric utility plant, generally no gain or loss is recogniz ed. The cost of the plant retired is charged to accumulated depreciation. Amounts collected fr om customers for cost of removal (expected to exceed salvage value in the future) are included in regulatory liabilities.

Depreciation. Depreciation is computed primar ily using the straight-line met hod over the estimated lives of the assets being depreciated. Electric utility plant addi tions in the current year are depreciat ed beginning January 1 of the following year in accordance with rate -making. Electric utility plant has lives ranging from 20 to 88 years for production plant, from 25 to 65 years for transmission and distribution plant and from 5 to 50 years for general plant. The electric utilities’ com posite annual depreciation rate, which includes a component
for cost of removal, was 3.2% in 2011, 3.5% in 2010 and 3.8% in 2009.

Leases. HEI, Hawaiian Electric Company, Inc. (HECO) and its subsidiaries and ASB have entered into lease agreements for the use of equipment an d office space. The provisions of some of the lease agreements contain renewal options. Operating lease expense was $14 million, $13 million and $16 million in 2011, 2010 and 2009, respectively. Future minimum lease payments are $23 million, $18 million, $15 million, $12 million and $10 million for 2012, 2013, 2014, 2015, 2016 and thereafter, respectively.

Retirement benefits. Pension and other postretirement benefit costs are charged primarily to expense and electric utility plant. Funding for the Company’s qualified pension plans (Plans) is based on actuarial assumptions adopted by the Pension Investment Comm ittee administering the Plans on the advice of an enrolled actuary. The participating em ployers contribute amounts to a mast er pension trust for the Plans in accordance with the funding requirements of the Empl oyee Retirement Income Security Act of 1974, as94 amended (ERISA), including changes promulgated by the P ension Protection Act of 2006, and considering the deductibility of contributions under the Internal Revenue Code. The Company generally funds at least the net periodic pension cost during the year, subject to limits and targeted funded status as determined with the consulting actuary. Under a pension tracking mechani sm approved by the Public Utilities Commission of the State of Hawaii (PUC), HECO generally will make contributions to the pension fund at the greater of the minimum level required under the law or net periodic pension cost less pension asset, until its pension asset (existing at the time of the PUC decision and determined based on the cumulative fund contributions in excess of the cumulative net periodic pension cost recognized) is reduced to zero, at which time HECO would fund the pension cost as specified in the pension tracking me chanism. Hawaii Electric Light Company, Inc. (HELCO) and Maui Electric Company, Limited (MECO) will genera lly fund the greater of the minimum level required under the law or net periodic pension cost. Future dec isions in rate cases could further impact funding

amounts.
Certain health care and/or life in surance benefits are provided to elig ible retired employees and the employees’ beneficiaries and covered dependents. T he Company generally funds the net periodic postretirement benefit costs other than pensions and the amortization of the regulatory asset for postretirement benefits other than pensions (OPEB), while maximizing t he use of the most tax advantaged funding vehicles, subject to cash flow requirements and reviews of the funded status with the consulting actuary. The electric utilities must fund OPEB costs as specified in the OPEB tracking mechanisms, which were approved by the

PUC. Future decisions in rate case s could further impact funding amounts. The Company recognizes on its balance sheet the fu nded status of its defi ned benefit pension and other postretirement benefit plans, as adjusted by the impact of decisions of the PUC.

Environmental expenditures. The Company is subject to numerous federal and state envir onmental statutes and regulations. In general, environmental contamination treatment costs are charged to expense, unless it is probable that the PUC would allow such costs to be recover ed in future rates, in which case such costs would be capitalized as regulatory assets. Also, environmental costs are capita lized if the costs extend the life, increase the capacity, or improve the safety or effici ency of property; the costs mi tigate or prevent future
environmental contamination; or the costs are incurred in preparing t he property for sale. Environmental costs are either capitalized or charged to expense when env ironmental assessments and/or remedial efforts are probable and the cost can be reasonably estimated.

Financing costs. Financing costs related to the registration and sale of HEI common stock are recorded in shareholders’ equity. HEI uses the straight-line method to amortize t he long-term debt financing costs of the holding company

over the term of the related debt. HECO and its subsidiaries use the straight-line method to amortize long-term debt financing costs and premiums or discounts over the te rm of the related debt. Unamortiz ed financing costs and premiums or

discounts on HECO and its subsidiaries’ long-term debt retired prior to matu rity are classified as regulatory assets (costs and premiums) or liabilities (discounts) and are amortized on a stra ight-line basis over the remaining original term of the re tired debt. The method and periods for am ortizing financing costs, premiums and discounts, including the treatment of these items w hen long-term debt is retire d prior to maturity, have been established by the PUC as part of the rate-making process. HEI and HECO and its subsidiaries use the straight- line method to amortize the fees and related costs paid to secure a firm commitment under their line-of-c redit arrangements.

Income taxes. Deferred income tax assets and liabilities are established for the temporary differences between the financial reporting bases and the tax bases of the Company’s a ssets and liabilities at federal and state tax rates expected to be in effect when such deferred tax assets or liab ilities are realized or settled. The

ultimate realization of deferred ta x assets is dependent upon t he generation of future taxable income during the periods in which those tempor ary differences become deductible. Generally, federal and state investm ent tax credits are defer red and amortized over the estimated useful lives of the properties which qualified for the credits.95 Governmental tax authorities could challenge a tax return position taken by management. If the Company’s position does not prevail, the Company’s results of operations and financial condition may be adversely affected as the related def erred or current income tax asset might be impaired and written down or an unanticipated tax liability might be incurred. The Company uses a “more-likely-than-not” rec ognition threshold and measurement standard for the financial statement recognition and meas urement of a tax position taken or expected to be taken in a tax
return. As of December 31, 2011, the valuation allowance for defe rred tax benefits is not significant.

Earnings per share. Basic earnings per share (EPS) is comput ed by dividing net income for common stock by the weighted-average number of common shares outstanding for the period. Diluted EPS is computed similarly, except that common shares for dilutive stock compensation are added to the denominator. The Company uses the two-class method of computing EPS as restricted stock grants incl ude non-forfeitable rights to dividends and are participating securities. Under the two-class method, EPS was comprised as follows for both unvested restricted stock awards and

unrestricted common stock:

2011 2010 2009

Basic Diluted Basic Diluted Basic and

diluted

Distributed earnings $ 1.24 $ 1.24 $ 1.24 $ 1.24 $ 1.24 Undistributed earnings (loss) 0.21 0.20 (0.02) (0.03) (0.33)

$ 1.45 $ 1.44 $ 1.22 $ 1.21 $ 0.91

As of December 31, 2010, the antid ilutive effect of stock appreciation rights (SARs) on 450,000 shares of common stock (for which the SARs’ exercise prices we re greater than the closing market price of HEI’s common stock) was not included in t he computation of diluted EPS.

Share-based compensation. The Company applies the fair value based method of accounting to account for its stock compensation, including the use of a forfeiture assump tion. See Note 10.

Impairment of long-lived assets and l ong-lived assets to be disposed of. The Company reviews longlived assets and certain identifiable intangibles for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Reco verability of assets to be held and used is measured by a comparison of the carrying amount of an asset to future net cash flows expected to be generated by the asset. If such assets are considered to be impaired, the impairm ent to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets. Assets to be disposed of are reported at the lower of the carrying amount or fair va lue, less costs to sell.

Recent accounting pronouncements and interpretations.

Repurchase agreements . In April 2011, the FASB issued A ccounting Standards Update (ASU) No. 2011- 03, “Transfers and Servicing (Topic 860): Reconsiderati on of Effective Control fo r Repurchase Agreements,” which is intended to improve the financial reporti ng of repurchase agreement s and other agreements that entitle and obligate a transferor to repurchase or redeem financial assets before their maturity. This ASU

removes from the assessment of effective control the cr iterion requiring the transferor to have the ability to repurchase or redeem the financial a ssets. ASB will apply this guidance prospectively to transactions or modifications of existing transactions that occur on or after January 1, 2012 and does not expect it to have a material impact on the Company’s results of operations, financial condition or liquidity.

Fair value measurements . In May 2011, the FASB issued ASU No. 2011-04, “Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. generally accepted accounting principles (GAAP) and IF RSs,” which represents th e converged guidance of the FASB and the International Accounting Standards Board (the Boards) on fair value measurement. This ASU includes the Boards’ common requirem ents for measuring fair value and fo r disclosing information about fair value measurements, including a consistent meaning of t he term “fair value.” The Boards have concluded the common requirements will result in gr eater comparability of fair valu e measurements presented and disclosed96 in financial statements prepared in accordance with U.S. GAAP and International Financial Reporting

Standards. The Company will prospectively adopt this standard in the first quarter of 2012 and does not expect it to have a material impact on the Company’s results of operations, financial co ndition or liquidity.

Comprehensive income . In June 2011, the FASB issued ASU No. 2011-05, “Comprehensive Income (Topic 220): Presentation of Comprehensive Income,” and in December 2011, the FASB issued ASU No.
2011-12, which amended ASU No. 2011-05. ASU No. 2011-05, as amended, eliminates the option to present components of other comprehensive income as part of the statement of changes in shareholders’ equity. All items of net income and other comprehensive income are required to be present ed in either a single continuous statement of comprehensive income or in two separate, but consec utive, statements—a net

income statement and a total co mprehensive income statement. The Company expects to retrospectively adopt thisstandard during the first quarter of 2012 using a twostatement approach.

Reclassifications. Certain reclassifications have been made to pr ior years’ financial statements to conform to the 2011 presentation, which did not affect previously reported results of operations.

Electric utility

Accounts receivable. Accounts receivable are recorded at t he invoiced amount. The electric utilities generally assess a late payment charge on balances unpai d from the previous month. The allowance for doubtful accounts is the Company’s best estimate of the amount of probable credit losses in the Company’s existing accounts receivable. On a monthly basis, the Company adjusts its allowance, with a corresponding charge (credit) on the statement of in come, based on its historical write-o ff experience. Account balances are charged off against the allowance after collection effo rts have been exhausted and the potential for recovery is

considered remote.

Contributions in aid of construction. The electric utilities receive cont ributions from customers for special construction requirements. As directed by the PUC, cont ributions are amortized on a straight-line basis over 30 to 51 years as an offset against depreciation expense.

Electric utility revenues. Electric utility revenues are based on rates authorized by the PUC and include revenues applicable to energy consumed in the account ing period but not yet billed to the customers. Revenues related to the sale of energy are generally re corded when service is rendered or energy is delivered

to customers.

The rate schedules of the electric utilities include energy cost adjustment clauses (ECACs) under which electric rates are adjusted for changes in the we ighted-average price paid for fuel oil and certain components of purchased power, and the relative amounts of company-generat ed power and purchased power. The rate schedules of HECO include a purc hased power adjustment clause (PPAC) under which HECO recovers purchase power expenses through a surcharge mechanism. The amounts collected through the ECACs and PPAC are required to be reconciled quarterly. HECO and its subsidiaries’ operating revenues include amounts for various Hawa ii state revenue taxes. Revenue taxes are generally recorded as an expense in the year the related revenues are recognized. However, HECO and its subsidiaries’ revenue tax paym ents to the taxing authorit ies are based on the prior years’ revenues. For 2011, 2010 and 200 9, HECO and its subsidiaries in cluded approximat ely $264 million,
$211 million and $181 mill ion, respectively, of revenue taxes in “operating revenues” and in “taxes, other than income taxes” expense.

Power purchase agreements. If a power purchase agr eement (PPA) falls within the scope of Accounting Standards Codification (ASC) Topic 840, “Leases,” and resu lts in the classification of the agreement as a capital lease, the electric utility would recognize a ca pital asset and a lease obligat ion. Currently, none of the PPAs are required to be recorded as a capital lease.

The utilities evaluate PPAs to determine if the PPAs ar e VIEs, if the utilities are primary beneficiaries and if consolidation is required. See Note 5.97 Repairs and maintenance costs. Repairs and maintenance costs for overhauls of generating units are generally expensed as they are incurred.

Allowance for funds used during construction (AFUDC). AFUDC is an accounting practice whereby the costs of debt and equity funds used to finance plant cons truction are credited on the statement of income and charged to construction in progress on the balance shee t. If a project under construction is delayed for an extended period of time, AFUDC on the delayed project may be stopped after assessing the causes of the delay and probability of recovery. The weighted-average AFUDC rate was 8.0% in 2011 and 8.1% in 2010 and 2009, and reflected quarterly compounding.

Bank

Loans receivable . ASB states loans receivable at amortized cost less the allowance for loan losses, loan origination fees (net of direct loan origination costs), commitment f ees and purchase premiums and discounts.

Interest on loans is credited to income as it is earned. Discounts and premiums are accreted or amortized over the life of the loans using the interest method. Loan origination fees (net of dire ct loan origination costs) are def erred and recognized as an adjustment in yield over the life of the loan using the interest me thod or taken into income when the loan is paid off or sold. Nonrefundable commitment fees (n et of direct loan origination co sts, if applicable) received for commitments to originate or purchase loans are deferred and, if the commitm ent is exercised, recognized as an adjustment of yield over the lif e of the loan using the interest method. Nonrefundable commitment fees received for which the commitment expires unexercise d are recognized as income upon expiration of the

commitment.

Loans held for sale, gain on sale of loans, and mortgage servicing assets and liabilities. Mortgage and

educational loans held for sale are stated at the lower of cost or estimated fair value on an aggregate basis. Generally, the determination of fair va lue is based on the fair value of t he loans. A sale is recognized only

when the consideration received is other than beneficial interests in the assets sold and control over the assets is transferred irrevocably to the buyer . Gains or losses on sales of loans are recognized at the time of sale and are determined by the difference between the net sales proceeds and the a llocated basis of the loans sold. ASB capitalizes mortgage servicing assets or liabilitie s when the related loans are sold with servicing rights retained. Accounting for the servicing of financia l assets requires that mo rtgage servicing assets or liabilities resulting from the sale or securitization of loans be initially m easured at fair value at the date of transfer, and permits a class-by-class election between fair value and the lo wer of amortized cost or fair value for subsequent measurements of mortgage servicing asset classes. Mortgage servicing assets or liabilities are included as a component of gain on sa le of loans. Under ASC Topic 860, “Transfers and Servicing,” ASB elected to continue to amortize all mortgage servicing assets in proportion to and over the period of estimated net servicing income and assess se rvicing assets for impairment based on fair value at each reporting date. Such amortization is reflect ed as a component of rev enues on the consolidated statements of income. The fair value of mortgage se rvicing assets, for the purposes of impairment, is calculated by discounting expected net income streams us ing discount rates that re flect industry pricing for similar assets. Expected net income streams ar e estimated based on industry assumptions regarding prepayment speeds and income and expenses associated with servicing residential mortgage loans for others. ASB measures impairment of mortgage servicing assets on a disaggregated basis based on certain risk characteristics including loan type and note rate. Impairment losses are recognized through a valuation allowance for each impaired stratum, with any a ssociated provision recorded as a component of loan servicing fees included in ASB’s noninterest income.

Allowance for loan losses. ASB maintains an allowance for loan losses that it believes is adequate to absorb losses inherent in its loan portfolio. The level of allowance for loan losses is based on a continuing assessment of existing risks in the loan portfolio, histor ical loss experience, changes in collateral values and current conditions (e.g., economic conditions, real esta te market conditions and interest rate environment). Adverse changes in any of these factors could result in higher charge-offs and provision for loan losses.98 Commercial and commercial real estate loans are defined as non-homogeneous loans and ASB utilizes a ten-point risk rating system for eval uating the credit quality of the l oans. Loans are rated based on the degree of risk at origination and periodically thereafter, as appropriate. ASB’s credit review department performs an evaluation of these loan portfolios to ensure compliance with the internal risk rating system and timeliness of rating changes. Non-homogeneous loans ar e categorized into the regulatory asset quality classifications – Pass (Risk Rating 1 to 6), Special Mention (Risk Rati ng 7), Substandard (Risk Rating 8), Doubtful (Risk Rating 9), and Loss (Risk Rating 10) based on credit quality. The allowance for loan loss allocations for these loans are based on internal migration analyses with actual ne t losses. For loans classified as substandard, an analysis is done to determine if the loan is impaired. A loan is deemed impaired when it is probable that ASB will be unable to collect all amounts due according to t he contractual terms of the loan agreement. Once a loan is deemed impaired, ASB applies a valuation methodol ogy to determine whether there is an impairment shortfall. The measurement of impairm ent may be based on (i) the present value of the expected future cash flows of the impaired loan discounted at the loan’s original effective interest rate, (ii) the observable market price of the impaired loan, or (iii) the fair value of the co llateral, net of costs to sell. For all loans collateralized by real estate whose repayment is dependent on the sa le of the underlying collateral property, ASB measures impairment by utilizing the fair value of the collateral, net of costs to sell; for other loans, discounted cash flows are used to measure impairment. For loans collateralized by real estate that are classified as troubled debt restructured loans, the present value of the expected fu ture cash flows of the loans may also be used to measure impairment as these loans are expected to perfo rm according to their res tructured terms. Impairment shortfalls are charged to the provision for loan losses and included in the allowance for loan losses. However, impairment shortfalls that are deemed to be confirmed losses are char ged off, with the loan written down by

the amount of the confirmed loss.
Residential, consumer and credit scored busine ss loans are considered homogeneous loans, which are typically underwritten based on common, uniform standards, and are generally cl assified as to the level of loss exposure based on delinquency status. The homogeneous loan portfolios are stratified into individual products

with common risk characteristics and the allowance fo r loan loss allocations for these loan types uses historical loss ratio analyses based on actual net char ge-offs. For residential loans, the loan portfolio is segmented by loan categories and geographic location with in the State of Hawaii. The consumer loan portfolio is segmented into various secured and unsecured lo an product types. The credit scored business loan portfolio is segmented by loans under li nes of credit or term loans, and cor porate credit cards. The look-back period of actual loss experience is reviewed annually and may vary depending on the credit environment. In addition to actual loss experience, ASB consider s the following qualitative factors for all loans in estimating the allowance for loan losses:

 Changes in lending policies and procedures

 Changes in economic and business conditions and devel opments that affect the collectability of the portfolio

 Changes in the nature, volume and terms of the loan portfolio

 Changes in lending management and other relevant staff

 Changes in loan quality (past due, non-accrual, classified loans)

 Changes in the quality of the loan review system

 Changes in the value of underlying collateral

 Effect and changes in the level of any concentrations of credit

 Effect of other external and internal factors For all loan segments, ASB generally ceases the accrual of interest on loans when they become contractually 90 days past due or when there is reasonable doubt as to collectability. Subsequent recognition of interest income for such loans is generally on the cash method. When, in management’s judgment, the borrower’s ability to make principal and interest payments has resumed and collectability is reasonably assured, a loan not accruing interest (nonaccrual loan) is returned to accrual status . ASB uses either the cash or cost-recovery method to record cash receipts on im paired loans that are not accruing interest. While the majority of consumer loans are subject to ASB’s policies regarding nonaccrual loans, all past due unsecured99 consumer loans may be charged off upon reaching a pr edetermined delinquency status varying from 120 to 180 days. Management believes its allowance for loan losses adequately estimates actual loan losses that will ultimately be incurred. However, such estimates are based on currently available information and historical experience, and future adjustments ma y be required from time to time to the allowance for loan losses based on new information and changes that occur (e.g., due to changes in economic conditions, particularly in Hawaii). Actual losses could diffe r from management’s estimates, a nd these differences and subsequent adjustments could be material.

Loans modified in a troubled debt restructuring. Loans are considered to have been modified in a troubled debt restructuring (TDR) when, due to a borrower’s financia l difficulties, ASB makes certain concessions to the

borrower that it would not otherwise consider. Modifications may include in terest rate reductions, forbearance,

and other actions intended to minimize economic loss and to provide alternatives to foreclosure or repossession of collateral. Generally, a nonaccrual l oan that has been modified in a TDR remains on

nonaccrual status until the borrower has demonstrated su stained repayment performance for a period of six consecutive months. However, performance prior to the m odification, or significant events that coincide with
the modification, are included in a ssessing whether the borrower can meet the new terms and may result in the loan being returned to accrual stat us at the time of loan modification or after a shorter performance period. If the borrower’s ability to meet the revised payment schedule is uncertain, or t here is reasonable doubt over the full collectability of principal and inte rest, the loan remains on nonaccrual status.

Real estate acquired in settlement of loans. ASB records real estate acquir ed in settlement of loans at the
lower of cost or fair value, less estimated se lling expenses. ASB obtains appraisals based on recent comparable sales to assist management in estimating the fa ir value of real estate acquired in settlement of loans. Subsequent declines in value are charged to expens e through a valuation allow ance. Costs related to holding real estate are charged to operations as incurred. As of December 31, 2011 and 2010, ASB had $7.3 million and $4.3 million, respec tively, of real estate acqui red in settlement of loans.

Goodwill and other intangibles. Goodwill is tested for impairment at least annually. Intangible assets with definite useful lives are amortized over their respecti ve estimated useful lives to their estimated residual values, and reviewed for impairment in accor dance with ASC 350, “Intangibles—Goodwill and other” (ASC 350).

Goodwill. At December 2011 and 2010, the amount of goodwill was $82.2 milli on, which is the Company’s only intangible asset with an indefin ite useful life and is tested for impai rment annually in the fourth quarter using data as of September 30. In December 2008, ASB recorded a write-off of $0. 9 million of goodwill related

to the sale of the business of Bishop Insurance Agency. In September 2011, ASB adopted FASB ASU 2011-8, “ Intangibles-Goodwill and Other (Topic 350): Testing Goodwill for Impairment” (ASU 2011-8), which permits an entity to first assess qualitative factors (Step 0) to determine whether it is more likely than not (that is, a likeli hood of more than 50%) that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform Step 1 of a two-st ep goodwill impairment test. An entity has an unconditional option to bypass the qualitative assessment and proceed directly to performing the first step of the goodw ill impairment test. In evaluating whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount under ASU 2011-8, an entity shall assess re levant events and circumstances such as:

1. Macroeconomic conditions such as a deterioration in general economic condi tions, limitations on accessing capital, or other developm ents in equity and credit markets;

2. Industry and market considerations such as a det erioration in the environment in which an entity operates, an increased competitive environment, a change in the market for an entity’s products or services, or a regulatory or political development;

3. Cost factors that have a negative effe ct on earnings and cash flows;

4. Overall financial performance such as a decline in actual or planned revenues or earnings compared with actual and projected resu lts of relevant prior periods;100 5. Other relevant entity-specific events such as changes in management, key personnel, strategy, or customers; contemplation of bankruptcy; or litigation;

6. Events affecting a reporting unit such as a change in the composition or ca rrying amount of its net

assets;

7. If applicable, a sustained decrease in share price (c onsider in both absolute terms and relative to peers).

If, after assessing the totality of events or circumstances , an entity determines that it is not more likely than

not that the fair value of a reporting unit is less than its carrying am ount, then the first and second steps of the goodwill impairment test under ASC 350 are unnecessary. ASB performed a Step 0 analysis and determined that it was not more likely than not t hat the fair value of ASB was less than its carrying value. The most recent Step 1 goodwill impairment analysis under ASC 350 wa s performed as of September 30, 2010 and the

estimated fair value of ASB exceeded its book value by 35%. For the three year s ended December 31, 2011, there has been no impairment of goodwill.

Amortized intangible assets.

December 31 2011 2010

Gross carrying Accumulated Valuation Net carrying Gross carrying Accumulated Valuation Net carrying (in thousands) amount amortization allowance amount amount amortization allowance amount Mortgage servicing assets $21,171 (12,769) (175) $8,227 $18,483 (11,656) (128) $6,699

Changes in the valuation allowance for mortgage servicing assets were as follows:

(in thousands) 2011 2010 2009

Valuation allowance, January 1 $128 $201 $268 Provision (recovery) 121 (12) 166 Other-than-temporary impairment (74) (61) (233)

Valuation allowance, December 31 $175 $128 $201

The estimated aggregate amortization expenses fo r mortgage servicing assets for 2012, 2013, 2014, 2015 and 2016 are $1.3 million, $1.1 m illion, $0.9 million, $0.8 million and $0.7 million, respectively. ASB capitalizes mortgage servicing assets acquired through either the purchas e or origination of mortgage loans for sale or the securitization of mortgage loans with servicing rights retained. Changes in mortgage interest rates impact the value of ASB’s mortgage servicing assets. Rising interest rates typically result in slower prepayment speeds in the loans bei ng serviced for others which increases the value of mortgage servicing assets, whereas declining interest ra tes typically result in faster prepayment speeds which decrease the value of mortgage servicing a ssets and increase the amortization of the mortgage servicing assets. In 2011, 2010 and 2009, mortgage se rvicing assets acquired through the sale or securitization of loans held for sale were $2.8 million, $3.3 million and $3.3 million, respectively. Amortization expenses for ASB’s mortgage servicing assets amount ed to $1.1 million, $0.9 million and $0.8 million for 2011, 2010 and 2009, respectively, and are recorded as a reduction in revenues on the consolidated

statements of income.101 2 • Segment financial information

The electric utility and bank segments are strategic bus iness units of the Company that offer different products and services and operate in different regulat ory environments. The acc ounting policies of the segments are the same as those descr ibed in the summary of significant accounting policies, except that federal and state income taxes for each segment are calculated on a “stand-alone” basis. HEI evaluates segment performance based on net income. The Company accounts for intersegment sales and transfers as if the sales and transfers were to third parties, that is, at current market pr ices. Intersegment revenues consist primarily of interest, rent and preferred stock dividends.

Electric utility

HECO and its wholly-owned operating subsidiaries, HE LCO and MECO, are public electric utilities in the business of generating, purchasing, transmitting, distri buting and selling electric energy on all major islands in Hawaii other than Kauai, and are regulated by the PUC. HECO also owns the following non-regulated subsidiaries: Renewable Hawaii, Inc. (RHI), which was formed to invest in renewable energy projects; HECO Capital Trust III, which is a financing entity; and Uluwehiokama Biofuels Corp. (UBC), which was

formed to own a new biodiesel refi ning plant to be built on the island of Maui, which project has been

terminated.

Bank

ASB is a federally chartered savings bank providing a full range of banking services to individual and business customers through its branch system in Hawa ii. ASB is subject to examination and comprehensive regulation by the Office of the Comptroller of the Currency (OCC) (p reviously by the Department of Treasury, Office of Thrift Supervision (OTS)) and the Federal Deposit Insurance Corporation (FDIC), and is subject to reserve requirements established by the B oard of Governors of the Federal Reserve System.

Other

“Other” includes amounts for the holding companies (HEI and American Savings Holdings, Inc.), other subsidiaries not qualifying as reportable segments and intercompany eliminations.102 Segment financial information was as follows:

(in thousands) Electric utility Bank Other Total

2011 Revenues from external customers $2,978,547 $ 264,407 $ (619) $3,242,335 Intersegment revenues (eliminations) 143 – (143) – Revenues 2,978,690 264,407 (762) 3,242,335

Depreciation and amortization 160,353 5,909 1,208 167,470

Interest expense 60,031 14,469 22,075 96,575
Income (loss) before income taxes 163,565 91,536 (39,049) 216,052 Income taxes (benefit) 61,584 31,693 (17,345) 75,932 Net income (loss) 101,981 59,843 (21,704) 140,120 Preferred stock dividends of subsidiaries 1,995 – (105) 1,890 Net income (loss) for common stock 99,986 59,843 (21,599) 138,230

Capital expenditures 226,022 8,984 110 235,116 Tangible assets (at December 31, 2011) 4,671,942 4,819,557 10,815 9,502,314

2010 Revenues from external customers $2,382,211 $ 282,693 $ 78 $2,664,982 Intersegment revenues (eliminations) 155 – (155) – Revenues 2,382,366 282,693 (77) 2,664,982

Depreciation and amortization 157,432 749 947 159,128

Interest expense 61,510 20,349 20,028 101,887
Income (loss) before income taxes 125,452 92,512 (34,717) 183,247 Income taxes (benefit) 46,868 34,056 (13,102) 67,822 Net income (loss) 78,584 58,456 (21,615) 115,425 Preferred stock dividends of subsidiaries 1,995 – (105) 1,890 Net income (loss) for common stock 76,589 58,456 (21,510) 113,535

Capital expenditures 174,344 7,709 72 182,125 Tangible assets (at December 31, 2010) 4,285,680 4,707,870 2,905 8,996,455

2009 Revenues from external customers $2,034,834 $ 274,719 $ 37 $2,309,590 Intersegment revenues (eliminations) 175 – (175) – Revenues 2,035,009 274,719 (138) 2,309,590

Depreciation and amortization 154,578 1,309 784 156,671
Interest expense 57,944 43,543 18,386 119,873 Income (loss) before income taxes 129,217 31,705 (32,098) 128,824 Income taxes (benefit) 47,776 9,938 (13,791) 43,923 Net income (loss) 81,441 21,767 (18,307) 84,901 Preferred stock dividends of subsidiaries 1,995 – (105) 1,890 Net income (loss) for common stock 79,446 21,767 (18,202) 83,011

Capital expenditures 286,445 2,188 246 288,879 Tangible assets (at December 31, 2009) 3,978,392 4,854,595 5,625 8,838,612

Intercompany electricity sales of the electric utilit ies to the bank and “other” segments are not eliminated because those segments would need to purchase electricity from another source if it were not provided by consolidated HECO, the profit on su ch sales is nominal and the elimination of electric sales revenues and expenses could distort segment operating in come and net income for common stock. Bank fees that ASB charges the electric utility and “other” segment s are not eliminated because those segments would pay fees to another financia l institution if they were to bank with another institution, the profit

on such fees is nominal and the e limination of bank fee income and expens es could distort segment operating

income and net income for common stock.103 3 • Electric utility subsidiary

Selected financial information Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statements of Income Data

Years ended December 31 2011 2010 2009 (in thousands)

Revenues Operating revenues $2,973,764 $2,367,441 $2,026,672 Other – nonregulated 4,926 14,925 8,337

Total revenues 2,978,690 2,382,366 2,035,009 Expenses
Fuel oil 1,265,126 900,408 671,970 Purchased power 689,652 548,800 499,804 Other operation 257,065 251,027 248,515
Maintenance 121,219 127,487 107,531 Depreciation 142,975 149,708 144,533
Taxes, other than income taxes 276,504 222,117 191,699 Other – nonregulated 11,015 4,431 1,286 Total expenses 2,763,556 2,203,978 1,865,338 Operating income from regulated and nonregulated activities 215,134 178,388 169,671 Allowance for equity funds used during construction 5,964 6,016 12,222 Interest expense and other charges (60,031) (61,510) (57,944) Allowance for borrowed funds used during construction 2,498 2,558 5,268

Income before income taxes 163,565 125,452 129,217
Income taxes 61,584 46,868 47,776

Net income 101,981 78,584 81,441

Preferred stock dividends of subsidiaries 915 915 915

Net income attributable to HECO 101,066 77,669 80,526
Preferred stock dividends of HECO 1,080 1,080 1,080

Net income for common stock $ 99,986 $ 76,589 $ 79,446104 Consolidated Balance Sheet Data

December 31 2011 2010 (in thousands, except share data)

Assets Utility plant, at cost Property, plant and equipment $ 5,103,541 $ 4,948,338 Less accumulated depreciation (1,966,894) (1,941,059) Construction in progress 138,838 101,562 Net utility plant 3,275,485 3,108,841 Regulatory assets 669,389 478,330
Other 727,068 698,509
Total assets $ 4,671,942 $ 4,285,680

Capitalization and liabilities Common stock ($6 2/3 par value, authorized 50,000,000 shares, outstanding 14,233,723 shares and 13,830,823 shares in 2011 and 2010, respectively) $ 94,911 $ 92,224
Premium on common stock 426,921 389,609 Retained earnings 884,284 854,856 Accumulated other comprehensive income (loss), net of income taxes (32) 709 Common stock equity 1,406,084 1,337,398 Cumulative preferred stock – not subject to mandatory redemption (authorized 5,000,000 shares, $20 par value (1,114,657 shares outstanding), and 7,000,000 shares, $100 par value (120,000 shares outstanding); dividend rates of 4.25-7.625%) 34,293 34,293 Commitments and contingencies (see below) Long-term debt, net 1,000,570 1,057,942 Total capitalization 2,440,947 2,429,633 Current portion of long-term debt 57,500 –
Deferred income taxes 337,863 269,286 Regulatory liabilities 315,466 296,797
Contributions in aid of construction 356,203 335,364
Other 1,163,963 954,600 Total capitalization and liabilities $ 4,671,942 $ 4,285,680

Regulatory assets and liabilities. In accordance with ASC Topic 9 80, “Regulated Operations,” HECO and
its subsidiaries’ financial statements reflect assets, li abilities, revenues and expenses based on current costbased rate-making regulations. Their continued accounti ng under ASC Topic 980 generally requires that rates are established by an independent, third- party regulator; rates are designed to recover the costs of providing
service; and it is reasonable to assume that rate s can be charged to and coll ected from customers. Management believes HECO and its subsidiaries’ operations currently satisfy the ASC Topic 980 criteria. If events or circumstances should change so that those criteria are no longer sati sfied, the electric utilities expect that the regulatory assets would be charged to expense and the regulator y liabilities would be credited to income or refunded to ratepayers immediately. In the event of unforeseen regul atory actions or other circumstances, management believes that a material adv erse effect on the Company’s financial condition, results of operations and/or liquidity may result if regulatory assets have to be charged to expense or if regulatory liabilities are required to be refunded to ratepayers immediately. Regulatory assets represent deferred costs expected to be fully recovered through rates over PUCauthorized periods. Generally, HECO an d its subsidiaries do not earn a return on their regulatory assets; however, they have been allowed to recover interest on certain regulatory assets and to include certain regulatory assets in rate base. Regulatory liabiliti es represent amounts included in rates and collected from ratepayers for costs expected to be incurred in the futu re. For example, the regulatory liability for cost of removal in excess of salvage value represents amounts that have been collected from ratepayers for costs that are expected to be incurred in the future to retire utility plant. Generally, HECO and its subsidiaries include regulatory liabilities in rate base or are requi red to apply interest to ce rtain regulatory liabilities. Noted in parentheses are the original PUC authorized amortization or recovery periods and the remaining amortization or recovery periods as of December 31, 2011, if different.105 Regulatory assets were as follows:

December 31 2011 2010 (in thousands)

Retirement benefit plans (balance primarily va ries with plans’ funded statuses) $523,640 $356,591 Income taxes, net (1 to 48 years) 83,386 82,615 Decoupling revenue balancing account (1 year) 20,780 – Unamortized expense and premiums on retired debt and equity issuances (14 to 30 years; 1 to 17 years remaining) 12,267 13,589 Vacation earned, but not yet taken (1 year) 8,161 7,349 Postretirement benefits other than pensions (18 years; 1 year remaining) 1,861 3,579 Other (1 to 50 years; 1 to 48 years remaining) 19,294 14,607
$669,389 $478,330

Regulatory liabilities were as follows:

December 31 2011 2010 (in thousands)

Cost of removal in excess of salvage value (1 to 60 years) $294,817 $277,341 Retirement benefit plans (5 years beginning with respective utility’s next rate case; primarily 5 years remaining) 20,000 18,617 Other (5 years; 1 to 5 years remaining) 649 839
$315,466 $296,797

The regulatory asset and liability re lating to retirement benefit plans was created as a result of pension and OPEB tracking mechanisms adopted by the PUC in ra te case decisions for HECO, MECO and HELCO in 2007 (see Note 9).

Cumulative preferred stock. The cumulative preferred stock of HE CO and its subsidiaries is redeemable at the option of the respective company at a premium or par, but is not subject to mandatory redemption.

Major customers. HECO and its subsidiaries received 11% ($316 million), 10% ($242 million) and 10% ($199 million) of their operating revenues from the sale of electricity to various federal government agencies in 2011, 2010 and 2009, respectively.

Commitments and contingencies.

Fuel contracts. HECO and its subsidiaries have contract ual agreements to purc hase minimum quantities of fuel oil, diesel fuel and biodiesel for multi-year periods, some through December 31, 2014. Fossil fuel prices are tied to the market prices of crude oil and petroleum products in the Far East and U.S. West Coast and the biodiesel price is tied to the market prices of anima l fat feedstocks in the U.S. Midwest. Based on the average price per barrel as of December 31, 2011, the estima ted cost of minimum purchases under the fuel supply contracts is $1.0 billion in 2012, $0.5 billion in 2013 an d $0.3 billion in 2014. The actual cost of purchases in 2012 and future years could vary substantially from this estimate as a result of changes in market prices, quantities actually purchased and/or other factors. HECO and its subs idiaries purchased $1.3 billion,
$1.0 billion and $0.7 bill ion of fuel under contra ctual agreements in 2011, 2010 and 2009, respectively. HECO and Chevron Products Company (Chevron), a division of Chevr on USA, Inc., are parties to an amended contract for the purchase/sale of low sulfur fuel oil (LSFO), which terminates on April 30, 2013. HECO and Tesoro are parties to an amended LSFO suppl y contract (LSFO contract). The term of the amended agreement runs through April 30, 2013 and may aut omatically renew for annual terms thereafter unless earlier terminated by either party. The energy charge for energy purchased from Kalaeloa Partners, L.P. (Kalaeloa ) under HECO’s PPA with Kalaeloa is based, in part, on the price Kalaeloa pays Tesoro for fuel oil under a Facility Fuel Supply Contract (fuel contract) between them. Kalaeloa and Tesoro have negotiated a proposed am endment to the pricing

formula in their fuel contract. The amend ment could result in higher fuel pric es for Kalaeloa, which would in turn increase the energy charge paid by HECO to Kalaeloa . HECO consented to the amendment on September 7,

2010.106 The costs incurred under the utilities’ fuel contracts ar e included in their respective ECACs, to the extent

such costs are not recovered th rough the utilities’ base rates.

Power purchase agreements. As of December 31, 2011, HECO and its subsidiaries had six firm capacity PPAs for a total of 548 megawatts (MW) of firm c apacity. Purchases from these six independent power producers (IPPs) and all other IPPs totaled $0.7 bill ion, $0.5 billion and $0.5 billion for 2011, 2010 and 2009, respectively. The PUC allows rate recovery for ener gy and firm capacity payments to IPPs under these agreements. Assuming that each of t he agreements remains in place for its current term and the minimum availability criteria in the PPAs are met, aggregate minimum fi xed capacity charges are expected to be approximately $0.1 billion per year for 2012 through 2016 and a total of $0.6 billion in the period from 2017 through 2030. In general, HECO and its subsidiaries base thei r payments under the PPAs upon available capacity and actually supplied energy and they ar e generally not required to make pay ments for capacity if the contracted capacity is not available, and payment s are reduced, under certain condition s, if available capacity drops below contracted levels. In general, the payment rate s for capacity have been predet ermined for the terms of the agreements. Energy payments will va ry over the terms of the agreements. HECO and its subsidiaries pass on changes in the fuel component of the energy charges to customers through the ECAC in their rate

schedules. HECO and its subsidiaries do not operate, or participate in the operation of, any of the facilities that provide power under the agreements. Ti tle to the facilities does not pass to HECO or its subsidiaries upon expiration of the agreements, and the agreements do not contain bargain purc hase options for the facilities.

Purchase power adjustment clause. The final decision and order (D&O ) for the HECO 2009 test year rate case approved a purchased power adjustment clause (PPAC). HECO purchased power capacity, operation and maintenance (O&M) and ot her non-energy costs previously recovered through base rates are now recovered in the PPAC, and subject to approval by the PUC, such costs resulting from new purchased power agreements can be added to the PPAC outside of a rate case. Purchased energy costs will continue to be recovered through the ECAC to the extent they ar e not recovered through base rates. HELCO will also implement a PPAC pursuant to the final D&O issued in its 2010 test year rate case.

Hawaii Clean Energy Initiative. In January 2008, the State of Hawa ii (State) and the U.S. Department of Energy signed a memorandum of understanding establishing the Hawaii Clean Energy Initiative (HCEI). In
October 2008, the Governor of the State, the State Department of Business, Economic Development and
Tourism, the Division of Consumer Advocacy of the State Department of Commerce and Consumer Affairs,
and HECO, on behalf of itself and its subsidiaries, HE LCO and MECO (collectively, the parties), signed an agreement setting forth goals and objectives under the HCE I and the related commitments of the parties (the Energy Agreement), including pursuing a wide range of actions to decrease the State’s dependence on imported fossil fuels through substant ial increases in renewable energ y and programs intended to secure greater energy efficiency and conservation. Many of the actions and program s included in the Energy Agreement require approv al of the PUC. Renewable energy projects. HECO and its subsidiaries continue to negotiate with developers of proposed projects to integrate power in to its grid from a variety of renew able energy sources, including solar, biomass, wind, ocean thermal energy conversion, wave and others. This includes HECO's plan to integrate wind power into the Oahu electrical grid that would be imported via a yet-to-be-built undersea transmission cable system from a windfarm proposed to be built on t he island of Lanai. The State and HECO are working together to ensure the supporting infrastructure needed is in place to reliably accommodate this large increment of wind power, in cluding any required utility syst em connections or interfaces with the cable and the windfarm facility. In December 2009, t he PUC allowed HECO to defer the costs of studi es for this large wind project for later review of prudence and reasonableness, and HECO is now seeking PUC approval to recover the deferred costs totaling $3.9 million for the stage 1 st udies through the REIP surcharge. Additionally, in July 2011, the PUC directed HECO to file a draft Request for Proposal (RFP) for 200 MW or more of renewable energy to be delivered to O ahu from any of the Hawaiian islands. In October 2011, HECO filed the
draft RFP with the PUC. In November 2011, HECO and ME CO filed their application to seek PUC approval to defer for later recovery approximat ely $0.6 million for additional studies to address whether an inter-island107 cable system that ties the Oahu, M aui, Molokai and Lanai electrical syst ems would be operationally beneficial

and cost-effective.

Interim increases. As of December 31, 2011, HECO and it s subsidiaries had recognized $40 million of revenues with respect to interim orders related to general rate incr ease requests. Revenue amounts recorded pursuant to interim orders are subject to refund, with in terest, if they exceed amount s allowed in a final order.

Major projects . Many public utility projects require P UC approval and various permits from other governmental agencies. Difficulties in obtaining, or the inability to obtain, the nece ssary approvals or permits can result in significantly increased project costs or even cancellation of projects. Further, completion of projects is subject to various risks, such as problems or disputes with vendors. In the event a project does not proceed, or if it becomes pr obable the PUC will disallo w cost recovery for all or part of a project, project costs may need to be written off in amounts that could result in significant reductions in HECO’s consolidated net income. Significant projects whose costs (or costs in excess of estimates) have not yet been allowed in rate base by a final PUC order in clude those described below. In May 2011, based upon recommendations by the Consum er Advocate in HECO’s 2009 test year rate case, the PUC ordered independently c onducted regulatory audits on the r easonableness of costs incurred for HECO's East Oahu Transmission Project (EOTP), Campbe ll Industrial Park (CIP) combustion turbine No. 1 (CT-1) project, and Customer Inform ation System Project. The PUC conf irmed that any revenue requirements arising from project costs being audit ed shall either remain interim and s ubject to refund until audit completion, or remain within regulatory deferral a ccounts. In the Interim D&O in the 2011 te st year rate case, issued in July 2011, the PUC approved the portion of the settlement agr eement in that proceeding allowing HECO to defer the portion of costs that are in excess of the prior PUC approved amounts and related depreciation for HECO’s EOTP Phase 1 ($43 million) and the CIP CT-1 project ($32 million) until completion of an independently conducted regulatory audit. In the in terim order in HECO’s 2011 test y ear rate case, the PUC approved the accrual of a carrying charge on the cost of such projects not yet included in rates and the related depreciation expense, from July 1, 2011 until the regulatory audits ar e completed and allowed the remaining project costs

that were not deferred to be include d in electric rates. For accountin g purposes, HECO will recognize the equity portion of the carrying charge when it is allo wed in electric rates. The PUC did not approve the agreement to defer expenses (subject to a limit to which the parties had agr eed) associated with the yet-to-be completed Customer Information Syst em. Pursuant to the PUC’s order in HECO’s 2009 test year rate case, HECO and the Consumer Advocate submitted proposal s for the scope, timing, management and structure for the regulatory audits for the PUC’s re view and consideration, however, t he PUC has not yet issued a schedule or requirements for the regulatory audits.

Campbell Industrial Park combustion turbine No. 1 and transmission line. HECO’s incurred costs for this project, which was placed in service in 2009, were $195 million, including $9 m illion of AFUDC. HECO’s current rates reflect recovery of project costs of $163 million. See “M ajor projects” above regarding the regulatory audit process that must be completed in co nnection with determining reco very of the remaining costs for this project. Management belie ves no adjustment to project costs is required as of December 31,

2011.

East Oahu Transmission Project. HECO had planned a project to c onstruct a partially underground transmission line to a major substation. However, in 2002, an application for a permit, which would have allowed construction in a route through conservation district lands, was denied. In 2007, the PUC approved HECO’s request to expend funds for a revised EOTP us ing different routes requiring the construction of subtransmission lines in two phases (then estimated at $56 million - $42 million for Phase 1 and $14 million for Phase 2), but did not address the issue as to whet her the pre-2003 planning and permitting costs, and related
AFUDC, should be included in the project costs. Phase 1 was placed in service on June 29, 2010. As of December 31, 2011, HECO’s incurred costs for Phase 1 of this project was $59 million (as a result of higher costs and the project delays), including (i) $12 million of pre-2003 planning and permitting costs, (ii) $24 million of planning , permitting and construction costs incurred after the denial of the permit and (iii) $23 million for AFUDC. The interim D&O issued in HECO’s 2011 test year rate case reflects approximately $16 m illion of EOTP Phase 1 costs and related depreciation108 expense in determining revenue requirem ents. See “Major projects” above r egarding the regulatory audit that is

to be conducted before the PUC determi nes the recoverability of the rema ining costs for EOTP Phase 1. On February 3, 2012, HECO, the C onsumer Advocate and the Department of Defense (parties in the HECO 2011 test year rate case proceeding) signed a settlement agreement, subject to PUC approval, regarding the EOTP Phase 1 project co sts. The parties agreed that, in li eu of a regulatory audit, HECO would write-off $9.5 million of gr oss plant in service costs associated with EOTP Phase 1, and associated adjustments in the accumulated deprec iation, deferred depreciation expens e, accumulated deferred income
taxes, unamortized state investment tax credits and carrying charges. In dec iding to enter into the agreement

HECO took into account a number of considerations, including (1) the si gnificant passage of time since the initial costs for the EOTP Phase 1 project were incurred , (2) the significant resources that would be required by the PUC, HECO and the other parties to conduct a fair and meaningful r egulatory audit of project costs, and (3) additional carrying charges that would be accrued to the project cost during a lengthy audit process. The settlement agreement does not address the costs that are being deferred in connection with the CIP CT-1 project or the Customer In formation System Project. The settlement agreement resulted in an after-tax charge to net income in the fourth quarter of 2011 of approximately $6 million. The parties agreed to stipulate, subject to PUC approval, to an additional annual
interim increase of $5 million to be effective Marc h 1, 2012, based on additional revenue requirements reflecting all remaining EOTP costs not previously incl uded in rates or agreed to be wr itten off (an increase of approximately $31 million to rate base) and offset by other minor adjustments to the interim increase that became effective on July 26, 2011. The agreement allo ws HECO to continue to defer depreciation expense and accrue carrying charges related to the costs not yet included in rates. For accounting purposes, HECO will recognize the equity portion of the carrying charge when it is allowed in electric rates. In April 2010, HECO proposed a modification of Phase 2 of the EOTP that uses smart grid technology and is estimated to cost $10 million (total cost of $15 million less $5 million of funding through the Smart Grid Investment Grant Program of the American Reco very and Reinvestment Act of 2009). In October 2010, the PUC approved HECO’s modification request for Phase 2, which is projected for completion in 2012. As
of December 31, 2011, HECO’s incurr ed costs for the Modified Phase 2 pr oject amounted to $8 million (total
cost $11 million less $3 million received in Smart Grid Investment funding). Management believes no adjustment to project costs of EOTP Phase 1 or Modified Phase 2 is r equired as of December 31, 2011.

Customer Information System Project. In 2005, the PUC approved the utilities’ request to (i) expend the then-estimated $20 million (including $18 million for capital and deferred costs) for a new Customer Information System (CIS), provided that no part of the proj ect costs may be included in rate base until the project is in service and is “used and useful for public utility purposes,” and (ii) defer certain computer software development costs, accumulate AFUDC during the defer ral period, amortize t he deferred costs over a specified period and include the unamortized deferred costs in rate base, subject to specified conditions. The CIS project is proceeding with the implementati on of a new software system. As of December 31, 2011, HECO’s total deferred and capital cost estimate for the CIS was $57 million (of which $43 million was recorded). The PUC has ordered that this project under go a regulatory audit, which likely will not be planned until the CIS project is complete and the CIS is operational. Management belie ves no adjustment to CIS project costs is required as of December 31, 2011.

Environmental regulation . HECO and its subsidiaries are subj ect to environmental laws and regulations that regulate the operation of existi ng facilities, the construction and operat ion of new facilities and the proper cleanup and disposal of hazardous waste and toxic substanc es. In recent years, legislative, regulatory and governmental activities related to the environment, including proposals and rulemaking under the Clean Air Act (CAA) and Clean Water Act (CWA), have increased significant ly and management anticipates that such activity

will continue. On April 20, 2011, the Federal Register published t he federal Environmental Protection Agency’s (EPA’s) proposed regulations required by sect ion 316(b) of the CWA designed to protect aquatic organisms from adverse impacts associated with existing power pl ant cooling water intake structures. The proposed regulations would apply to the cooling water systems for the steam generating units at the utilities’ Honolulu,109 Kahe and Waiau power plants on the island of Oahu. Although the proposed regulations provide some flexibility, management believes t hey do not adequately focus on site-spec ific conditions and cost-benefit factors and, if adopted as proposed, would require significant capital and annua l O&M expenditures. As proposed, the regulations would require facilities to come into compliance within 8 year s of the effective date of the final rule, which the EPA expects to issue in 2012.
On December 21, 2011, the EPA issued the final rule establishing the EPA’s National Emission Standards

for Hazardous Air Pollutants for fossil-fuel fired steam electrical generating units (EGUs). The final rule, known as the Mercury and Air Toxics Standards (MATS), applie s to the 14 EGUs at HECO’s Honolulu, Kahe and Waiau power plants. MATS establishes the Maximum Achi evable Control Technology standards for the control of hazardous air pollutants emissions from new and ex isting EGUs. The final rule is under review and a compliance plan and schedule are under development. Dependi ng on the specifics of the compliance plan, MATS may require significant capital and annual expendi tures for the installation and operation of emission control equipment on HECO’s EGUs. The CAA requires that facilities come into compliance with the MATS limits within 3 years of the final rule, although fac ilities may be granted two 1-year extensions to install emission control technology. In view of the isolated nature of HECO’s electric al system and the potential requirement to install control equipment on all HECO EGUs while maintaining syst em reliability, the MATS compliance schedule poses a significant challenge to HECO. Depending upon the final outcome of the CWA 316(b) regul ations, possible changes in CWA effluent standards, the specifics of the MATS compliance plan, the tightening of the Nati onal Ambient Air Quality Standards, and the Regional Haze rule under the CAA, HECO and its subsid iaries may be required to incur material capital expenditures and other compliance costs, but such amounts are not determinable at this time. Additionally, the combined effects of these regulatory initiatives may result in a decision to retire certain generating units earlie r than anticipated. HECO, HELCO and MECO, like other utilities, periodi cally experience petroleum or other chemical

releases into the environment associated with curr ent operations and repor t and take action on these releases when and as required by applicable law and r egulations. Except as otherwise disclosed herein,

HECO and its subsidiaries believe t he costs of responding to their releas es identified to date will not have a material adverse effect, individually or in the aggr egate, on HECO’s consolidat ed results of operations, financial condition or liquidity.

Global climate change and gr eenhouse gas emissions reduction . National and international concern about climate change and the contributio n of GHG emissions (including carbon dioxide emissions from the combustion of fossil fuels) to global warming have led to action by the State and to federal legislative and regulatory proposals to reduce GHG emissions. In July 2007, Act 234, which requires a statewide redu ction of GHG emissions by January 1, 2020 to levels

at or below the statewide GHG emission levels in 1990, became law in Hawaii. The electric utilities are participating in a Task Force established under Act 234, which is charged with developing a work plan and regulatory approach to reduce GHG emissions, as well as in initiatives aimed at reducing their GHG emissions, such as those being implemented under the Energy Ag reement. Because the regul ations implementing Act 234 have not yet been promulgated, managem ent cannot predict the impact of Act 234 on the electric utilities, but compliance costs could be significant. Several approaches (e.g., “cap and trade”) to GHG emission reduction have been either introduced or discussed in the U.S. Congress; however, no federal legislation has yet been enacted. On September 22, 2009, the EPA issued its Final Mandatory Reporting of Greenhouse Gases Rule, which requires that sources emitting GHGs above certain threshold levels m onitor and report GHG emissions. The utilities’ reports for 2010 were submitted to the EPA. In December 2009, the EPA m ade the finding that motor vehicle GHG emissions endanger public health or welfare. Since then, t he EPA has also issued rules that begin to address GHG emissions from stationary sources, like the utilities’ generating units.
In June 2010, the EPA issued its “Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule” (GHG Tailoring Rule) that created new thresholds for GHG emissions from new and existing stationary source facilities. States ma y need to increase fees to cover the increased level of activity caused by this rule. Effective January 2, 2011, under the Preventi on of Significant Deterior ation program, permitting of110 new or modified stationary sources (such as utility elec trical generating units) that have the potential to emit GHGs in greater quantities than the thresholds in the GHG Tailoring Rule will entail GHG emissions evaluation, analysis and, potentially, control requirements. In J anuary 2011, the EPA announced that it plans to defer, for three years, GHG permitting require ments for carbon dioxide (CO2) emi ssions from biomass-fired and other biogenic sources. The utilities are evaluating the impact of this deferral on their generat ion units that are or will

be fired on biofuels.
HECO and its subsidiaries have taken, and continue to identify opportunities to take, direct action to reduce GHG emissions from their operations, including, but not limited to, supporting DSM programs that foster energy efficiency, using renewable resources for energy production and purchasing power from IPPs generated by renewable resources, burni ng renewable biodiesel in HECO’s CIP CT-1, using biodiesel for startup and shutdown of selected ME CO generation units, and testing bi ofuel blends in other HECO and MECO generating units. Management is unable to evaluate t he ultimate impact on the utilities’ operations of eventual comprehensive GHG regulation. However, management believes that the various initiatives it is undertaking will provide a sound basis for managing the el ectric utilities’ carbon footprint and meeting GHG reduction goals that will ultimately emerge. While the timing, extent and ultimate effects of climate change cannot be deter mined with any certainty, climate change is predicted to result in sea level ri se, which could potentially impact coastal and other lowlying areas (where much of the utilities’ electric infrastructure is sited), and could cause erosion of beaches, saltwater intrusion into aquifers and surface ecosystem s, higher water tables and increased flooding and storm damage due to heavy rainfall. The effects of climat e change on the weather (for example, floods or hurricanes), sea levels, and water availability and quality have the potential to materially adversely affect the results of operations, financial condition and liquidity of t he electric utilities. For example, severe weather could cause significant harm to the electr ic utilities’ physical facilities.

Asset retirement obligations. Asset retirement obligations (AROs) represent legal oblig ations associated with the retirement of certain tangi ble long-lived assets, are measured as the present value of the projected

costs for the future retireme nt of specific assets and are recognized in the period in which the liability is

incurred if a reasonable estimate of fair value can be made. HECO and its subsidiari es’ recognition of AROs have no impact on its earnings. The cost of the AROs is recovered over the life of the asset through depreciation. AROs recognized by HECO and its subsidia ries relate to obligatio ns to retire plant and equipment, including removal of asbestos and other hazar dous materials. In September 2009, HECO recorded an estimated ARO of $23 million related to removing re tired generating units at its Honolulu power plant, including abating asbestos and lead-based paint. The obligation was subsequently increased in June 2010,

due to an increase in the estimated costs of the remo val project. In August 2010, HECO recorded a similar estimated ARO of $12 million related to removing reti red generating units at HECO’s Waiau power plant. Changes to the ARO liability included in “Other liab ilities” on HECO’s balance sheet were as follows:

(in thousands) 2011 2010

Balance, January 1 $ 48,630 $ 23,746 Accretion expense 2,202 2,519
Liabilities incurred 256 11,949 Liabilities settled (835) (725)
Revisions in estimated cash flows 618 11,141
Balance, December 31 $ 50,871 $ 48,630

Collective bargaining agreements. As of December 31, 2011, approximately 53% of the electric utilities’ employees were members of the Inte rnational Brotherhood of Electrical Workers, AFL-CIO, Local 1260, which is the only union representing employees of the electric utilities. On Ma rch 11, 2011, the utilities’ bargaining unit employees ratified a new collective bargaini ng agreement and a new benefit agreement. The new collective bargaining agreement cove rs a term from January 1, 2011 to October 31, 2013 and provides for non-compounded wage increases (1.75%, 2.5%, and 3.0% for 2011, 2012 and 2013, respectively). The new benefit agreement covers a term from January 1, 2011 to October 31, 2014 and includes changes to medical, dental and vision plans with increased employee cont ributions and changes to retirement benefits for employees.111 4 • Bank subsidiary

Selected financial information American Savings Bank, F.S.B. and Subsidiaries

Consolidated Statements of Income Data

Years ended December 31 2011 2010 2009 (in thousands)

Interest and dividend income Interest and fees on loans $184,485 $195,192 $217,838 Interest and dividends on investment and mortgage-related securities 14,568 14,946 26,977

Total interest and dividend income 199,053 210,138 244,815 Interest expense Interest on deposit liabilities 8,983 14,696 34,046 Interest on other borrowings 5,486 5,653 9,497 Total interest expense 14,469 20,349 43,543

Net interest income 184,584 189,789 201,272
Provision for loan losses 15,009 20,894 32,000 Net interest income after provision for loan losses 169,575 168,895 169,272

Noninterest income Fee income on deposit liabilities 18,026 26,369 30,713
Fees from other financial services 28,881 27,280 25,267 Fee income on other financial products 6,704 6,487 5,833 Net gains (losses) on sale of securities 371 – (32,034) Net losses on available-for-sale securities – – (15,444) (includes $32,167 of other-than-temporary impairment losses, net of $16,723 of non-credit losses recognized in other comprehensive income, for 2009) Other income 11,372 12,419 15,569

Total noninterest income 65,354 72,555 29,904 Noninterest expense Compensation and employee benefits 71,137 71,476 73,990 Occupancy 17,154 16,548 22,057 Data processing 8,155 13,213 14,382
Services 7,396 6,594 11,189 Equipment 6,903 6,620 8,849 Office supplies, printing and postage 3,934 3,928 3,758 Marketing 3,001 2,418 2,134
Communication 1,764 2,221 2,446 Loss on early extinguishment of debt – – 760 Other expense 23,949 25,920 27,906 Total noninterest expense 143,393 148,938 167,471

Income before income taxes 91,536 92,512 31,705
Income taxes 31,693 34,056 9,938
Net income $ 59,843 $ 58,456 $ 21,767112 Consolidated Balance Sheet Data

December 31 2011 2010 (in thousands)

Assets Cash and cash equivalents $ 219,678 $ 204,397
Federal funds sold – 1,721 Available-for-sale investment and mortgage-related securities 624,331 678,152
Investment in stock of Federal Home Loan Bank of Seattle 97,764 97,764
Loans receivable held for investment, net 3,642,818 3,489,880
Loans held for sale, at lower of cost or fair value 9,601 7,849

Other 233,592 234,806

Goodwill 82,190 82,190

Total assets $4,909,974 $4,796,759

Liabilities and shareholder’s equity Deposit liabilities–noninterest- bearing $ 993,828 $ 865,642 Deposit liabilities–interest-bearing 3,076,204 3,109,730 Other borrowings 233,229 237,319

Other 118,078 90,683

Total liabilities 4,421,339 4,303,374

Commitments and contingencies (see below)
Common stock 331,880 330,562 Retained earnings 166,126 169,111 Accumulated other comprehensive loss, net of tax benefits (9,371) (6,288) Total shareholder’s equity 488,635 493,385 Total liabilities and shareholder’s equity $4,909,974 $4,796,759

Other assets
Bank-owned life insurance $121,470 $117,565 Premises and equipment, net 52,940 56,495 Prepaid expenses 15,297 18,608
Accrued interest receivable 14,190 14,887 Mortgage-servicing rights 8,227 6,699 Real estate acquired in settlement of loans, net 7,260 4,292

Other 14,208 16,260
$233,592 $234,806

Other liabilities Accrued expenses $ 21,216 $16,426 Federal and state income taxes payable 35,002 28,372

Cashier’s checks 22,802 22,396 Advance payments by borrowers 10,100 10,216

Other 28,958 13,273
$118,078 $ 90,683

Investment and mortgage-related securities. ASB owns investment securities (federal agency obligations) and mortgage-related securities issued by the Federal National Mortgage Association (FNMA), Federal Home Loan Mortgage Corporation (FHLMC), Government Nati onal Mortgage Association (GNMA) and municipal

bonds. In the past, ASB owned private-issue mortgage-related se curities (PMRS). To further improve its credit risk profile and reduce the potential volatility of future earnings, and in light of the improvement in the fixed-income
securities markets, ASB sold the PMRS held in its investment portfolio in the fourth quarter of 2009.
As of December 31, 2011, ASB’s in vestment portfolio distribution wa s 55% mortgage-related securities issued by FNMA, FHLMC or GNMA, 35% federal agency obligations and 10% municipal bonds. These investment and mortgage-related securities are all active and readily priced. Prices for investments and mortgage-related secu rities are provided by an independent third party pricing service and are based on observable inputs, including historical trading levels or sector yields, using market-based valuation techniques. The price of thes e securities is generally based on observable inputs,113 which includes market liquidity, credit considerations of the underlying collatera l, the levels of interest rates, expectations of prepayments and defaults , limited investor base, market se ctor concerns and overall market psychology. To validate the accuracy and completeness of security pricing, a separate third party pricing service is used on a quarterly basis to compare prices t hat were received from the initial third party pricing service. If the pricing differential between the two pricing sources exc eeds an established threshold, the security price will be re-evaluated by sending a re -pricing request to both indepen dent third party pricing services, to another third party vendor, or to an i ndependent broker to determine the most accurate price based on all observable inputs found in the market plac e. The third party price selected will be based on the

value that best reflects the data and obser vable characteristics of the security.

December 31, 2011

Gross Gross Estimated Gross unrealized losses

Amortized unrealized unrealized fair Less than 12 months 12 months or longer
(dollars in thousands) cost gains losses value Fair value Amount Fair value Amount

Available-for-sale Federal agency obligations $218,342 $ 2,393 $ (8) $220,727 $ 19,992 $ (8) $ – $ – Mortgage-related securities-
FNMA, FHLMC and GNMA 334,183 10,699 (17) 344,865 11,994 (17) – – Municipal bonds 55,393 3,346 – 58,739

– – – – $607,918 $16,438 $(25) $624,331 $31,986 $(25) $ – $ –

December 31, 2010

Gross Gross Estimated Gross unrealized losses

Amortized unrealized unrealized fair Less than 12 months 12 months or longer (dollars in thousands) cost gains losses value Fair value Amount Fair value Amount

Available-for-sale Federal agency obligations $317,945 $ 171 $(2,220) $315,896 $205,316 $(2,220) $ – $ – Mortgage-related securities-
FNMA, FHLMC and GNMA 310,711 9,570 (311) 319,970 30,986 (311)

– – Municipal bonds 43,632 7 (1,353) 42,286 41,479 (1,353) – –
$672,288 $9,748 $(3,884) $678,152 $277,781 $(3,884) $ – $ –

Federal agency obligations have contra ctual terms to maturity. Mortgage-re lated securities have contractual terms to maturity, but requi re periodic payments to reduce principal. In addition, expected maturities will differ

from contractual maturities because borrowers hav e the right to prepay the underlying mortgages (see contractual maturities table below).

The contractual maturities of availabl e-for-sale securities were as follows:

Amortized Fair (in thousands) Cost value

Due in one year or less $ – $ – Due after one year through five years 208,342 210,106 Due after five years through ten years 58,113 61,585 Due after ten years 7,280 7,775

273,735 279,466 Mortgage-related securities-FNMA,FHLMC and GNMA 334,183 344,865
Total available-for-sale securities $607,918 $624,331

All positions with variable matu rities (e.g. callable debentures and mortgage-related securities) are disclosed based upon the bond’s contractual maturity. Actual ma turities will likely differ from these contractual maturities because borrowers may have the right to ca ll or prepay obligations with or without call or prepayment penalties. In 2011, 2010 and 2009, proceeds from sales of avail able-for-sale mortgage-related securities were $30.7 million, nil and $185.1 million, resu lting in gross realized gains of $0.4 million, nil and $0.8 million and114 gross realized losses of nil, nil and $32.9 million, respectively. In 2011, pr oceeds from the sale of municipal bonds were $2.1 million resulting in gross realized gains of $5,000 and no gross realized losses. There were no sales of municipal bonds in 2010 and 2009. ASB pledged mortgage-related securities and federal agency obligations with a carrying value of approximately $91.9 million and $60.8 million as of December 31, 20 11 and 2010, respectively, as collateral for public funds deposits, automated clearinghouse transacti ons with Bank of Hawaii, and deposits in ASB’s bankruptcy and treasury, tax, and loan a ccounts with the Federal Reserve Bank of San Francisco. As of December 31, 2011 and 2010, mortgage-related securities and federal agency obligations with a carrying value of $219.7 million and $204.8 million, respectively, were pledged as collateral for securities sold under agreements to repurchase.

FHLB of Seattle stock . As of December 31, 2011 and 2010, ASB’s investment in stock of the FHLB of Seattle was carried at cost because it can only be r edeemed at par and it is a r equired investment based on measurements of ASB’s capital, assets and/or borrowing levels. Periodically and as conditions warrant, ASB

reviews its investment in the sto ck of the FHLB of Seattle for impai rment. ASB evaluated its investment in

FHLB stock for OTTI as of December 31, 2011, consistent with its acc ounting policy. ASB did not recognize an

OTTI loss for 2011 based on its evaluation of the underlying investment, including:

 the net income recorded by the FHLB of Seattle in the first nine months of 2011;

 the significance of the decline in net assets of the FHLB of Seattle as compared to its capital stock

amount and the length of time this situation has persisted;

 commitments by the FHLB of Seattl e to make payments required by la w or regulation and the level of such payments in relation to the operating performance of the FHLB of Seattle;

 the impact of legislative and regulatory changes on in stitutions and, accordingly, on the customer
base of the FHLB of Seattle;

 the liquidity position of the FHLB of Seattle; and

 ASB’s intent and assessment of whether it will more likely than not be required to sell before recovery of its par value.

Deterioration in the FHLB of Seattle’s financia l position may result in future impairment losses.

Other-than-temporary impaired securities. All securities are reviewed for impairment in accordance with accounting standards for OTTI recognition. Under thes e standards ASB’s intent to sell the security, the probability of more-likely-than-not being forced to sell the position prior to recovery of its cost basis and the probability of more-likely-than-not reco vering the amortized cost of the pos ition was determined. If ASB’s intent is to hold positions determined to be other-than-temporar ily impaired, credit losses, which are recognized in earnings, are quantified using the posit ion’s pre-impairment discount rate and the net present value of cash flows expected to be collected from the security. N on-credit related impairments are reflected in other comprehensive income. Cumulative OTTIs for expected losses that have been recognized in earnings were as follows:

Nine months ended (in thousands) December 31, 2009 Balance, April 1, 2009 $ 1,486

Additions: Initial credit impairments 4,870 Subsequent credit impairments 10,574

Reductions:

For securities sold (16,930)
Balance, December 31, 2009 $ –

The beginning balance for the nine months ended Decem ber 31, 2009 relates to credit losses realized prior to April 1, 2009 on debt securities held by ASB as of March 31, 2009. This beginning balance includes the net impact of non-credit losses that were originally reported as losse s prior to March 31, 2009 and were subsequently recharacterized from retained earnings as a result of the adoption of new accounting standards115 for OTTI recognition effective April 1, 2009. Additions to this balance includ e new securities in which initial credit impairments have been identified and incremental increases of credi t impairments on positions that had already taken similar impairments. In the fourth quarter of 2009, ASB sold its private-issue mortgage-related securities portfolio. ASB did not recognize OTTI for 2011 or 2010.

Loans receivable.

December 31 2011 2010 (in thousands)

Real estate loans: Residential 1-4 family $1,926,774 $2,087,813
Commercial real estate 331,931 300,689 Home equity line of credit 535,481 416,453
Residential land 45,392 65,599
Commercial construction 41,950 38,079
Residential construction 3,327 5,602

Total real estate loans 2,884,855 2,914,235

Commercial loans 716,427 551,683
Consumer loans 93,253 80,138

Total loans 3,694,535 3,546,056 Deferred loan fees, net and unamortized discounts (13,811) (15,530) Allowance for loan losses (37,906) (40,646)
Total loans, net $3,642,818 $3,489,880

As of December 31, 2011 and 2010, ASB’s commitment s to originate loans, including the undisbursed portion of loans in process, approx imated $95.4 million and $77.6 million, respectively. Commitments to extend credit are agreements to lend to a customer as long as t here is no violation of any condition established in the commitments. Commitments generally have fixed expira tion dates or other termination clauses and may require payment of a fee. Since ce rtain of the commitments are expected to expire without being drawn upon,

the total commitment amounts do not necessarily represent future ca sh requirements. ASB minimizes its exposure to loss under these commitments by requiring that customers meet cert ain conditions prior to disbursing funds. The amount of collateral, if any, is based on a credit evaluation of the borrower and may
include residential real estate, accounts rece ivable, inventory and proper ty, plant and equipment.
As of December 31, 2011 and 2010, ASB had commitment s to sell residential loans of $44.9 million and $21.9 million, respectively. The loans are included in loans receivable as held for sale or represent

commitments to make loans at an in terest rate set prior to funding (rate lock commitments). Rate lock commitments guarantee a specified interest rate for a loan if ASB’s underwriting standards are met, but do not obligate the potential borrower. Rate lock commi tments on loans intended to be sold in the secondary

market are derivative instrum ents, but have not been designated as hedges. Rate lock commitments are carried at fair value and adjustment s are recorded in “Other income,” wi th an offset on the ASB balance sheet
in “Other” liabilities. As of December 31, 2011 and 2010, ASB had rate lock commitments on outstanding loans totaling notional amounts of $35.8 million and $15.1 milli on, respectively. To offset the impact of changes in market interest rates on the rate lock co mmitments on loans held for sale, ASB utilizes short-term

forward sale contracts. Forward sales contracts are also derivative instru ments, but have not been designated as hedges, and thus any changes in fair value are also recorded in ASB “Other income,” with an

offset in the ASB balance sheet in “Other” assets or liabilities. As of December 31, 2011 and 2010, the

notional amounts for forward sales contracts were $44.9 million and $21.9 million, respectively. Valuation models are applied using current market information to estimate fair value. There were no significant gains or
losses on derivatives in 2011, 2010 and 2009. As of December 31, 2011 and 2010, standby, commerc ial and banker’s acceptance letters of credit totaled $10.8 million and $16.3 million, respectively. Lette rs of credit are conditional commitments issued by ASB to guarantee payment and performance of a customer to a third par ty. The credit risk involved in issuing letters of credit is essentially the same as t hat involved in extending loan facilities to customers. ASB holds collateral supporting those commitments fo r which collateral is deemed necessary. As of
December 31, 2011 and 2010, undrawn consumer lines of credit, including credit cards, totaled116 $943.1 million and $856.7 million, res pectively, and undrawn commercial loans including lines of credit totaled $289.3 million and $263.4 million, respectively. ASB services real estate loans for investors ($1.0 billion, $0.8 billion and $0.6 bil lion as of December 31, 2011, 2010 and 2009, respectively), which are not in cluded in the accompanying consolidated financial statements. ASB reports fees earned for servicing such loans as income when the related mortgage loan payments are collected and charges loan se rvicing costs to expense as incurred. As of December 31, 2011 and 2010, ASB had pledged l oans with an amortized cost of approximately $1.1 billion and $1.4 billion, respectively, as collate ral to secure advances from the FHLB of Seattle.
As of December 31, 2011 and 2010, the aggregate amount of loans to di rectors and executive officers of ASB and its affiliates and any related interests (as def ined in Federal Reserve Board (FRB) Regulation O)
of such individuals, was $62.1 milli on and $60.9 million, respectively. The $1.2 million increase in such loans

in 2011 was attributed to new commitments and loans of $15.9 million to new and existing directors and executive officers, offset by closed lines of credits and repayments of $14.7 millio n. As of December 31, 2011 and 2010, $56.4 million and $52.5 million of the loan balances, respectively, were to related interests

of individuals who are directors of ASB. All such l oans were made at ASB’s normal credit terms except that

residential real estate loans and consumer loans to directors and executive officers of ASB were made at preferred employee interest rates. Management believes these loans do not represent more than a normal

risk of collection.

Allowance for loan losses. As discussed in Note 1, ASB must maintain an allowance for loan losses that is adequate to absorb estimated probable credit losses associ ated with its loan portfolio. The allowance for loan losses consists of an allocated portion, which estimates credit losses for specifically identified loans and pools of loans, and an unallocated portion.

Segmentation . ASB segments its loan portfolio by three levels. In the first level, the loan portfolio is separated into homogeneous and non-homogeneous loan portfolios. Residential, consumer and credit scored business loans are considered homogeneous loans. These ar e loans that are typica lly underwritten based on common, uniform standards, and are generally classi fied as to the level of loss exposure based on delinquency status. Commercial loans and commercia l real estate (CRE) loans are defined as nonhomogeneous loans and ASB utilitizes a uniform ten–point ri sk rating system for evaluat ing the credit quality of

the loans. These are loans where the underwriting criteria are not uniform and the risk rating classification is based upon considerations broader t han just delinquency performance. In the second level of segmentation, the loan portfolios are further stratified into individual products with

common risk characteristics. For re sidential loans, the loan portfolio is segmented by loan categories and geographic location first within the State of Hawaii (Oahu vs. the neighbor islands) and second collectively outside of the state. The consumer loan portfolio is segmented into various secured and unsecured loan product types. The credit scored business loan portfolio is segmented by loans under lines of credit or term loans, and corporate credit cards. Fo r commercial loans, the portfolio is differentiated by separating Commercial & Industrial (C&I) loans and C&I loans guaranteed by Small Busine ss Administration programs while CRE loans are grouped by owner-occupied loans, investor loans, construction loans, and vacant land

loans. For the third and last level of segmentation, l oans are categorized into the regulatory asset quality
classifications – Pass, Substandard, and Loss for homogeneous loans based primar ily on delinquency status, and Pass (Risk Rating 1 to 6), Special Mention (Risk Rating 7), Substandard (Risk Rating 8), Doubtful (Risk Rating 9), and Loss (Risk Rating 10) for non-homogeneous loans based on credit quality.

Specific allocation

.
Residential real estate. All residential real estate loans t hat are 180 days delinquent, or where ASB

has initiated foreclosure action or have been modified in a TDR are reviewed for impairment based on the fair
value of the collateral, net of costs to sell. G enerally, impairment amounts der ived under this method are immediately charged off.117 Consumer. The consumer loan portfolio specific allo cation is determined based on delinquency; unsecured consumer loans are generally charged-off based on delinquency status varying from 120 to 180 days.

Commercial and CRE . A specific allocation is determi ned for impaired commercial and CRE loans.

See further discussion in Note 1.

Pooled allocation.

Residential real estate and consumer . Pooled allocation for non-impaired residential real estate and consumer loans are determined using a historical loss rate analysis and qua litative factor considerations.

Commercial and CRE . Pooled allocation for pass, specia l mention, substandard, and doubtful grade

commercial and CRE loans that share common risk ch aracteristics and properties are determined using a historical loss rate analysis and qual itative factor considerations.

Qualitative adjustments. Qualitative adjustments to historical loss rates or other static sources may be necessary since these rates may not be an accurate guide to assessing losse s inherent in the current portfolio. To estimate the level of adjustment s, management considers factors incl uding levels and trends in problem loans, volume and term of loans, changes in risk fro m changes in lending policie s and practices, management expertise, economic conditions, industry trends, and the effect of credit concentrations.

Unallocated allowance. ASB’s allowance incorporates an unallo cated portion to cover risk factors and events that may have occurred as of the evaluation date that have not been reflected in the risk measures due to inherent limitations to the precis ion of the estimation process. These risk factors, in addition to micro- and macro- economic factors, past, current and anticipat ed events based on facts at the balance sheet date, and realistic courses of action that management expects to take, are assessed in determining the level of

unallocated allowance.118 The allowance for loan losses was comprised of the following:

Residential Commercial

real Home equity line Residential Commercial Residential Commercial Consumer Unallo- (in thousands) 1-4 family estate of credit land construction construction loans loans cated Total

December 31, 2011

Allowance for loan losses:

Beginning balance $ 6,497 $1,474 $ 4,269 $ 6,411 $ 1,714 $ 7 $16,015 $3,325 $ 934 $ 40,646 Charge-offs (5,528)

– (1,439) (4,071)

– – (5,335) (3,117)

– (19,490)

Recoveries 110

– 25 170

– – 869 567

– 1,741
Provision 5,421 214 1,499 1,285 174 (3) 3,318 3,031 70 15,009

Ending balance $ 6,500 $1,688 $ 4,354 $ 3,795 $ 1,888 $ 4 $14,867 $3,806 $1,004 $ 37,906

Ending balance: individually evaluated for impairment $203 $ – $ – $2,525 $ – $ – $976 $ – $ – $3,704

Ending balance: collectively evaluated for impairment $6,297 $1,688 $4,354 $1,270 $1,888 $ 4 $13,891 $3,806 $1,004 $34,202

Financing Receivables: Ending balance $1,926,774 $331,931 $535,481 $45,392 $41,950 $3,327 $716,427 $93,253 $

– $3,694,535

Ending balance: individually evaluated for impairment $26,012 $13,397 $1,450 $39,364 $ – $ – $48,241 $24 $ – $128,488

Ending balance: collectively evaluated for impairment $1,900,762 $318,534 $534,031 $6,028 $41,950 $3,327 $668,186 $93,229 $ – $3,566,047

December 31, 2010

Allowance for loan losses: Beginning balance $ 5,522 $ 861 $ 4,679 $ 4,252 $ 3,068 $ 19 $19,498 $ 2,590 $1,190 $ 41,679 Charge-offs (6,142)

– (2,517) (6,487)

– – (6,261) (3,408)

– (24,815)

Recoveries 744

– 63 63

– – 1,537 481

– 2,888
Provision 6,373 613 2,044 8,583 (1,354) (12) 1,241 3,662 (256) 20,894

Ending balance $ 6,497 $1,474 $ 4,269 $ 6,411 $ 1,714 $ 7 $16,015 $3,325 $ 934 $ 40,646

Ending balance: individually evaluated for impairment $230 $ – $ – $1,642 $ – $ – $ 1,588 $ – $ – $ 3,460

Ending balance: collectively evaluated for impairment $6,267 $1,474 $4,269 $4,769 $1,714 $ 7 $ 14,427 $3,325 $934 $37,186

Financing Receivables: Ending balance $2,087,813 $300,689 $416,453 $65,599 $38,079 $5,602 $551,683 $80,138 $

– $3,546,056

Ending balance: individually evaluated for impairment $34,615 $12,156 $827 $39,631 $ – $ – $28,886 $76 $ – $116,191

Ending balance: collectively evaluated for impairment $2,053,198 $288,533 $415,626 $25,968 $38,079 $5,602 $522,797 $80,062 $ – $3,429,865

Changes in the allowance for loan losses were as follows:

(dollars in thousands) 2011 2010 2009

Allowance for loan losses, January 1 $40,646 $41,679 $35,798

Provision for loan losses 15,009 20,894 32,000

Charge-offs, net of recoveries
Real estate loans 10,733 14,276 9,526
Other loans 7,016 7,651 16,593 Net charge-offs 17,749 21,927 26,119

Allowance for loan losses, December 31 $37,906 $40,646 $41,679

Ratio of net charge-offs to average loans outstanding 0.49% 0.61% 0.66%

Credit quality . ASB performs an internal loan review and grading on an ongoing basis. The review provides management with periodic information as to the quality of the loan portfolio and effectiveness of its lending policies and procedures. The objectives of the loan review and grading procedures are to identify, in a timely manner, existing or emerging cr edit quality problems so that appropria te steps can be initiated to avoid or minimize future losses. Loans subject to grading include commercial and CRE loans. A ten-point risk rating system is used to determi ne loan grade and is based on borrower loan risk. The risk rating is a numerical representation of risk based on the overall assessment of the borrower’s financial and operating strength including earnings, oper ating cash flow, debt service capacity, asset and liability structure,119 competitive issues, experience and quality of management, fi nancial reporting issues and industry/economic

factors. The loan grade categories are: 1- Substantially risk free 6- Acceptable risk 2- Minimal risk 7- Special mention

3- Modest risk 8- Substandard 4- Better than average risk 9- Doubtful 5- Average risk 10- Loss

Grades 1 through 6 are considered pass grades. Pass exposures generally are well protected by the current net worth and paying capacity of the obligor or by the value of the asset or underlying collateral. The credit risk profile by internally assigned grade for loans was as follows:

December 31 2011 2010

(in thousands) Commercial

real estate Commercial

construction Commercial Commercial

real estate Commercial

construction Commercial

Grade: Pass $308,843 $41,950 $650,234 $285,624 $38,079 $462,078 Special mention 8,594 – 14,660 526 – 44,759
Substandard 11,058 – 47,607 14,539 – 44,259
Doubtful 3,436 – 3,926 – – 556

Loss – – – – – 31
Total $331,931 $41,950 $716,427 $300,689 $38,079 $551,683

The credit risk profile based on payment activity for loans was as follows:

(in thousands) 30-59 days past due 60-89 days past due Greater

than 90 days Total past due Current Total financing

receivables Recorded

Investment> 90 days and

accruing

December 31, 2011

Real estate loans: Residential 1-4 family $10,391 $4,583 $28,113 $43,087 $1,883,687 $1,926,774 $ –

Commercial real estate – – – – 331,931 331,931 – Home equity line of credit 1,671 494 1,421 3,586 531,895 535,481 –
Residential land 2,352 575 13,037 15,964 29,428 45,392 205

Commercial construction – – – – 41,950 41,950 –

Residential construction – – – – 3,327 3,327 –
Commercial loans 226 733 1,340 2,299 714,128 716,427 28
Consumer loans 553 344 486 1,383 91,870 93,253 308
Total loans $15,193 $6,729 $44,397 $66,319 $3,628,216 $3,694,535 $ 541

December 31, 2010

Real estate loans: Residential 1-4 family $ 8,245 $3,719 $36,419 $48,383 $2,039,430 $2,087,813 $ –

Commercial real estate – 4 – 4 300,685 300,689 – Home equity line of credit 1,103 227 1,659 2,989 413,464 416,453 –
Residential land 1,543 1,218 16,060 18,821 46,778 65,599 581

Commercial construction – – – – 38,079 38,079 –

Residential construction – – – – 5,602 5,602 –
Commercial loans 892 1,317 3,191 5,400 546,283 551,683 64
Consumer loans 629 410 617 1,656 78,482 80,138 320
Total loans $12,412 $6,895 $57,946 $77,253 $3,468,803 $3,546,056 $ 965120 The credit risk profile based on nonaccrual loans and a ccruing loans 90 days or more past was as follows:

December 31 2011 2010

Nonaccrual

loans Accruing loans 90 days or more past due Nonaccrual

loans Accruing loans 90 days or more past due (in thousands)

Real estate loans:

Residential 1-4 family $28,298 $ – $36,420 $ –
Commercial real estate 3,436 – –

– Home equity line of credit 2,258 – 1,659

–

Residential land 14,535 205 15,479 581

Commercial construction – – –

– Residential construction – – –

– Commercial loans 17,946 28 4,956 64

Consumer loans 281 308 341 320
Total $66,754 $541 $58,855 $965

The total carrying amount and the total unpaid princi pal balance of impaired loans was as follows:

December 31 2011 2010

(in thousands) Recorded

investment Unpaid principal

balance Related

Allowance A verage recorded

investment Interest

income recognized Recorded

investment Unpaid principal

balance Related

allowance A verage recorded

investment Interest

income recognized

With no related

allowance recorded

Real estate loans: Residential 1-4 family $ 19,217 $ 26,614 $

– $ 21,385 $ 282 $ 18,205 $ 24,692 $

– $14,609 $ 278
Commercial real estate 13,397 13,397

– 13,404 747 12,156 12,156

– 14,276 979 Home equity line of credit 711 1,612

– 954 6

– – – – – Residential land 30,781 39,136

– 33,398 1,779 33,777 40,802

– 29,914 1,499

Commercial construction

– – – – – – – – – – Residential construction

– – – – – – – – – – Commercial loans 41,680 43,516

– 40,952 2,912 22,041 22,041

– 29,636 1,846

Consumer loans 25 25

– 16

– – – – – – 105,811 124,300

– 110,109 5,726 86,179 99,691

– 88,435 4,602

With an allowance recorded

Real estate loans: Residential 1-4 family 3,525 3,525 203 3,527 201 3,917 3,917 230 2,807 175

Commercial real estate

– – – – – – – – – – Home equity line of credit

– – – – – – – – – – Residential land 7,792 7,852 2,525 8,158 603 5,041 5,090 1,642 3,753 327

Commercial construction

– – – – – – – – – – Residential construction

– – – – – – – – – – Commercial loans 6,561 6,561 976 8,131 737 6,845 6,845 1,588 2,796 182

Consumer loans

– – – – – – – – – – 17,878 17,938 3,704 19,816 1,541 15,803 15,852 3,460 9,356 684

Total

Real estate loans: Residential 1-4 family 22,742 30,139 203 24,912 483 22,122 28,609 230 17,416 453
Commercial real estate 13,397 13,397

– 13,404 747 12,156 12,156

– 14,276 979 Home equity line of credit 711 1,612

– 954 6

– – – – – Residential land 38,573 46,988 2,525 41,556 2,382 38,818 45,892 1,642 33,667 1,826

Commercial construction

– – – – – – – – – – Residential construction

– – – – – – – – – – Commercial loans 48,241 50,077 976 49,083 3,649 28,886 28,886 1,588 32,432 2,028

Consumer loans 25 25

– 16

– – – – – – $123,689 $142,238 $3,704 $129,925 $7,267 $101,982 $115,543 $3,460 $97,791 $5,286121 Troubled debt restructurings. A loan modification is deemed to be a TDR when ASB grants a concession it

would not otherwise consider were it not for the borrower’s financial difficult y. When a borrower fails to make a required payment on a loan or is in imminent default, ASB takes a number of steps to induce the borrower to cure the delinquency and restore the loan to current stat us or to avoid payment default. At times, ASB may restructure a loan to help a distressed borrower improve their financial position to eventually be able to fully repay the loan, provided the borrower has demonstr ated both the willingness and the ability to handle the

modified terms. TDR loans are considered an alternat ive to foreclosure or liquidation with the goal of minimizing losses to ASB and maximizing recovery. ASB may consider various types of concessions in granting a TDR including maturity date extensions, temporary deferral of principal pay ments, temporary interest rate reductions, and covenant amendments or waivers. ASB does not grant principal forgiveness in its TDR modifications. Residential loan modifications generally involve the deferral of prin cipal payments for a period of time not exceeding one year or a temporary reduction of principal and/or interest rate for a period of time generally not exceeding two years. Land loans are typically structured as a three- year term, interest-only monthly pay ment with a balloon payment due at maturity. Land loan TDR modifications typically involve extending the maturity date another one to three years and converting the payments from interest-only to principal and interest monthly, at t he same or higher interest rate. Commercial loan modifications generally involve ext ensions of maturity dates, amendment or waiver of
financial covenants, and to a lesser ext ent temporary deferral of princi pal payments. ASB does not reduce the

interest rate on commercial loan TDR modifications. O ccasionally, additional collat eral and/or guaranties are

obtained.

All TDR loans are classified impaired and are segregated and review ed separately when assessing the adequacy of the allowance for loan lo sses based on the appropriate method of measuring impairment: (1) present value of expected future cash flows discounted at the loan’s original effectiv e interest rate, (2) fair value of collateral less costs to sell, or (3) observabl e market price. The financia l impact of the calculated impairment amount is an increase to the allowance associated with the modified loan. When available information confirms that specific loans or portions th ereof are uncollectible (con firmed losses), these amounts are charged off against the allowance for loan losses. Loan modifications that occurred during 2011 were as follows:

2011 Outstanding recorded investment (dollars in thousands) Number of contracts Pre-modification Post-modification

Troubled debt restructurings

Real estate loans: Residential 1-4 family 42 $11,233 $ 9,853

Commercial real estate

– – – Home equity line of credit 1 93 93
Residential land 46 9,965 9,946
Commercial loans 56 35,349 35,349

Consumer loans 1 25 25
146 $56,665 $55,266

Loans modified in TDRs that experienced a payment default of 90 days or more in 2011, and for which the payment default occurred within one year of the modification, were as follows:

2011 (dollars in thousands) Number of contracts Recorded investment Troubled debt restructurings that subsequently defaulted

Real estate loans: Residential 1-4 family

– $

– Commercial real estate

– – Home equity line of credit

– – Residential land 1 528

Commercial loans 4 799

Consumer loans

– – 5 $1,327122 The residential land loan TDR that subsequently defau lted was modified by extending the maturity date.

The four commercial loans that subsequently defaulted were modified by extending the maturity date and deferring principal payments for a short period of time.

Deposit liabilities.

December 31 2011 2010 Weighted-average Weighted-average (dollars in thousands) stated rate Amount stated rate Amount

Savings 0.07% $1,684,875 0.12% $1,623,211 Other checking Interest-bearing 0.02 610,542 0.05 589,228 Noninterest-bearing – 538,214 – 473,297 Commercial checking – 455,614 – 392,345 Money market 0.21 236,641 0.28 230,990
Term certificates 0.98 544,146 1.25 666,301

0.18% $4,070,032 0.28% $3,975,372

As of December 31, 2011 and 2010, certificate a ccounts of $100,000 or more totaled $119 million and $153 million, respectively. The approximate amounts of term certificates outstanding as of De cember 31, 2011 with scheduled maturities for 2012 through 2016 were $325 million in 2012, $79 million in 2013, $45 million in 2014,
$56 million in 2015, $26 million in 2016, and $13 million thereafter. Interest expense on deposit liabilities by type of deposit was as follows:

(in thousands) 2011 2010 2009

Term certificates $6,393 $11,221 $27,369 Savings 1,756 2,262 4,952 Money market 650 884 886 Interest-bearing checking 184 329 839
$8,983 $14,696 $34,046

Other borrowings.

Securities sold under agreements to repurchase.

December 31, 2011

Maturity Repurchase liability Weighted-average

interest rate Collateralized by mortgage-related

securities and federal

agency obligations– fair value plus accrued interest (dollars in thousands)

Overnight $132,932 0.35% $156,478 1 to 29 days – – – 30 to 90 days – – – Over 90 days 50,297 4.75 63,930
$183,229 1.56% $220,408

At December 31, 2011, $50 million of securities sold under agreements to repurchas e with a rate of 4.75% and maturity date over 90 days is calla ble quarterly at par until maturity. The securities underlying the agreements to repurchas e are book-entry securities and were delivered by appropriate entry into the counterparties’ accounts at the Federal Reserve System. Securities sold under agreements to repurchase are account ed for as financing transactions and the obligations to repurchase

these securities are recorded as liabilities in the c onsolidated balance sheets. The securities underlying the agreements to repurchase continue to be re flected in ASB’s asset accounts.123 Information concerning securities sold under agreements to repurchase, which provided for the repurchase of identical securities, was as follows:

(dollars in millions) 2011 2010 2009

Amount outstanding as of December 31 $183 $172 $233 Average amount outstanding during the year $183 $201 $230 Maximum amount outstanding as of any month-end $186 $238 $241 Weighted-average interest rate as of December 31 1.56% 1.71% 1.38% Weighted-average interest rate during the year 1.61% 1.53% 1.55% Weighted-average remaining days to maturity as of December 31 490 628 544

Advances from Federal Home Loan Bank.

December 31, 2011 Weighted-average

stated rate Amount (dollars in thousands)

Due in
2012 –% $ –

2013 – –

2014 – –

2015 – –

2016 – –
Thereafter 4.28 50,000

4.28% $50,000

At December 31, 2011, $50 million of fixed rate FHLB advances with a rate of 4.28% is callable quarterly at par until maturity in 2017. ASB and the FHLB of Seattle are parties to an Ad vances, Security and Deposit Agreement (Advances Agreement), which applies to cu rrently outstanding and future adv ances, and governs the terms and

conditions under which ASB borrows and the FHLB of S eattle makes loans or advanc es from time to time. Under the Advances Agreement, ASB agrees to abide by the FHLB of Seattle’s credit policies, and makes certain warranties and representations to the FHLB of Seattle. Upon the o ccurrence of and during the

continuation of an “Event of Default” (which term includes any event of nonpayment of interest or principal of any advance when due or failure to perform any promise or obligation under the Adv ances Agreement or other credit arrangements between the parties), the FHLB of Seattle may, at its option, declare a ll indebtedness and accrued interest thereon, including any prepayment fees or charges, to be immediately due and payable.

Advances from the FHLB of Seattle are collateraliz ed by loans and stock in the FHLB of Seattle. ASB is required to obtain and hold a specific nu mber of shares of capital stock of the FHLB of Seattle. ASB was in compliance with all Advances Agreement r equirements as of December 31, 2011 and 2010.

Common stock equity. In 1988, HEI agreed with the OTS predec essor regulatory agency at the time, to contribute additional capital to ASB up to a maxi mum aggregate amount of appr oximately $65.1 million (Capital Maintenance Agreement). As of December 31, 2011, as a result of c apital contributions in prior years, HEI’s maximum obligation to contribute additional c apital under the Capital Maintenance Agreement had been reduced to approximately $28.3 million. As of December 31, 2011, ASB was in compliance with the minimum capital requirements under OCC regulations. In 2011, ASB paid cash dividends of $58 million and di stributed noncash dividends of $5 million to HEI, compared to cash dividends of $62 million in 2010. The noncash dividend was the fair value of assets

associated with an ASB office lease assumed by HEI. The FRB and OCC approved the dividends.

Guarantees. In October 2007, ASB, as a member financial institution of Visa U.S.A. Inc., received restricted shares of Visa, Inc. (Visa) as a resu lt of a restructuring of Visa U.S.A. Inc. in prep aration for an initial public offering by Visa. As a part of the restructuring, ASB entered into a judgment and loss sharing agreement with Visa in order to apportion financial responsibilities aris ing from any potential adv erse judgment or negotiated settlements related to indemnified litigation involv ing Visa. As of December 31, 2011, ASB had accrued $1.1 million related to the agreement. Because the ex tent of ASB’s obligations under this agreement depends124 entirely upon the occurrence of future events, ASB’s maximum potential future liability under this agreement is

not determinable.

Federal Deposit Insurance Corporation restoration plan. In November 2009, the Board of Directors of the Federal Deposit Insurance Co rporation (FDIC) approved a restor ation plan that required banks to prepay, by December 30, 2009, their estimated quarte rly, risk-based assessments fo r the fourth quarter of
2009, and for all of 2010, 2011 and 2012 . For the fourth quarter of 2009 and all of 2010, the prepaid assessment rate was assessed according to a ri sk-based premium schedule ado pted earlier in 2009. The prepaid assessment rate for 2011 and 2012 was the curr ent assessment rate plus 3 basis points. The prepaid assessment was recorded as a prepaid asset as of December 30, 2009, and each quarter thereafter ASB will record a charge to earnings for its regular quarterly assessment and offset the prepaid expense

until the asset is exhausted. Once the asset is ex hausted, ASB will record an accrued expense payable each quarter for the assessment to be paid. If the prepaid assessment is not exhausted by December 30, 2014, any remaining amount will be returned to ASB. ASB’s prepaid assessment was approximately $24 million. For the year ended December 31, 2010, ASB’s assessment rate was 14 basis points of deposits, or
$5.7 million. In February 2011, the FDIC finalized rules to c hange its assessment base from total domestic deposits to average total assets minus average tangible equity, as required in the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act). Assessment rates were reduced to a range of 2.5 to 9 basis points on the new assessment base for fi nancial institutions in the lowest risk category. Financial institutions in the highest risk category have assessment rates of 30 to 45 basis points. The new rate schedule was effective April 1, 2011. For the year ended December 31, 2011, ASB’s FDIC insurance assessment was $3.6

million. The FDIC may impose additional special assessments in the future if it is deemed necessary to ensure the Deposit Insurance Fund ratio does not decline to a le vel that is close to zero or that could otherwise undermine public confidence in federal deposit insurance.

Deposit insurance coverage. In July 2010, the Dodd-Frank Ac t permanently raised the current standard maximum deposit insurance amount to $250,000. Pr eviously, the standard maximum deposit insurance amount of $100,000 had been tem porarily raised to $250,000 through December 31, 2013.

Litigation. In March 2011, a purported class ac tion lawsuit was filed in the Firs t Circuit Court of the state of Hawaii by a customer who claimed that ASB had improperly charged overdr aft fees on debit card transactions. Management is evaluating the merits of the claims alleged in the lawsuit, which is still in its preliminary stage. Thus, the probable outcome and range of reas onably possible loss are not determinable. ASB is subject in the normal course of bus iness to pending and threatened legal proceedings. Management does not anticipate that the aggregate ultimate liability arising out of these pending or threatened legal proceedings will be material to its financial posit ion. However, ASB cannot ru le out the possibility that

such outcomes could have a material adverse effect on the results of operations or liquidity for a particular reporting period in the future.

5 • Unconsolidated variable interest entities

HECO Capital Trust III. HECO Capital Trust III (T rust III) was created and exists for the exclusive purposes of (i) issuing in March 2004 2,000,000 6.50% Cumulative Quarterly Income Preferred Securities, Series 2004 (2004 Trust Preferred Securities) ($50 million aggregat e liquidation preference) to the public and trust common securities ($1.5 million aggreg ate liquidation preference) to HECO, (ii) inve sting the proceeds of these trust securities in 2004 Debentures issued by HECO in the principal amount of $31.5 million and issued by HELCO and MECO each in the principal amount of $10 million, (iii) making distributions on these trust securities and (iv) engaging in only those other activities necessary or incidental thereto. The 2004

Trust Preferred Securities are m andatorily redeemable at the maturity of the underlying debt on March 18, 2034, which maturity may be extended to no later than March 18, 2053; and are currently redeemable at the issuer’s option without premium. The 2004 Debentures, together with t he obligations of HECO, HELCO and MECO under an expense agreement and HECO’s obligat ions under its trust guarantee and its guarantee of125 the obligations of HELCO and MECO under their respec tive debentures, are the sole assets of Trust III.

Trust III has at all times been an unconsolidated subsidia ry of HECO. Since HECO, as the common security holder, does not absorb the majority of the variability of Trust III, HECO is not the primary beneficiary and

does not consolidate Trust III in accordance with accoun ting rules on the consolidation of VIEs. Trust III’s
balance sheet as of December 31, 2011 consisted of $51.5 million of 2004 Debentures; $50.0 million of 2004 Trust Preferred Securities; and $1.5 m illion of trust common securities. Tr ust III’s income statement for 2011
consisted of $3.4 million of interest income receiv ed from the 2004 Debentures; $3. 3 million of distributions
to holders of the Trust Preferred Securities; and $0.1 million of common divi dends on the trust common securities to HECO. So long as the 2004 Trust Preferr ed Securities are outstanding, HECO is not entitled to receive any funds from Trust III other than pro-rata di stributions, subject to certain subordination provisions,

on the trust common securities. In the event of a default by HECO in the performance of its obligations under

the 2004 Debentures or under its G uarantees, or in the event HECO, HELCO or MECO elect to defer payment of interest on any of their respective 2004 De bentures, then HECO will be subject to a number of restrictions, including a prohibition on the payment of dividends on its common stock.

Power purchase agreements. As of December 31, 2011, HECO and its subsidiaries had six PPAs totaling 548 MW of firm capacity, and other PPAs with smaller IPPs and Schedule Q providers (i.e., customers with cogeneration and/or small power production facilities with a capacity of 100 kW or less who buy power from or sell power to the utilities), none of which are currently required to be consolidated as VIEs. Approximately 90% of the 548 MW of firm capacity is pursuant to PPAs, entered into before December 31, 2003, with AES Hawaii, Inc. (AES Hawaii), Kalaeloa, Hamakua Energy Partners, L.P. (HEP) and HPOWER. Purchases from all IPPs for 2011 totaled $690 million with purchas es from AES Hawaii, Kalaeloa, HEP and HPOWER totaling $133 million, $310 milli on, $59 million and $62 million, respectively. Some of the IPPs provided sufficient information fo r HECO to determine that t he IPP was not a VIE, or was either a “business” or “gov ernmental organization” (e.g., HPOW ER), and thus excluded from the scope of accounting standards for VIEs. Other IPPs, including the three largest, declined to provide the information necessary for HECO to determine the applicab ility of accounting standards for VIEs.
Since 2004, HECO has continued its efforts to obtain from the IPPs t he information necessary to make the determinations required under accounting standards for VIEs. In each year from 2005 to 2011, HECO

and its subsidiaries sent letters to the identified IPPs requesting the requir ed information. All of these IPPs declined to provide the necessary information, except that Kalaeloa provided the in formation pursuant to the amendments to its PPA (see below) and an entity owning a wind farm prov ided information as required under its PPA. Management has concluded that the consolidation of two entities owning wind farms was not required as HELCO and MECO do not have variable in terests in the entities because the PPAs do not require them to absorb any variability of the entities. If the requested information is ultimately received fr om the remaining IPPs, a po ssible outcome of future analyses of such information is the consolidation of one or more of such IPPs in HECO’s consolidated

financial statements. The cons olidation of any significant IPP could have a material effect on the Company’s

and HECO’s consolidated financial stat ements, including the recognition of a significant amount of assets
and liabilities and, if such a consolidated IPP we re operating at a loss and had insufficient equity, the potential recognition of such losses. If HECO and its subs idiaries determine they ar e required to consolidate

the financial statements of such an IPP and the consolidation has a material effect, HECO and its subsidiaries would retrospectively apply accounting standards for VIEs.

Kalaeloa Partners, L.P. In October 1988, HECO entered into a PPA with Kalaeloa, subsequently approved by the PUC, which provided that HECO would purchase 180 MW of firm capacity for a period of 25 years beginning in May 1991. In October 2004, HE CO and Kalaeloa entered in to amendments to the PPA, subsequently approved by the PUC, which together effectively increased the firm capacity from 180 MW to 208 MW. The energy payments that HECO makes to Kalaeloa include: (1) a fuel component, with a fuel price adjustment based on the cost of low sulfur fuel oil, (2) a fuel additives cost component, and (3) a non-fuel component, with an adjustment based on changes in the Gross National Product Implicit Price Deflator. The capacity payments that HECO makes to Kalaeloa are fixed in accordance with the PPA.126 Kalaeloa also has a steam delivery cogeneration contract with another customer, the term of which coincides with the PPA. The facility has been certified by the Federal Energy Regulatory Commission as a Qualifying Facility under the Public Ut ility Regulatory Policies Act of 1978. Pursuant to the current accounting standards for VI Es, HECO is deemed to hav e a variable interest in Kalaeloa by reason of the provisions of HECO’s PPA with Kalaeloa. However, management has concluded that HECO is not the primary beneficiary of Kalaeloa because HECO does not have the power to direct the activities that most significantly impact Kalaeloa’ s economic performance nor the obligation to absorb Kalaeloa’s expected losses, if any, that could potentially be significant to Kalaeloa. Thus, HECO has not

consolidated Kalaeloa in its consolid ated financial statements. A significant factor affecting the level of expected losses HECO could potentially absorb is the fact that HECO’s exposure to fuel price variability is limited to the remaining term of t he PPA as compared to the facility’s re maining useful life. Although HECO absorbs fuel price variability for t he remaining term of the PPA, the PPA does not currently expose HECO to losses as the fuel and fuel related energy paym ents under the PPA have been approved by the PUC for recovery from customers through base electric rates and through HECO’s ECAC to the extent the fuel and fuel related energy payments are not included in base energy rates.

6 • Interest rate swap agreements

In June 2010, HEI entered into multiple Forward Starting Swaps (FSS) with notional amounts totaling $125 million to hedge against interest rate fluctuations on medium-term notes expected to be issued by HEI in 2011, thereby enabling HEI to bette r forecast its future interest expense. The FSS entitled HEI to receive/(pay) the present value of the positive/(negative) difference between three-month LIBOR and a fixed rate at termination applied to t he notional amount over a five-year period. The outstanding FSS were designated and accounted for as cash flow hedges an d had a negative fair value of $2.8 million as of December 31, 2010 (recorded in “Other ” liabilities). Changes in fair val ue were recognized (1) in other comprehensive income to the extent that they were considered effective, and (2) in “Interest expense—other than on deposit liabilities and ot her bank borrowings” for any portion considered ineffective. In 2011, HEI settled the FSS for payments totaling $5.2 million, of which $3.3 milli on was the ineffective portion ($0.8 million and $2.5 milli on recognized in 2010 and 2011, respectively) and $1.9 million being amortized to interest expense over five years beginn ing March 24, 2011 (the date that HEI issued $125 million of Senior Notes via a private placement).

7 • Short-term borrowings

As of December 31, 2011 and December 31, 2010, HEI had $69 million and $25 million of outstanding commercial paper, respectively, with a weighted-average interest rate of 0.8% and 0.9%, respectively, and HECO had no commercial paper outstanding.
As of December 31, 2011, HEI and HECO each main tained a syndicated credit facility of $125 million and $175 million, respectively. Both HEI and HECO had no borrowings under its facility during 2011 and

2010. None of the facilitie s are collateralized.

Credit agreements. Effective December 5, 2011, HEI and a syndi cate of eight financial institutions entered into an amendment to their revolving unsecured credi t agreement. The amendment revised the pricing of HEI’s $125 million line of credit facility (with a letter of cr edit sub-facility) and extended the term of the facility to December 5, 2016. Any draws on the facility bear interest at the “Adjus ted LIBO Rate”, as defined in the agreement, plus 150 basis points or the greatest of (a) the “Prime Rate,” (b) the sum of the “Federal Funds Rate” plus 50 basis points and (c) the “Adjusted LIBO Rate” for a one month “Interest Period” plus 50 basis points per annum, as defined in the agreement. Annual fees on undrawn commitments are 25 basis points. The amended agreement contains provisions for revised pricing in the event of a long-term ratings change. The agreement does not contain clauses that would a ffect access to the lines by reason of a ratings downgrade, nor does it have broad “material adverse change” clauses. However, the agreement does contain customary conditions that must be met in or der to draw on it, including compliance with its

covenants.127 The facility will be maintained to support the i ssuance of commercial paper, but also may be drawn to repay HEI’s short-term and long-term indebtedness, to ma ke investments in or loans to subsidiaries and for HEI’s working capital and general corporate purposes. Effective December 5, 2011, HECO and a syndicate of eight financial institutions entered into an amendment to their revolving unsecured credit agreem ent. The amendment revised the pricing of HECO’s $175 million line of credit facility (wit h a letter of credit sub-facility). The credit agreement, as amended, has a term which expires on December 5, 2016. Any draws on the facility bear interest at the “Adjusted LIBO Rate”, as defined in the agreement, plus 150 basis points or the gr eatest of (a) the “Prime Ra te,” (b) the sum of the “Federal Funds Rate” plus 50 basis points and (c) the “A djusted LIBO Rate” for a one month “Interest Period” plus 50 basis points per annum, as defined in the agreement. Annual fees on undrawn commitments are 25 basis points. The amended agr eement contains provisions for revised pricing in the event of a long-term ratings change. The agreement does not c ontain clauses that would affect a ccess to the lines by reason of a ratings downgrade, nor does it hav e broad “material adverse change” cl auses. However, the agreement does contain customary conditions that must be met in order to draw on it, including comp liance with its covenants. The credit facility will be maintained to support the issuance of commercial paper, but also may be drawn to repay HECO’s short-term indebtedness, to make loans to subsidiaries and for HECO’s capital expenditures, working capital and general corporate purposes.

8 • Long-term debt

December 31 2011 2010 (dollars in thousands)

6.50% Junior Subordinated Deferrable Interest Debentures, Series 2004, due 2034 (see Note 5) $ 51,546 $ 51,546

Obligations to the State of Hawaii for the repayment of special purpose revenue bonds issued on behalf of electric utility subsidiaries

4.75-4.95%, due 2012-2025 118,500 118,500
5.00-5.50%, due 2014-2032 203,400 203,400
5.65-5.75%, due 2018-2027 216,000 216,000
6.15-6.20%, due 2020-2029 55,000 55,000
4.60-4.65%, due 2026-2037 265,000 265,000
6.50%, due 2039 150,000 150,000

1,007,900 1,007,900 Less unamortized discount (1,376) (1,504)

1,006,524 1,006,396

HEI medium-term notes 4.23-6.141%, paid in 2011 – 150,000
HEI medium-term note 7.13%, due 2012 7,000 7,000
HEI medium-term note 5.25%, due 2013 50,000 50,000
HEI medium-term note 6.51%, due 2014 100,000 100,000
HEI senior note 4.41%, due 2016 75,000 –
HEI senior note 5.67%, due 2021 50,000 –
$ 1,340,070 $ 1,364,942

As of December 31, 2011, the aggregate principal payments required on long-term debt for 2012 through 2016 are $65 million in 2012, $50 milli on in 2013, $111 million in 2014, nil in 2015 and $75 million in 2016.

9 • Retirement benefits

Defined benefit plans. Substantially all of the em ployees of HEI and the electric utilities participate in the Retirement Plan for Employees of Hawaiian Electric I ndustries, Inc. and Participati ng Subsidiaries (HEI/HECO Pension Plan). Substantially all of the employees of ASB and its subsidiaries participated in the American Savings Bank Retirement Plan (ASB Pension Plan) unt il it was frozen on December 31, 2007. The HEI/HECO Pension Plan and the ASB Pension Plan (c ollectively, the Plans) are qualifi ed, noncontributory defined benefit128 pension plans and include benefits for union employees determined in accordance with the terms of the collective bargaining agreements between the utilities and their respective unions. The Plans are subject to the provisions of ERISA. In addition, some current and form er executives and directors of HEI and its subsidiaries participate in noncontributory, nonqualifie d plans (collectively, Supplement al Plans). In general, benefits are based on the employees’ or directors’ years of service and compensation. The continuation of the Plans and the Supplement al Plans and the payment of any contribution thereunder are not assumed as contractual obligations by the participating empl oyers. The Supplemental

Plan for directors has been frozen since 1996. The ASB P ension Plan was frozen as of December 31, 2007. The HEI Supplemental Executive Retirement Plan and ASB Supplemental Executive Retirement, Disability, and Death Benefit Plan (noncontri butory, nonqualified, defined benefit plans) were frozen as of December 31, 2008. No participants have accrued any benefit s under these plans after the respective plan’s freeze and the plans will be terminated at t he time all remaining benefits have been paid. Each participating employer reserves the right to terminate its partici pation in the applicable plans at any time, and HEI and ASB reserve the right to terminate thei r respective plans at any time. If a participating employer terminates its participation in the Plans, the interest of each affected participant would become 100% vested to the extent funded. Upon t he termination of the Plans, assets would be distributed to affected participants in accordance with the appl icable allocation provisions of ERI SA and any excess assets that exist would be paid to the participating empl oyers. Participants’ benefits in the Pl ans are covered up to certain limits under insurance provided by the Pens ion Benefit Guaranty Corporation. To determine pension costs for HEI and its subsidia ries under the Plans and the Supplemental Plans, it is necessary to make complex calculations and es timates based on numerous assumptions, including the assumptions identified below.

Postretirement benefits other than pensions. HEI and the electric utilities pr ovide eligible employees health and life insurance benefits upon retirement under the Postretirement Welfare Benefits Plan for Employees of Hawaiian Electric Company, Inc. and participating employ ers (HECO Benefits Plan). E ligibility of employees and dependents are based on eligibility to retire at termi nation, the retirement date and the date of hire. The plan was amended in 2011, changing eligib ility for certain bargaining unit employees hired prior to May 1, 2011, based on new minimum age and service requirement s effective January 1, 2012, per the collective bargaining agreement, and certain managem ent employees hired prior to Ma y 1, 2011 based on new eligibility minimum age and service requirements effectiv e January 1, 2012. The minimum age and service requirements for management and bar gaining unit employees hired May 1, 2011 and thereafter have increased and their dependents are not eligible to receive postretirement benefits. Employees may be eligible

to receive benefits from the HEI/HEC O Pension Plan but may not be elig ible for postretirement welfare benefits if the different eligib ility requirements are not met. The executive death benefit plan was frozen on Sept ember 10, 2009 to participant s and benefit levels as

of that date. The electric disc ount was eliminated for management empl oyees and retirees of HECO in August 2009, HELCO in November 2010, and MECO in August 2010, and for bargaining unit employees and retirees on January 31, 2011 per the collective bargai ning agreement. The Company’s cost for OPEB has been adjusted to reflect the plan amendment, which reduc ed benefits. The elimination of the electric discount benefit will generate credits through ot her benefit costs over the next few years as the total amendment credit

is amortized. Each participating employer reserv es the right to terminate its parti cipation in the plan at any time.

Balance sheet recognition of the funded status of retirement plans. Employers must recognize on their

balance sheets the funded stat us of defined benefit pension and other postretirement benefit plans with an offset to AOCI in shareholders’ equity (using the pr ojected benefit obligation ( PBO), to calculate the funded status). The PUC allowed the utilities to adopt pension and OPEB tracking mechanisms in re cent rate cases. The amount of the net periodic pension cost (NPPC) and net periodic benefits costs (NPBC) to be recovered in rates is established by the PUC in each rate case. Under the utilities’ tracking mec hanisms, any actual costs determined in accordance with U.S. generally accepted accounting principles that are over/under amounts129 allowed in rates are charged/credited to a regulatory asset/liabilit y. The regulatory asset/liability for each utility will then be amortized over 5 years beginning with the re spective utility’s next rate case. Accordingly, all retirement benefit expenses (except for exec utive life and nonqualif ied pension plan expenses, which amounted to $1.6 million in 2011) det ermined in accordance with U.S. generally accepted accounting principles will be recovered. Under the tracking mechanisms, amounts that w ould otherwise be recorded in AOCI (excluding amounts for executive life and nonqua lified pension plans), which am ounts include the prepaid pension asset, net of taxes, as well as other pension and OP EB charges, are allowed to be reclassified as a regulatory asset, as those costs will be recovered in rates through the NPPC and NPBC in the future. The electric utilities have reclassified to a regulatory asse t charges for retirement benefits that would otherwise be recorded in AOCI (amounting to t he elimination of a potent ial charge/(credit) to AOCI of $165 million pretax and $55 million pretax for 2011 and 2010, respectively). In 2007, the PUC allowed HELCO to record a regulat ory asset in the amount of $12.8 million (representing HELCO’s prepaid pension asset and reflecting the accumu lated pension contributions to its pension fund in excess of accumulated NPPC), which is included in ra te base, and allowed recovery of that asset over a period of five years. HELCO is required to make c ontributions to the pension tr ust in the amount of the actuarially calculated NPPC that would be allowed without penalty by the tax laws.
In 2007, the PUC declined to allow HECO and MECO to include their pension assets (representing the

accumulated contributions to thei r pension fund in excess of accumula ted NPPC), in their rate bases. However, under the tracking mechanisms, HECO and ME CO are required to fund only the minimum level required under the law until their pension assets are re duced to zero, at which time HECO and MECO will make contributions to the pension trust in the amount of the actuarially calculated NPPC, except when limited by the ERISA minimum contribution requirem ents or the maximum con tribution limitations on deductible contributions imposed by the Internal Revenue Code. The PUC’s exclusion of HECO’s and MECO’s pensi on assets from rate base does not allow HECO and MECO to earn a return on the pension asset, but this exclusion does not result in the exclusion of any pension benefit costs from their ra tes. The pension asset is to be ( and has been, in the case of MECO) recovered in rates (as NPPC is recorded in excess of contributions). As of December 31, 2011, HECO’s pension asset had been reduced to $3 million. The OPEB tracking mechanisms generally require the electric utilities to make contributions to the

OPEB trust in the amount of the ac tuarially calculated NPBC, except when limited by material, adverse consequences imposed by federal regulations. Retirement benefits expense for the electr ic utilities for 2011, 2010 and 2009 was $34 million, $39 million and $32 million, respectively.

Retirement benefit plan changes. On March 11, 2011, the utilities’ bargaining unit employees ratified a new benefit agreement, which included changes to retirement benefits. Changes to reti rement benefits for HEI and utility employees commencing employment after Apr il 30, 2011 include a modified defined benefit plan (the Retirement Plan for Employees of Hawaiian Electric I ndustries, Inc. and Participating Subsidiaries) (with a lower payment formula than the formula in the plan fo r employees hired before Ma y 1, 2011) and the addition of a 50% match by the applicable employ er on the first 6% of employee elec tive deferrals by such employees through the defined contribution plan (under the Hawa iian Electric Industries Retirement Savings Plan (HEIRSP)). In addition, new eligib ility rules and contribution levels applicable to existing and new HEI and utility employees were adopted for postretirement we lfare benefits. In general, defined pension benefits are based on the employees’ years of service and compensation.130 Defined benefit and pension and other pos tretirement benefit plans information. The changes in the obligations and assets of the Com pany’s retirement benefit plans and the changes in AOCI (gross) for 2011

and 2010 and the funded status of these plans and amounts related to these plans reflected in the Company’s

consolidated balance sheet as of Dece mber 31, 2011 and 2010 were as follows:

2011 2010

(in thousands) Pension

benefits Other

benefits Pension

benefits Other

benefits
Benefit obligation, January 1 $1,174,534 $180,332 $1,014,287 $170,572
Service cost 35,016 4,409 28,801 4,739
Interest cost 64,966 9,534 64,527 10,378 Amendments – (11,365) – (7,713)
Actuarial losses 104,970 16,518 121,898 11,817 Benefits paid and expenses (57,056) (8,879) (54,979) (9,461) Benefit obligation, December 31 1,322,430 190,549 1,174,534 180,332

Fair value of plan assets, January 1 832,356 151,117 738,971 134,608 Actual return (loss) on plan assets (9,713) (2,308) 119,446 21,271 Employer contribution 72,931 2,030 27,803 3,989 Benefits paid and expenses (55,994) (7,847) (53,864) (8,751) Fair value of plan assets, December 31 839,580 142,992 832,356 151,117

Accrued benefit liability, December 31 (482,850) (47,557) (342,178) (29,215)

AOCI, January 1 (excluding impact of PUC D&Os) 366,552 9,036 302,147 14,693 Recognized during year – net recognized transition obligation (2) – (2) – Recognized during year – prior service credit 389 1,494 388 396 Recognized during year – net actuarial gai ns (losses) (16,987) (234) (7,392) 14 Occurring during year – prior service cost – (11,365) – (7,714) Occurring during year – net actuarial losses 183,585 29,753 71,411 1,647

533,537 28,684 366,552 9,036 Cumulative impact of PUC D&Os (486,710) (29,183) (340,187) (10,880)

AOCI, December 31 46,827 (499) 26,365 (1,844)

Net actuarial loss 534,054 48,152 367,456 18,633 Prior service gain (518) (19,468) (907) (9,597) Net transition obligation 1 – 3 –

533,537 28,684 366,552 9,036 Cumulative impact of PUC D&Os (486,710) (29,183) (340,187) (10,880)

AOCI, December 31 46,827 (499) 26,365 (1,844) Income taxes (benefits) (18,495) 194 (10,403) 717

AOCI, net of taxes (benefits), December 31 $ 28,332 $ (305) $ 15,962 $ (1,127)

The dates used to determine retirement benefit measurements for the defi ned benefit plans were
December 31 of 2011, 2010 and 2009. The defined benefit pension plans with accumulated benefit obligations (ABOs ), which do not consider projected pay increases (unlike the PBOs shown in the table above), in excess of plan assets as of December 31, 2011 and 2010, had aggregat e ABOs of $1,182 million and $990 million, respectively, and plan assets of $840 million and $758 million, respectively. The Pension Protection Act provides that if a pension plan’s funded status falls below certain levels, more conservative assumptions must be used to value obligations under the pensio n plan and restrictions on participant benefit accruals may be placed on the plan. The HEI Retirement Plan has fallen below these thresholds and the minimum required contribution esti mated for 2012 incorporates the more conservative assumptions required. Other factors could cause changes to the required contribution levels. Effective April 1, 2011, accelerated distribution options (the $50,000 single su m distribution option and a Social Security level income option) under the HEI Re tirement Plan became subject to partial restrictions

because the funded status of the HEI Retirement Pl an was deemed to be less than 80%. Generally, while the partial restrictions are in effect, a retiring participant may only elect an a ccelerated distribution option for 50% of the participant’s total benefit. The partial re strictions are expected to continue through 2012.131 The Company estimates that the cash funding for the qualified defined benef it pension plans in 2012
and 2013 will be $104 million and $89 million, respectively, which should fully satisfy the minimum required contributions to those plans, including requi rements of the utilities pe nsion tracking mechanisms and the Plan’s funding policy. The Com pany’s current estimate of cont ributions to the qualified defined benefit plans and all other retirement benefit plans in 2012 is $107 million.
As of December 31, 2011, the benef its expected to be paid under the re tirement benefit plans in 2012, 2013, 2014, 2015, 2016, and 2017 through 2021 amounted to $69 million, $72 million, $75 million, $78 million, $82 million and $469 million, respectively. The Company has determined the market-related value of retirement benefit plan assets by calculating the difference between the expected return and the actual return on the fair value of the plan assets, then amortizing the difference over future years – 0% in t he first year and 25% in years two to five – and finally adding or subtracting the unamortized differences for the past four years from fair value. The method includes a 15% range around the fair value of such assets (i.e., 85% to 115% of fair value ). If the market-related value is outside the 15% range, then the am ount outside the range will be recognized immediately in the calculation

of annual NPBC. A primary goal of the plans is to achieve long-te rm asset growth sufficient to pay future benefit obligations at a reasonable level of risk. The inve stment policy target for defined benefit pension and OPEB plans reflects the philosophy that long-term growth can best be achieved by prudent investments in equity securities while balancing overall fund volatility by an appropriate allocation to fixed income securities. In order to reduce the level of portfolio risk and volatility in returns, efforts have been made to diversify the plans’ investments by asset class, geographic region, market capitalization and investment style. The weighted-average asset allocation of def ined benefit retirement plans was as follows:

Pension benefits Other benefits Investment policy Investment policy December 31 2011 2010 Target Range 2011 2010 Target Range Asset category Equity securities 68% 71% 70% 65-75% 69% 70% 70% 65-75%

Fixed income 32 29 30 25-35% 31 30 30 25-35%

100% 100% 100% 100% 100% 100%

See Note 15 for additional disclosures about the fair value of the retirement benefit plans’ assets. The following weighted-average assumptions we re used in the accounting for the plans:

Pension benefits Other benefits

December 31 2011 2010 2009 2011 2010 2009

Benefit obligation

Discount rate 5.19% 5.68% 6.50% 4.90% 5.60% 6.50% Rate of compensation increase 3.5 3.5 3.5 NA NA NA Net periodic benefit cost (years ended)

Discount rate 5.68 6.50 6.625 5.60 6.50 6.50
Expected return on plan assets 8.00 8.25 8.25 8.00 8.25 8.25 Rate of compensation increase 3.5 3.5 3.5 NA NA 3.5

NA Not applicable

The Company based its selection of an assumed di scount rate for 2012 NPBC and December 31, 2011 disclosure on a cash flow matching analysis that utiliz ed bond information provided by Bloomberg for all non-callable, high quality bonds (i.e., rated AA- or better) as of December 31, 2011. In selecting the expected rate of return on plan assets of 7.75% for 2012 NPBC, the Company considered economic forecasts for the types of investments held by the plans (primarily equity and fixed income investments), the Plans’ asset allocations and the past performance of the plans’ assets.
As of December 31, 2011, the assumed health care trend rates fo r 2012 and future years were as follows: medical, 8.5%, grading down to 5% for 2019 and thereafter; dental, 5%; and vision, 4%. As of
December 31, 2010, the assumed health care trend ra tes for 2011 and future years were as follows: medical, 9%, grading down to 5% for 201 9 and thereafter; dental, 5%; and vision, 4%.132 The components of NPBC were as follows:

Pension benefits Other benefits (in thousands) 2011 2010 2009 2011 2010 2009

Service cost $ 35,016 $ 28,801 $ 25,688 $ 4,409 $ 4,739 $ 4,846
Interest cost 64,966 64,527 61,988 9,534 10,378 10,981 Expected return on plan assets (68,901) ( 68,959) (57,244) (10,650) (11,101) (8,902) Amortization of net transition obligation 2 2 2 – – 1,831 Amortization of net prior service gain (389) (388) (387) (1,494) (396) (79) Amortization of net actuarial loss (gain) 16,987 7,392 15,847 234 (14) 401 Net periodic benefit cost 47,681 31,375 45,894 2,033 3,606 9,078 Impact of PUC D&Os (3,516) 10,207 (10,570) 2,674 5,400 (132) Net periodic benefit cost (adjusted for impact

of PUC D&Os) $ 44,165 $ 41,582 $ 35,324 $ 4,707 $ 9,006 $ 8,946

The estimated prior service credit, net actuarial loss and net transition ob ligation for defined benefit pension plans that will be amortized fr om AOCI or regulatory assets into net periodic pension benefit cost during 2012 are $(0.3) million, $25.7 m illion and de minimis, respectively. The estimated prior service cost (gain), net actuarial loss and net tr ansitional obligation for other benefit plans that will be amortized from AOCI or regulatory assets into net periodic other than pension benefit cost dur ing 2012 are $(1.8) million, $1.8 million and nil, respectively. The Company recorded pension expense of $32 m illion, $32 million and $27 mill ion and OPEB expense of $4 million, $7 million and $7 million in 2011, 2010 and 2009, respectively, and charged the remaining amounts primarily to electric utility plant. All pension plans and other benefits plans, with the exception of the ASB Retirement Plan at December 31, 2010, had ABO exceeding plan assets as of December 31, 2011 and December 31, 2010. The health care cost trend rate assumptions can have a significant effect on the amounts reported for
other benefits. As of December 31, 2011, a one-percentage-point increase in the assumed health care cost

trend rates would have increased the total service and interest cost by $0.2 million and the accumulated postretirement benefit obligation (APBO) by $4 m illion, and a one-percentage-point decrease would have

reduced the total service and interest cost by $0.2 million and the APBO by $5 million.

Defined contribution plans information. The ASB 401(k) Plan is a defined contribution plan, which includes a discretionary employer profit s haring contribution (AmeriShare). Changes to retirement benefits for HEI and utility em ployees commencing employment after April 30, 2011 include a reduction of benefits prov ided through the defined benefit plan and the addition of a 50% match by the applicable employer on the first 6% of employee de ferrals through the defined contribution plan (under the

Hawaiian Electric Industries Retirement Savings Plan). For 2011, 2010 and 2009, the Company’s expense for it s defined contribution pen sion plans under the HEIRSP and the ASB 401(k) Plan was $3 million, $4 million and $3 million, respectively, and cash contributions were $4 million for each year.133 10 • Share-based compensation

Under the 2010 Equity and Incentive Plan (EIP) HEI can issue an aggregate of 4 million shares of common stock as incentive compensation to selected employees in the form of stock options, stock appreciation rights, restricted shares, restricted st ock units, performance shar es and other share-based and

cash-based awards. From inception through December 31, 2011, grants under the EIP consisted of 18,009 restricted shares (counted against the shares authorized for issuance under t he EIP as four shares fo r every share issued, or 72,036 shares), 178,286 restricted stock units (which will be counted against the shares authorized for

issuance under the EIP as four shares for ever y share issued when iss ued or 713,144 shares) and 368,323 shares that may be issued under the 2011-2013 long-term incentive plan (LTIP) at maximum levels. Under the 1987 Stock Option and Incentive Plan, as amended (SOIP), grants and awards of an

estimated 0.6 million shares of co mmon stock (based on various assumptions, including LTIP awards at
maximum levels and the use of the December 31, 201 1 market price of shares as the price on the exercise/payment dates) were outstandi ng as of December 31, 2011 to selected employees in the form of nonqualified stock options (NQSOs), stock appreciation rights (SARs) , restricted stock units, LTIP performance and other shares and dividend equivalents. As of May 11, 2010 (when the EIP became effective), no new awards may be granted under the SO IP. After the shares of common stock for the outstanding SOIP grants and awards are issued or such grants and awards expire , the remaining shares registered under the SOIP will be deregistered and delisted. For the NQSOs and SARs outstanding under the SOIP, the exercise price of each NQSO or SAR generally equaled the fair market value of HEI’s stock on or near the date of grant. NQSOs, SARs and related dividend equivalents issued in the form of sto ck awards generally became exercisable in installments of 25% each year for four years, and expire if not exercised ten years from the date of the grant. NQSOs and SARs compensation expense has been recognized in a ccordance with the fair value-based measurement method of accounting. The estimated fair value of each NQSO and SAR grant was calculated on the date of grant using a Binomial Option Pricing Model.

The restricted shares that have been issued under the EIP become unrestricted in four equal annual

increments on the anniversaries of t he grant date and are forfeited to the extent they have not become unrestricted for terminations of empl oyment during the vesting period, exc ept accelerated vesting is provided for terminations by reason of death, disability and term ination without cause. Restricted stock awards under the SOIP generally become unrestricted four years after the date of grant and are forfe ited for terminations of employment during the vesting period, except that pro-rata vesting is pr ovided for terminations by reason of death, disability or termi nation without cause. Restricted shares and restricted stock awards compensation expense has been recognized in accordance with the fa ir-value-based measurement method of accounting.

Dividends on restricted shares and restricted stock awards are paid quarterly in cash.

Restricted stock units awarded under the EIP in 2011 will vest and be issued in unrestricted stock in four equal annual increments on the anniversar ies of the grant date and are forfeit ed to the extent they have not

become vested for terminations of em ployment during the vesting period, except that pro-rata vesting is provided for terminations due to death, disability and retirement. Rest ricted stock units awarded under the SOIP and EIP in 2010 and prior years generally vest and will be issued as unrestricted stock four years after the date of the grant and are forfeited for terminations of employment during the ve sting period, except that pro-rata vesting is provided for te rminations due to death, disability a nd retirement. Restricted stock units expense has been recognized in accordance with the fa ir-value-based measurement method of accounting. Dividend equivalent rights are accrued quarterly and are paid in cash at the end of the restriction period

when the restricted stock units vest. Stock performance awards granted under t he 2009-2011, 2010-2012 and 2011-2013 LTIPs entitle the grantee to shares of common stock with dividend equ ivalent rights once service conditions and performance conditions are satisfied at the end of the three-year performance period. LTIP awards are forfeited for terminations of employment during t he performance period, except that pr o-rata participation is provided for
terminations due to death, disabi lity and retirement based upon comple ted months of service after a minimum of 12 months of service in the perfo rmance period. Compensati on expense for the stock134 performance awards portion of the LTIP has been recognized in acco rdance with the fair-value-based

measurement method of account ing for performance shares. The Company’s share-based compens ation expense and related income tax benefit were as follows:

(in millions) 2011 2010 2009

Share-based compensation expense 1 $3.8 $2.7 $1.1

Income tax benefit 1.3 0.9 0.3

1 The Company has not capitalized any share-based compensation cost.

Nonqualified stock options. Information about HEI’s NQ SOs was as follows:

2011 2010 2009 Shares (1) Shares (1) Shares (1)

Outstanding, January 1 215,500 $20.76 374,500 $19.73 375,500 $19.73

Granted – –

– – – – Exercised (160,000) 20.70 (157,000) 18.32

– – Forfeited – –

– – – – Expired – – (2,000) 20.49 (1,000) 17.61 Outstanding, December 31 55,500 $20.92 215,500 $20.76 374,500 $19.73

Exercisable, December 31 55,500 $20.92 215,500 $20.76 374,500 $19.73

(1) Weighted-average exercise price

December 31, 2011 Outstanding & Exercisable (Vested)

Year of

Grant Range of exercise prices Number of options Weighted-average remaining

contractual life Weighted-average

exercise price

2002 $ 21.68 20,000 0.3 $21.68

2003 20.49 35,500 1.0 20.49
$20.49 – 21.68 55,500 0.7 $20.92

As of December 31, 2011, all NQSOs outstanding were exercisabl e and had an aggregate intrinsic value (including dividend equivalents) of $0.5 million. NQSO activity and statistics were as follows:

(dollars in thousands) 2011 2010 2009

Cash received from exercise $3,312 $2,876

– Intrinsic value of shares exercised 1 1,270 1,355

– Tax benefit realized for the deduction of exercises 181 278

–

1 Intrinsic value is the amount by which the fair market value of the underlying stock and the related dividend equivalents exceeds the exercise price of the option.

Stock appreciation rights. Information about HEI’s SARs is summarized as follows:

2011 2010 2009 Shares (1) Shares (1) Shares (1)

Outstanding, January 1 450,000 $26.13 480,000 $26.13 791,000 $26.12

Granted – – – – – – Exercised (110,000) 26.09

– – – – Forfeited – – – – (6,000) 26.18 Expired (58,000) 26.13 (30,000) 26.18 (305,000) 26.10 Outstanding, December 31 282,000 $26.14 450,000 $26.13 480,000 $26.13

Exercisable, December 31 282,000 $26.14 450,000 $26.13 480,000 $26.13

(1) Weighted-average exercise price135 December 31, 2011 Outstanding & Exercisable (Vested)

Year of

Grant Range of exercise prices Number of shares underlying SARs Weighted-average remaining

contractual life Weighted-average exercise price

2004 $ 26.02 72,000 2.3 $26.02

2005 26.18 210,000 2.6 26.18
$26.02 –26.18 282,000 2.5 $26.14

As of December 31, 2011, all SARs outstanding were exercisable and had an aggregate intrinsic value (including dividend equivalent s) of $0.2 million. SARs activity and statistics were as follows:

(dollars in thousands, except prices) 2011 2010 2009

Shares vested –

– 228,000 Aggregate fair value of vested shares –

– $1,354

Intrinsic value of shares exercised 1 $64

– – Tax benefit realized for the deduction of exercises $25

– – Dividend equivalent shares di stributed under Section 409A –

– 3,143 Weighted-average Section 409A distribution price –

– $13.64

Intrinsic value of shares distributed under Section 409A –

– $43

Tax benefit realized for Section 409A distributions –

– $17

1 Intrinsic value is the amount by which the fair market value of the underlying stock and the related dividend equivalents excee ds the exercise price of the right.

Section 409A. As a result of the changes enacted in Secti on 409A of the Internal Revenue Code of 1986, as amended (Section 409A), in 2009, a total of 3,143 dividend equivalent shares, respectively, for NQSO and SAR grants were distributed to SOIP participants. Section 409A, which amended the federal income tax rules governing deferred compensati on, required the Company to change the way certain affected dividend equivalents are paid in order to avoid significant adverse tax consequences to the SOIP participants. Generally, dividend equivalents subject to Section 409A will be paid within 21⁄2 months after the end of the calendar year. Upon retirement, an SOIP participant may elect to take di stributions of dividend equivalents subject to Section 409A at the time of retirement or at the end of the calendar year. The dividend equivalents associated with the 2005 SAR grants had no intrinsic val ue at December 31, 2009; thus, no distribution was made in 2010. No further dividend equi valents are intended to be paid in a ccordance with this Section 409A

modified distribution.

Restricted shares and rest ricted stock awards. Information about HEI’s grants of restricted shares and

restricted stock awards was as follows:

2011 2010 2009 Shares (1) Shares (1) Shares (1)

Outstanding, January 1 89,709 $24.64 129,000 $25.50 160,500 $25.51

Granted –

– 18,009 (2) 22.21

– – Vested (40,102) 24.83 (43,565) 26.29 (3,851) 24.52 Forfeited (2,800) 24.93 (13,735) 24.35 (27,649) 25.67 Outstanding, December 31 46,807 $24.45 89,709 $24.64 129,000 $25.50

(1) Weighted-average grant-date fair value per share. The grant date fair value of a restricted stock award share was the closing o r average price of HEI common stock on the date of grant. (2) Total weighted-average grant-date fair value of $0.4 million.

For 2011, 2010 and 2009, total restricted stock vested had a fair value of $1. 0 million, $1.1 million and $0.1 million, respectively, and the tax benefits realized for the tax deductions re lated to restricted stock awards were $0.2 million for 2011, $0.3 million for 2010 and $0.1 million for 2009.
As of December 31, 2011, there was $0.3 million of total unrecognized compensation cost related to

nonvested restricted shares and restricted stock awards . The cost is expected to be recognized over a weighted-average period of 2.4 years.136 Restricted stock units. Information about HEI’s grants of restricted stock units was as follows:

2011 2010 2009 Shares (1) Shares (1) Shares (1)

Outstanding, January 1 146,500 $19.80 70,500 $16.99

– – Granted 101,786 (2) 24.68 77,500 (3)

22.30 70,500 (4)

$16.99

Vested –

– (250) 16.99

– – Forfeited (1,000) 22.60 (1,250) 16.99

– – Outstanding, December 31 247,286 $21.80 146,500 $19.80 70,500 $16.99

(1) Weighted-average grant-date fair value per share. The grant date fair value of the restricted stock units was the average price of HEI common stock on the date of grant. (2) Total weighted-average grant-date fair value of $2.5 million. (3) Total weighted-average grant-date fair value of $1.7 million. (4) Total weighted-average grant-date fair value of $1.2 million.

As of December 31, 2011, there was $2.9 million of total unrecognized compensation cost related to the nonvested restricted stock units. The cost is expect ed to be recognized over a weighted-average period of 2.7 years.

LTIP payable in stock. The 2011-2013 LTIP provides for perfo rmance awards under the EIP and the 2009- 2011 LTIP and the 2010-2012 LTIP provide for performance awards under the SOIP of shares of HEI common stock based on the satisfaction of performance goals and service conditions over a three-year performance period. The number of shares of HEI common stock that may be awarded is fixed on the dat e the grants are made subject to the achievement of specified performanc e levels. The payout varies from 0% to 200% of the number of target shares depending on achievement of the goals. The LTIP performance goals for both LTIP periods include awards with a market goal based on to tal return to shareholders (TRS) of HEI stock as a percentile to the Edison Electric Institute Index over the applicable three-year period. In addition, the 2009- 2011 LTIP has performance goals based on HEI retu rn on average common equity (ROACE), the 2010-2012 LTIP has performance goals related to levels of HEI consolidated net income, HECO consolidated ROACE,

ASB net income and ASB return on assets – all bas ed on two-year averages (2011-2012), and the 2011-2013 LTIP has performance goals related to levels of HEI consolidated net income, HECO consolidated ROACE, HECO 3-year average consolidated net income, ASB return on assets and ASB 3-year average net income.

LTIP linked to TRS. Information about HEI’s LTIP grants linked to TRS was as follows:

2011 2010 2009 Shares (1) Shares (1) Shares (1)

Outstanding, January 1 126,782 $20.33 36,198 $14.85

– – Granted 75,015 (2)

35.46 97,191 (3) 22.45 36,198 (4)

$14.85

Vested – – – – – – Forfeited (4,412) 29.56 (6,607) 21.53 Outstanding, December 31 197,385 $25.94 126,782 $20.33 36,198 $14.85

(1) Weighted-average grant-date fair value per share determined using a Monte Carlo simulation model. (2) Total weighted-average grant-date fair value of $2.7 million. (3) Total weighted-average grant-date fair value of $2.2 million. (4) Total weighted-average grant-date fair value of $0.5 million.

The grant date fair values of the shares were determined using a Monte Carlo simulation model utilizing

actual information for the common shares of HEI and its peers for the period from the beginning of the performance period to the gr ant date and estimated future stock volatility and dividends of HEI and its peers over the remaining three-year perfo rmance period. The expected stock vo latility assumptions for HEI and its peer group were based on the three-year historic sto ck volatility, and the annual dividend yield assumptions were based on dividend yields calculated on the basis of daily stock prices over the same three-year historical period. The following table summarizes the assumptions used to determine the fair value of the

LTIP linked to TRS and the resulti ng fair value of LTIP granted:137 2011 2010 2009

Risk-free interest rate 1.25% 1.30% 1.30% Expected life in years 3 3 3 Expected volatility 27.8% 27.9% 23.7% Range of expected volatility for Peer Group 21.2% to 82.6% 22.3% to 52.3% 20.8% to 46.9% Grant date fair value (per share) $35.46 $22.45 $14.85

As of December 31, 2011, there was $2.4 million of total unrecognized compensation cost related to the nonvested performance awards payable in shares linked to TRS. The cost is expected to be recognized over a weighted-average period of 1.2 years.

LTIP linked to other performance conditions

. Information about HEI’s LTIP awards payable in shares linked to other performance conditions was as follows:

2011 2010 2009 Shares (1) Shares (1) Shares (1)

Outstanding, January 1 161,310 $18.66 24,131 $16.99 – –
Granted 113,831 24.96 160,939 (2) 18.95 24,131 (3) $16.99

Vested – – – – – – Cancelled (81,908) 18.38

– – – – Forfeited (10,735) 20.12 (23,760) 18.90 – – Outstanding, December 31 182,498 $22.63 161,310 $18.66 24,131 $16.99

(1) Weighted-average grant-date fair value per share based on the average price of HEI common stock on the date of grant. (2) Total weighted-average grant-date fair value of $3.0 million. (3) Total weighted-average grant-date fair value of $0.4 million.
In 2011, LTIP grants (under the 2011-2013 LTIP) we re made payable in 113,831 shares of HEI common stock (based on the grant date pr ices of $24.95 and $26.25 and target performance levels relating to performance goals other than TRS), wi th a weighted-average grant date fa ir value of $2.8 million based on the weighted-average grant date fair value per share of $24.96.
As of December 31, 2011, there was $2.3 million of total unrecognized compensation cost related to the nonvested shares linked to performance conditions other than TRS. The cost is expected to be recognized over a weighted-average period of 1.6 years.

11 • Income taxes

The components of income taxes attributable to net income for common stock were as follows:

Years ended December 31 2011 2010 2009 (in thousands)

Federal

Current $ (7,638) $(25,446) $25,691
Deferred 73,494 85,268 14,161 Deferred tax credits, net – (901) (593)

65,856 58,921 39,259

State

Current 2,437 (7,392) 6,930 Deferred 5,949 13,425 (783) Deferred tax credits, net 1,690 2,868 (1,483)

10,076 8,901 4,664

Total $ 75,932 $ 67,822 $43,923138 A reconciliation of the amount of income taxes comput ed at the federal statutory rate of 35% to the amount provided in the Company’s consolidated statements of income was as follows:

Years ended December 31 2011 2010 2009 (in thousands)

Amount at the federal statutory income tax rate $75,618 $64,136 $45,088 Increase (decrease) resulting from:
State income taxes, net of federal income tax benefit 6,550 5,786 3,033 Other, net (6,236) (2,100) (4,198)
Total $75,932 $67,822 $43,923

Effective income tax rate 35.1% 37.0% 34.1%

The effective tax rate decreased from 2010 to 2011 due primarily to additional lo w income housing credits and tax-free income from municipal bonds and bank-owned life insurance at ASB, and a favorable Internal Revenue Service (IRS) appeals settlement related to foreign losses at HEI in 2011. The lower effective tax rate for 2009 was due primarily to the greater relative impact of tax credit amor tization to net income, which was reduced by ASB’s losses from sales of mortgage-rela ted securities and other-t han-temporary impairments. The tax effects of book and tax basis differences that gi ve rise to deferred tax assets and liabilities were as

follows:

December 31 2011 2010 (in thousands)

Deferred tax assets Allowance for loan losses $ 14,076 $ 16,461
Retirement benefits 6,175 –

Other 33,217 35,878

53,468 52,339

Deferred tax liabilities Property, plant and equipment related 255,488 188,490
Retirement benefits – 2,479

Goodwill 22,028 20,130 Regulatory assets, excluding amounts attributable to property, plant and equipment 32,343 32,074
FHLB stock dividend 20,552 20,552 Change in accounting method related to repairs 48,566 46,702

Other 28,542 20,870

407,519 331,297 Net deferred income tax liability $354,051 $278,958

The ultimate realization of deferred tax asse ts is dependent upon the generat ion of future taxable income during the periods in which those temporar y differences are deductible. Based upon historical taxable income and projections for fu ture taxable income, management believe s it is more likely than not the Company will realize substantially a ll of the benefits of the deferred ta x assets. In 2011, the net deferred income tax liability continued to increase primarily as a result of accelerated tax deductions taken for bonus depreciation (resulting from the 2010 Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act).
In 2010, interest income on income tax refunds was reflected in “Revenues—Electric utility” in the amount of $9.7 million, which resulted from the settlement with the IRS of appealed issues for the tax years 1996 to 2006 and was due in large part to a change in the method of allocating overhead costs to selfconstructed assets. In 2011, 2010 and 2009, interest ex pense/(credit adjustments to interest expense) on income taxes was reflected in “Interest expens e – other than on deposit li abilities and other bank borrowings” in the amount of $(1.2) million, $(0.9) mill ion and $0.7 million, respectively. The credit adjustments to interest expense were primarily due to the resolution of tax issues with the IRS. As of
December 31, 2011 and 2010, the total amount of accrued interest related to uncertain tax positions and recognized on the balance sheet in “Interest and di vidends payable” was $1.5 million and $2.7 million, respectively.139 As of December 31, 2011, the total amount of liability for uncertain tax positions was $5.7 million and, of this amount, $0.9 million, if recognized, would affect the Company’s effective tax rate. The Company’s unrecognized tax benefits are primarily the result of temporary differences rela ting to the deductibility of costs incurred to repair generation property. The Company believe s that it is reasonably possible that the IRS may issue guidance on the deductibility of these repair co sts and this guidance will eliminate much of the uncertainty in 2012. Management has concluded that it is reasonably possible that the liability for uncertain tax positions may decrease by $5 million within the next 12 months. The changes in total unrecognized tax benefits were as follows:

(in millions) 2011 2010 2009 Unrecognized tax benefits, January 1 $ 15.4 $ 26.5 $ 27.9 Additions based on tax positions taken during the year – 11.0 – Reductions based on tax positions taken during the year (0.6) – – Additions for tax positions of prior years 0.1 2.2 0.4 Reductions for tax positions of prior years (8.1) (18.2) (1.8) Settlements – (6.1) – Lapses of statute of limitations (1.1) – – Unrecognized tax benefits, December 31 $ 5.7 $ 15.4 $ 26.5

The 2011 reduction in unrecognized tax benefits was primarily due to the IRS’s issuance of guidance on the deductibility of cost s of repairs to utility transmission and distribution (T&D) property (Revenue Procedure 2011-43, issued in August 2011), including a “safe harbor” method under which taxpayers could transition and minimize the uncertainty of the repairs expense deduction for T&D property. The Company

intends to elect the “safe harbor” method in its 2011 ta x return, which resulted in the reduction of associated unrecognized tax benefits for 2011. Tax years 2007 to 2010 currently remain subject to examination by the IRS. Tax years 2005 to 2010 remain subject to examination by the Department of Ta xation of the State of Hawa ii. HEI Investments, Inc., which owned leveraged lease investments in other states prior to its disso lution in 2008, is also subject to examination by those state tax aut horities for tax years 2005 to 2007.
As of December 31, 2011, the disclosures above present the Com pany’s accrual for potential tax

liabilities and related interest. Based on information cu rrently available, the Company believes this accrual has adequately provided for potential income tax issues with federal and state ta x authorities and related
interest, and that the ultimate resolution of tax iss ues for all open tax periods will not have a material adverse effect on its results of operat ions, financial condition or liquidity.

12 • Cash flows

(in millions) 2011 2010 2009
Supplemental disclosures of cash flow information Interest paid to non-affiliates $ 97 $ 95 $106 Income taxes paid/(refunded) (22) 6 21 Supplemental disclosures of noncash activities

Common stock dividends reinvested in HEI common stock 1 12 23 17

Increases in common stock issued under dire ctor and officer compensatory plans 8 4 2 Electric utility property, plant and equipment AFUDC-equity 6 6 12

Estimated fair value of noncash c ontributions in aid of construction 7 7 12 Unpaid invoices and other 45 21 16

Loans transferred from held for investment to held for sale 6 – 10 Real estate acquired in settlement of loans 12 7 5

1 The amounts shown represents common stock dividends reinvested in HEI common stock under the HEI DRIP in noncash transactions.140 13 • Regulatory restrictions on net assets

As of December 31, 2011, HECO and its subsidiaries could not tr ansfer approximately $588 million of

net assets to HEI in the form of dividend s, loans or advances without PUC approval. ASB is required to file a notice with the FRB and O CC prior to making any capital distribution to HEI. Generally, the FRB and OCC may disappro ve or deny ASB’s notice of intenti on to make a capital distribution if the proposed distribution will c ause ASB to become undercapitalized, or the proposed distribution raises safety and soundness concerns, or the proposed distribution violates a prohibition contained in any statute, regulation, or agreement between ASB and the OCC. As of Decem ber 31, 2011, ASB could transfer approximately $107 million of net assetsto HEI in the form of dividends and still maintain its “wellcapitalized” position. HEI management expects that the regulatory restrictions will not ma terially affect the operations of the Company nor HEI’s ability to pay common stock dividends.

14 • Significant group concentr ations of credit risk

Most of the Company’s business activity is with cu stomers located in the State of Hawaii. Most of ASB’s

financial instruments are based in the State of Hawaii, except for the investment and mortgage-related securities it owns. Substantially all real estate loans receivable are collateralized by real estate in Hawaii. ASB’s policy is to require mortgage insurance on all real estate loans with a loan to appraisal ratio in excess of 80% at origination.

15 • Fair value measurements

Fair value estimates are based on the price that would be received to sell an asset, or paid upon the transfer of a liability, in an orderly transaction between market participants at the m easurement date. The fair value estimates are generally determined based on assu mptions that market participants would use in pricing the asset or liability and are based on market data obtained from independent sources. However, in certain cases, the Company uses its own assumpti ons about market participant assumptions based on the

best information available in the circumstances. These va luations are estimates at a specific point in time,
based on relevant market information, informati on about the financial instru ment and judgments regarding future expected loss experience, economic conditions, risk characteristics of various financial instruments and other factors. These estimates do not reflect any pr emium or discount that coul d result if the Company were to sell its entire holdings of a particular financ ial instrument at one time. Because no active trading market exists for a portion of the Company’s financ ial instruments, fair value estimates cannot be determined with precision. Changes in the underlyin g assumptions used, including discount rates and
estimates of future cash flows, coul d significantly affect the estimates. Fair value estimates are provided for certain financial instruments without attempting to esti mate the value of anticipated future business and the

value of assets and liabilities that ar e not considered financial instruments. In addition, the tax ramifications

related to the realization of the unrealized gains and losses could have a significant effect on fair value estimates, but have not been considered in making such estimates. The Company groups its financial a ssets measured at fair value in three levels outlined as follows:

Level 1: Inputs to the valuation methodology are quoted prices, unadjusted, for identical assets or liabilities in active markets. A quoted price in an active market provides the most reliable

evidence of fair value and shall be used to measure fair value whenever available.

Level 2: Inputs to the valuation methodology include quoted prices for similar assets or liabilities in active markets; inputs to the valuation methodology include quoted prices for identical or similar assets or liabilities in markets that are not active; or inputs to the valuation methodology that are derived principally from or can be corroborated by observable market data by correlation or other means.

Level 3: Inputs to the valuation methodology are unobservable and significant to the fair value

measurement. Level 3 assets and liabilities include financial instruments whose value is determined using discounted cash flow methodologies, as well as instruments for which the determination of fair value requires significant management judgment or estimation.141 The Company used the following methods and assumptions to estimate the fair value of each applicable

class of financial instruments for which it is practicable to es timate that value:

Cash and cash equivalents and shor t-term borrowings—other than bank. The carrying amount approximated fair value because of the short maturity of these instruments.

Investment and mortgage-related securities. Fair value prices were provided by independent market participants and were based on observable inputs using market-based valuation techniques.

Loans receivable. For residential real estate loans, fair value was calculated by discounting estimated cash flows using discount rates based on current industry pricing for loans with similar contractual

characteristics. For other types of loans, fair value was estimated by discounting contractual cash flows using discount rates that reflect current industry pricing for loans with similar characteristics and remaining maturity. Where industry pricing is not available, discount rates are based on ASB’s current pricing for loans with similar characteristics and remaining maturity. The fair value of all loans was adjusted to reflect current assessments of loan collectability.

Deposit liabilities. The fair value of savings, negotiable orders of withdrawal, demand and money market deposits was the amount payable on demand at the reporting date. The fair value of fixed-maturity certificates of deposit was estimated by discounting the future cash flows using the rates currently offered for deposits of simila r remaining maturities.

Other bank borrowings and long-term debt. Fair value was estimated by discounting the future cash flows using the current rates available for borrowings with similar credit terms and remaining maturities.

Forward Starting Swaps. Fair value was estimated by discounting the expected future cash flows of theswaps, using the contractual terms of the swaps, including the period to maturity, and observable marketbased inputs, including forward interest rate curves. Fair value incorporates credit valuation adjustments to appropriately reflect nonperformance risk.

Off-balance sheet financial instruments. The fair value of loans serviced for others was calculated by discounting expected net income streams using discount rates that reflect industry pricing for similar assets. Expected net income streams were estimated based on industry assumptions regarding prepayment speeds and income and expenses associated with servicing residential mortgage loans for others. The fair value of commitments to originate loans was estimated based on the change in current primary market prices of new commitments. Since lines of credit can expire without being drawn and customers are under no obligation to utilize the lines, no fair value was assigned to unused lines of credit. The fair value of letters of credit was estimated based on the fees currently charged to enter into similar agreements, taking into account the remaining terms of the agreements. The fair value of HECO-obligated preferred securities of trust subsidiaries was based on quoted market prices.

The estimated fair values of certain of the Company’s financial instruments were as follows:

December 31 2011 2010

(in thousands) Carrying or

notional

amount Estimated

fair value Carrying or

notional

amount Estimated

fair value

Financial assets

Cash and cash equivalents, excluding money market funds $ 270,255 $ 270,255 $ 329,553 $ 329,553 Money market funds 10 10 1,098 1,098 Available-for-sale investment and mortgage-related securities 624,331 624,331 678,152 678,152
Investment in stock of Federal Home Loan Bank of Seattle 97,764 97,764 97,764 97,764
Loans receivable, net 3,652,419 3,888,558 3,497,729 3,639,983

Financial liabilities

Deposit liabilities 4,070,032 3,991,717 3,975,372 3,979,027 Short-term borrowings—other than bank 68,821 68,821 24,923 24,923 Other bank borrowings 233,229 250,486 237,319 251,822 Long-term debt, net—other than bank 1,340,070 1,400,241 1,364,942 1,345,770 Forward starting swaps – – 2,762 2,762

Off-balance sheet items

HECO-obligated preferred securities of trust subsidiary 50,000 50,000 50,000 52,500142 As of December 31, 2011 and 2010, loan commitmen ts and unused lines and letters of credit issued by
ASB had notional amounts of $1.3 billion and $1.2 billion, respectively, and their estimated fair value on such dates were $0.3 million and $0.4 million, respec tively. As of December 31, 2011 and 2010, loans serviced by ASB for others had noti onal amounts of $993.3 million and $817.7 million and the estimated fair value of the servicing rights for such loans was $9.8 million and $8.8 million, respectively.

Fair value measurements on a recurring basis. While securities held in ASB’s investment portfolio trade in active markets, they do not trade on listed exchange s nor do the specific holdings trade in quoted markets by dealers or brokers. All holdings are valued using market-based approaches that are based on exit prices

that are taken from identical or si milar market transactions, even in situations where trading volume may be low when compared with prior periods as has been the ca se during the recent mark et disruption. Inputs to these valuation techniques reflect the assumptions t hat consider credit and nonperf ormance risk that market participants would use in pricing the asset bas ed on market data obtained from independent sources.

Available-for-sale securities we re comprised of federal agency obligations and mortgage-backed securities and municipal bonds. Assets and liabilities measured at fair value on a recurring basis were as follows:

Fair value measurements using Quoted prices in Signifi cant other Significant

active markets

for identical observable inputs unobservable inputs (in thousands) assets (Level 1) (Level 2) (Level 3)

December 31, 2011 Money market funds (“other” segment) $ – $ 10 $ – Available-for-sale securities (bank segment) Mortgage-related securities-FNMA, FHLMC and GNMA $ – $344,865 $ – Federal agency obligations – 220,727 – Municipal bonds – 58,739 –
$ – $624,331 $ –

December 31, 2010 Money market funds (“other” segment) $ – $ 1,098 $ – Available-for-sale securities (bank segment) Mortgage-related securities-FNMA, FHLMC and GNMA $ – $319,970 $ – Federal agency obligations – 315,896 – Municipal bonds – 42,286 –
$ – $678,152 $ – Forward starting swaps (“other” segment) $ – $(2,762) $ –

Fair value measurements on a nonrecurring basis. From time to time, t he Company may be required to measure certain assets at fair value on a nonrecurring basis in accordance with GAAP. These adjustments to fair value usually result from the writedowns of indivi dual assets. ASB does not record loans at fair value on a recurring basis. However, from time to time, ASB records nonrecurring fair va lue adjustments to loans to reflect specific reserves on loans based on the current apprai sed value of the collateral or unobservable market assumptions. Unobservable assumptions reflect ASB’s own estimate of the fair value of collateral used in valuing the loan. ASB may also be required to measur e goodwill at fair value on a nonrecurring basis. See “Goodwill and other intangibles” in Note 1 for ASB’ s goodwill valuation methodology. During 2011 and 2010, goodwill was not measured at fair value. From time to time, the Company may be required to measure certain liabilities at fair value on a nonrecurring basis in accordance with GAAP. The fair value of HECO’s ARO (Level 3) was determined by discounting the expected future cash flows using mark et-observable risk-free rates as adjusted by HECO’s credit spread (also see Note 3).143 Assets measured at fair value on a nonrecurring basis were as follows:

Fair value measurements using Quoted prices in active Significant other Significant

markets for identical Observable inputs Unobservable inputs (in millions) Balance assets (Level 1) (Level 2) (Level 3)

Loans December 31, 2011 $ 34 $

– $ 25 $ 9
December 31, 2010 35

– 26 9

Specific reserves as of December 31, 2011 and 2010 were nil and $3.5 million, respectively, and were
included in loans receivable held for investment, net . For 2011 and 2010, there were no adjustments to fair

value for ASB’s loans held for sale.

Retirement benefit plans

Assets held in various trusts fo r the retirement benefit plans (Plans) are measured at fair value on a recurring basis (including items that are required to be measured at fair value and items for which the fair value option has been elected) and were as follows:

Pension benefits Other benefits Fair value measurements using Fair value measurements using Quoted prices

in active

markets for

identical

assets Significant

other

observable

inputs Significant

unobservable inputs Quoted prices

in active

markets for

identical

assets Significant

other

observable

inputs Significant

unobservable inputs (in millions) December 31 (Level 1) (Level 2) (Level 3) December 31 (Level 1) (Level 2) (Level 3)

2011

Equity securities $425 $425 $ – $ – $ 73 $ 73 $ – $ – Equity index funds 82 82

– – 15 15

– – Fixed income securities 283 98 185

– 43 37 6

– Pooled and mutual funds 87 1 86

– 13

– 13

– Total 877 $606 $271 $

– 144 $125 $ 19 $

– Receivables and payables, net (37) (1)

Fair value of plan assets $840 $143

2010

Equity securities $453 $453 $ – $ – $ 80 $ 80 $ – $ – Equity index funds 80 80

– – 14 14

– – Fixed income securities 238 55 183

– 8 2 6

– Pooled and mutual funds 78 9 69

– 49 39 10

– Total 849 $597 $252 $

– 151 $135 $ 16 $

– Receivables and payables, net (17)

–

Fair value of plan assets $832 $151

The fair values of the financial instruments show n in the table above represent the Company’s best estimates of the amounts that would be received upon sale of those assets or that would be paid to transfer those liabilities in an orderly transaction between mark et participants at that date. Those fair value

measurements maximize the use of obser vable inputs. However, in situati ons where there is little, if any, market activity for the asset or liability at the meas urement date, the fair val ue measurement reflects the Company’s judgments about the assumptions that market participants would use in pricing the asset or liability. Those judgments are developed by the Com pany based on the best information available in the

circumstances. In connection with the adoption of the fair va lue measurement standards, the Company adopted the provisions of ASU No. 2009-12, “Investments in Certain Entities that Calculate Ne t Asset Value per Share (or Its Equivalent),” which allows for the estimation of the fair value of investments in investment companies for144 which the investment does not have a re adily determinable fair value, usi ng net asset value per share or its equivalent as a practical expedient. The Company used the following val uation methodologies for assets meas ured at fair value. There have been no changes in the methodologies used at December 31, 2011 and 2010.

Equity securities, equity index funds, U.S. Treasur y fixed income securities and public mutual funds (Level 1). Valued at the closing price reported on the active market on which the individual securities are traded or the published net asset value (NAV) of the fund.

Fixed income securities, equity securities, pooled securities and mutual funds (Level 2). Fixed income securities, other than those issued by the U.S. Treasury, are valued bas ed on yields currently available on comparable securities of issuer s with similar credit ratings. Equity securities and pooled and mutual funds include commingled equity funds and other closed f unds, respectively, that are not open to public investment and are valued at the net asset value per share. Certain other inve stments are valued based on discounted cash flow analyses.

Other (Level 3). The venture capital and limit ed partnership interests are valued at historical cost, modified by revaluation of financial assets and financial liabilities at fair value through profit or loss. For 2011 and 2010, the changes in Level 3 assets were as follows:

2011 2010

(in thousands) Pension

benefits Other

benefits Pension

benefits Other

benefits Balance, January 1 $141 $ 5 $ 67,420 $ 13,703 Realized and unrealized gains 92 3 6,650 1,445 Purchases and settlements, net (16) (1) (317) (3,854)

Transfer in or out of Level 3

– – (73,612) (11,289)

Balance, December 31 $217 $ 7 $ 141 $ 5145 16 • Quarterly information (unaudited)

Selected quarterly information was as follows:

Quarters ended Years ended (in thousands, except per share amounts) March 31 June 30 Sept. 30 Dec. 31 December 31

2011

Revenues 1 $710,633 $794,319 $886,355 $851,028 $3,242,335 Operating income 63,375 63,661 94,490 68,170 289,696

Net income for common stock 1 28,462 27,139 48,404 34,225 138,230 Basic earnings per common share 2 0.30 0.28 0.50 0.36 1.45 Diluted earnings per common share 3 0.30 0.28 0.50 0.36 1.44 Dividends per common share 0.31 0.31 0.31 0.31 1.24 Market price per common share 4

High 26.40 26.38 24.95 26.79 26.79

Low 22.79 23.25 20.59 22.91 20.59

2010 Revenues $619,040 $655,664 $694,541 $695,737 $2,664,982 Operating income 60,707 63,631 72,631 59,242 256,211

Net income for common stock 5 27,126 29,262 32,449 24,698 113,535 Basic earnings per common share 2 0.29 0.31 0.35 0.26 1.22 Diluted earnings per common share 3 0.29 0.31 0.35 0.26 1.21 Dividends per common share 0.31 0.31 0.31 0.31 1.24 Market price per common share 4

High 23.01 24.04 24.99 23.41 24.99

Low 18.63 21.07 22.04 21.77 18.63

1 In the fourth quarter of 2011, HECO reco rded an adjustment of $6 million to re venues related to the third quarter of 2011, which decreased net income for the fourth quarter of 2011 by $3 million. Also, in the fourth quarter of 2011, HECO recorded an impairment charge of $6 million (net of taxes) of a transmission project.

2 The quarterly basic earnings per common share are based upon the weighted-average number of shares of common

stock outstanding in each quarter.

3 The quarterly diluted earnings per common share are based upon the weighted-average number of shares of common

stock outstanding in each quarter plus the dilutive incremental shares at quarter end.

4 Market prices of HEI common stock (symbol HE) sh own are as reported on the NYSE Composite Tape.

5 The fourth quarter of 2010 includes $6 million of interest in come (net of taxes) at the utilities due to a federal tax settlement and $2 million of taxes for the write-off of a deferred tax asset due to the expiration of a capital loss carryforward period.146 HECO: The information required by this Item 8 for HECO is incorporated herein by reference to pages 5 to 46 of

HECO Exhibit 99.2.

ITEM 9. CHANGE IN AND DI SAGREEMENTS WITH ACCOUNT ANTS ON ACCOUNTING AND

FINANCIAL DISCLOSURE

HEI and HECO:

None

ITEM 9A. CONTROLS AND PROCEDURES

HEI:

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
Constance H. Lau, HEI Chief Executive Officer, and James A. Ajello, HEI Chief Financial Officer, have evaluated the disclosure controls and procedures of HEI as of December 31, 2011. Based on their evaluations, as of December 31, 2011, they have concluded that the disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities E xchange Act of 1934, as amended) were effective in ensuring that information required to be disclosed by HE I in reports HEI files or submits under the Securities Exchange Act of 1934: (1) is recorded, processed, summarized, and reported wi thin the time periods specified in the Securities and Exchange Commission rules and forms, and (2) is accumulated and communicated to HEI m anagement, including HEI’s principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

Annual Report of Management on Intern al Control Over Financial Reporting Management is responsible for establishing and main taining adequate internal control over financial reporting, as such term is defi ned in Rule 13a-15(f) and Rule 15d-15 (f) promulgated under the Securities Exchange Act of 1934, as amended. The Company’s inte rnal control over financial reporting was designed to provide reasonable assurance to management and the Board of Directors regar ding the reliability of financial reporting and the pr eparation of financial statements for exte rnal purposes in accordance with generally accepted accounting principles.
Because of its inherent limitations, internal contro l over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of e ffectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2011 based on the framework in Internal Control—Integrated

Framework issued by the Committee of Sponsoring Organi zations of the Treadway Commission. Based on this evaluation, management has conc luded that the Company’s internal control over financial reporting was
effective as of December 31, 2011. The effectiveness of the Company’s internal contro l over financial reporting as of December 31, 2011 has been audited by PricewaterhouseCooper s LLP, an independent registered public accounting firm, as stated in their report which appears on page 86.

Changes in Internal Control over Financial Reporting There have been no changes in internal contro l over financial reporting during the quarter ended December 31, 2011 that have materially affected, or ar e reasonably likely to materially affect, the Company’s internal control over financial reporting.147 HECO:

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
Richard M. Rosenblum, HECO Chief Executive Office r, and Tayne S. Y. Sekimura, HECO Chief Financial Officer, have evaluated the disclosure controls and procedur es of HECO as of December 31, 2011. Based on
their evaluations, as of December 31, 2011, they have concluded that t he disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d- 15(e) under the Securities Exchange Act of 1934, as amended) were effective in ensuring that information required to be di sclosed by HECO in reports HECO files or submits under the Securities Exchange Act of 1934: (1) is recorded, processed, summarized, and reported wi thin the time periods specified in the Securities and Exchange Commission rules and forms, and (2) is accumulated and communicated to HECO m anagement, including HECO’s principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

Annual Report of Management on Intern al Control Over Financial Reporting Management is responsible for establishing and main taining adequate internal control over financial reporting, as such term is defi ned in Rule 13a-15(f) and Rule 15d-15 (f) promulgated under the Securities Exchange Act of 1934, as amended. HECO’s internal control over financial reporting was designed to provide reasonable assurance to m anagement and the Board of Directors r egarding the reliability of financial reporting and the preparation of financ ial statements for external purpos es in accordance with generally accepted accounting principles.
Because of its inherent limitations, internal contro l over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of e ffectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Management conducted an evaluation of the effectiveness of HECO’s internal control over financial reporting as of December 31 , 2011 based on the framework in Internal Control—Integrated Framework issued by the Committee of Spons oring Organizations of the Treadway Commission. Based on this evaluation, management has concluded that the Company’s internal control over financial reporting was
effective as of December 31, 2011.

Changes in Internal Control over Financial Reporting There have been no changes in internal contro l over financial reporting during the quarter ended December 31, 2011 that have materially affected, or are reasonably likely to materially affect, HECO’s internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

HEI and HECO: Interest of named experts . HEI and HECO have agreed to i ndemnify and hold KPMG LLP (KPMG) harmless against and from any and all legal costs and ex penses incurred by KPMG in successful defense of any legal action or proceeding that arises as a result of KPMG’s consent to the inclusion of its audit report on HEI’s and HECO’s past financial statem ents included in this Form 10-K.148 

### PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

HEI:

Information regarding HEI’s executive officers is prov ided in the “Executive Officers of the Registrant” section following Item 3 of this report. The remaining information called for by this item is incorporated herein by reference to the following sections in the HEI 2012 Proxy Statement:

 “Nominees for Class I directors whose te rms expire at the 2015 Annual Meeting”

 “Continuing Class II directors whose te rms expire at the 2013 Annual Meeting”

 “Continuing Class III directors whose term s expire at the 2014 Annual Meeting”

 “Committees of the Board” (por tions regarding whether HEI has an audit committee and identifying its members; no other portion of the Committees of the Board section is incorporated herein by reference)

 “Audit Committee Report” (portion i dentifying audit committee financial experts who serve on the HEI Audit Committee only; no other portion of the A udit Committee Report is incorporated herein by reference)

Family relationships; director arrangements

There are no family relationships between any HEI di rector or director nominee and any other HEI director or director nominee or any HEI ex ecutive officer. There are no arra ngements or underst andings between any HEI director or director nominee and any other person pursuant to which such director or director nominee was

selected.

Code of Conduct

The HEI Board has adopted a Corporate Code of C onduct that includes a code of ethics applicable to, among others, its principal executive officer, principal financial officer and principal accounting officer. The Corporate Code of Conduct is available on HEI’s w ebsite at www.hei.com. HEI elects to disclose the information required by Form 8-K, Ite m 5.05, “Amendments to t he Registrant’s Code of Et hics, or Waiver of a Provision of the Code of Ethics,” through this websit e and such information will remain available on this website for at least a 12-month period.

Section 16(a) beneficial ow nership reporting compliance

Information required to be reported under this capti on is incorporated herein by reference to the “Stock Ownership Information—Section 16(a) Beneficial Ownership Reporting Co mpliance” section in the HEI 2012 Proxy Statement.

HECO:

Executive officers of HECO

The executive officers of HECO are listed below. Messrs. Ignacio and Reinhardt are officers of HECO

subsidiaries rather than of HECO , but are deemed to be executive offi cers of HECO under SEC Rule 3b-7 promulgated under the 1934 Exchange Act. HECO executive o fficers serve from the date of their initial appointment until the annual meet ing of the HECO Board (or applicable HECO subsidiary board of directors) at which officers are appointed, and thereafter are appointed for one-year terms or until their successors have been duly appointed and qualified or until their earlier resignation or removal. HECO executive officers may also hold

offices with HECO subsidiaries and other affiliates in addition to their current positions listed below.149 Name Age Business experience for last 5 years and prior positions

with HECO and its affiliates

Richard M. Rosenblum 61 HECO President and Chief Executive Officer since 1/09

HECO Director since 2/09

 Prior to joining the Company : Southern California Edison Company Senior Vice President of Generation and Chief Nuclear Officer, 11/05 until his retirement in 5/08

Robert A. Alm 60 HECO Executive Vice President since 3/09

 HECO Executive Vice President – Public Affairs, 2/08 to 3/09

 HECO Senior Vice President – Public Affairs, 7/01 to 2/08

Stephen M. McMenamin 56 HECO Senior Vice Pres ident and Chief Information Officer since 9/09

 Prior to being appointed to his current officer position at HECO, served as a full-time consultant to HECO in an acting chief information officer capacity from 6/09 to 9/09 and as a part-time

information services consultant to HECO from 3/09 to 5/09

 Prior to joining the Company: Borland Software Corp. Vice President, Engineering, 1/06 to 2/09

Tayne S. Y. Sekimura 49 HECO Senior Vice President and Chief Financial Officer since 9/09

 HECO Senior Vice President, Finance and Administration, 2/08 to

9/09

 HECO Financial Vice President, 10/04 to 2/08

 HECO Assistant Financial Vice President, 8/04 to 10/04

 HECO Director, Corporate & Prope rty Accounting, 2/01 to 8/04

 HECO Director, Internal Audit, 7/97 to 2/01

 HECO Capital Budgets Administrator, 5/93 to 7/97

 HECO Capital Budgets Supervisor, 10/92 to 5/93

 HECO Auditor (internal), 5/91 to 10/92

Patricia U. Wong 55 HECO Senior Vice President, Corporate Services since 9/09

 HEI Vice President, Administrati on and Corporate Secretary, 4/05

to 9/09

 HEI Vice President, Administration, 1/05 to 4/05

 HECO Vice President, Corpor ate Excellence, 3/98 to 1/05

 HECO Manager, Envir onmental, 9/96 to 3/98

 HECO Associate General Counsel, 12/94 to 9/96

 HECO Corporate Attorney, 5/90 to 12/94

Jay M. Ignacio 52 HELCO President since 3/08

 HELCO Manager, Distribution and Transmission, 11/96 to 3/08

 HELCO Superintendent, Construction & Maintenance, 4/94 to

11/96

 HELCO Electrical Engineer, 4/90 to 4/94

Edward L. Reinhardt 59 ME CO President since 5/01

 MECO Manager, Energy Delivery, 12/99 to 5/01

 MECO Manager, Engineering, 8/90 to 12/99

 MECO Senior Electrical Engineer, 11/89 to 8/90

 MECO Staff Engineer, 5/88 to 11/89

 MECO Electrical Engineer, 4/86 to 5/88150 HECO Board

The directors of HECO are list ed below. HECO directors are elect ed annually by HEI, as sole common shareholder of HECO, taking into account recomm endations made by the HEI Nominating and Corporate Governance Committee. Below is information regar ding the business experience and certain other directorships for each HECO director, together with information about legal proceedings in which certain directors were involved and a description of the experi ence, qualifications, attributes and skills that led to the

HECO Board’s conclusion at the time of this Form 10-K that each of t he directors should serve on the HECO Board in light of HECO’s cu rrent business and structure.

Don E. Carroll , age 70, HECO director since 2011

HECO Audit Committee Member

Business experience and other public company directorships since 2007

 Retired Chairman, Oceanic Time Warner Cable Advisory Board, since 2004

 Director, HEI (parent company of HECO), 1996-2011

 Director, ASB (HECO affiliate), 2004-2011

Skills and qualifications for HECO Board service

 38 years of executive and finance management exper ience as President and Vice President, Finance

of Oceanic Cable.

 Experience with oversight of executive compens ation, compensation pr ograms and finance matters from serving as Chair of the Compensation Commi ttee for Island Insurance Company, Ltd., a member of the Compensation Committees of HEI and Pacifi c Guardian Life, and as a member of the ASB Audit

Committee.

 In-depth knowledge of issues facing HECO gained fr om 15 years as a director for HECO’s parent company, HEI.

 Strong understanding of concerns of the communities HECO serves fr om his lengthy career with
Oceanic Cable, which serves the same communities.

Thomas B. Fargo , age 63, HECO director since 2005

Business experience and other public company directorships since 2007

 Operating Executive Board Mem ber, J.F. Lehman & Company (private equity firm), since 2008

 Owner, Fargo Associates, LLC (defense and homelan d/national security consultancy), since 2005

 Chief Executive Officer, Hawaii Superfe rry, Inc. (interisland ferry), 2008-2009

 President, Trex Enterprises Corporation ( defense research and development firm), 2005-2008

 Commander, U.S. Paci fic Command, 2002-2005

 Chairman of the Board and Compensation and Go vernance Committee Member , Huntington Ingalls
Industries, Inc., since 2011

 Director, Alexander & Baldwin, Inc., since 2011

 Director, Northrop Grum man Corporation, 2008-2011

 Director, Hawaiian Holdings, Inc., 2005-2008

 Director since 2005 and Compensation Committee Chair, HEI (parent company of HECO)

Skills and qualifications for HECO Board service

 Extensive knowledge of the U.S. military, a major customer of HECO and its subsidiaries.

 Leadership, strategic planning and financial and non-fin ancial risk assessment skills developed over 39 years of leading 9 organizat ions ranging in size from 130 to 300,000 people and managing budgets up to $8 billion.

 Experience with corporate governance, incl uding audit, compensation and governance committees, from service on several public and private company boards.151 Peggy Y. Fowler , age 60, HECO director since 2009

HECO Audit Committee Member

Business experience and other public company directorships since 2007

 Co-Chief Executive Officer, Portl and General Electric Company (PGE), 2009

 President and Chief Executive Officer, PGE, 2000-2008

 Director, HEI (parent company of HECO), since 2011

 Director, Umpqua Holdings Co rporation, since 2009, and C hair of Budget and Compensation
Committees, since 2010

 Director, PGE, since 1998

Skills and qualifications for HECO Board service

 35 years of executive leadership, financial oversight and utility operations experience from serving at PGE in senior officer positions, including Chief Operating Officer, President and CEO.

 Environmental and renewable energy expertise from managing PGE’s environmental department, overseeing initiatives that improved fish pa ssage on multiple Oregon rivers, supervising the construction and integration into PGE’s grid of wind and solar projects, and leading PGE to be ranked #1 by the National Renewable E nergy Laboratory for selling more renewable power to residential customers than any other utility in the U.S. for several y ears during her tenure as PGE’s CEO.

 Proven management, leadership and analytical skills, including crisis management, risk assessment, strategic planning and public relations skills, demonstra ted especially by her leadership of PGE after the 2001 bankruptcy of its parent company, Enron Corp., through it s independence from Enron in 2006.

 Expertise in financial oversight, regulatory co mpliance and corporate governance from serving as President (1997-2000), CEO (2000-2008) and Chair ( 2001-2004) of PGE, as a director for the

Portland Branch of the Federal Reserve Bank of San Francisco and as a director and committee member for several private and public companies, including Umpqua Holdings Corporation (publicly traded bank holding company).

Involvement in certain legal proceedings

 PGE was owned by Enron Corp. from 1997 to 2006. Enron also owned Portland General Holdings, Inc., previously a holding company for the nonregulated business of PGE that became a subsidiary of Enron, holding Enron’s nonregulated businesses in Portland. Enron Corp. filed for bankruptcy in 2001.

Ms. Fowler was President of Portland General Ho ldings from 1999 to 2003, when it also filed for bankruptcy protection. The case was procedurally cons olidated with the Enr on bankruptcy, but Enron’s bankruptcy reorganization plan did not expressly per tain to Portland General Holdings. The Portland General Holdings bankruptcy case wa s dismissed in October 2005, after substantially all of its assets were distributed or placed in segregated accounts.

Timothy E. Johns , age 55, HECO director since 2005

HECO Audit Committee Chair

Business experience since 2007

 Senior Vice President, Hawaii Medical Service Association (HMSA), since 2011

 President and Chief Executive Officer, Bishop Museum, 2007-2011

 Chief Operating Officer, Estate of Samuel Mills Damon, 2000-2007

Skills and qualifications for HECO Board service

 Executive management, leadership and strategic planning skills developed over a 28-year career as a businessperson and lawyer and currently as Senior Vice President of HMSA.

 Business, regulatory, financial stew ardship and legal experience from his prior roles as President and CEO of the Bishop Museum, Chief Operating Officer for the Estate of Samuel Mills Damon (private
trust with assets valued at over $900 million in 2004) (2000-2007), Chairpers on of the Hawaii State152 Board of Land and Natural Resources (1999-2000), Dire ctor of the Hawaii St ate Department of Land and Natural Resources (1999-2000) and Vice Presid ent and General Counsel at Amfac Property Development Corp. (1994-1998).

 Corporate governance knowledge and familiarity with financial oversight and fiduciary responsibilities from overseeing the HMSA Internal Audit department, fr om his prior service as a director for The Gas Company LLC (Hawaii gas energy provider) (2003-2005) and his current service as a trustee of the Parker Ranch Foundation Trust (charitable trust with assets valued at over $350 million), as a director

and Audit Committee member for Gr ove Farm Company, Inc. (priva tely-held community and real estate development firm operating on the island of Kauai) and on the board of Kualoa Ranch, Inc. (private ranch in Hawaii offering t ours and activity packages to the public).

Bert A. Kobayashi, Jr. , age 41, HECO director since 2006

Business experience since 2007

 Managing Partner, BlackSand Capital, LLC (real estate investment firm), since 2010

 President and Chief Executive Officer, Kobay ashi Group, LLC, 2001-2010, and Partner, since 2001

 Vice President, Nikken Holdings, LLC, since 2003

Skills and qualifications for HECO Board service

 From his leadership of BlackSand Capital, LLC and Kobayashi Group, LLC, a Hawaii-based real estate development firm he co-founded with family members in 2001, extensive experience with planning, financing and leading large real estate development projects ranging from large office buildings to a luxury residential high-rise in dow ntown Honolulu, Hawaii to a country club on the island of Maui, and experience with executive m anagement, marketing and government relations.

 Organizational governance and financial ov ersight experience from his curr ent service as a director or trustee for two mutual funds (Pacific Capital F unds of Cash Assets and Hawaiian Tax Free Trusts, both from the Aquila Group of F unds), East-West Center Foundation, Nature Conservancy of Hawaii

and GIFT Foundation of Hawa ii, which he co-founded.

 Recognized business and community leader in Hawaii, named as “Young Business Leader of the Year” for 2007 by Pacific Business News.

Constance H. Lau , age 59, HECO director since 2006

HECO Chairman of the Board since 2006

Current and prior positions with HECO and its affiliates

 President and Chief Executive Officer and Dire ctor, HEI (parent company of HECO), since 2006

 Chairman of the Board, HECO, since 2006

 Chairman of the Board, ASB (a ffiliate of HECO), since 2006

 Chairman of the Board and Chief Executive Officer, ASB, 2008-2010

 Chairman of the Board, President and Chief Executive Officer, ASB, 2006-2008

 President and Chief Executive Officer and Director, ASB, 2001-2006

 Senior Executive Vice President and Chief Operating Officer and Director, ASB, 1999-2001

 Treasurer, HEI, 1989-1999

 Financial Vice President & Treasurer, HEI Po wer Corp. (former affiliate of HECO), 1997-1999

 Treasurer, HECO and Assist ant Treasurer, HEI, 1987-1989

 Assistant Corporate Counsel, HECO, 1984-1987

Other public company directorships since 2007

 Director, HEI, 2001-2004 and since 2006

 Director since 2004 and Audit Committee Member, Alexander & Baldwin, Inc.

Skills and qualifications for HECO Board service

 Intimate understanding of HECO and its affiliates fro m serving in various chief executive, chief operating and other executive, financ e and legal positions at HEI and its major operating subsidiaries,153 HECO and ASB, over the last 28 years.

 Familiarity with current managem ent and corporate governance prac tices from her service as a

director and Audit Committee member for Alexander & Baldwin, In c. and as a director of the
Associated Electric & Gas Insurance Services, Inc.

 Experience with financial oversight and expansive knowledge of the Hawa ii business community and the local communities that compose the customer bas es of HECO and its subsidiaries from serving as

a director for various local industry, business development, educ ational and nonprofit organizations.

 Utility and banking industry knowledge from serving as a director or task force member of the Hawaii
Bankers Association, the American Bankers Association, the Edison El ectric Institute and the Electric

Power Research Institute.

 Nationally recognized leader in the fields of in frastructure, banking and energy, demonstrated by her appointment by President Obama to the National Infrastructure Advi sory Council, her appointment to

the Federal Reserve Board of San Francisco’s 12 th

District Community Depository Institutions Advisory Council and her receipt of the 2011 Woman of the Y ear award from the Women’s Council on Energy

and the Environment.

Richard M. Rosenblum , age 61, HECO director since 2009

Current and prior positions with HECO

 President and Chief Executive Officer, HECO, since 2009

Other business experience since 2007

 Senior Vice President of Generation and Chief Nu clear Officer, Southern California Edison Company,

2005-2008

Skills and qualifications for HECO Board service

 34 years of experience in all phases of electri c utility operations, includi ng 32 years at Southern California Edison Company, one of California’s lar gest electric utilities, and experience leading renewable energy efforts, including in itiating one of the nation’s largest solar photovoltaic projects with a goal of installing 250 megawatts of solar generating capacity over five years on commercial rooftops throughout Southern California.

 Operational leadership, strategic planning, customer relations and financial oversight skills from his

career at Southern California Edis on Company, including as Senior Vice President of Generation and Chief Nuclear Officer (2005-2008), Senior Vice President of Transmission and Distribution (1998- 2005), Vice President of Customer Service and Distribution (1996-1998) and Vice President of Engineering and Technica l Services (1993-1995).

Kelvin H. Taketa , age 57, HECO director since 2004

Business experience and other public company directorships since 2007

 President and Chief Executive Officer, Hawaii Community Foundation, since 1998

 Director since 1993 and Nominati ng and Corporate Governance Co mmittee Chair, HEI (parent company of HECO)

Skills and qualifications fo r HECO Board service

 Executive management experience with responsibilit y for overseeing more than $500 million in

charitable assets as President and Chief Execut ive Officer of the Ha waii Community Foundation.

 Proficiency in risk assessment, strategic planning and organizational leadership as well as marketing and public relations obtained from his current pos ition at the Hawaii Comm unity Foundation and his prior experience as Vice President and Executive Dire ctor of the Asia/Pacific Region for The Nature Conservancy and as Founder, Managing Partner and Director of Sunrise Capital Inc.

 Knowledge of corporate and nonprofit governance issues gained from his pr ior service as a director for Grove Farm Company, Inc., his current service as director and Acting Chair of the Independent Sector and Director of the Stupski Foundat ion and through publishing articles and lecturing on governance of154 tax-exempt organizations.

Audit Committee of the HECO Board

HECO has a guarantee with respect to 6.50% cumulati ve quarterly income preferred securities series 2004 (QUIPS) listed on the New York Stock Exchange (NYSE). Because HEI has common stock listed on the NYSE and HECO is a wholly-owned subsidiary of HE I, HEI is subject to the corporate governance listing standards in Section 303A of the NYSE Listed Company Manual and, by reason of an exemption resulting from HEI’s listing, HECO is not. Accordingly, HECO is exempt from NYSE list ing standards 303A.04, 303A.05 and 303A.06, which require listed co mpanies to have nominating/corp orate governance, compensation and

audit committees. Although not required by NYSE rules to do so, HECO has established one standing committee, the HECO Audit Committee, and voluntarily endeavors to comply with NYSE and SEC requi rements regarding audit committee composition. The current members of the HECO Audit Committee are nonemployee directors Timothy E. Johns (chairperson), Peggy Y. Fowler and Don E. Carroll. All commi ttee members are independent and qualified to serve on the committee pursuant to NYSE and SEC requirements. Each of Timothy E. Johns and Peggy Y. Fowler has been determined by the HECO Board to be an “audit committee financial expert” on

the HECO Audit Committee. The HECO Audit Committee operates and acts under a written charter approved by the HECO Board and

available on HEI’s website at www.hei.com. The HECO Audit Committee is responsible for overseeing (1) HECO’s financial reporting processes and internal contro ls, (2) the performance of HECO’s internal auditor, (3) risk assessment and risk management policies set by management and (4) the Cor porate Code of Conduct compliance program for HECO and its subsidiaries. In addi tion, the committee provides input to the HEI Audit Committee regarding the appointment, compensation and oversight of the independent registered public accounting firm that audits HEI’s consolidated financial statements and maintains pr ocedures for receiving and reviewing confidential reports to the HECO Audit Committee of potenti al accounting and auditing concerns.
In 2011, the HECO Audit Committee held four meetings. At each meet ing, the committee held executive sessions without management present with the independent r egistered public accounting firm that audits HEI’s

consolidated financial statement s and the internal auditor.

Attendance at HECO Boar d and Committee meetings

In 2011, there were seven regular meetings of the HECO Board. All HECO directors attended at least 75%

of the combined total number of meet ings of the HECO Board and the HE CO Audit Committee (for those who served on such committee).

Family relationships; executive o fficer and director arrangements

There are no family relationships between any executiv e officer, director or director nominee of HECO and any other executive officer, director or dire ctor nominee of HECO. T here are no arrangements or understandings between any executive officer, director or director nominee of HECO and any other person pursuant to which such executive officer, di rector or director nominee was selected.

Code of Conduct

The HEI Board has adopted a Corporate Code of Conduc t that applies to all of HEI’s subsidiaries, including HECO, and which includes a code of ethics app licable to, among others, HECO ’s principal executive officer, principal financial officer and principal account ing officer. The Corporate Code of Conduct is available

on HEI’s website at www.hei.com. HECO elects to disclos e the information required by Form 8-K, Item 5.05, “Amendments to the Registrant’s Code of Ethics, or Waiver of a Provision of the Code of Ethics,” through this

website and such information will remain availabl e on this website for at least a 12-month period.155 Section 16(a) beneficial ow nership reporting compliance

Section 16(a) of the 1934 Exchange Act requires HECO ’s executive officers, controller, directors and persons who own more than ten percent of a registered class of HECO’s equi ty securities to file reports of ownership and changes in ownership with the SEC. Such reporting persons are also required by SEC regulations to furnish HECO with copies of all Section 16( a) forms they file. Based so lely on its review of such forms provided to it during 2011, or written representations from some of those persons that no Forms 5 were required from such persons, HECO belie ves that each of the perso ns required to comply with Section 16(a) of the 1934 Exchange Act with respect to HECO, including its executive officers, controller, directors and persons who own more than ten percent of a registered class of HECO’s equity se curities, complied with the reporting requirements of Section 16(a) of the 1934 Exchange Act for 2011.

ITEM 11. EXECUTIVE COMPENSATION

HEI:

The information required under this item for HEI is incorporated herein by reference to the information relating to executive and director comp ensation in the HEI 2012 Proxy Statement.

HECO:

As Richard M. Rosenblum was deemed an executive offi cer of HEI and certain dire ctors of HECO are also directors of HEI, information required under this item for HECO, in addition to that set forth below, is incorporated herein by reference to the informati on in the HEI 2012 Proxy Statement relating to the compensation of Mr. Rosenblum and the directors of HECO who also serve on the HEI Board.

Compensation Committee Interlo cks and Insider Participation

HEI:

The information required to be reported under this caption is incorporated herein by reference to the “Other Relationships and Related Person Transac tions—Compensation Committee Interlocks and Insider Participation” section in the HEI 2012 Proxy Statement.

HECO:

The HECO Board does not have a separate compens ation committee. Rather, the entire HECO Board serves as HECO’s compensation committee and over sees HECO executive compensation matters. In addition, as part of its responsibility to oversee com pensation programs at HEI and its subsidiaries, the HEI Compensation Committee assists t he HECO Board by reviewing a nd making recommendations regarding HECO executive compensation matters. HECO director Thom as B. Fargo, who is also an HEI director, is the chairperson of the HEI Compensation Committee. HECO di rector Don E. Carroll attends meetings of the HEI Compensation Committee as a non-voting r epresentative of the HECO Board. During the last fiscal year, the following HECO office rs, who are also director s of HECO, participated in

deliberations of the HECO Board regarding HECO exec utive compensation matters:

 HECO Chairman of the Board Constance H. Lau, who is also HEI President & Chief Executive Officer and an HEI director and is not compensated by HECO, participated in deliberations of the HEI Compensation Committee in recommending, and of the HECO Board in determining, compensation for HECO’s President & Chief Ex ecutive Officer and other HECO named executive

officers.

 HECO President and Chief Executive Officer Richar d M. Rosenblum, who is also a HECO director, was responsible for evaluating the performance of the other HECO named executive officers and other HECO Vice Presidents based on perform ance goals and subjective measures, which evaluations were used by the HEI Compensati on Committee in recommending, and by the HECO Board in determining, compensation for those office rs. Mr. Rosenblum did not participate in the156 deliberations of the HEI Co mpensation Committee to recommend, or of the HECO Board to determine, his own compensation, but did participate in deliberations of the HECO Board to determine the compensation

of the other HECO named executive officers.

HECO Board and HEI Compensation Committee Report

The HECO Board and the HEI Compensation Committee have reviewed and discussed with management the Compensation Discussion and Analysis t hat follows. Based on such review and discussion, the HEI Compensation Committee reco mmended to the HECO Board that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K.

SUBMITTED BY THE HECO BOARD OF DIRECTORS
Constance H. Lau, Chairman

Don E. Carroll Thomas B. Fargo Peggy Y. Fowler Timothy E. Johns Bert A. Kobayashi, Jr.

Richard M. Rosenblum

Kelvin H. Taketa

AND SUBMITTED BY THE COMPEN SATION COMMITTEE OF

THE HEI BOARD OF DIRECTORS

Thomas B. Fargo, Chairperson A. Maurice Myers Jeffrey N. Watanabe157 Compensation Discussion and Analysis

Who were the named executive officers for HECO in 2011?

For 2011, the HECO named executive officers were:

1. Richard M. Rosenblum, HECO President and Chief Executive Officer.

2. Tayne S. Y. Sekimura, HECO Senior Vice President and Chief Financial Officer.

3. Robert A. Alm, HECO Executive Vice President.

4. Stephen M. McMenamin, HECO Senior Vice Pr esident and Chief Info rmation Officer.

5. Patricia U. Wong, HECO Senior Vi ce President, Corporate Services.

Executive Summary

Objectives and Com pensation Components. Our executive compensation progr am is designed to: (i) pay for performance in metri cs that address shareholder, customer, empl oyee and regulator considerations, (ii) align the interests of executives with those of our s hareholders, (iii) attract, motivate and retain talented executives who can drive HECO’s success and (iv) ens ure that the cost of executive compensation is

reasonable. The primary components of executive compensat ion are base salary, annual incentives (based on achieving performance goals over a one-year period) , long-term incentives (contingent on meeting performance goals over rolling three-y ear periods) and service-based grants of restricted stock units (RSUs) vesting over four years. Other named executive officer benefits in clude double-trigger change-in-control agreements, eligibility to participate in retirement and nonqualified deferred compensation plans, and limited perquisites. Named executive officer compensation is described in greater detail in the remainder of this Compensation Discussion and Anal ysis and under “Executive Compensation” below.

2011 Program Changes. The HECO Board and HEI Compensat ion Committee made the following changes in 2011 to further strengthen our executive com pensation program:

 For employees (including executive officers) who join HECO or its subsidiaries at any time after May 1,
2011, retirement benefits have been restructured to reduce costs over the long term. The changes include decreasing the benefit under the defined benefit pension plan and providing for limited matching contributions under HEI’s 401(k) Plan. Th is change did not, however, affect any of HECO’s
named executive officers, all of whom were employed by HECO prior to May 1, 2011.

 Operations and Maintenance Ex pense Management was added as a me tric for evaluating annual performance of HECO executives. This metric is part of HECO’s balanced scorecard of performance

metrics and incentivizes executives to seek be tter methods to perform operations and maintenance projects.

2011 Performance. In 2011, HECO continued to focus on its crit ical role in achieving the state’s clean energy goals, among the most aggressive in the nation. HECO successfully im plemented a new regulatory model (called “decoupling”) on Oahu. This new model delinks revenues from kilowatt-hour sales and supports the utility’s efforts to achieve Hawaii’s clean energy goal s. In July 2011, HECO obtained an interim decision in its 2011 rate case, resulting in an annualized revenue incr ease of $53.2 million, largely to help recover costs and investments to increase the use of clean energy sour ces and maintain and improve reliable service to its
customers. In addition, HECO and its subsidiari es completed additional pow er purchase agreements for energy produced from solar, wind and geothermal sources and fuel contracts for renewable biofuels to replace fossil fuel in their generating units to help Hawaii ac hieve its goal of 40% of energy produced from renewable sources by 2030. Please see “Item 7. Management’s Discussion and A nalysis of Financial C ondition and Results of Operations” above for a more detail ed description of our 2011 results.158 Pay for Performance. The compensation our named executive offi cers earned for 2011 reflects the strong performance summarized above as well as our perfo rmance over the three- year period that ended
December 31, 2011:

 HECO Consolidated Net Income, HECO Oper ations & Expense Management, Safety, HECO

Consolidated Customer Satisfacti on and Hawaii Clean Energy Initiati ve were the key metrics for 2011

HECO named executive officer annual incent ives. 2011 performance was between minimum and target for two metrics, at maximum for one metric, below minimu m for one metric, and at target for one metric, resulting, in the aggregate, in payment of annual cash incent ives at 98.7% of target. For further detail, please see “What was HECO’s annual incentive plan and were there any payouts?”

below.

 Long-term incentives comprise a significant po rtion of each HECO named executive officer’s compensation. For the three- year period that ended December 31, 2011, the prim ary HECO named executive officer performance metrics were HE I Total Return to Shareholders (TRS) and HECO Consolidated Return on Average Common Equity (ROACE). HECO President and CEO Mr.
Rosenblum had an additional metric, HEI ROACE. Despite HEI and HECO’s strong performance in 2011, the improvement in HECO and HEI ROACE ov er the three-year period was slower than originally anticipated and performance in these tw o metrics was below mi nimum, while HEI TRS performance was at minimum. As a result, t he HECO named executive officer 2009-2011 incentives paid out at 31.5% of ta rget. For further detail, please s ee “What was HECO’s 2009-2011 long-term incentive plan and were there any payouts?” below.

The HECO Board and HEI Compensat ion Committee believe that our executive compensation program reflects best practices and is structured to encourage parti cipants to build long-term value in the Company for

the benefit of our sharehol ders and all stakeholders.

Compensation Process

Does the HECO Board have a desi gnated compensation committee?

The HECO Board does not have a separate compensation committee. Rather, the ent ire HECO Board serves as HECO’s compensation committee and oversees HECO executive compensation matters. As part of its responsibility to oversee comp ensation programs at HE I and its subsidiaries , the HEI Compensation

Committee assists the HECO Board by reviewing and making recommen dations regarding HECO executive compensation matters. HECO director Thomas B. Fargo, who is also an HEI director , is the chairperson of the HEI Compensation Committee. HECO director Don E. Carroll attends meetings of the HEI Compensation Committee as a non-voting repres entative of the HECO Board. During the last fiscal year, the following HECO office rs, who are also director s of HECO, participated in

deliberations of the HECO Board regarding HECO exec utive compensation matters:

 HECO Chairman of the Board Constance H. Lau, who is also HEI President & Chief Executive Officer and an HEI director and is not compensated by HECO, participated in deliberations of the HEI Compensation Committee in recommending, and of the HECO Board in determining, compensation for HECO’s President & Chief Ex ecutive Officer and other HECO named executive

officers.

 HECO President and Chief Executive Officer Richar d M. Rosenblum, who is also a HECO director, was responsible for evaluating the performance of the other HECO named executive officers and other HECO Vice Presidents based on perform ance goals and subjective measures, which evaluations were used by the HEI Compensati on Committee in recommending, and by the HECO Board in determining, compensation for those offi cers. Mr. Rosenblum did not participate in the

deliberations of the HEI Compensation Committee to recommend, or of the HECO Board to determine his own compensation, but did pa rticipate in deliberations of the HECO Board to determine the compensation of the other HE CO named executive officers.159 Can the HECO Board and the HEI Compensation Committee modify or terminate executive compensation programs?

The HECO Board and the HEI Compensation Committee may amend, suspend or termi nate any incentive program or other executive compensa tion program, or any individual ex ecutive’s participation in such programs. The HECO Board and the HEI Compensation Committee have discretion to reduce or, except to the extent an award or payout is intended to satisfy the requirement s for deductibility under Section 162(m) of the Internal Revenue Code, increase the size of any award or payout to HECO or subsidiary executives. HECO’s incentive compensation plans and awards ar e designed to comply with Section 162(m), although the HECO Board and HEI Compensatio n Committee reserve the right to award compensation even when not

deductible if it is reasonab le and appropriate to do so. In making compensation determinations, the HECO Board and the HEI Comp ensation Committee will

consider financial accountin g and tax consequences, if appropriate. For instance, as noted above, the HECO Board and HEI Compensation Committ ee take into acco unt tax deductibility in establishing executive compensation. As another example, the HECO Board and HEI Compensation Commi ttee may determine that there should not be any incent ive payout that woul d result solely from a new way of accoun ting for a financial

measure.

How do HECO’s compensation policies and prac tices relate to HECO’s risk management?

HECO has an Enterprise Risk Management function t hat is principally responsible for identifying and monitoring risk across HECO and its subsidiaries, and for reporting high risk areas to the HECO Board and the HECO Audit Committee. HECO’s Enterprise Risk Management function is part of HEI’s overall Enterprise Risk Management function, which is responsible for identifying and monitoring risk throughout the HEI companies and for reporting on areas of signi ficant risk to the HEI Board and designated board
committees. As a result, all HECO and HEI directors, including those t hat comprise the HEI Compensation Committee, are apprised of risks that could have a mate rial adverse effect on HECO. The HECO Board and HEI Compensation Committee assessed and considered these potential risks when establishing HECO’s compensation policies and practices and the execut ive compensation program described in this Compensation Discussion and Analysis. The Enterprise Risk Management function conducts an annual risk review of HECO’s executive compens ation program and findings from this review are considered by the HEI Compensation Committee in designing t he next year’s compensation program. The HEI Compensation

Committee has concluded that the HECO exec utive compensation pr ogram does not encourage unnecessary or excessive risk-taking and repor ted such conclusion to the HECO Board. HECO’s compensation policies and practices are desig ned to focus executives on initiatives that benefit

shareholders and other stakehol ders, including customers, employ ees and regulators, and to discourage decisions that introduce risks that may have a mate rial adverse effect on the Company. Because the executive officers are in a position to directly in fluence HECO’s performance, compensation for executive officers involves a significant portion of pay that is “at risk” and tied directly to HECO and HEI performance – namely, the annual incentive plan and lo ng-term incentive plan. In a ddition, annual equity grants to

executive officers in the form of restricted stock units ensure that executives share in both the upside potential and downside risk of HEI shareholders. In structuring incentive compensation plans and setting metrics and goals for awards under those plans, the HEI Compensation Committee and HECO Board incorporate the fo llowing elements and practices to ensure prudent decision-making without encouraging empl oyees to take unnecessary or excessive risks:

 Financial performance objectives for the annual ca sh incentive program are linked to approved budget guidelines and nonfinanc ial measures are aligned with t he interests of all of HECO’s

stakeholders.

 Financial and nonfinancial performance for annual cash incentive programs are aligned for named executive officers, other officers and nonexecutive employees.

 An executive compensation recovery policy permits clawback/recoupment of performancebased compensation paid to executives found pers onally responsible for fraud, gross negligence

or intentional misconduct that causes a rest atement of HECO’s fi nancial statements.160  Financial opportunities under long-term incentive programs are greater than financial opportunities under annual incentive programs, thereby encouraging sustained attention to long-term value growth and mitigating excessive short-term risk-taking.

 Stock ownership guidelines requiring Mr. Rosenblum to hold certain amounts of HEI Common Stock ensure that HECO’s chief executive has a substantial personal stake in the long-term performance of HECO and HEI. The guidelines specific to Mr. Rosenblum are incorporated herein by reference to the discussion of stock ownership guidelines in the HEI 2012 Proxy Statement.

 Payouts under the long-term incentive plan are 100% equity based beginning with the 2010-2012 performance period, so executives share in the same upside potential and downside risk as all

shareholders.

 Payouts under performance-based plans are generally pro-rata (only when performance is above minimum thresholds), rather than “all-or-nothing.”

 Annual grants of long-term equity-based incentives vest over a period of years to encourage executives to focus on sustaining HECO’s and HEI’s long-term performance.

 Performance-based plans use a variety of financial and nonfinancial performance metrics (e.g., net income, return on average common equity, total shareholder return, achievement of clean energy initiatives, safety and customer satisfaction, among others), that correlate to long-term creation of shareholder value and are impacted by management decisions.

 The goal-setting process is variable and nonformulaic and considers prior performance, market conditions and peer group measures relative to future expected performance to assess the reasonableness of the goals.

 The HECO Board and HEI Compensation Committee exercise discretion in establishing performance goals and metrics, in determining whether these goals have been achieved and in administering all performance-based and equity awards.

 The HECO Board and HEI Compensation Committee continuously monitor HECO’s progress toward its goals in juxtaposition to ri sks faced by the enterprise, thro ugh management presentations at quarterly meetings and through periodic written reports from management.

Compensation Philosophy

What is HECO’s philosophy regarding its executive compensation programs?

The overall objective of HECO’s philosophy is to have compensation plans that enhance long-term shareholder value while considering HECO’s stakeholders, including empl oyees, customers and regulators. The specific goals that sati sfy this objective are:

 To attract and retain talented executives;

 To motivate that talent thro ugh rewards aligned to the creat ion of sustainable value; and

 To satisfy these attraction and a lignment goals at a reasonable cost.

How are the programs designed and wh at are they designed to reward?

The compensation programs’ objecti ves of attraction, alignment and cost are designed to be mutually distinct and collectively complete.

 Total compensation is levelized at approximately the competitive mark et median of the relevant peer group of companies to promote executive recruitm ent, retention and motivation, while at a reasonable

cost.

 Compensation elements are designed to incent individual and gr oup performance toward achieving the Company’s strategic goals.

 Compensation components are proportionally bal anced between cash and equity to ensure an appropriate level of alignment of executives ’ compensation with shareholders’ interests.

 Multiple metrics are established that focus execut ives on long-term value creation and risk management consideration, with Company per formance measured against its peers.

 In making executive compensation decisions, the HECO Board and HEI Compensation Committee consider how changes in one elem ent impact other compensation elem ents as well as the overall pay

mix for each executive.161 Compensation Program

What is each element of executive compensati on and how does it fit HECO’s compensation objectives?

The following chart summarizes the components of HE CO’s executive compensat ion program and their connection to the Company’s executive compensation objec tives. Each compensation element is described in further detail in the pages that follow and in the c harts and notes under “Executi ve Compensation” below.

Element Description Objectives

CURRENT YEAR PERFORMANCE Base Salary Fixed level of cash compens ation targeted to peer group median (but may vary based on performance, experience, responsibilities and other factors). A ttract and retain talented executives by providing marketcompetitive base salary.

A nnual Incentive Cash award based on achievem ent of Company goals during the year.

Awards are at risk becaus e they depend on pre-set performance goals. Poor perfo rmance yields no incentive payment.

Combined with base salary, tar get annual incentive provides a market-competitive total annual cash opportunity. Motivate executives and pay for performance that benefits key stakeholders, including shareholders, customers and employees.

Attract and retain talented leaders by providing competitive annual cash opportunity.

Balance compensation cost and return by paying awards based on Company performance.

LONG-TERM COMPENSATIONLong-term Performancebased Awards Long-term incentive award opportunity based on meeting performance objectives over rolling three-year periods.

Awards are at risk becaus e they depend on pre-set performance goals. Poor perfo rmance yields no incentive payment.

Target level of performance is based on peer group median.

Beginning with 2010-2012 long-term incentive plan, awards are payable 100% in shares of HEI stock. Motivate executives and pay for performance that creates long-term value.

Align executive interests wi th those of shareholders by focusing on long-term growth and by paying awards in the form of equity.

Attract and retain talented leaders by setting target level to be competitive with peer median.

Balance compensation cost and return by paying awards based on performance.

A nnual Stock-based

Grant A nnual equity grants in the form of restricted stock units (RSUs).

Amount of annual grant is a percentage of long-term compensation at market-competitive levels.

Awards vest in annual installments over 4 years. A lign executive and shareholder interests by ensuring executives have a significant personal stake in long-term growth of the company.

Motivate high business performance.

Retain talented leaders th rough multi-year vesting.

RETIREMENT, PENSION & SAVINGS

HEI Retirement Plans HECO executives participate in defined benefit pension plans and savings plans under the same terms and conditions as all HEI and HECO employees.

The HEI Excess Pay Plan enables HEI and HECO executives to earn retirement benefits correlated to salary compensation in excess of limits applicable to defined benefit pension plans. A ttract and retain talented leaders by providing retirement income and enhancing long-te rm employee well-being.

HEI Deferred Compensation Plans Enable HEI and HECO executives to defer portions of cash compensation, with certain limitations. A ttract and retain talented leader s by providing an additional method of saving for retirement and enhancing long-term employee well-being.

OTHER BENEFITS
Double Trigger Changein-control Agreements Double-trigger agreem ents, with 1 times to 2 times payment multiples. (Double-trigger = change in control followed by qualifying loss of employment.) A ttract and retain qualified leaders capable of a high level of performance that creates va lue for shareholders and other

stakeholders.

Encourage focused attention of executives in the change-incontrol context.

HEI Executive Death

Benefit Plan Form of insurance that provides benefits to HEI and HECO
executive beneficiaries in event of executive’s death; frozen to those participants who were employees as of September

2009. Provide peace of mind to enhance long-term employee wellbeing.

How does HECO determine the amount for each element?

Peer Benchmarking. The HECO Board and HEI Compensatio n Committee focus heavily on peer group comparisons to determine the appropria te compensation for named executive officers. The HECO Board162 and HEI Compensation Committee benchmark the elem ents of named executive officer compensation toward the median of HECO’s peer group, while al lowing individual differences based on an executive’s importance to the organization, indi vidual competency and performance, l ength of time in the position, execution of strategy, competitive options and retention and succession considerations. Peer companies are, in the aggregat e, similar in financial scope and va luation, provide similar products and services and are sources for talented employ ees. Peer companies are selected by the HEI Compensation Committee’s independen t compensation consultant and are reviewed and approved by the HEI Compensation Committee and HECO Board. In late 2010, Frederic W. Cook & Co., Inc. (F red Cook & Co.) the HEI Compensation Committee’s independent compensation consultant, conducted a peer group selection and compensation comparison for purposes of setting 2011 compensation. HECO’s peers were chosen from among utilities with primarily regulated operations. The resulting peer group included 18 public utilities with annual revenue generally between approximately one-half to two-times that of HECO. Following is HECO’s peer group* for 2011 compensation:

Allegheny Energy Alliant Energy

Avista

Black Hills

DPL Great Plains Energy

IDACORP

NorthWestern

NSTAR NV Energy OGE Energy Pinnacle West Capital

PNM Resources

Portland General Electric TECO Energy UniSource Energy

Vectren Westar Energy

* Some company names have changed and some compani es no longer exist due to transactions that

occurred after the Fred Cook & Co. peer group selection was completed.

The results of the review revealed that the tota l direct compensation (i.e., annual cash compensation plus long-term incentive awards) of Messrs. Ros enblum and McMenamin and Ms. Wong is approximately at

the median level. Ms. Sekimura’s tota l direct compensation is below the 25 th

percentile and the total direct compensation for Mr. Alm is between the 25 th

percentile and median.

Other Considerations. In addition to using the above peer group as a reference, the HECO Board and HEI Compensation Committee consider other factors in developing the amount of compensation, including internal equity among the named executive officers , individual and Company performance, experience and other matters. The HECO Board and HEI Compens ation Committee believe that the comparative compensation among the named executive officers is fa ir, considering job scope, experience, value to the organization and duties relative to the other named execut ive officers, and that the total compensation for the named executive officers is appropriate given the needs of the Company, the experience, responsibilities, competencies and performance of the ex ecutive team and market comparisons.

What are the base salaries of the HECO named executive officers?

Base salaries for our named executive officers ar e targeted to the median of the competitive peer group (with individual differences above or below the median in light of considerations discussed above under “How

does HECO determine the amount for ea ch element?”) in order to provide a base level of compensation for the year and to attract and retain the talent needed to run HECO’s comple x operations and create value for all

HECO stakeholders. In February 2011, the HECO Board approved base salary increases for the HECO named executive officers to be effective as of January 2011 as shown in the table below:

Name Base Salary

Increase % Base Salary

Increase Base Salary

Effective January 2011
Richard M. Rosenblum $15,000 2.6% $602,000 Tayne S. Y. Sekimura $7,000 2.6% $281,000 Robert A. Alm $8,400 2.4% $365,000 Stephen M. McMenamin $9,000 3.5% $264,000 Patricia U. Wong $5,800 2.0% $295,000163 What was HECO’s 2011 annual incentive plan and were there any payouts?

HECO named executive officers have the opportuni ty to earn an annual cash incentive award based on the achievement of performance goals during the year. Goals under HECO’s annual incentive plan, known as the Executive Incentive Compensation Plan (EICP) , are designed to (i) focus executives on building fundamental earnings in a controlled risk manner, (ii) promote nonfinanc ial goals important to HECO’s stakeholders and (iii) motivate executives and encour age their commitment to HECO’s success. Award ranges are determined in comparison to competitive peers to assist in attracting and retaining high-caliber

executives.

Award ranges . Following are the 2011 HECO EICP named executive office r award ranges established by the HECO Board and HEI Comp ensation Committee in February 2011, s hown as a percentage of base salary as of January 3, 2011:

Name Minimum Threshold Target Maximum

Richard M. Rosenblum 35% 70% 140% Tayne S. Y. Sekimura 20% 40% 80%

Robert A. Alm 25% 50% 100% Stephen M. McMenamin 20% 40% 80% Patricia U. Wong 20% 40% 80%

Metrics, goals and results . In February 2011, the HECO Board and HEI Compensation Committee established the 2011 EICP performance metrics and goals, wh ich focused on four key constituencies of the utility: (i) shareholders, (ii) employees, (iii) customers and (iv) regulators. The following table lists the metrics, weightings, minimum thresholds, targ et and maximum goals and results fo r the 2011 HECO EICP. The named executive officers listed together below shared the same goals.

Metric and Weighting (%) Minimum

Threshold Target Maximum Result

Richard M. Rosenblum

HECO Consolidated Net Income (1) (40%) $98 million $109 million $120 million $105.7 million (between minimum and target)

HECO Operations & Maintenance Expense Management (2)

(20%) $420 million $400 million $380 million $373.8 million (maximum)

HECO Consolidated Safety (3)

(15%) 2.41 1.85 1.30 1.99 (between minimum and target)

Hawaii Clean Energy Initiative (4) (15%) Meet minimum

milestones Meet target

milestones Meet maximum

milestones Met target milestones

HECO Consolidated Customer Satisfaction (5) (10%) 52 nd

percentile 54 th percentile 56 th percentile 21 st percentile (below minimum)

Tayne S. Y. Sekimura, Robert A. Alm, Stephen M. McMenamin, Patricia U. Wong

HECO Consolidated Net Income (1) (30%) $98 million $109 million $120 million $105.7 million (between minimum and target)

HECO Operations & Maintenance Expense Management (2)

(20%) $420 million $400 million $380 million $373.8 million (maximum)

HECO Safety (3)

(15%) 2.41 1.85 1.30 2.00 (between minimum and target)

Hawaii Clean Energy Initiative (4) (15%) Meet minimum

milestones Meet target

milestones Meet maximum

milestones Met target milestones

HECO Consolidated Customer Satisfaction (5) (15%) 52 nd

percentile 54 th percentile 56 th percentile 21 st percentile (below minimum)

Individual Goal (6) (5%) Meet minimum

milestones Meet target

milestones Meet maximum

milestones Varies by individual (see note 6)

(1) For the purpose of determining the net income result for the 2011 EICP for all named executive officers, and in accordance with authority provided under the HEI 2010 Equity and Incentive Plan, in February 2012 the HEI Com pensation Committee and HECO Bo ard approved an adjustment to HE CO GAAP net income to exclude the impact of a charge to net income of approxi mately $6 million, which related to HECO’s write off of $9.5 m illion in project costs with respect to Phase 1 of the East Oahu Trans mission Project (EOTP). For further detail on the EOTP Phase 1 write off and the resu lting charge to net income,

see Note 3 to HEI’s Consolidated Financial Statements.

(2) Operations and Maintenance Expense Managem ent encourages utility executives to seek better ways to perform operations and m aintenance projects. Demand-side management expenses were excluded for purposes of this metric.164 (3) Consolidated Safety and HECO Safety focus on employee safety for HECO and its subsidiaries and for HECO alone, respectively . HECO Consolidated Safety and HECO Safety are measured by Total Cases Incident Rate (TCIR) , which is a standard measure of safety. TCIR is equal to the total number of Occupational Safety and Health Administ ration recordable cases × 200,000 productive hours divided by the to tal number of produc tive hours for the year, with

the lower the TCIR the better.

(4) Hawaii Clean Energy Initiative (HCEI) focuses executives on projects intended to obtain r enewable energy from wind, photovo ltaics, biomass, geothermal, ocean and other sources to help the utilities meet their commi tments under the HCEI, an agreement between the state of Hawaii a nd the utilities to reduce the state’s dependency on fossil fuels by increasing the development and usage of renewable energy. HECO achieved the target level for this metric by meeting four out of five project objec tives set as goals for the HCEI metric. Specified milestones were achieved or exceeded with resp ect to: contracting to purchase renewable energy, biofuels contract ing, continued development of Smart Grid and Adv anced Metering Infrastructure projects and t he interisland cable project.

(5) HECO Consolidated Customer Satisfaction focuses on customer s, is based on customer surveys conducted by a third party vendo r, and compares utility performance to the national utility industry. This metric is an indicator of how satisfied customers are with the utilities’ s ervice, reliability and pricing relative to

other utilities.

(6) Individual goals are based on achievement of objectives s pecific to the executive’s area of responsibility. Ms. Sekimura ac hieved her individual goal at the target

level. Mr. McMenamin had two individual goals, evenly weighted at 2.5%, one was achi eved at the minimum threshold level and on e was achieved at the target level. Ms. Wong achieved her goal at the minimum threshold level.
As a result of achieving the performance levels indicated above, in Febr uary 2012 the HECO Board and HEI Compensation Committee approved payment of the following 2011 EICP awar ds for the HECO named

executive officers:

Name Payout

Richard M. Rosenblum $430,355 Tayne S. Y. Sekimura $110,704

Robert A. Alm $170,622 Stephen M. McMenamin $102,687 Patricia U. Wong $113,269

What was HECO’s 2009-2011 l ong-term incentive plan and were there any payouts?

HECO named executive officers have the opportunity to earn awards under HECO’s long-term incentive plan (LTIP) based on meeting or exceedi ng performance goals over rolling thr ee-year performance periods. The three-year performance periods provide balance with the shorter-term focus of the annual incentive program. In addition, the overlapping three-y ear performance periods encourage su stained high levels of performance because at any one time three separate potential awards ar e affected by current performance. These incentives also are intended to have a favorable retention impact on executives due to their long-term nature. The 2009- 2011 LTIP awards were paid in cash or in a mix of cash and HEI Common Stock, as described below. Beginning with the 2010-2012 performance period, LTIP awards will be paid 100% in HEI Common Stock.

Award ranges . In February 2009, the HECO Board and HEI Compensa tion Committee approved the following award ranges for Messrs. Rose nblum and Alm and for Ms . Sekimura. At the time the 2009-2011 LTIP was approved, Ms. Wong was serving as HEI Vice President – Administra tion and Corporate Secretary. Her award range was approved by the HEI Compensation Committee and HEI Board. Mr. McMenamin did not participate in the 2009-2011 LTIP because he became employ ed at HECO after the start of this performance period. The award ranges below are shown as a percentage of annual base sa lary as of January 1, 2009:

Name Minimum Threshold Target Maximum

Richard M. Rosenblum 45% 90% 180% Tayne S. Y. Sekimura 20% 40% 80%

Robert A. Alm 20% 40% 80% Patricia U. Wong 35% 70% 140%

Metrics, goals and results . The table below lists th e metrics, weightings, mini mum thresholds, target and maximum goals and results for the 2009-2011 LTIP . The 2009-2011 LTIP metrics and goals below were selected by the HECO Board and HEI Compensati on Committee in February 2009 because they were believed to provide the necessary incentives to ali gn executive compensation with shareholder value while considering key HECO stakeholders, including customer s, employees and regulators. Each goal was aligned with HECO’s strategic plan and determined by the HECO Board and HEI Compensation Committee to be at a
level which, if achieved, would be wo rthy of the incentive compensation.

The named executive officers listed together below shared the same goals. During part of this performance period (from January 2008 to Septem ber 2009), Ms. Wong serv ed as Vice President – Administration and165 Corporate Secretary at HEI. In September 2009, Ms. Wong transferred to HECO as its Seni or Vice President, Corporate Services and assumed HECO goals at the same aw ard ranges establishe d for her at HEI.

Metric and Weighting (%) Minimum Threshold Target Maximum Result

Richard M. Rosenblum

HEI Total Return to Shareholders (TRS) as percentile of Edison Electric Institute (EEI)

Index (1)

(60%) 30 th percentile 50 th percentile 70 th percentile 31 st percentile

HEI Return on Average Common Equity (ROACE) (2) (20%) 9.1% 10.1% 11.1% 8.4% (below minimum)

HECO Consolidated ROACE as % of

consolidated allowed rate of return on equity (3)

(20%) 90% 95% 100% 64% (below minimum)

Tayne S. Y. Sekimura, Robert A. Alm and HECO Metrics & Goals for Patricia U. Wong

HEI TRS as percentile of EEI Index (1)

(60%) 30 th percentile 50 th percentile 70 th percentile 31 st percentile

HECO Consolidated ROACE as % of

consolidated allowed rate of return on equity (3)

(40%) 90% 95% 100% 64% (below minimum)

HEI Metrics & Goals for Patricia U. Wong

HEI TRS as percentile of EEI Index (1)

(60%) 30 th percentile 50 th percentile 70 th percentile 31 st percentile

HEI ROACE (2) (40%) 9.1% 10.1% 11.1% 8.4% (below minimum)

(1) Total Return to Shareholders (TRS) is based on the relationship between HEI’s total return and that of the Edison Electric Inst itute (EEI) Index. TRS is the sum of the growth in the price per share of HEI Common Stock fr om the beginning of the performance period to the end, plus dividend s paid during the period, assuming reinvestment, divided by the beginni ng price of HEI Common Stock. The EEI is an association of U.S. shareholder-owned electric companies that are representative of comparable investment alter natives to HEI. The EEI’s members serve 95% of the ultimate customers in the share holder-owned segment of the industry and represent approxim ately 70% of the U.S. electric power industry. The following companies were in the three-year EE I Index in 2011:

A LLETE Alliant Energy

Ameren

American Electric Power

Avista

Black Hills Centerpoint Energy

Central Vermont Public

Service CH Energy Group

CLECO CMS Energy

Consolidated Edison Constellation Energy Group

Dominion Resources DTE Energy Duke Energy

Edison International

El Paso Electric The Empire District Electric Entergy

Exelon First Energy Great Plains Energy

Hawaiian Electric Industries

IDACORP Integrys Energy Group MDU Resources Group MGE Energy NEXTERA Energy

NiSource

Northeast Utilities NorthWestern Energy

NSTAR NV Energy OGE Energy

Otter Tail Pepco Holdings

PG&E Pinnacle West Capital

PNM Resources

Portland General Electric

PPL Progress Energy Public Service Enterprise Group

Scana Sempra Energy

Southern TECO Energy UIL Holdings UniSource Energy

Unitil

Vectren Westar Energy Wisconsin Energy Xcel Energy

(2) HEI ROACE is the ratio of average net in come (which is HEI GAAP net income, adjus ted for any exclusions authorized by the H EI Compensation Committee and HECO Board) over the three- year performance period divided by average common equity as meas ured from the beginning to the e nd of the performance period.

(3) HECO Consolidated ROACE as a percentage of allowed return is measured as the average consolidated return on average common equity for the three-year period compared to the average consolidated allowed return on co mmon equity as determined by the PUC for the three-year perform ance period.

In February 2009, when the 2009-2011 LTIP awar d opportunities were establ ished, the HECO Board and HEI Compensation Committee approved that, if earned, the 2009-2011 LT IP awards for Ms . Sekimura and Mr. Alm would be paid 100% in cash. In recognition of Mr. Rosenblum’s abi lity to impact HEI’s performance, and because Ms. Wong was still employed by HEI at the time the 2009-20 11 LTIP award opportunities were
established, the 2009-2011 LTIP aw ard opportunities for Mr. Rosenblum and Ms. Wong were defined 60% in
cash and 40% in HEI Common Stock, wi th the number of shares of HEI st ock determined base d on the price of

HEI stock on the date the 2009-2011 award opportunities were establis hed. In accordance with these
determinations, the 2009-2011 LTIP awar d payouts for Ms. Sekimura and Mr. Al m were entirely in cash and the payouts for Mr. Rosenblum and Ms. W ong included both cash and stock (plu s accrued dividends less applicable taxes). Ms. Wong’s to tal 2009-2011 LTIP payout (b oth the cash and st ock portions) is ba sed on her HEI and HECO goals and was prorated for the period that s he served at each company. Despite HECO and HEI’s strong performance in 2011, the improvement in HEI ROACE and HECO

Consolidated ROACE over t he three-year 2009-2011 LTIP period was sl ower than originally anticipated.166 Based on the achievement of the perfo rmance levels indicated in the c hart above, in February 2012 the HECO Board and HEI Compensation Committee approved the following cash payouts under the 2009-2011 LTIP for

the HECO named executive officers below:

Name Cash Payout
Richard M. Rosenblum $98,658 Tayne S. Y. Sekimura $32,256

Robert A. Alm $37,422 Patricia U. Wong $37,799

The remaining portion of the payouts for Mr. Ro senblum and Ms. Wong was in HEI Common Stock. Following are the stock awards approved by the HECO Board and HEI Compensation Committee for Mr. Rosenblum and Ms. Wong as part of their total 2009-2011 LTIP payout:

Name Stock Award Richard M. Rosenblum 3,872 shares (plus accrued dividends) Patricia U. Wong 1,482 shares (plus accrued dividends)

What is HECO’s 2010-2012 long-term incentive plan?

HECO’s 2010-2012 long-term incentive plan was explained at pages 178-179 of its Annual Report on Form 10-K for the fiscal year ended De cember 31, 2010, which explanation is incorporated by reference.

What is HECO’s 2011-2013 long-term incentive plan?

In accordance with design changes made by the HECO Board and HEI Compensation Committee beginning with the 2010-2012 LTIP, awards under the 2011- 2013 LTIP will be paid 100% in shares of HEI Common Stock (plus accrued dividends less applicabl e taxes). The potential number of shares was determined at the beginning of the performance period based on the participant’s salary at the beginning of the performance period and the fair mark et value of HEI Common Stock on the date the award opportunity was

established. The HECO Board and HEI Compensation Committee believe that setting a fixed number of shares at the beginning of the performance period, rather than a number of shares based on the dollar value of the award divided by the market pric e of the shares at payout, encourages even greater alignment of executive incentives with long-term value creation.

Award ranges . In February 2011, the HE CO Board and HEI Compensation Committee established the following 2011-2013 LTIP award ranges for HECO named executive officers, shown as a percentage of annual base salary as of January 3, 2011:

Name Minimum

Threshold Target Maximum

Richard M. Rosenblum 45% 90% 180% Tayne S. Y. Sekimura 20% 40% 80%

Robert A. Alm 20% 40% 80% Stephen M. McMenamin 20% 40% 80% Patricia U. Wong 20% 40% 80%

Metrics and goals . In February 2011 the HECO Board and HEI Compensation Committee also approved the following metrics, weightings , minimum threshold, target and ma ximum goals for the 2011-2013 LTIP. All

HECO named executive officers share the goals listed below.

Metric and Weighting (%) Minimum Threshold Target Maximum Richard M. Rosenblum, Tayne S. Y. Sekimura, Robert A. Alm, Stephen M. McMenamin, Patricia U. Wong

HEI TRS as percentile of EEI Index (40%) 30 th percentile 50 th percentile 75 th percentile

Utility Consolidated Return on Average Common Equity (ROACE) (30%) 79% 84% 89%

Utility 3-year Average Consolidated Net Income (30%) $118 million $131 million $144 million167 The HECO Board and HEI Compensation Commi ttee chose the metrics and goals above to encourage long-term achievement of HECO earnings and enhancement of shareholder value. Shareholders, customers and employees all benefit when these goals are met.

 Total return to shareholders is a performance measure to show the return on stock to an investor. HEI’s total return is compared to that of the EEI Index of investor-owned electric companies. It is a primary measure that reflects value created for HEI shareholders compared to that created by other investor-owned electric companies.

 HECO Consolidated Return on Average Common Equity as a percentage of allowed return is measured as the average consolidated return on average common equity for the three-year period compared to the average consolidated allowed return on common equity as determined by the PUC for the three-year performance period. The utility return on average common equity is a useful measurement for comparing the utility’s earnings to the earnin gs regulators have determined are reasonable in the most recent ratemaking proceeding of each respective utility. It encourages executives to seek to have each utility earn its allowed regulated return, which is important to shareholders and to regulators who share an interest in assuring that the utility can attract capital at a cost that is reasonable fo r utility customers.

 HECO Consolidated Net Income is a basic financial measure of earnings for the year and represents GAAP net income adjusted for any exclusions au thorized by the HEI Compensation Committee and

HECO Board.

From a historical perspective, payouts are not easy to achieve, nor are they guaranteed, under the HECO LTIP. The utilities face significant external challe nges in the 2011-2013 LTIP perfo rmance period. Extraordinary leadership on the part of the named executive officers will be neede d to achieve the long-term strategic objectives required for them to earn the incentive payou ts. The utility is focused on implementing Hawaii’s clean energy goals, which direct HECO to increase its portfolio of renewable resources. This increase in renewable sources requires major capital invest ments over the next several years, in turn requiring timely filing and regulatory approval in utility rate cases and other important dockets. The HECO Board and HEI Compensation Committee believe that the LTIP targets are challeng ing and that all stakeholders will benefit if HECO is successful in achieving these goals.

Do HECO named executive officers receive equity-based awards other than through the long-term incentive plan?

HECO named executive officers are eligible to re ceive annual equity-based grants in the form of restricted stock units (RSUs) that vest over f our years. RSUs offer executives t he opportunity to receive shares of HEI Common Stock on the date the restrictions lapse, ge nerally subject to continued employment with the company. The amount of the annual RSU grant is a percentage of the executive’s base salary. These awards align named executive officers’ interests with those of shareholders by exposing executives to the same upside potential and downside risk as shareholders. Since they take four years to fully vest, these awards focus executives on creating long-term value for shareholders and other stak eholders and encourage retention. In February 2011, RSUs were granted to all of t he HECO named executive officers. The HECO Board and HEI Compensation Committee determi ned the number of RSUs to be awarded in consultation with its independent compensation consultant and considering peer practices. T he RSUs granted in 2011 vest in equal annual installments over a four-year period and accrue dividend equivalent s, which are paid in conjunction with the annual installment vesting. The 2011 RSU grants are summarized in the 2011 Grants

of Plan-Based Awards tabl e and related notes below.

What retirement benefits do HE CO named executive officers have?

HECO provides retirement benefit s to named executive officers to promote financial security in recognition of years of service and to attract and re tain high-quality leaders. HE CO employees, including named executive officers, who joined the Company befor e May 1, 2011 were eligible to participate in the tax-qualified HEI Retirement Plan, a defined benefit pension plan, and to save for retirement on a taxdeferred basis through HEI’s 401(k) Plan, which does not provide matching contributions for participants who joined the Company before Ma y 1, 2011. In 2011, revisions were made to reduce the168 pension benefit under the HEI Retire ment Plan and to provide for limited Company matching contributions under the HEI 401(k) Plan, but only fo r employees hired on or after May 1, 2011. These changes are intended to lower the cost of pension benefits over the long term. Additional retirement benefits are also provided to certain HECO named executive officers through the nonqualified HEI Excess Pay Plan. Bene fits under the HEI Excess Pay Pl an are determined using the same formula as the HEI Retirement Plan, but are not subjec t to the Internal Revenue C ode limits on the amount of annual compensation that can be used for calculati ng benefits under qualified reti rement plans and on the amount of annual benefits that can be paid from qualified reti rement plans. This allows those participating in the HEI Excess Pay Plan the same general percentage of final average pay benef it afforded to other employees in the HEI Retirement Plan.

Retirement benefits are discussed in further detail in the 2011 Pension Benefits table and related notes

below.

May HECO named executive officers participate in nonqualified deferred compensation plans?

HECO provides named executive officers the opportunity to participate in plans that allow them to defer compensation and the resulting tax liability. HECO nam ed executive officers may participate in the HEI Deferred Compensation Plan, a nonqualified deferred co mpensation plan implemented in 2011 that allows deferral of portions of the participants’ cash compensat ion, with certain limitati ons, and provides investment opportunities that are substantiall y similar to those available under the HEI 401(k) Plan. There are no matching contributions under the HEI Deferred Compens ation Plan. HECO named executive officers are also eligible to defer payment of annual and long-term incentive awards and the resulting tax liability under a prior HEI nonqualified deferred compensat ion plan. No HECO named executiv e officer participated in either of the HEI deferred compensation plans in 2011.

Do HECO named executive officers have executive death benefits?

The Executive Death Benefit Plan of HEI and Particip ating Subsidiaries, which provides death benefits to

an executive’s beneficiaries in the ev ent of the executive’s death while employed or after retirement, was closed to new participants effective September 9, 2009. These death benefits are provided to beneficiaries of

HECO named executive officers other than Mr. McMenamin, who is not covered by the plan because he became a HECO executive officer after September 9, 2009. In addition, the benefits to beneficiaries of participants who were employees as of such date were frozen (i.e., the plan was amended to foreclose any

increase in death benefits that would occur due to sa lary increases after September 9, 2009). Under the

Executive Death Benefit Plan contracts with participants in effect be fore September 9, 2009, the death benefits were grossed up for tax purposes. This treatment was considered appropriate because the executive death

benefit is a form of life insuranc e and traditionally life insurance proceeds have been tax-exempt. Death

benefits are discussed in further detail in the 2011 Pension Benefit s table and related notes below.

Do HECO named executive officers have change-in-control agreements?

Mr. Rosenblum and Ms. Wong are t he only HECO named executive office rs who are parties to a changein-control agreement. The HECO Board and HEI Compensation Committ ee view change-in-control agreements to be an appropriate tool to recruit executives as an expect ed part of their compensati on package, to encourage the continued attention of key executives to the performance of their duties without dist raction in the event of a potential change in control and to assist in reta ining key executives. Change-in-control agreements can protect against executive flight during a transaction when key executives might, in the absence of the agreement, accept employm ent with competitors. The change-in-control agreements for Mr. Rosenblum and Ms. Wong are double trigger, which means that the executive would receive a severance payme nt only if there is both a change in control and the executive loses his/her job as a result. The agreements provide for a cash lump sum severance multiplier of two times for Mr. Rosenblum and one time for Ms. Wong. The multiplier is appl ied to the sum of the executive’s annual base salary and annual incentive compensation (determined to be the greater of the current target incentive compensat ion or the largest actual incent ive compensation during the preceding169 three fiscal years). Aggregate payments under these agr eements are limited to the maximum amount

deductible under Section 280G of the Internal Revenue Code and there are no tax gross ups with respect to these agreements. Payment of the severance benefits is conditioned on the Company receiving a release of claims by the executive. The change-in control agreements have initial term s of two years and automatically renew for an additional year on each anniversary unless 90 days’ notice of nonrenewal is provided by either party, so that the protected period is at least one year upon nonrenewal. The agreements remain in effect for two years following a change in control. The agreements define a c hange in control as a change in ownership of HEI, a substantial change in the voting power of HEI’s securities or a change in the majority of the composition of the HEI Board following the consummation of a merger, t ender offer or similar tran saction. Mr. Rosenblum’s agreement also defines a change in control as a c hange in ownership of HECO . Change-in-control benefits are discussed in further detail in the Potential Paym ents upon Termination or Change in Control section and

related notes below.

What other benefits do HECO named executive officers have?

HECO provides limited other com pensation to the named executive officers because they are commonly provided to business executives in Hawaii, such as club memberships primarily for the purpose of business entertainment, or are necessary to recruit executiv es, such as relocation expenses or extra weeks of vacation, or because of legacy program s that are no longer available to new participants. HECO may, from
time to time, reimburse for r easonable business-related expenses. HECO has eliminated nearly all tax gross-ups for nam ed executive officers. There are no tax gross-ups allowed on club membership initiati on or membership fees, or in t he change-in-control agreements for Mr. Rosenblum or Ms. Wong. As discussed under “Do HE CO named executive officers have executive death benefits?,” tax gross-ups of death benef its have been restricted to the exec utives who participated in the Executive Death Benefit Plan pr ior to September 9, 2009 (the date the plan was frozen). In 2011, Mr. Rosenblum had a club membership fo r the primary purpose of business entertainment expected of executives in his position. As part of his employment offe r, Mr. Rosenblum received a signing bonus upon his hire by HECO in 2009, subject to monthly pro-rata reim bursement in the event of a volunt ary termination or termination for cause prior to the completion of 36 months of servic e. This reimbursement period ended as of January 2012. In addition, as part of his recrui tment, Mr. Rosenblum was extended a special severance agreement that provided that, in the event his empl oyment was terminated without caus e on or before the third anniversary
of the date of his hire, he would be paid a declining portion of his annual base salary and any target annual incentive compensation amount, depending on his length of service. This special severance agreement has now expired since three years have elapsed since Mr. Rosenblum joined HECO . Such a severance agreement is not uncommon when hiring experienced executives, especially from the mainland United States, who may have difficulty in finding other employment if their job is terminated within months of their hire and relocation. Since the special severance agreem ent for Mr. Rosenblum has now expired, there are no separate severance agreements for an y named executive officers. The named executive officers would participate in the same manner as all HECO non-bargaining unit employ ees in HECO’s standard severance policy based on years of service. As part of Mr. Rosenblum’s recr uitment, HECO also agreed to give him a credit of two years age and service for purposes of calculating his retirement benefits under the HEI Excess Pay Plan and ten days of
sick leave and four weeks of vacation, which is mo re than a new employee would usually receive. Mr. McMenamin, who joined HECO in Sept ember 2009, is eligible for reimbur sement for tem porary housing and monthly round-trip airfare to California, and associated ground transportation, for 36 months after his date of hire and is eligible for three weeks of vacation, whic h is more than a new employee would usually receive. For further description of the amounts descr ibed above see footnote 5 to the 2011 Summary Compensation Table below.170 Summary Compensation Table The following summary compensation table shows th e base salary, bonus (if applicable), grant date fair value of stock awards, non-equity incentive compens ation, change in pension va lue and nonqualified deferred compensation earnings and all other compensati on and benefits paid or aw arded to the HECO named executive officers during 2009, 2010 and 2011 (as applic able). All compensation amounts presented for Mr. Rosenblum are the same amounts that will be pres ented for him in the HEI 2012 Proxy Statement.

2011 SUMMARY COMPENSATION TABLE

Name and 2011
Principal Positions Year Salary ($) Bonus ($) (1) Stock

Awards ($) (2) Non-Equity

Incentive

Plan
Compensation ($) (3) Change in

Pension Value
and Nonqualified

Deferred
Compensation Earnings ($) (4) All Other
Compensation ($) (5) Total ($)

Richard M. Rosenblum * 2011 602,000 – 873,872 529,013 337,515 25,696 2,368,096

President and Chief 2010 584,667 – 786,620 282,037 279,777 26,335 1,959,436

Executive Officer 2009 580,000 250,000 348,916 322,289 435,513 149,881 2,086,599

Tayne S. Y. Sekimura 2011 281,000 – 229,667 142,960 256,733 – 910,360

Senior Vice President and 2010 271,334 – 204,667 236,944 263,699 – 976,644

Chief Financial Officer 2009 262,667 – 25,478 68,953 118,328 – 475,426

Robert A. Alm 2011 365,000 – 316,593 208,044 309,198 – 1,198,835

Executive Vice President 2010 354,933 – 286,658 325,720 288,234 – 1,255,545

2009 340,833 – 33,970 112,765 184,754 – 672,322

Stephen M. McMenamin ** 2011 264,000 – 176,176 102,687 80,096 27,344 650,303

Senior Vice President and 2010 253,333 – 152,591 58,736 62,032 44,775 571,467

Chief Information Officer 2009 62,500 – – – 34,103 267,852 364,455

Patricia U. Wong *** 2011 295,000 – 241,116 151,068 303,615 – 990,799

Senior Vice President, 2010 288,033 – 213,134 400,226 332,812 – 1,234,205
Corporate Services

* Richard M. Rosenblum joined HECO as President and Chief Executive Officer on January 1, 2009.
** Stephen M. McMenamin joined HECO as Senior Vice President and Chief Information Officer on September 28, 2009, and was a consultant to HECO prior to that time. Compensation for his consulting services in 2009 is included in “All Other Compensation” for 2009 for Mr. McMenamin and was described in footnote 6 to the 2009 Summary Compensation Table in HECO’s Form 10-K for 2009.
*** Patricia U. Wong rejoined HECO as Senior Vice President-Corporate Services on September 28, 2009. (1) Represents bonuses paid in cash that were not awarded under a non-equity incentive plan. Incentive compensation awarded under nonequity incentive plans are reported under “Non-Equity Incentive Plan Compensation.” Mr. Rosenblum received a signing bonus of $250,000 upon his hiring in 2009. (2) These amounts represent the aggregate grant date fair value of stock awards computed in accordance with FASB ASC Topic 718. Stock awards include restricted stock units and performance awards under the 2011-2013 LTIP (based on probable outcome of performance conditions as of the grant date). See 2011 Grants of Plan Based Awards table for the 2011 grants of restricted stock units and performance

awards under the 2011-2013 LTIP to the HECO named executive offi cers. Assuming achievement of the highest level of performance conditions, the maximum value of the performance awards payable in 2014 under the 2011-2013 LTIP is: Mr. Rosenblum $1,266,183, Ms. Sekimura $262,678, Mr. Alm $341,187, Mr. McMenamin $246,789 and Ms. Wong $275,772. For a discussion of the assumptions underlying the amounts set out for restricted stock units and performance shares, see Note 10 to HEI’s Consolidated Financial S tatements.171 (3) The 2011 EICP and non-equity 2009-2011 LTIP awards to the HECO named executive officers in the table below were approved by the HEI Compensation Committee and HECO Board and paid in February 2012. LTIP awards are generally determined in the first quarter of t he year following the three-y ear cycle ending on December 31 of the applicable plan year. In the table below, the payments shown for th e 2009-2011 LTIP for Ms. Sekimura and Mr. Alm represent their respective total awards. For Mr. Rosenblum and Ms. Wong, the amounts shown fo r the 2009-2011 LTIP represent the non-equity portion of their 2009-2011 LTIP award. Mr. Rosenblum and Ms. Wong also received a stock award under the 2009-2011 LTIP, with the stock award opportunity defined in shares at the beginning of the performance period. The n umber and value of the shares vested and awarded, and the dividend equivalents on those shares (which were paid in cash), are not reporte d in the 2011 Summary Compensation Table above but are shown in the 2011 Option Exercises and Stock Vested table below.

Name 2011 EICP ($) 2009-2011 LTIP ($) Total Non-Equity

Incentive Plan Compensation ($)

Richard M. Rosenblum 430,355 98,658 529,013 Tayne S. Y. Sekimura 110,704 32,256 142,960
Robert A. Alm 170,622 37,422 208,044 Stephen M. McMenamin 102,687

- 102,687 Patricia U. Wong 113,269 37,799 151,068

(4) These amounts represent the change in pension and executive death benefit values from December 31, 2010 to December 31, 201 1, December 31, 2009 to December 31, 2010 and December 31, 2008 to December 31, 2009, respectively. For a further discussion of th ese plans, see the 2011 Pension Benefits table and related notes below. No HECO named executive officer currently participates in either of the HEI nonqualified deferred compensation plans and none of them had above-market or preferential earnings on nonqualified def erred compensation for the periods covered in the table above.

(5) The following table summarizes the components of “All Other Compensation” paid with respect to 2011:

Name Travel Expense
Reimbursements ($) Other

($) Total All
Other Compensation ($)

Richard M. Rosenblum

— 25,696 25,696
Tayne S.Y. Sekimura

— — — Robert A. Alm

— — — Stephen M. McMenamin 22,267 5,077 27,344
Patricia U. Wong

— — —

 Mr. Rosenblum received a club membership and was granted four weeks of vacation.

 The total value of perquisites and other personal benefits provided by or paid by HECO was less than $10,000 for each of Ms.
Sekimura, Mr. Alm, and Ms. Wong and the value of such perquisites and other personal benefits is not included in the table

above.

 Mr. McMenamin was paid $22,267 in travel reimbursements for monthly round-trip airfare to California, and associated ground
transportation, in accordance with his offer letter, which provides for reimbursement of airfare for one round trip per month t o California for the 36 months following his date of hire. Mr. McMenamin was also eligible for three weeks of vacation.

Additional narrative disclosure about salary, bonus, stock awards, non-equity incentive plan compensation, change in pension va lue, nonqualified

deferred compensation, and other compensation can be found in the Compensation Discussion and Analysis above

.172 Grants of Plan-Based Awards

The following table relates to awards to the HE CO named executive officers in 2011 under the annual EICP tied to performance in 2011 and under the LT IP tied to performance over the 2011-2013 period and payable in 2014. Also shown are the RSUs granted under the 2010 Equity and Incentive Plan in 2011.

2011 GRANTS OF PLAN-BASED AWARDS

Estimated Future Payouts
Under Non-Equity Incentive
Plan Awards (1) Estimated Future Payouts
Under Equity Incentive Plan
Awards (2) A ll Other

Stock

Awards:

Number Grant Date

Name Grant

Date Threshold ($) Target ($) Maximum
($) Threshold (#) Target (#) Maximum
(#) of Shares

of Stock

or Units
(#) (3) Fair Value

of Stock

Awards
($) (4)

Richard M. Rosenblum 2/4/11 EICP 210,700 421,400 842,800

– – – – – 2/4/11 LTIP 10,858 21,715 43,431

– 633,080

2/4/11 RSU

– – – – – – 9,651 240,792

Tayne S. Y. Sekimura 2/4/11 EICP 56,200 112,400 224,800

– – – – – 2/4/11 LTIP 2,253 4,505 9,010

– 131,339

2/4/11 RSU

– – – – – – 3,941 98,328

Robert A. Alm 2/4/11 EICP 91,250 182,500 365,000

– – – – – 2/4/11 LTIP 2,926 5,852 11,703

– 170,611

2/4/11 RSU

– – – – – – 5,851 145,982

Stephen M. McMenamin 2/4/11 EICP 52,800 105,600 211,200

– – – – – 2/4/11 LTIP 2,116 4,232 8,465

– 123,382

2/4/11 RSU

– – – – – – 2,116 52,794

Patricia U. Wong 2/4/11 EICP 59,000 118,000 236,000

– – – – – 2/4/11 LTIP 2,365 4,729 9,459

– 137,873

2/4/11 RSU

– – – – – – 4,138 103,243

EICP Executive Incentive Compensation Plan (annual incentive)
LTIP Long-Term Incentive Plan (2011-2013 period)

RSU Restricted stock unit

(1) Includes awards under HECO’s 2011 EICP based on meeting performance goals at minimum threshold, target and maximum levels. See further discussion of the features of the awards in the Compensation Discussion and Analysis above.

(2) Represents number of shares of stock that would be issued under 2011-2013 LTIP awards payable in HEI Common Stock based upo n the achievement of all performance goals at minimum threshold, target and maximum levels and vesting at the end of the three-year performance period. LTIP awards are forfeited for terminations of employment during the vesting period, except for terminations due to death, disability and retirement, which allow for pro-rata participation based upon completed months of service after a minimum of 12 months of service in the performance period. See further discussion of the features of the awards in the Compensation Discussio n and Analysis above. Dividends accrue quarterly based on the actual dividend rate and are paid in cash at the end of the performance period

based on actual shares earned.

(3) Represents number of restricted stock units awarded in 2011 that will vest and be issued as unrestricted stock in four equ al annual increments on the grant date anniversary if the awardee has remained with the Company until that time. The awards are forfeited for terminations of employment during the vesting period, except for terminations due to death, disability and retirement, which al low for prorata vesting. The primary purpose of the RSUs is retention and there are no conditions to vesting other than the four-year grad ed vesting period. Dividend equivalent rights accrue quarterly based on the actual dividend rate and are paid in cash when the RSUs vest.

(4) Grant date fair value for shares under the 2011-2013 LTIP is estimated in accordance with the fair-value based measurement of accounting as described in FASB ASC Topic 718 based on the probable outcome of the performance conditions as of the grant date. For a disc ussion of the assumptions and methodologies used to calculate the amounts reported, see the discussion of performance awards contained in Note 10 (Share-based compensation) to HEI’s Consolidated Financial Statements. Grant date fair value for RSUs is based on the c losing sales prices of HEI Common Stock on the New York Stock Exchange on the date of the grant of the award.173 Outstanding Equity Awar ds at Fiscal Year-End

OUTSTANDING EQUITY AWARDS AT 2011 FISCAL YEAR-END

Option Awards Stock Awards

Equity

Incentive Equity Incentive Plan Awards

Number of

Securities
Underlying

Unexercised

Options Plan

Awards:

Number of

Securities
Underlying Option Shares or Units of Stock

That Have
Not Vested (1) Number of

Unearned

Shares, Units,

or Other Rights Market or
Payout Value

of Unearned

Shares,

Units, or

Name Grant

Year Exerciseable

(#) Unexerciseable

(#) Unexercised

Unearned Options (#) Option

Exercise
Price ($) Expiration

Date Number
(#) Market

Value
($) (2) That Have

Not Vested

(#) (3) Other Rights

That Have Not
Vested ($) (2)

Richard M. Rosenblum 2009

– – – – – 11,000 291,280

– – 2010

– – – – – 10,000 264,800 13,777 364,815

2011

– – – – – 9,651 255,558 10,858 287,520

Total

– – – – – 30,651 811,638 24,635 652,335
Tayne S. Y. Sekimura 2005 6,000

– – 26.18 4/07/15

– – – – 2008

– – – – – 1,000 26,480

– – 2009

– – – – – 1,500 39,720

– – 2010

– – – – – 4,000 105,920 2,808 74,356

2011

– – – – – 3,941 104,358 2,253 59,659

Total 6,000

– – – – 10,441 276,478 5,061 134,015

Robert A. Alm 2005 12,000

– – 26.18 4/07/15

– – – – 2008

– – – – – 1,000 26,480

– – 2009

– – – – – 2,000 52,960

– – 2010

– – – – – 6,000 158,880 3,712 98,294

2011

– – – – – 5,851 154,934 2,926 77,480

Total 12,000

– – – – 14,851 393,254 6,638 175,774
Stephen M. McMenamin 2010

– – – – – 2,000 52,960 2,639 69,881

2011

– – – – – 2,116 56,032 2,116 56,032

Total

– – – – – 4,116 108,992 4,755 125,913
Patricia U. Wong 2005 24,000

– – 26.18 4/07/15

– – – – 2008

– – – – – 1,500 39,720

– – 2009

– – – – – 2,500 66,200

– – 2010

– – – – – 4,000 105,920 3,016 79,864

2011

– – – – – 4,138 109,574 2,365 62,625

Total 24,000

– – – – 12,138 321,414 5,381 142,489

DE Dividend equivalents

(1) The 2008 restricted stock awards become unrestricted on April 15, 2012. The 2009 and 2010 RSUs become unrestricted on February 20, 2013 and May 11, 2014, respectively. The 2011 RSUs become unrestricted in four equal annual increments on the grant date annive rsary of February 4 over the four year period beginning February 4, 2011.

(2) Market value is based upon the closing price of HEI Common Stock on the New York Stock Exchange of $26.48 as of December 31, 20 11.

(3) Represents shares of stock that would be issued under the 2010- 2012 LTIP and 2011-2013 LTIP based upon achievement of performan ce goals at the minimum threshold level at the end of the three-year performance periods.174 Option Exercises and Stock Vested

2011 OPTION EXERCISE S AND STOCK VESTED

Option Awards Stock Awards

Name Number of
Shares Acquired on Exercise (#) Value

Realized on Exercise ($) Number of Shares
Acquired on Vesting (#) Value Realized on Vesting ($)

Richard M. Rosenblum – – 3,872 (1)

115,773
Tayne S. Y. Sekimura – – 500 (2) 12,260

Robert A. Alm 12,287 (3)

66,254 1,000 (2) 24,520
Stephen M. McMenamin – – – –
Patricia U. Wong 2,048 (3)

6,286 3,000 (2) 73,560

1,482 (1) 44,312

(1) Represents the number of shares acquired on vesting of performance share awards under the 2009-2011 LTIP, which were payable in stock at the end of the performance period. The HE I Compensation Committee certified the achievement of the applicable performance measures on February 7, 2012. Dividend equivalents were paid in cash based on the number of shares received as follows: Mr. Rosenblum $14,404 and Ms . Wong $5,513. For discussion of the payment of the performance shares in 2011, see discussion of “What was HECO’s 2009-2011 long-term incentive plan and was there any payout?” above.

(2) Represents the number of shares of restricted sto ck issued on April 12, 2007 and vesting on April 12, 2011.

(3) The options exercised by Mr. Alm and Ms. Wong were grant ed on April 21, 2003 with exercise price of $20.49.

Pension Benefits

The table below shows the present value as of December 31, 2011 of accumulated benefits for each of the HECO named executive officers and the number of years of service credited to each such executive under the applicable pension plan and executive death benefit plan, determined using the interest rate, mortality rate, and other assumptions set out below, which are consistent with those used in HEI’s financial statements (see Note 9 to HEI’s Consolidated Financial Statements):

2011 PENSION BENEFITS

Name Plan Name Number of

Years Credited

Service (#) Present Value of

Accumulated Benefit ($) (4) Payments During

the Last Fiscal Year ($)

Richard M. Rosenblum HEI Retirement Plan (1) 3.0 212,048 – HEI Excess Pay Plan (2) 5.0 588,150 –
HEI Executive Death Benefit (3) – 252,607 –
Tayne S. Y. Sekimura HEI Retirement Plan (1) 20.6 950,017 – HEI Excess Pay Plan (2) 20.6 102,685 –
HEI Executive Death Benefit (3) – 96,514 –
Robert A. Alm HEI Retirement Plan (1) 10.5 808,554 – HEI Excess Pay Plan (2) 10.5 353,456 –
HEI Executive Death Benefit (3) – 242,508 –
Stephen M. McMenamin HEI Retirement Plan (1) 2.3 167,734 – HEI Excess Pay Plan (2) 2.3 8,497 –
Patricia U. Wong HEI Retirement Plan (1) 21.6 1,324,893 – HEI Excess Pay Plan (2) 21.6 240,314 –
HEI Executive Death Benefit (3) – 144,818 –

(1) The HEI Retirement Plan is the standard retirement plan for HEI and HECO employees. Normal retirement benefits under the HEI Retirement Plan for management employees hired befor e May 1, 2011, including the named executive officers, are

calculated based on a formula of 2.04% × Credited Servic e (maximum 67%) × Final Average Compensation (average monthly base salary for highest thirty-six consecutive months out of the last ten years). The retirement plan for bargaining unit employees is determined under a different formula per the collective bargaining agreement. Credited service is generally the same as the years of service with HEI or ot her participating companies (Hawaiian Electric Company, Maui Electric Company and Hawaii Electric Light Company). A dditional credited service of up to eight months is175 used to calculate benefits for participants who retire at age 55 or later with respect to unused sick leave from the current y ear and prior two years. Credited service is also granted to disabled par ticipants who are vested at the time of disability for the per iod of disability. The normal form of benefit is a joint and 50% surv ivor annuity for married participants and a single life annuity f or unmarried participants. Other actuarially equivalent optional forms of benefit are also available. Participants who qualify to receive benefits immediately upon termination may also elect a single sum distribution of up to $50,000 with the remaining benefit paya ble as an annuity. At early retirement, the single sum distribution opt ion is not actuarially equivalent to the other forms of bene fit. Retirement benefits are increased by an amount equal to approximat ely 1.4% of the initial benefit every twelve months following retirement. Effective April 1, 2011, accelerated distributi on options (the $50,000 single sum distribution option and a Social Security level income option) under the HEI Retirement Plan becam e subject to partial restrictions because the funded status of the HEI Retirement Plan was deemed to be less than 80%. Generally, while the partial restrictions are in effect, a retiring participant may only elect an accelerated distribution option for 50% of the participant’s total benefit. The partial restrict ions are expected to continue through 2012. The plan provides benefits at ear ly retirement (prior to age 65), normal retirement (age 65)

, deferred retirement (over age 65) and death. Early retirement benefits are available for participants who meet the age and serv ice requirements at ages 50-64. Early retirement benefits are r educed for participants who retire prior to age 60, based on the participant’s age at the early retirement date. The accrued normal retirement benefit is reduced by an applicable percentage, which ranges from 30% for early retirement at age 50 to 1% at age 59. Accrued or earned benefits are not reduced for eligible employees who retire at age 60 and above. Changes to reti rement benefits for HEI and utility employees commencing employment after April 30, 2011 include a modified defined benefit plan (the Retirement Plan for Employees of Hawaiian Electric Industries, Inc. and Participating Subsidiaries) with a lower payment formula than the formula in the plan for employees hired before May 1, 2011 and the addition of a 50% match by the applicable employer on the first 6% of employee deferrals through the defined contribution plan under the Hawaiian Electric Industries Re tirement Savings Plan (HEIRSP). In addition, new eligibility rules and contribution levels applicable to certain HEI and Utilit y employees hired prior to May 1, 2011 and all employees hire d after April 30, 2011 were adopted for postretirement welfar e benefits. In general, defined pension benefits are based on the employees’ years of service and compensation. As of December 31, 2011, Mr. Alm and Ms. Wong are eligible for early retirement

benefits under the HEI Retirement Plan. Benefits for Ms. Sekimura are vested and her earliest retirement date is August 1, 2012

, when she will meet the age and service requirements for early retirement under the plan, assuming continued employment. Messrs. Rosenblum and McMenamin are not eligible for early retirement benefits under the HEI Retirement Plan and have no vested interest in the amounts reported above because they have not satisfied the five-year minimum service period that is required before vesting occurs.

(2) Benefits under the HEI Excess Pay Plan are determined using the same formula as the HEI Retirement Plan, but are not subject to the Internal Revenue Code limits on the amount of annual compensation that can be used for calculating benefits under qualified retirement plans ($245,000 in 2011 as indexed fo r inflation) and on the amount of annual benefits that can be paid from qualified retirement plans (the lesser of $195,000 in 2011 as indexed for inflation, or the participant’s highest ave rage compensation over three consecutive ca lendar years). Benefits payable under the HEI Excess Pay Plan are reduced by the benefit payable from the HEI Retirement Plan. Early retirement, death benefits and vesting provisions are similar to the HEI Retirement Plan. As of December 31, 2011, all of the HECO named executive officers were participants in the plan. On November 16, 2009, the HEI Board approved an Addendum to the HEI Excess Pay Plan, which granted Mr. Rosenblum an additional two years of service and two years added to his age to be applied in the calculation of his benefit under the HEI Excess Pay Plan. This resulted in the present value of his accumulated benefit under the HEI Excess Pay Plan shown in the table above being $291,021 more than it would have been without the additional credited years (i.e., without the additional credited years, the present value of his accumulated benef it under the HEI Excess Pay Plan would be $297,129). As of December 31, 2011, Mr. Alm and Ms. Wong are eligible for early retirement benefits immediately upon termination of employment. Accrued benefits for Ms. Sekimura are vested under t he HEI Excess Pay Plan and her earliest retirement date is August 1, 2012, when she will meet the age and service requirement s for early retirement under the plan, assuming continued employment. Messrs. Rosenblum and McMenamin are not eligible for early retirement benefits and have no vested interest in amounts reported above because they have not satisfied the minimu m five-year service period that is required before vesting

occurs.

(3) Messrs. Rosenblum and Alm and Mses. Wong and Sekimura ar e covered by the Executive Death Benefit Plan of HEI and Participating Subsidiaries. The plan provides death benefits equal to two times the executive’s base salary if the executive di es while actively employed or, if disabled, dies prior to age 65, and one times the executive’s base salary if the executive dies following retirement. Death benefits are grossed up by the amount necessary to pay income taxes on the grossed up benefit amount as an equivalent to the exempt status of death benefits pa id from a life insurance policy. The Executive Death Benefit Plan of HEI and Participating Subsidiaries was amended effective September 9, 2009 to close participation to new participants and freeze the benefit for existing participants. Under the amendment, death benefits including the grossed up amount payable

to the beneficiaries of Messrs. Rosenblum and Alm and Mses. Wong and Sekimura are equal to two times the respective executive’s base salary on September 9, 2009, if they die while actively employed, or, if disabled, die prior to age 65. Mr. McMenamin is not eligible for benefits under the Executive Deat h Benefit Plan of HEI and Participating Subsidiaries because he became a HECO executive officer after September 9, 2009.

(4) The present value of accumulated benefits for the HECO named executive officers included in the 2011 Pension Benefits table was determined based on the following:176 Methodology The benefits are calculated as of December 31, 2011 based on the credited service and pay of the HECO named executive officer as of such date (or the date of benefit freeze, if earlier).

Assumptions (a) Discount Rate – The discount rate is the interest rate used to discount future benefit payments in order to reflect the time value of money. The discount rates used in the present value calculations are 5.19% for retirement benefits and 4.9% for
executive death benefits as of December 31, 2011. (b) Mortality Table – The RP-2000 Mortality Table (separate male and female rates) projected seven years beyond the date of determination with Scale AA is used to discount future pens ion benefit payments in order to reflect the probability of survival to any given future date. For the calculation of t he executive death benefit present value, the mortality table rates are multiplied by the death benefit to capture the death benefit payments assumed to occur at all future dates. Mortality is applied post-retirement only. (c) Retirement Age – Each HECO named executive officer is assu med to remain in active employment until, and assumed to retire at, the earliest age when unreduced pension benefits would be payable, but no earlier than attained age as of December 31, 2011 (if later). (d) Pre-Retirement Decrements – Pre-retirement decrements refe r to events that could occur between the measurement date and the retirement age (such as withdrawal, early retirement, and death) that would impact the present value of benefits. No pre-retirement decrements are assumed in the calculat ion of pension benefit table present values. Decrements are assumed for financial statement purposes. (e) Unused Sick Leave – Each HECO named executive officer is assumed to have accumulated 1,160 unused sick leave hours at retirement age.

Nonqualified Deferred Compensation

Although HECO named executive officers are eligible to participate in the HEI deferred compensation plans, which are described in the Compensation Di scussion and Analysis above, no HECO named executive officer deferred any amount, and no HECO named executiv e officer had an account balance under those plans during 2011.177 Potential Payments Upon Termination or Change in Control

The table below reflects the amount of potential pay ments to each HECO named executive officer in the event of retirement, voluntary term ination, termination for cause, te rmination without cause and qualifying termination following a change in control, assumi ng termination occurred on December 31, 2011. The
amounts listed below are estimates; actual am ounts to be paid would depend on the actual date of termination and circumstances existing at that ti me. Mr. Rosenblum and Ms. Wong are the only HECO named executive officers with a change-in-control agreement.

2011 TERMINATION/CHANGE-IN-CONTROL PAYMENT TABLE

Name / Benefit Plan or Program Retirement on

12/31/11

($) (1) Voluntary

Termination

on 12/31/11 ($) (2) Termination

for Cause on

12/31/11

($) (3) Termination

without Cause

on 12/31/11 ($) (4) Qualifying

Termination after Change in

Control on

12/31/11

($) (5)

Richard M. Rosenblum Executive Incentive Compensation Plan (6) – – – – – Long-Term Incentive Plan (7) – – – – – Restricted Stock and Restricted Stock Unit (8) – – – – – Special Severance Payment (9) – – – 301,000 – Change-in-Control Agreement – – – – 2,580,856
TOTAL – – – 301,000 2,580,856

Tayne S. Y. Sekimura Executive Incentive Compensation Plan (6) – – – – – Long-Term Incentive Plan (7) – – – – 138,914 Restricted Stock and Restricted Stock Unit (8) – – – 24,549 118,956

TOTAL – – – 24,549 257,870

Robert A. Alm Executive Incentive Compensation Plan (6) – – – – – Long-Term Incentive Plan (7) 182,685 – – – 182,685 Restricted Stock and Restricted Stock Unit (8) 147,964 – – 24,549 161,051

TOTAL 330,649 – – 24,549 343,736

Stephen M. McMenamin Executive Incentive Compensation Plan (6) – – – – – Long-Term Incentive Plan (7) – – – – 130,493 Restricted Stock and Restricted Stock Unit (8) – – – – 33,772

TOTAL – – – – 164,265

Patricia U. Wong Executive Incentive Compensation Plan (6) – – – – – Long-Term Incentive Plan (7) 148,261 – – – – Restricted Stock and Restricted Stock Unit (8) 123,384 – – 36,824 – Change-in-Control Agreement – – – – 1,062,060
TOTAL 271,645 – – 36,824 1,062,060

Note: All stock-based award amounts were valued using the 2011 y ear-end closing price of HEI Common Stock of $26.48 per share. Other benefits that are available to all employees on a non- discriminatory basis and perquisites aggregating less than $10,000 in

value have not been listed.

(1) Retirement Payments & Benefits . Only Mr. Alm and Ms. Wong were eligible for early retirement as of December 31, 2011 and accordingly no amounts are shown in this column for any other HECO named executive officer. Amounts in this column also do not include amounts payable to Mr. Alm and Ms. Wong under the 2011 executive incentive compensation plan (EICP) or the 2009-2011 long term incentive plan (LTIP) because those amount s would have vested without regard to retirement since December 31, 2011 was the end of their performance periods. In addi tion to the amounts shown in this column, retired executives are entitled to receive their vested retirement plan benefits under all termination scenarios. See the 2011 Pension Benefits ta ble

above.

(2)

Voluntary Termination Payment & Benefits . If a HECO named executive officer voluntarily terminates employment, he or she could lose any annual or long-term incentives based upon t he HEI Compensation Committee’s right to amend, suspend or terminate any incentive award or any portion of it at any time. Voluntary termination results in the forfeiture of all unvested178 restricted stock, unvested restricted shares, unvested restrict ed stock units and participation in incentive plans. Amounts in this column also do not include amounts payable under the 2011 EICP or the 2009-2011 LTIP because those amounts would have vested without regard to voluntary termination since De cember 31, 2011 was the end of their performance periods. The executive’s participation in the change- in-control agreement would also end.

(3) Termination for Cause Payments & Benefits. If the executive is terminated for cause, he or she could lose any annual or longterm incentives based upon the HEI Compensation Committee’s right to amend, suspend or terminate any incentive award or any portion of it at any time. “Cause” generally means a violat ion of the HEI Corporate Code of Conduct or, for purposes of awards under the 1987 Stock Option and Incentive Plan (under which no new awards may be made) and the 2010 Equity Incentive Plan, has the meaning set forth in those plans. Termination for cause results in the forfeiture of all vested stock appreciation rights and related dividend equivalents, unvested re stricted stock, unvested restricted stock units and participation in incentive plans. The executive’s partici pation in a change-in-control agreement would also end and the executive’s benefit from the nonqualified retirement plans would be forfeited.

(4)

Termination without Cause Payments & Benefits. If the executive is terminated without cause, he or she could lose any annual or long-term incentives based upon the HEI Compensat ion Committee’s right to amend, suspend or terminate any incentive award or any portion of it at any time. Termination wi thout cause results in the pro rata vesting of restricted stock (based on service to date compared to origi nal vesting period) and forfeiture of unvested restricted stock units. In the case o f stock appreciation rights, the executive has one year in which to exercise.

(5) Change-in-Control Payments & Benefits. Of the HECO named executive officers, only Mr. Rosenblum and Ms. Wong have a change-in-control agreement. “Ch ange in control,” as defined under the change-in-control agreements and HEI’s 1987 Stock Option Incentive Plan and 2010 Equity and Incentive Plan, generally means a change in ownership of HEI, a substantial change in the voting power of HEI’s securities or a change in t he majority of the composition of the HEI Board following the consummation of a merger, tender offer or similar transacti on. Mr. Rosenblum’s change-in-control agreement also defines a change in control as essentially a change in ownership of HECO. Mr. Rosenblum’s and Ms. Wong’s change-in-control agreements provide lump sum severance multipliers of two times and one time, respectively, applied to the sum of the executive’s base salary and annual incentive compensation (det ermined to be the greater of the current target incentive compensation or the largest actual incentive compensation dur ing the preceding three years). In addition, Mr. Rosenblum and Ms. Wong would receive continued life, disability, dental, accident and health insurance benefits for two years and one year, respectively, and a lump sum payment equal to the present value of the additional benefit they would have earned under the applicable retirement and savings plans during the severance per iod. Mr. Rosenblum and Ms. Wong would also receive the greater of current target or actual pr ojected short- and long-term incentive comp ensation, prorated if termination occurs during the first half of the applicable performance period and t he full aggregate value if termination occurs after the end of the first half of the applicable performance period. Any unvested restricted stock and restricted stock units will become vested and free of restrictions upon a change in control. Additional age and service credit is received for the severance period for purposes of determining retiree welfare benefit eligibility. Exec utives would receive financial, tax planning and outplacement services, capped at 15% of annual base salary. Payment woul d generally be delayed for six months following termination of employment to the extent required to avoid an additional ta x under Section 409A of the Internal Revenue Code. Interest would accrue during the six-month delay per iod at the prevailing six-month certificate of deposit rate and payments would be set aside during that period in a grantor (rabbi) trust. All t he foregoing benefit amounts are included in this column but the

total severance is limited to the maximum amount deductible under Section 280G of the Internal Revenue Code for each of Mr. Rosenblum and Ms. Wong. Payment of the foregoing benefits is subject to a release of claims by the applicable named

executive officer. Other benefits are provided to executives, whether or not they have a change-in-control agreement, upon a change in control under the 1987 Stock Option Incentive Plan and 2010 Equity and Incentive Plan. The provisions in these plans and respective plan agreements provide for accelerated vesting or payments to be made to executives upon a change in control.

(6) Executive Incentive Compensation Plan (EICP). Upon death, disability or retirement, executives continue to participate in the annual incentive compensation plan at a pro-rated amount, prov ided there has been a minimum service of nine months during the annual performance period, with payment to be made by the Company in a lump sum at the end of the annual incentive plan cycle if the applicable performance goals are achieved, using the executive’s salary at the time of termination. In termination scenarios other than a change in control, death, di sability or retirement, participants who terminate during the pl an cycle forfeit any accrued annual incentive award. Annual incentive compensation payments in the event of a change in control are described in footnote 5 above and quantified as part of the Change- in-Control Agreement payment in the table above.

(7) Long-Term Incentive Plan (LTIP). Upon death, disability or retirement, executiv es continue to participate in each on-going LTIP cycle at a prorated amount, provided there has been a minimum serv ice of twelve months during the three-year performance period, with payment to be made by the Company as a lump sum at the end of the three-year cycle if performance goals are achieved, using the executive’s salary at the time of terminat ion. The amounts shown are at target for goals achievable for all applicable plan years, prorated based upon service through December 31, 2011; actual payouts will depend upon performance achieved at the end of the plan cycle. In termination scenario s other than a change in control, participants who terminate duri ng the plan cycle for reasons other than death, disability or retirem ent forfeit any accrued long-term incentive award. Long-term ince ntive179 compensation payments in the event of a change in control are described in footnote 5 above and quantified as part of the Change-in-Control Agreement payment in the table above.

(8) Restricted Stock and Restricted Stock Units. Restricted stock vests on a pro-rata basis (based on service to date compared to the original vesting period) upon termination without c ause and becomes fully vested upon a change in control for all

executives who have restricted stock. For all other termination events, the unvested restricted stock is forfeited. Restricted stock units vest on a pro-rata basis (based on completed quarters of service over the original vesting period) upon termination due to death, disability and retirement and become fully vested upon a change in control for all executives who have
restricted stock units. For all other termination events, the unv ested restricted stock units are forfeited. The amount shown i s based on the 2011 year-end closing price of vested shares. Restri cted stock and restricted stock unit severance payments in the event of a change in control are described in footnot e 5 above and have been quantified as part of the Change-in-Control Agreement payment in the table above.

(9)

Special Arrangements . As part of his employment offer, Mr. Rosenblum had a special severance agreement where in the event that his employment was terminated without cause on or before the third anniversary of his date of hire (January 1, 2009), he would be paid a declining portion of his annual base sa lary and any target annual incentive compensation under the EICP. If his employment was terminated after his second anniversary in 2011 and on or before his third anniversary of employment, he would have received 6 months of salary and any target annual incentive compensation. This special severance agreement expired in January 2012 and he is now elig ible for severance under the terms of HECO’s standard Severance Pay Plan, the terms of which apply equally to all HECO employees who are not bargaining unit employees.

Director compensation

The HECO Board believes that a co mpetitive compensation package is necessary to attract and retain individuals with the experienc e, skills and qualifications needed for the challe nging role of serving as a director

on the board of a regulated electric utility. Based on the recommendations of t he HEI Compensation
Committee, which is responsible for recommending nonemployee dire ctor compensation for the boards of HEI and its subsidiary companies, and taking into consideratio n the recommendations of the HEI Compensation Committee’s independent compensation consultant who periodically revi ews directors’ compensation, the HECO Board chooses to compensate nonemployee directors us ing a mix of cash a nd HEI Common Stock to allow for an appropriate level of compensation for se rvices, including stock awar ds designed to align the

interests of HECO directors with the interests of HEI shareholders. In 2010, the HEI Compensation Committee asked its independent compensation c onsultant, Fred Cook & Co., to conduct an evaluation of HECO’s nonemployee di rector compensation practices. Fred Cook & Co. assessed the structure of HECO’s nonemployee director compensation program and its value compared to competitive market practices of utility peer companies, similar to t he assessments used in its executive compensation review, which is described under “Compensation Discussion and Analysis—Compensation Program—How does HECO determine the amount for eac h element?” above. The 2010 analysis took into consideration the duties and scope of re sponsibilities of directors. The HEI Compensation Committee reviewed the analysis in determining its re commendations to the HECO Board concerning the appropriate nonemployee director compensation, including ca sh retainers, stock awards and meeting fees, and the HECO Board approved the HEI Compensation Committee’s recommendati ons to be effective on January 1, 2011. Although

Ms. Lau and Mr. Rosenblum are members of the HECO Board, they did not participate in the determination of nonemployee director compensation. Likewise, no other executive officer participated in the determination of nonemployee director compensation. Only nonemployee directors receive compensation for th eir service as directors. Nonemployee directors of HECO who are not also nonemployee di rectors of HEI receive co mpensation in the form of a cash retainer and an HEI stock grant. Don E. Carroll, Ti mothy E. Johns and Bert A. Kobayashi, Jr. are the nonemployee directors

of HECO who are not also di rectors of HEI. For part of 2011, Peggy Y. Fowler, David M. Nakada and Alan M.

Oshima were also HECO nonemployee directors who did not also serve on th e HEI Board. Nonemployee

directors of HECO who are also nonemployee directors of HEI do no t receive any addition al compensation for serving on the HECO Board. Thom as B. Fargo, Peggy Y. Fowler an d Kelvin H. Taketa are nonemployee

directors of HECO who are also nonemployee directors of HEI. For part of 2011, HEI directors Barry K. Taniguchi and Jeffrey N. Watanabe also served as HECO directors.

Stock awards. On June 30, 2011, each HECO nonemployee director who is not also on the HEI Board

received shares of HEI Common Stock with a val ue equal to $40,000 as an annual grant under the HEI 2011180 Nonemployee Director Stock Pl an, which was approved by HE I shareholders on May 10, 2011 (2011 Director Plan), for the purpose of further aligning directors’ and shareholders’ interests. The number of shares issued to each HECO nonemployee director wa s determined based on the clos ing sales price of HEI Common Stock on the New York Stock Exchange on June 30, 2011, Stock grants to nonemployee directors

under the 2011 Director Plan are made annual ly on the last business day in June.

Cash retainers . The following is the 2011 ca sh retainer schedule fo r nonemployee director s of HECO for 2011, which was paid in quarterly installment s. Nonemployee directors of HECO who also serve as a member or chairperson of the HECO Audit Commi ttee or as a non-voting HE CO Board representative to attend meetings of the HEI Compensation Committee receive additional retainer am ounts, as indicated below.

2011 HECO Director (who is not also an HEI director) .................................................................... $40,00 0
HECO Audit Committee Chairman .......................................................................................... $1 0,000

HECO Audit Committee Member ............................................................................................. $4,000 HECO Non-Voting Representative to HEI Compensation Committee ................................... $6,000

Further, the HECO Board has approv ed meeting fees of $750 per meeting payable to a director who is a

member or chair of the HECO Audit Committee afte r attending a minimum of ei ght HECO Audit Committee meetings during the calendar y ear and $1,500 per meeting payable to the HECO Board’s non-voting representative after attending six meeti ngs of the HEI Compensation Committee.

The boards of HECO subsidiaries HELCO and MECO ar e composed entirely of officers of HECO and/or its subsidiaries who receive no additional compensation for such service. Nonemployee directors may elect to participate in the HEI Nonemployee Direct ors’ Deferred Compensation Plan, as amended January 1, 2009, and the HEI Deferred Compensation Pl an implemented in 2011, both of which allow any nonemployee director to defer compensation from HEI or its participating subsidiaries for

service as a director. The HEI Deferred Compensation Plan allows deferral of portions of the participants’ cash compensation, with certain limit ations. No HECO director cu rrently participates in either plan. Directors, at their election and at their cost, may also participate in the gr oup employee medical, vision and dental plans generally made available to all HECO employ ees. Mr. Oshima was th e only HECO director wh o participated in the program duri ng 2011. Information concerning the compensation paid to direct ors of HECO who were also directors of HEI (or persons who were directors of both HECO and HEI for part of 2011), including Ms. Fowler and Messrs. Fargo, Myers, Taketa, Taniguchi and Watanabe, will be set forth in the applicable sections of the HEI 2012 Proxy Statement, which are incorporated herein by reference. The tables below include the following

information for Ms. Fowler and Mr. Taniguchi: (i) for Ms. Fowler, compensation for her 2011 service on the HECO Board prior to joining the HEI Board and co mpensation for her 2011 service on the HECO Audit Committee and (ii) for Mr. Taniguchi, compensation fo r his 2011 service on the HECO Audit Committee.181 2011 HECO DIRECTOR COMPENSATION TABLE

The following director compensation table show s the compensation paid or granted to nonemployee

members of the HECO Board for 2011:

Name Fees

Earned

or Paid in

Cash ($) (1) Stock

Awards ($) (2) Option

Awards

($) Non-Equity

Incentive

PlanCompensation ($) Change in

Pension Value and Nonqualified

Deferred Compensation

Earnings ($) All OtherCompensation ($) (3) Total ($)

Don E. Carroll (4) 29,639 40,000 NA NA NA – 69,639
Thomas B. Fargo (5) – – NA NA NA – –
Peggy Y. Fowler (6) 18,395 – NA NA NA – 18,395

Timothy E. Johns

Chairman Audit Committee 50,000 40,000 NA NA NA – 90,000

Bert A. Kobayashi, Jr. 40,000 40,000 NA NA NA – 80,000
A. Maurice Myers (5)(7) – – NA NA – – –

David M. Nakada (7) 14,396 – NA NA NA – 14,396

Alan M. Oshima (8) 35,625 40,000 NA NA NA – 75,625

Kelvin H. Taketa (5) – – NA NA NA – –
Barry K. Taniguchi (5)(7) 1,440 – NA NA NA – 1,440
Jeffrey N. Watanabe (5)(7) – – NA NA NA – –

NA Not applicable
(1) See detail of cash retainers for board and committee service below. (2) See description of annual HECO director stock awards in narrative preceding the above table. HECO directors do not receive any HEI restricted stock, restricted stock unit or stock option awards. (3) The total value of perquisites and other personal benefits provided by or paid by HECO was less than $10,000 for each of the nonemployee directors and the value of such perquisites and other personal benefits is not included in the table above. (4) Mr. Carroll joined the HECO Board on May 10, 2011. (5) During the entire period of their service on the HECO Board in 2011, Messrs. Fargo, Myers, Taketa, Taniguchi and Watanabe also served on the HEI Board. Information concerning their compensation will be set forth in the applicable sections of the HEI 2012 Proxy Statement, which are incorporat ed herein by reference. The amount shown in this table for Mr. Taniguchi reflects his service on the HECO Audit Committee prior to the end of his service on the HECO Board on May 10, 2011. (6) Ms. Fowler was elected to the HEI Board on May 10, 2011. She continued to serve on the HECO Board throughout 2011.

Amounts shown in this table for Ms. Fowler reflect com pensation she received for her 2011 service on the HECO Board prior to joining the HEI Board and for her 2011 service on the HECO Audit Committee. (7) The service of Messrs. Myers, Nakada, Taniguchi and Watanabe on the HECO Board ended effective May 10, 2011. (8) Mr. Oshima resigned from the HECO Board effective October 9, 2011 and became an employee of HEI.

Details of cash retainers for HECO Board and committee service are noted below:

Name HECO Board Retainer ($) HECO Audit

Committee Retainer ($) HECO Nonvoting Rep. to HEI Compensation Committee Retainer ($) Fees Earned

or Paid in Cash ($)

Don E. Carroll 25,714 2,572 1,353 29,639 Thomas B. Fargo – – – – Peggy Y. Fowler 14,395 4,000 – 18,395 Timothy E. Johns 40,000 10,000 – 50,000 Bert A. Kobayashi, Jr. 40,000 – – 40,000 A. Maurice Myers – – – –
David M. Nakada 14,396 – – 14,396
Alan M. Oshima 30,978 – 4,647 35,625

Kelvin H. Taketa – – – – Barry K. Taniguchi – 1,440 – 1,440 Jeffrey N. Watanabe – – – –182 ITEM 12. SECURITY OWNERSHIP OF CERTAI N BENEFICIAL OWNERS AND MANAGEMENT

AND RELATED STOCKHOLDER MATTERS

HEI:

Security Ownership of Cert ain Beneficial Owners

The information required under this item is incor porated herein by reference to the “Stock Ownership Information—Security Ownership of Certain Beneficia l Owners” and “Stock Ownership Information—Does HEI have stock ownership and retention guidelines for dire ctors and officers and does it have a policy regarding hedging the risk of ownership?” secti ons in the HEI 2012 Proxy Statement.

Equity compensation plan information

Information as of December 31, 2011 about HEI Common Stock that may be issued under all of the Company’s equity compensation plans was as follows:

Plan category (a)

Number of

securities
to be issued upon

exercise of
outstanding
options, warrants

and rights (1) (b)
Weighted-average
exercise price of

outstanding

options,

warrants and

rights (2) (c)

Number of securities
remaining available for

future issuance

under equity
compensation plans (excluding securities
reflected in column (a))
(3)

Equity compensation plans approved by shareholders 1,136,927 $25.28 3,111,589
Equity compensation plans not approved by shareholders –

– –
Total 1,136,927 $25.28 3,111,589

(1) This column includes the number of shares of HEI Common Stock which may be issued under the HEI 2010 Equity Incentive Plan (EIP) and the 1987 Stock Option and Incentive Plan (SOIP) on account of awards outstanding as of December 31, 2011, including:

SOIP EIP TOTAL

61,951

– 61,951 Non q ualified stock o p

tions p lus accrued dividend e q uivalents
5,900

– 5,900 Stock a pp reciation ri g hts p lus accrued dividend e q uivalent ri g hts
69,000 178,286 247,286 Restricted stock units * 18,577

– 18,577 Shares issued in Februar y 2012 under the 2009-2011 LTIP

434,890 368,323 803,213 Shares issuable at maximum payouts under the 2010-2012 and 2011-

2013 LTIPs

590,318 546,609 1,136,927

* Under the EIP, RSUs will be counted against the shares authoriz ed for issuance as four shares for every share issued. Accordingly, the 178,286 RSU shares in the table are c ounted as 713,144 shares in determining the 3,111,589 shares

available for future issuance under the EIP.

(2) The weighted average exercise price in this column rela tes to the outstanding 55,500 nonqualified stock options and 282,000 stock appreciation rights. Excluded from the weighted average exer cise price calculation are shares that may be issued without the payment of additional consideration (including the LTIP and restricted stock unit awards).

(3) This represents the number of shares available as of De cember 31, 2011 for future awards, including 2,846,497 shares
available for future awards under the EIP and 265,092 shares av ailable for future awards under the 2011 Nonemployee Director Plan. As of May 11, 2010, no new awards may be granted under the SOIP.183 HECO:

Security Ownership of Certain Beneficial Owners

HECO Common Stock. HEI owns all of HECO’s outstanding Common Stock, which is HECO’s only class of securities generally entitled to vote on matters requiring shareholder approval.

HECO Preferred Stock. Various series of HE CO Preferred Stock have been issued and are outstanding.

Shares of HECO Preferr ed Stock are not considered voting securities, but upon certain defaults in dividend payments holders of HECO Preferred St ock may have the right to elect a ma jority of the directors of HECO.
HEI owns 100,000 shares of HECO Pr eferred Stock, or approximately 9% of the 1,114,657 shares of HECO Preferred Stock outstanding. No HECO di rectors, executive officers or named executive officers (as listed in the 2011 Summary Compensation Table abov e) own HECO Preferred Stock.

HEI Common Stock. The table below shows the number of shares of HEI Common Stock beneficially owned by each person who is a current HECO director, each HECO named executive officer (as listed in the 2011 Summary Compensation Table above) and director s and executive officers as a group as of February 7, 2012.

Name of Individual or Group Amount and Nature of Beneficial Ownership of HEI Common Stock

Sole Voting or

Investment

Power (1) Shared Voting

or
Investment

Power (2) Other

Beneficial Ownership (3) Stock Options/

Restricted

Stock Units (4) Total (5)

Nonemployee directors
Don E. Carroll 28,859 –

– – 28,859 Thomas B. Fargo 18,566 – – – 18,566 Peggy Y. Fowler 1,081 6,283 – – 7,364 Timothy E. Johns 18,850 – – – 18,850 Bert A. Kobayashi, Jr. 12,942 – – – 12,942
Kelvin H. Taketa 27,357 – – – 27,357

Employee director

Constance H. Lau 261,966 – 8,012 45,501 315,479

Employee director and Named

Executive Officer
Richard M. Rosenblum 6,168 – – 6,168

Other Named Executive Officers
Robert A. Alm 35,307 – 4,197 5,346 44,850 Stephen M. McMenamin 342 – – – 342 Tayne S. Y. Sekimura 8,588 – – 3,708 12,296 Patricia U. Wong 30,055 – – 4,539 34,594

All directors and executive officers as a group (14 persons) 482,319 6,283 12,208 91,028 591,838

(1) Includes the following shares held as of February 7, 2012 in the form of stock units in the HEI Common Stock fund pursuant to the HEI Retirement Savings Plan: approximately 88 shares for Ms. Lau, 866 shares for Ms. Sekimura, 1,072 shares for Mr. Alm, 8,308 shares for Ms. Wong and 18,819 shares for all direct ors and executive officers as a group. The value of a unit is measured by the closing price of HEI Common Stock on the measurement date. Also includes the following unvested restricted shares over which the holders have sole voting but no investment power until the restrictions lapse: approximately
8,000 shares for Ms. Lau, 1,000 shares for Ms. Sekimura, 1,000 shares for Mr. Alm, 1,500 shares for Ms. Wong and 13,500 shares for all directors and executive officers as a group. (2) Shares registered in name of the individual and spouse. (3) Shares owned by spouse, children or other relatives sharing t he home of the director or officer in which the director or of ficer disclaims personal interest. (4) Includes the number of shares that the individuals nam ed above had a right to acquire as of or within 60 days after February 7, 2012 pursuant to (i) stock options, stock apprec iation rights and related dividend equivalent rights thereon and184 (ii) restricted stock units. These shares are included for pur poses of calculating the percentage ownership of each individual named above and all directors and executive officers as a group as described in footnote (5) below, but are not deemed to be outstanding as to any other person. This column does not incl ude any shares subject to stock appreciation rights (SARs) granted in 2005 and held by Mses. Lau, Sekimura and Wong and Mr. Al m. As of February 7, 2012, these persons held a total of 92,000 SARs granted in 2005, which have vested as of February 7, 2012 or will vest within 60 days after February 7, 2012. Upon exercise of a SAR, the holder will receive the number of s hares of HEI Common Stock that has a total value equivalent to the difference between the exercise price of the SAR and the fair market value of HEI Common Stock on the date of exercise, which is defined in the grant agreement as the aver age of the high and low sales prices on the NYSE on that date. As of February 7, 2012, the fair market value of HEI Co mmon Stock as defined in the grant agreement was $26.145 per share, which is lower than the exercise price of all of the 2005 SARs held by Mses. Lau, Sekimura and Wong and Mr. Alm on February 7, 2012. Thus, as of February 7, 2012, no shares would be issuable under the 2005 SARs. If the market value of HEI Common Stock increases to a sufficient level (above $26.18 in the case of SARs granted in 2005), then shares could be issued under these SARs within 60 days after February 7, 2012, but the number of shares that could be acquired in such event cannot be determined because it would depend on the fair mark et value of HEI Common Stock, as defined in the grant agreement, on the exercise date. (5) As of February 7, 2012, the directors and executive o fficers of HECO as a group and each individual named above beneficially owned less than one percent of the record number of outstanding shares of HEI Common Stock as of that date and no shares were pledged as security.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR

INDEPENDENCE

HEI:

The information required under this item for HEI is incorporated herein by reference to the sections relating to related person transactions and di rector independence in the HEI 2012 Proxy Statement.

HECO:

Does HECO have a written related person transaction policy?

The HEI Board has adopted a written related person trans action policy that is spec ifically incorporated in HEI’s Corporate Code of Conduct. The Corporate Code of Conduct, including the related person transaction policy, also applies to HECO and its subsidiaries. The related person transaction policy is specific to transactions between the Company and related persons su ch as executive officers and directors, their immediate family members or entities with which they are affiliated in which the amount involved exceeds $120,000 and in which any related person had or will have a direct or indirect mate rial interest. Under the policy, the HEI Board, acting through the HEI Nominating and Corpor ate Governance Committee, will approve a related person transaction involving a director or an officer if the HEI Board determines in advance

that the transaction is not inconsis tent with the best interests of HEI and its shareholders and is not in violation of HEI’s Corporate Code of Conduct.

Are there any related person transactions with HECO?

There have been no transactions since January 1, 2011, and there are no currently proposed transactions, in which HECO or any of its subsidia ries was a participant, the amount involved exceeds $120,000, and any related person (as defined in Item 404 of Regulation S-K) had or will have a direct or

indirect material interest.

Are HECO directors independent?

HECO has a guarantee with respect to 6.5% cumulati ve quarterly income prefe rred securities series 2004 (QUIPS) listed on the New York Stock Exchang e (NYSE). Because HEI has common stock listed on NYSE and HECO is a wholly-owned subsidiary of HE I, HEI is subject to the corporate governance listing standards in Section 303A of the NYSE Listed Company Manual and, by reason of an exemption resulting from HEI’s listing, HECO is not. Accordingly, HE CO is exempt from NYSE listing standards 303A.01 and 303A.02 regarding dire ctor independence.185 Although HECO is exempt from NYSE listing standards 303A.01 and 303A.02, HECO voluntarily endeavors to comply with these standards for direct or independence. The HEI No minating and Corporate

Governance Committee assists the HECO B oard with its independence determinations. For a director to be considered independent under NYSE listing standards 303A.01 and 303A.02, the

HECO Board must determine that the di rector does not have any direct or i ndirect material relationship with HECO or its parent or subsidiaries apart from his or her service as a directo r. The NYSE listing standards also specify circumstances under which a director may not be considered i ndependent, such as when the director has been an employee of the Company within t he last three fiscal years, if the director has had certain relationships with the Company’s external or in ternal auditor within the last three fiscal years or when the Company has made or received payments for goods or se rvices to entities with which the director or an immediate family member (as defined by NYSE) of the director has s pecified affiliations and the aggregate amount of such payments in any year within the last three fiscal years exceeds t he greater of $1 million or 2% of such entity’s consolidated gross revenues for the last fiscal year. The HEI Nominating and Corporate Governanc e Committee and the HECO Board considered the information below, which was provided by HECO dire ctors and/or by HEI and its subsidiaries, concerning relationships between (i) HECO or its affiliates and (ii) the director, the director’s immediate family members (as defined by NYSE) or entities with which such di rectors or immediate family members have certain

affiliations. Based on its consideration of the relati onships described below and the recommendations of the HEI Nominating and Corporate Governance Committee, the HECO Board deter mined that all of the nonemployee directors of HECO (Me ssrs. Carroll, Fargo, Johns, Kobayashi and Taketa and Ms. Fowler) are independent. In addition, the HECO Board had previously determined that Messrs. Myers, Nakada, Oshima, Taniguchi and Watanabe, each of whom served on th e HECO Board for part of 2011, were independent. The remaining directors of HECO, Ms. Lau and Mr. Rosenblum, are em ployee directors.

 With respect to Mr. Johns, the HECO Board cons idered amounts paid during the last three fiscal years to purchase electricity from HECO (the sole public utility providing electricity to the island of Oahu) by entities by which he was employed. None of the amounts paid by these entities for electricity (excluding pass-through surcharges for fuel and for Hawaii state revenue taxes) within the last three fiscal years exceeded the NYSE threshold t hat would automatically result in a director not being independent (i.e., the greater of $1 million or 2% of such entity’s consolidated gross revenues for the last fiscal year). The HECO Board also consi dered that HECO is the sole source of electric power on the island of Oahu and that the rates HE CO charges for electricity are fixed by state regulatory authority. Since purchas ers of electricity from HECO have no choice as to supplier and no ability to negotiate rates or other terms, the HECO Boar d determined that these relationships do not impair the independence of Mr. Johns.

 With respect to Messrs. Johns and Taketa, the HE CO Board considered the amount of charitable contributions during the last three fiscal year s from HEI and its subsidiaries to nonprofit organizations where these directors serve or serv ed as executive officers. No Company donations exceeded $300,000 per entity in any single fiscal y ear during the last three fiscal years. In determining that none of these relationships affe cted director independence, the HECO Board also considered the fact that Company policy requires that charitable contributions from HEI or its

subsidiaries to entities where a director serves as an executive officer, and where the director has a

direct or indirect material interest, and the aggregate amount donated by HEI and its subsidiaries to such organization would exceed $120,000 in any single fiscal year, be pr e-approved by the HEI Nominating and Corporate Governance Committee and ratified by the Board.

 With respect to Messrs. Carroll, Fargo and Johns , the HECO Board consi dered other director or officer positions held by those directors at entitie s for which a HECO officer serves or served as a

director and determined that none of these rela tionships affected the independence of these directors. None of these relationships resulted in a compensation committee interlock or would automatically prec lude independence under the NYSE standards.186  With respect to Mr. Johns, the HECO Board cons idered health insurance premiums paid by HEI, HECO and HECO’s subsidiaries to an entity where Mr. Johns became an executive officer in 2011. The health insurance premiums paid by HEI, HECO and HECO’s subsidiaries did not exceed the NYSE threshold that would automatically result in a director not being independent (i.e., the greater of $1 million or 2% of such entity’ s consolidated gross revenues for the last fiscal year) in any single year in any of the last three fiscal years. In addition, the HECO Board cons idered the fact that the relationship between HECO and the entity by which Mr. Johns is employed was established several decades before Mr. Johns’ employ ment by such entity.

 With respect to Mr. Kobayashi, Jr., the HECO Boar d determined that the service of his father as an ASB director did not impair Mr. Kobayashi , Jr.’s independence as a HECO director.

ITEM 14. PRINCIPAL ACCOUN TING FEES AND SERVICES

HEI:

The information required under this item is incorpor ated herein by reference to the relevant information in the Audit Committee Report in the HEI 2012 Proxy St atement (but no other part of the “Audit Committee Report” is incorporated herein by reference).

HECO:

Principal accountant fees

The table below shows the fees paid or payabl e to PricewaterhouseCooper s LLP (HECO’s independent registered public accounting firm) relating to the audi t of HECO’s 2011 consoli dated financial statements and fees for other professional services billed to HECO in 2011 with comparative amounts for 2010:

2011 2010 Audit fees (principally consisted of f ees associated with the audit of the

consolidated financial statements and in ternal control over financial reporting, quarterly reviews, issuances of letters to underwriters, review of registration statements and issuance of consents) $1,038,000 $ 902,000 Audit-related fees (principally consisted of fees associated with the audit of the financial statements of certain employee benefit plans) 19,000 15,000

Tax fees 146,000 298,000

All other fees

– –

$1,203,000 $1,215,000

Pre-Approval Policies

Pursuant to its charter, the HE CO Audit Committee provides input to the HEI Audit Committee regarding pre-approval of all audit and permitted non-audit servic es of the independent register ed public accounting firm engaged to audit HEI’s consolidated financial statements wi th respect to HECO, such as with respect to the

audit of HECO’s consolidated financial statement s. The HECO Audit Committee may delegate this responsibility to one or more of its members, provided that such mem ber or members report to the full committee at its next regularly scheduled meeting any su ch input provided to the HEI Audit Committee. The HECO Audit Committee has delegated such responsibility to its chairperson. With such input, the HEI Audit Committee pre-approved all of the audit and audit-related services re flected in the table above.187 

### PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)(1) Financial statements

See Item 8 for the financial statem ents of HEI. The financial statements for HECO are incorporated herein by reference to pages 5 to 46 of HECO Exhibit 99.2.

Page/s in HECO

Exhibit 99.2

Reports of Independent Registered Pu blic Accounting Firms ............ 5
Consolidated Statements of Income, Years ended
December 31, 2011, 2010 and 2009............................................. 7
Consolidated Balance Sheets, De cember 31, 2011 and 2010 ........... 8

Consolidated Statements of Capitalization,

December 31, 2011 and 2010 ......................................................... 9-10

Consolidated Statements of C hanges in Common Stock Equity,
Years ended December 31, 2011, 2010 and 2009 ....................... 11

Consolidated Statements of Cash Flows, Years ended December 31,
2011, 2010 and 2009 .................................................................... 12

Notes to Consolidated Fina ncial Statements ..................................... 13-46

(a)(2) and (c) Financial statement schedules

The following financial statement schedules for HEI and HECO are included in this report on the pages

indicated below:

Page/s in Form 10-K

HEI HECO

Reports of Independent Registered Public Accounting Firms .................... 188-189 190-191

Schedule I Condensed Financial Inform ation of Registrant, Hawaiian Electric Industries, Inc. (Parent Company) as of
December 31, 2011 and 2010 and Years ended
December 31, 2011, 2010 and 2009 .............................. 192-194 NA

Schedule II Valuation and Q ualifying Accounts, Years ended
December 31, 2011, 2010 and 2009 .............................. 195 195

NA Not applicable.

Certain schedules, other than thos e listed, are omitted because they are not requir ed, or are not applicable, or the requi red information is shown in the consoli dated financial statements (including the notes)

included in HEI’s and HECO’s C onsolidated Financial Statements.188 [PricewaterhouseCoopers LLP letterhead]



### Report of Independent Registered Public Accounting Firm on

Financial Statement Schedules

To the Board of Directors and Shareholders of
Hawaiian Electric Industries, Inc.:

Our audits of the consolidated financia l statements and of the effectiveness of internal control over financial reporting referred to in our report dated February 17, 2012, wh ich appears in this Annual Report on Form 10-
K, also included an audit of the financial statement schedules as of December 31, 2011 and 2010 and for each of the two years in the period ended December 31, 2011 listed in Item 15(a )(2) of this Form 10-K. In our opinion, these financial statement schedules as of December 31, 2011 and 2010 and for each of the two years in the period ended December 31, 2011 present fairly, in all material respects, the information set forth therein when read in conjunction with the re lated consolidated financial statements.

/s/ PricewaterhouseCoopers LLP Los Angeles, California February 17, 2012189 [KPMG LLP letterhead]



### Report of Independent Register ed Public Accounting Firm

The Board of Directors and Shareholders
Hawaiian Electric Industries, Inc.:

Under date of February 19, 2010, we reported on the consolidated statements of income, changes in shareholders’ equity, and cash flows of Hawaiian Electric Industries, Inc. and subsidiaries for the year ended
December 31, 2009, which are include d in the Company’s annual report on Form 10-K for the year 2011. In

connection with our audits of the af orementioned consolidated financial statements, we also audited the

related financial statement schedules as listed in the accompanying index under Item 15.(a)(2). These financial statement schedules are the responsibi lity of the Company’s management. Ou r responsibility is to express an opinion on these financial statem ent schedules based on our audits.

In our opinion, such financial statement schedules, when considered in relation to the basic consolidated
financial statements taken as a whole, present fairly, in all material respects, the information set forth

therein.

/s/ KPMG LLP
Honolulu, Hawaii February 19, 2010190 [PricewaterhouseCoopers LLP letterhead]



### Report of Independent Registered Public Accounting Firm on

Financial Statement Schedule

To the Board of Directors and Shareholder of Hawaiian Electric Company, Inc.:

Our audit of the consolidated financial statements of Hawaiian Electric Com pany, Inc. referred to in our report dated February 17, 2012 appearing in Exhibit 99.2 to this Annual Report on Form 10-K (which report and

consolidated financial statements are in corporated by reference in this Annual Report on Form 10-K) also

included an audit of the financial statement schedule as of and for the year ended December 31, 2011 listed in Item 15(a)(2) of this Form 10-K. In our opinion, this financial statem ent schedule as of and for the year ended December 31, 2011 presents fairly, in all material res pects, the information set forth therein when read in conjunction with the related c onsolidated financia l statements.

/s/ PricewaterhouseCoopers LLP Los Angeles, California February 17, 2012191 [KPMG LLP letterhead]



### Report of Independent Register ed Public Accounting Firm

The Board of Directors and Shareholder Hawaiian Electric Company, Inc.:

Under date of February 19, 2010, we reported on the consoli dated statements of income, changes in common stock equity and cash flows of Hawaiian Electric Company, Inc. (a subsidiary of Ha waiian Electric Industries, Inc.) and subsidiaries for the year ended December 31, 2009. These consolidated financial statements and our report thereon are incorporated by re ference in the Company’s annual r eport on Form 10-K for the year 2011.

In connection with our audit of the aforementioned cons olidated financial statements, we also audited the

related financial statement schedule as listed in the accompanying index under Ite m 15.(a)(2). The financial statement schedule is the responsibil ity of the Company’s management. Ou r responsibility is to express an opinion on the financial statem ent schedule based on our audit.

In our opinion, such financial statement schedule, when considered in relation to the basic consolidated

financial statements taken as a whole, presents fairly, in all material re spects, the information set forth therein.

/s/ KPMG LLP
Honolulu, Hawaii February 19, 2010192 Hawaiian Electric Industries, Inc.

SCHEDULE I — CONDENSED FINANCIA L INFORMATION OF REGISTRANT HAWAIIAN ELECTRIC INDUSTRIES, INC. (PARENT COMPANY)

CONDENSED BALANCE SHEETS

December 31 2011 2010 (dollars in thousands)

Assets Cash and cash equivalents $ 1,765 $ 1,540
Accounts receivable 1,361 1,773 Property, plant and equipment, net 6,076 582
Deferred income tax assets 14,208 12,684
Other assets 7,661 6,041

Investments in subsidiaries , at equity 1,902,154 1,838,679
$1,933,225 $1,861,299

Liabilities and shareholders’ equity

Liabilities Accounts payable $ 3, 602 $ 722 Interest payable 5,270 6,826 Notes payable to subsidiaries 7,019 6,777 Commercial paper 68,821 24,923 Long-term debt, net 282,000 307,000 Retirement benefits liability 26,201 20,888
Other 8,363 10,526

401,276 377,662

Shareholders’ equity Preferred stock, no par value, authorized 10,000,000 shares; issued: none

– – Common stock, no par value, aut horized 200,000,000 shares; issued and outstanding: 96,038,328 s hares and 94,690,932 shares 1,349,446 1,314,199 Retained earnings 201,640 181,910 Accumulated other comprehens ive loss (19,137) (12,472)

1,531,949 1,483,637
$1,933,225 $1,861,299

Note to Balance Sheets Long-term debt consisted of : HEI medium-term notes 4.23 and 6.141%, paid in 2011 $ – $150,000
HEI medium-term note 7.13%, due 2012 7,000 7,000

HEI medium-term note 5. 25%, due 2013 50,000 50,000

HEI medium-term note 6. 51%, due 2014 100,000 100,000
HEI senior note 4.41%, due 2016 75,000 –
HEI senior note 5.67%, due 2021 50,000 –
$282,000 $307,000

The aggregate payments of principal required subsequent to December 31, 2011 on long-term debt are $7 million in 2012, $50 million in 2013, $100 million in 2014, nil in 2015 and $75 million in 2016. As of December 31, 2011, HEI has a General Agreement of Indemnity in favor of both SAFECO Insurance Company of America (SAFECO) and Travelers Casualty and Surety Company of America (Travelers) for losses in connection with any and all bonds, undertakings or instru ments of guarantee and any renewals or extensions thereof executed by SAFECO or Travelers, including, but not limite d to, a $0.2 million self-insured United States Longshore &
Harbor bond and a $0.5 million self-insured automobile bond.193 Hawaiian Electric Industries, Inc.

SCHEDULE I — CONDENSED FINANCIAL INFO RMATION OF REGISTRANT (continued) HAWAIIAN ELECTRIC INDUSTRIES, INC. (PARENT COMPANY)

CONDENSED STATEMENTS OF INCOME

Years ended December 31 2011 2010 2009 (in thousands)

Revenues $ 253 $ 204 $ 400

Equity in net income of s ubsidiaries 158,722 134,470 100,896

158,975 134,674 101,296

Expenses:

Operating, administrative and general 15,401 13,336 12,675

Depreciation of property, pl ant and equipment 227 320 409

Taxes, other than income taxes 409 314 337

16,037 13,970 13,421

Operating income 142,938 120,704 87,875

Interest expense 22,013 19,961 18,517

Income before income tax benefits 120,925 100,743 69,358

Income tax benefits 17,305 12,792 13,653

Net income $138,230 $113,535 $ 83,011

The Company’s financial reporting policy for income tax a llocations is based upon a separate entity concept whereby each subsidiary provides income tax expense (or benefits) as if each were a separate taxable entity. The difference between the aggregate separate tax return income tax provisions and the cons olidated financial reporting income tax provision is charged or credited to HEI’s separate tax provision.194 Hawaiian Electric Industries, Inc.

SCHEDULE I — CONDENSED FINANCIAL IN FORMATION OF REGISTRANT (continued) HAWAIIAN ELECTRIC INDUSTRIES, INC. (PARENT COMPANY)

CONDENSED STATEMENTS OF CASH FLOWS
Years ended December 31, (in thousands) 2011 2010 2009 Cash flows from operating activities Net income $ 138,230 $ 113,535 $ 83,011 Adjustments to reconcile net income to net cash provided by operating activities Equity in net income (158,722) (134,470) (100,896)
Common stock dividends/distributions received from subsidiaries 128,558 110,769 105,128 Depreciation of property, plant and equipment 227 320 409

Other amortization 981 625 373 Changes in deferred income taxes 276 (1,432) (78) Changes in excess tax benefits from s hare-based payment arrangements 35 45 310 Changes in assets and liabilities Decrease (increase) in accounts receivable 412 (148) 213 Increase in accounts and interest payable 1,324 936 165 Changes in prepaid and accrued income taxes 3,550 (1,897) (2,799) Contribution to defined benefit pension and other pos tretirement benefit plans (1,785) (724) (1,267) Changes in other assets and liabilities 5,183 4,381 4,922 Net cash provided by operating activities 118,269 91,940 89,491 Cash flows from investing activities
Net decrease in notes receivable from subsidiaries – – 10,464 Capital expenditures (110) (84) (246) Investments in subsidiaries (40,000) (4,364) (61,969)

Other (4,206) – – Net cash used in investing activities (44,316) (4,448) (51,751) Cash flows from financing activities Net decrease in notes payable to subsid iaries with original maturities

of three months or less (1,757) (1,428) (2,120) Net increase (decrease) in short-term borrowings with original maturities of three months or

less 43,897 (17,066) 41,989 Proceeds from issuance of long-term debt 125,000 – – Repayment of long-term debt (150,000) – – Changes in excess tax benefits from share-bas ed payment arrangements (35) (45) (310) Net proceeds from issuance of common stock 15,979 22,706 15,329 Common stock dividends (106,812) (93,034) (96,843) Net cash used in financing activities (73,728) (88,867) (41,955) Net increase (decrease) in cash and equivalents 225 (1,375) (4,215) Cash and cash equivalents, January 1 1,540 2,915 7,130 Cash and cash equivalents, December 31 $ 1,765 $ 1,540 $ 2,915

Supplemental disclosures of noncash activities: In 2011, 2010 and 2009, $1.3 million, $1.1 million and $1.3 million, respectively, of HEI advances to ASHI were converted to equity in noncash transactions.

Under the HEI Dividend Reinvestment and Stock Purchas e Plan (DRIP), common stock dividends reinvested by
shareholders in HEI common stock in noncash transactions amounted to $12 million, $23 million and $17 million in 2011, 2010 and 2009, respectively. HEI satisfied the requirements of the HE I DRIP and the Hawaiian Electric Industries Retirement Savings Plan (HEIRSP) (from April 16, 2009 through September 3, 2009 and from August 18, 2011 through December 31, 2011) and the ASB 401(k) Plan (from its inception on May 7, 2009 through Sept ember 3, 2009 and from August 18, 2011 through December 31, 2011) by acquiring for cash its common shares through open mark et purchases rather than by issuing additional shares.195 Hawaiian Electric Industries, Inc. and Hawaiian Electric Company, Inc.

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS

Years ended December 31, 2011, 2010 and 2009

Col. A Col. B Col. C Col. D Col. E (in thousands) Additions

Description Balanceat beginning of period Charged to

costs and

expenses Charged

to other

accounts Deductions Balance at

end of period

2011

Allowance for uncollectible accounts –

electric utility $1,278 $4,419 $1,857 (a) $5,333 (b) $2,221

Allowance for uncollectible interest –

bank $4,397

– $428

– $4,825

Allowance for losses for loans

receivable – bank $40,646 $15,009 $1,741 (a) $19,490 (b) $37,906

2010

Allowance for uncollectible accounts –

electric utility $3,822 $(1,296) $1,910 (a) $3,158 (b) $1,278

Allowance for uncollectible interest –

bank $2,947

– $1,450

– $4,397

Allowance for losses for loans

receivable – bank $41,679 $20,894 $2,888 (a) $24,815 (b) $40,646

2009

Allowance for uncollectible accounts –

electric utility $3,425 $4,704 $8,764 (a) $13,071 (b) $3,822

Allowance for uncollectible interest –

bank $634

– $2,313

– $2,947

Allowance for losses for loans

receivable – bank $35,798 $32,000 $847 (a) $26,966 (b) $41,679

(a) Primarily bad debts recovered. (b) Bad debts charged off.196 (a)(3) and (b) Exhibits

The Exhibit Index attached to this Form 10-K is inco rporated herein by reference. The exhibits listed for HEI and HECO are listed in the index under the headings “HEI” and “HECO,” respectively, except that the

exhibits listed under “HECO” are also exhibits for HEI.



### SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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 execution of this r eport by registrant Hawaiian Electr ic Company, Inc. shall be deemed to relate only to matters having reference to such registrant and its subsidiaries.

HAWAIIAN ELECTRIC INDUSTRIES, INC. HAWAIIAN ELECTRIC COMPANY, INC. (Registrant) (Registrant)

By /s/ James A. Ajello By /s/ Tayne S. Y. Sekimura James A. Ajello Tayne S. Y. Sekimura
Executive Vice President, Chief Financial Senior Vice President and

Officer and Treasurer of HEI Chief Financial Officer of HECO (Principal Financial Officer of HEI) (Principal Financial Officer of HECO)

Date: February 17, 2012 Date: February 17, 2012

Pursuant to the requirements of the Securities E xchange Act of 1934, this report has been signed below by the following persons on behalf of the registrants and in t he capacities indicated on February 17, 2012. The execution of this report by each of the undersigned who signs this report sole ly in such person’s capacity as a director or officer of Hawaiian Electric Company, In c. shall be deemed to relate only to matters having reference to such registrant and its subsidiaries.

Signature Title

/s/ Constance H. Lau President of HEI and Director of HEI

Constance H. Lau Chairman of t he Board of Directors of HECO (Chief Executive Officer of HEI)

/s/ Richard M. Rosenblum President and Director of HECO Richard M. Rosenblum (Chief Executive Officer of HECO)

/s/ James A. Ajello Executive Vice President, Chief Financial Officer James A. Ajello and Treasurer of HEI (Principal Financial Officer of HEI)

/s/ David M. Kostecki Vice President-Finance, Controller and David M. Kostecki Chief Accounting Officer (Principal Accounting Officer of HEI)197 

### SIGNATURES (continued)

Signature Title

/s/ Tayne S. Y. Sekimura Senior Vice President and Tayne S. Y. Sekimura Chief Financial Officer of HECO (Principal Financial Officer of HECO)

/s/ Patsy H. Nanbu Controller of HECO Patsy H. Nanbu (Principal Accounting Officer of HECO)

/s/ Don E. Carroll Director of HECO

Don E. Carroll

/s/ Thomas B. Fargo Director of HEI and HECO Thomas B. Fargo

/s/ Peggy Y. Fowler Director of HEI and HECO Peggy Y. Fowler

/s/Timothy E. Johns Director of HECO Timothy E. Johns

/s/ Bert A. Kobayashi, Jr. Director of HECO Bert A. Kobayashi, Jr.

/s/ A. Maurice Myers Director of HEI A. Maurice Myers198 

### SIGNATURES (continued)

Signature Title

/s/ Keith P. Russell Director of HEI

Keith P. Russell

/s/ James K. Scott Director of HEI

James K. Scott

/s/ Kelvin H. Taketa Director of HEI and HECO

Kelvin H. Taketa

/s/ Barry K. Taniguchi Director of HEI Barry K. Taniguchi

/s/ Jeffrey N. Watanabe Chairman of the Board of Directors of HEI Jeffrey N. WatanabeEXHIBIT INDEX The exhibits designated by an asterisk (*) are filed herewit h. The exhibits not so designated are incorporated by reference to the indicated filing. A copy of any exhibit may be obtained upon writ ten request for a $0.20 per page charge from the HEI Shareholder Services Division, P.O. Box 730, Honolulu, Ha waii 96808-0730.

Exhibit no. Description

HEI: 3(i) HEI’s Amended and Restated Articles of Incorporation (Exhib it 3(i) to HEI’s Current Report on Form 8-K, dated May 5, 2009, File No. 1-8503).

3(ii) Amended and Restated Bylaws of HEI as last amended May 9, 2011 (Exhibit 3(ii) to HEI’s Current Report on Form 8-K May 9, 2011, File No. 1-8503).

4.1 Agreement to provide the SEC with instruments which define the rights of holders of certain long-term debt of HEI and its subsidiaries (Exhibit 4.1 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 1992, File No. 1-8503).

4.2 Indenture, dated as of October 15, 1988, between HEI and Citibank, N.A., as Trustee (Exhibit 4 to Registration Statement on Form S-3, Registration No. 33-25216).

4.3(a) First Supplemental Indenture dated as of June 1, 1993 between HEI and Citibank, N.A., as Trustee, to Indenture dated
as of October 15, 1988 between HEI and Citibank, N.A., as Trus tee (Exhibit 4(a) to HEI’s Quarterly Report on Form 10- Q for the quarter ended September 30, 1993, File No. 1-8503).

4.3(b) Second Supplemental Indenture dated as of April 1, 1999 between HEI and Citibank, N.A., as Trustee, to Indenture
dated as of October 15, 1988 between HEI and Citibank, N.A., as Trustee (Exhibit 4.1 to HEI’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1999, File No. 1-8503).

4.3(c) Third Supplemental Indenture dated as of August 1, 2002 between HEI and Citibank, N.A., as Trustee, to Indenture
dated as of October 15, 1988 between HEI and Citibank, N.A., as Trustee (Exhibit 4 to HEI’s Current Report on Form 8- K, dated August 16, 2002, File No. 1-8503).

4.4(a) Pricing Supplement No. 13 to Registration Statement on Form S-3 of HEI (Registration No. 33-58820) filed on September 26, 1997 in connection with the sale of Medium-Term Notes, Series B, 7.13% due October 1, 2012.

4.4(b) Pricing Supplement No. 1 to Registration Statem ent on Form S-3 of HEI (Registration No. 333-73225) filed on May 3, 1999 in connection with the sale of Medium-Term Notes, Series C, 6.51% due May 5, 2014.

4.4(c) Pricing Supplement No. 2 to Registration Statem ent on Form S-3 of HEI (Registration No. 333-87782) filed on
March 5, 2003 in connection with the sale of Medium-Term Notes, Series D, 5.25% due March 7, 2013.

4.4(d) Master Note Purchase Agreement among HEI and the Purchas ers thereto, dated March 24, 2011 (Exhibit 4(a) to HEI’s Current Report on Form 8-K dated December 5, 2011, File No. 1-8503).

4.5(a) Hawaiian Electric Industries Retirement Savings Plan, re statement effective May 1, 2011 (Exhibit 4.1 to HEI’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, File No. 1-8503).

4.6(a) Trust Agreement dated as of February 1, 2000 betw een HEI and Fidelity Management Trust Company, as Trustee (Exhibit 99.1 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 1999, File No. 1-8503).

4.6(b) First Amendment dated as of August 1, 2000 to Trust Agreement (dated as of February 1, 2000) between HEI and Fidelity Management Trust Company, as Trustee (Exhibit 99. 1 to HEI’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2000, File No. 1-8503).

4.6(c) Second Amendment dated as of November 1, 2000 to Trust Agreement (dated as of February 1, 2000) between HEI and Fidelity Management Trust Company, as Trustee (Exhibit 99.2 to HEI’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2000, File No. 1-8503).

4.6(d) Third Amendment dated as of April 1, 2001 to Trust Ag reement (dated as of February 1, 2000) between HEI and Fidelity Management Trust Company, as Trustee (Exhibit 99 to HEI’s Current Report on Form 8-K dated June 19, 2001, File No. 1-8503).

4.6(e) Fourth Amendment dated as of December 31, 2001 to Trust Agreement (dated as of February 1, 2000) between HEI and Fidelity Management Trust Company, as Trustee (Exhibit 99.1 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2001, File No. 1-8503).Exhibit no. Description 4.6(f) Fifth Amendment dated as of April 1, 2002, to Trust Ag reement (dated as of February 1, 2000) between HEI and Fidelity Management Trust Company, as Trustee (Exhibit 99.1 to HEI’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2002, File No. 1-8503).

4.6(g) Sixth Amendment dated as of January 1, 2002, to Trus t Agreement (dated as of February 1, 2000) between HEI and Fidelity Management Trust Company, as Trustee (Exhibit 99. 8 to HEI’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2002, File No. 1-8503).

4.6(h) Seventh Amendment dated as of July 1, 2002, to Tr ust Agreement (dated as of February 1, 2000) between HEI and Fidelity Management Trust Company, as Trustee (Exhibit 99. 1 to HEI’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2002, File No. 1-8503).

4.6(i) Eighth Amendment dated as of September 1, 2003, to Tr ust Agreement (dated as of February 1, 2000) between HEI and Fidelity Management Trust Company, as Trustee (Exhibit 99 to HEI’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2003, File No. 1-8503).

4.6(j) Ninth Amendment dated as of February 2, 2004, to Trus t Agreement (dated as of February 1, 2000) between HEI and Fidelity Management Trust Company, as Trustee (Exhibit 99. 2 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2003, File No. 1-8503).

4.6(k) Tenth Amendment dated as of October 3, 2005, to Trus t Agreement (dated as of February 1, 2000) between HEI and Fidelity Management Trust Company, as Trustee (Exhibit 99. 2(k) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2005, File No. 1-8503).

4.6(l) Eleventh Amendment dated as of November 1, 2006, to Trust Agreement (dated as of February 1, 2000) between HEI and Fidelity Management Trust Company, as Trustee (Exhibit 99.2(l) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2006, File No. 1-8503).

4.6(m) Twelfth Amendment dated as of August 1, 2007, to Trus t Agreement (dated as of February 1, 2000) between HEI and Fidelity Management Trust Company, as Trustee (Exhibit 99. 2 to HEI’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2007, File No. 1-8503).

4.6(n) Thirteenth Amendment dated as of October 17, 2008, to Trust Agreement (dated as of February 1, 2000) between HEI and Fidelity Management Trust Company, as Trustee (Exhibit 99.2(n) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008, File No. 1-8503).

4.6(o) Fourteenth Amendment dated as of December 31, 2008, to Trust Agreement (dated as of February 1, 2000) between HEI and Fidelity Management Trust Company, as Trustee (Exhibit 99.2(o) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008, File No. 1-8503).

4.6(p) Fifteenth Amendment effective as of January 15, 2010, to Trust Agreement (dated as of February 1, 2000) between HEI, ASB and Fidelity Management Trust Company, as Trustee (Exhibit 99.2(o) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2009, File No. 1-8503).

4.6(q) Sixteenth Amendment effective as of March 10, 2010, to Trust Agreement (dated as of February 1, 2000) between HEI, ASB and Fidelity Management Trust Company, as Trustee (Exhib it 4 to HEI’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010, File No. 1-8503).

4.6(r) Seventeenth Amendment effective as of December 31, 2010, to Trust Agreement (dated as of February 1, 2000) between HEI, ASB and Fidelity Management Trust Company, as Trus tee (Exhibit 4.6(r) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2010, File No. 1-8503).

4.6(s) Letter Amendment effective April 29, 2011, to Trust Agreement (dated as of February 1, 2000) between HEI, ASB and Fidelity Management Trust Company, as Trustee (Exhibit 4. 2 to HEI’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, File No. 1-8503).

4.6(t) Letter Amendment effective August 19, 2011, to Trus t Agreement (dated as of February 1, 2000) between HEI, ASB and Fidelity Management Trust Company, as Trustee (Exhibit 4 to HEI’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, File No. 1-8503).

*4.6(u) Eighteenth Amendment effective as of October 17, 2011, to Trust Agreement (dated as of February 1, 2000) between HEI, ASB and Fidelity Management Trust Company, as Trustee.

4.7 Hawaiian Electric Industries, Inc. Dividend Reinvestm ent and Stock Purchase Plan, as amended and restated (Exhibit 4(a) to Registration Statement on Form S-3, Registration No. 333-158999).

4.8 American Savings Bank 401k Plan (Exhibit 4 to Regi stration Statement on Form S-8, Registration No. 333-159000).Exhibit no. Description 10.1 Conditions for the Merger and Corporate Restructuring of Hawaiian Electric Company, Inc. dated September 23, 1982. (Exhibit 10.1 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2006, File No. 1-8503).

10.2 Regulatory Capital Maintenance/Dividend Agreement dated May 26, 1988, between HEI, HEIDI and the Federal Savings and Loan Insurance Corporation (by the Federal Home L oan Bank of Seattle) (Exhibit (28)-2 to HEI’s Current Report on Form 8-K dated May 26, 1988, File No. 1-8503).

10.3 OTS letter regarding release from Part II.B. of the Regul atory Capital Maintenance/Dividend Agreement dated May 26, 1988 (Exhibit 10.3(a) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 1992, File No. 1- 8503).

HEI Exhibits 10.4 through 10.21 are management contracts or compens atory plans or arrangements required to be filed as exhibits pursuant to Item 15(b) of this report. HEI Exhibits 10.4 thr ough 10.18 are also management contracts or compensatory plans or arrangements with HECO participants.

10.4 HEI Executive Incentive Compensation Plan amended and re stated as of February 23, 2009 (Exhibit 10.4 to HEI’s Annual Report on Form 10-K for the fiscal y ear ended December 31, 2008, File No. 1-8503).

10.5 HEI Executives’ Deferred Compensation Plan (Exhibit 10.2 to HEI’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, File No. 1-8503).

10.6 Hawaiian Electric Industries, Inc. 2010 Equity an d Incentive Plan, as amended and restated November 16, 2010 (Exhibit 10.6 to HEI’s Annual Report on Form 10-K for t he fiscal year ended December 31, 2010, File No. 1-8503).

10.6(a) Form of Non-Qualified Stock Option Agreement pursuant to 2010 Equity and Incentive Plan (Exhibit 4.4 to Registration Statement filed on May 11, 2010 on Form S-8 Registration No. 333-166737).

10.6(b) Form of Stock Appreciation Right Agreement pursuant to 2010 Equity and Incentive Plan (Exhibit 4.5 to Registration Statement filed on May 11, 2010 on Form S-8 Registration No. 333-166737).

10.6(c) Form of Restricted Shares Agreement pursuant to 2010 Equi ty and Incentive Plan (Exhibit 4.6 to Registration Statement filed on May 11, 2010 on Form S-8 Registration No. 333-166737).

10.6(d) Form of Performance Shares Agreement pursuant to 2010 Equity and Incentive Plan (Exhibit 4.7 to Registration Statement filed on May 11, 2010 on Form S-8 Registration No. 333-166737).

10.6(e) Form of Restricted Stock Unit Agreement pursuant to 2010 Equity and Incentive Plan (Exhibit 10.6(e) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2010, File No. 1-8503).

10.7 1987 Stock Option and Incentive Plan of HEI (as amended and restated effective January 22, 2008) (Exhibit 10.3 to HEI’s Quarterly Report on Form 10-Q for t he quarter ended June 30, 2008, File No. 1-8503).

10.7(a) Form of Hawaiian Electric Industries, Inc. Stock Opti on Agreement with Dividend Equivalents (Exhibit 10.7(b) to HEI’s Annual Report on Form 10-K for the fiscal y ear ended December 31, 2004, File No. 1-8503).

10.7(b) Form of Hawaiian Electric Industries, Inc. Stock Appr eciation Right Agreement with Dividend Equivalents (Exhibit 10.2 t o HEI’s Quarterly Report on Form 10-Q for the qua rter ended September 30, 2004, File No. 1-8503).

10.7(c) Form of Hawaiian Electric Industries, Inc. Stock Appr eciation Right Agreement with Dividend Equivalents (effective for April 7, 2005 stock appreciation rights grant) (Exhibit 10.1 to HEI’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005, File No. 1-8503).

10.7(d) Form of Restricted Stock Unit Agreement Pursuant to the 1987 Stock Option and Incentive Plan of HEI (Exhibit 10.7(f) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008, File No. 1-8503).

10.8 HEI Long-Term Incentive Plan amended and restated as of February 23, 2009 (Exhibit 10.8 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008, File No. 1-8503).

10.9 HEI Supplemental Executive Retirement Plan amended and re stated as of January 1, 2009 (Exhibit 10.3 to Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, File No. 1-8503).

10.9(a) Amendments to the HEI Supplemental Executive Retirem ent Plan Freezing Benefit Accruals Effective December 31, 2008 (Exhibit 10.9(a) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008, File No. 1- 8503).

10.10 HEI Excess Pay Plan amended and restated as of January 1, 2009 (Exhibit 10.10 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008, File No. 1-8503).Exhibit no. Description 10.10(a) HEI Excess Pay Plan Addendum for Constance H. Lau (Exhib it 10.10(a) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008, File No. 1-8503).

10.10(b) HEI Excess Pay Plan Addendum for Curtis Y. Harada (Exh ibit 10.10(b) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008, File No. 1-8503).

10.10(c) HEI Excess Pay Plan Addendum for Richard M. Rosenblum (E xhibit 10.10(c) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2009, File No. 1-8503).

10.11 Form of Change in Control Agreement (Exhibit 10.11 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008, File No. 1-8503).

10.12 Nonemployee Director Retirement Plan, effective as of October 1, 1989 (Exhibit 10.15 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 1989, File No. 1-8503).

10.13 HEI 2011 Nonemployee Director Stock Plan (Exhibit A to HEI’s Proxy Statement for 2011 Annual Meeting of

Shareholders filed on March 21, 2011, File No. 1-8503).

10.14 Nonemployee Director’s Compensation Schedule effect ive January 1, 2011 (Exhibit 10.14 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2010, File No. 1-8503).

10.15 HEI Non-Employee Directors’ Deferred Compensation Plan (Exhibit 10.5 to Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, File No. 1-8503).

10.16 Executive Death Benefit Plan of HEI and Participating S ubsidiaries restatement effective as of January 1, 2009 (Exhibit 10.6 to HEI’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, File No. 1-8503).

10.16(a) Resolution of the Compensation Committee of the Board of Directors of Hawaiian Electric Industries, Inc. Re: Adoption of Amendment No. 1 to January 1, 2009 Restatement of the Executive Death Benefit Plan (Exhibit 10.1 to HEI’s Quarterly Report on Form 10-Q for the quarte r ended September 30, 2009, File No. 1-8503).

10.17 Severance Pay Plan for Merit Employees of HEI and affiliates, restatement effective as of January 1, 2009 (Exhibit 10.17 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008, File No. 1-8503).

10.17(a) Addendum A of Severance Pay Plan for Merit Employees of HEI and affiliates, restatement effective as of January 1, 2009 for James A. Ajello and Richard M. Rosenblum (Exhibit 10.17(a) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008, File No. 1-8503).

10.18 Hawaiian Electric Industries Deferred Compensation Plan adopted on December 13, 2010 (Exhibit 10.18 to HEI’s Annual Report on Form 10-K for the fiscal y ear ended December 31, 2010, File No. 1-8503).

10.19 American Savings Bank Select Deferred Compensation Plan (Restatement Effective January 1, 2009) (Exhibit 10.7 to HEI’s Quarterly Report on Form 10-Q for the qua rter ended September 30, 2008, File No. 1-8503).

10.20 American Savings Bank Supplemental Executive Retiremen t, Disability, and Death Benefit Plan, effective January 1, 2009 (Exhibit 10.8 to HEI’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, File No. 1-8503).

10.20(a) Amendments to the American Savings Bank Supplemental Executive Retirement, Disability, and Death Benefit Plan Freezing Benefit Accruals Effective December 31, 2008 (Exhibit 10.19(b) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008, File No. 1-8503).

10.21 Transition and Consulting Agreement between Timothy K. Schools and ASB dated April 27, 2010 (Exhibit 10.1 to HEI’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010, File No. 1-8503).

10.22 Credit Agreement, dated as of May 7, 2010, among HEI, as Borrower, the Lenders Party Hereto and Bank of Hawaii, as Co-Syndication Agent, and U.S. Bank, National Association, as Co-Syndication Agent, and Wells Fargo Bank, National Association, as Co-Syndication Agent, and Bank of Americ a, N.A., as Co-Documentation Agent, and Union Bank, N.A., as Co-Documentation Agent, and JPMorgan Chase Bank, N.A ., as Administrative Agent and Issuing Bank, and J.P. Morgan Securities Inc., as Sole Lead Arranger and Sole Book Runner (Exhibit 10.1 to HEI’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010, File No. 1-8503).Exhibit no. Description 10.23 Amendment No. 1, dated as of December 5, 2011, to the Credit Agreement, dated as of May 7, 2010, among HEI, as Borrower, the Lenders Party Hereto and Bank of Hawa ii, as Co-Syndication Agent, and U.S. Bank National Association, as Co-Syndication Agent, and Wells Fargo B ank, National Association, as Co-Syndication Agent, and Bank of America, N.A., as Co-Documentation Agen t, and Union Bank, N.A., as Co-Documentation Agent, and JPMorgan Chase Bank, N.A., as Administrative Agent and I ssuing Bank, and J.P. Morgan Securities Inc., as Sole Lead Arranger and Sole Book Runner (Exhibit 10.1 to HEI’s Current Report on Form 8-K dated December 5, 2011, File No. 1-8503).

*11 Computation of Earnings per Share of Common Stock.

*12 Computation of Ratio of Earnings to Fixed Charges.

*21 Subsidiaries of HEI.

*23.1 Consent of Independent Registered Public Ac counting Firm (PricewaterhouseCoopers LLP).

*23.2 Consent of Independent Registered Public Accounting Firm (KPMG LLP).

*31.1 Certification Pursuant to 13a-14 of the Securities E xchange Act of 1934 of Constance H. Lau (HEI Chief Executive Officer).

*31.2 Certification Pursuant to 13a-14 of the Securities Exchange Act of 1934 of James A. Ajello (HEI Chief Financial Officer).

*32.1 Written Statement of Constance H. Lau (HEI Chief Execut ive Officer) Furnished Pursuant to 18 U.S.C. Section 1350, as Adopted by Section 906 of the Sarbanes-Oxley Act of 2002.

*32.2 Written Statement of James A. Ajello (HEI Chief Financial Officer) Furnished Pursuant to 18 U.S.C. Section 1350, as Adopted by Section 906 of the Sarbanes-Oxley Act of 2002.

*101.INS XBRL Instance Document.

*101.SCH XBRL Taxonomy Extension Schema Document.

*101.CAL XBRL Taxonomy Extension Calculation Linkbase Document.

*101.DEF XBRL Taxonomy Extension Definition Linkbase Document.

*101.LAB XBRL Taxonomy Extension Label Linkbase Document.

*101.PRE XBRL Taxonomy Extension Presentation Linkbase Document.

HECO: 3(i).1 HECO’s Certificate of Amendment of Articles of Incor poration (Exhibit 3.1 to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1988, File No. 1-4955).

3(i).2 Articles of Amendment to HECO’s Amended Articles of Incorporation (Exhibit 3.1( b) to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1989, File No 1-4955).

3(i).3 Articles of Amendment to HECO’s Amended Articles of Incorporation (Exhibit 3(i) .4 to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1998, File No 1-4955).

3(i).4 Articles of Amendment V of HECO ’s Amended Articles of Incorporation effe ctive August 6, 2009 (Exhibit 3(i).4 to Quarterly Report on Form 10-Q for the quar ter ended June 30, 2009, File No. 1-4955).

3(ii) HECO’s Amended and Restated Bylaws (as last amended Augus t 6, 2010) (Exhibit 3(ii) to HECO’s Current Report on Form 8-K dated August 9, 2010, File No. 1-4955).

4.1 Agreement to provide the SEC with instruments which def ine the rights of holders of certain long-term debt of HECO, HELCO and MECO (Exhibit 4.1 to HEI’s Annual Report on Fo rm 10-K for the fiscal year ended December 31, 2002, File No. 1-4955).

4.2 Certificate of Trust of HECO Capital Trust III (incorporated by reference to Exhibit 4(a) to Registration No. 333-111073).

4.3 Amended and Restated Trust Agreement of HECO Capital Trust III dated as of March 1, 2004 (Exhibit 4(c) to HECO’s Current Report on Form 8-K dated March 16, 2004, File No. 1-4955).

4.4 HECO Junior Indenture with The Bank of New York, as Tr ustee, dated as of March 1, 2004 (Exhibit 4(f) to HECO’s Current Report on Form 8-K dated March 16, 2004, File No. 1-4955).Exhibit no. Description 4.5 6.500% Quarterly Income Trust Preferred Security issued by HECO Capital Trust III, dated March 18, 2004 (Exhibit 4(d) to HECO’s Current Report on Form 8-K dated March 16, 2004, File No. 1-4955).

4.6 6.500% Junior Subordinated Deferrable Interest Debent ure, Series 2004 issued by HECO, dated March 18, 2004 (Exhibit 4(g) to HECO’s Current Report on Form 8-K dated March 16, 2004, File No. 1-4955).

4.7 Trust Guarantee Agreement between The Bank of New Yo rk, as Trust Guarantee Trustee, and HECO dated as of March 1, 2004 (Exhibit 4(l) to HECO’s Current R eport on Form 8-K dated March 16, 2004, File No. 1-4955).

4.8 MECO Junior Indenture with The Bank of New York, as Trustee, including HECO Subsidiary Guarantee, dated as of March 1, 2004 (Exhibit 4(h) to HECO’s Current R eport on Form 8-K dated March 16, 2004, File No. 1-4955).

4.9 HELCO Junior Indenture with The Bank of New York, as Trustee, including HECO Subsidiary Guarantee, dated as of March 1, 2004 (Exhibit 4(j) to HECO’s Current R eport on Form 8-K dated March 16, 2004, File No. 1-4955).

4.10 6.500% Junior Subordinated Deferrable Interest Debent ure, Series 2004 issued by MECO, dated March 18, 2004 (Exhibit 4(i) to HECO’s Current Report on Form 8-K dated March 16, 2004, File No. 1-4955).

4.11 6.500% Junior Subordinated Deferrable Interest Debent ure, Series 2004 issued by HELCO, dated March 18, 2004 (Exhibit 4(k) to HECO’s Current Report on Form 8-K dated March 16, 2004, File No. 1-4955).

4.12 Expense Agreement, dated March 1, 2004, among HECO Capi tal Trust III, HECO, MECO and HELCO (Exhibit 4(m) to HECO’s Current Report on Form 8-K dated March 16, 2004, File No. 1-4955).

10.1(a) Power Purchase Agreement between Kalaeloa Partners, L.P., and HECO dated October 14, 1988 (Exhibit 10(a) to HECO’s Quarterly Report on Form 10-Q for the q uarter ended September 30, 1988, File No. 1-4955).

10.1(b) Amendment No. 1 to Power Purchase Agreement between HECO and Kalaeloa Partners, L.P., dated June 15, 1989 (Exhibit 10(c) to HECO’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1989, File No. 1-4955).

10.1(c) Lease Agreement between Kalaeloa Partners, L.P., as Le ssor, and HECO, as Lessee, dated February 27, 1989 (Exhibit 10(d) to HECO’s Quarterly Report on Form 10-Q fo r the quarter ended June 30, 1989, File No. 1-4955).

10.1(d) Restated and Amended Amendment No. 2 to Power Purchase Agreement between HECO and Kalaeloa Partners, L.P., dated February 9, 1990 (Exhibit 10.2(c) to HECO’s Annual R eport on Form 10-K for the fiscal year ended December 31, 1989, File No. 1-4955).

10.1(e) Amendment No. 3 to Power Purchase Agreement between HECO and Kalaeloa Partners, L.P., dated December 10, 1991 (Exhibit 10.2(e) to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1991, File No. 1- 4955).

10.1(f) Amendment No. 4 to Power Purchase Agreement between HECO and Kalaeloa Partners, L.P., dated October 1, 1999 (Exhibit 10.1 to HECO’s Quarterly Report on Form 10-Q fo r the quarter ended September 30, 2000, File No. 1-4955).

10.1(g) Confirmation Agreement Concerning Section 5.2B(2) of Power Purchase Agreement and Amendment No. 5 to Power Purchase Agreement between HECO and Kalaeloa Partners, L.P., dated October 12, 2004 (Exhibit 10.3 to HECO’s Quarterly Report on Form 10-Q for the quarte r ended September 30, 2004, File No. 1-4955).

10.1(h) Agreement for Increment Two Capacity and Amendment No. 6 to Power Purchase Agreement between HECO and Kalaeloa Partners, L.P., dated October 12, 2004 (Exhibit 10.4 to HECO’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2004, File No. 1-4955).

10.2(a) Power Purchase Agreement between AES Barbers Point, In c. and HECO, entered into on March 25, 1988 (Exhibit 10(a) to HECO’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1988, File No. 1-4955).

10.2(b) Agreement between HECO and AES Barbers Point, Inc ., pursuant to letters dated May 10, 1988 and April 20, 1988 (Exhibit 10.4 to HECO’s Annual Report on Form 10-K fo r fiscal year ended December 31, 1988, File No. 1-4955).

10.2(c) Amendment No. 1, entered into as of August 28, 1988, to Power Purchase Agreement between AES Barbers Point, Inc. and HECO (Exhibit 10 to HECO’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1989, File No. 1- 4955).

10.2(d) HECO’s Conditional Notice of Acc eptance to AES Barbers Point, Inc. dated Janu ary 15, 1990 (Exhibit 10.3(c) to HECO’s Annual Report on Form 10-K for the fiscal y ear ended December 31, 1989, File No. 1-4955).

10.2(e) Amendment No. 2, entered into as of May 8, 2003, to Power Purchase Agreement between AES Hawaii, Inc. and HECO (Exhibit 10.2(e) to HECO’s Annual Report on Form 10-K for fiscal year ended December 31, 2003, File No. 1-4955).Exhibit no. Description 10.3(a) Agreement between MECO and Hawaiian Commercial & S ugar Company pursuant to letters dated November 29, 1988 and November 1, 1988 (Exhibit 10.8 to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1988, File No. 1-4955).

10.3(b) Amended and Restated Power Purchase Agreement by and between A&B-Hawaii, Inc., through its division, Hawaiian Commercial & Sugar Company, and MECO, dated November 30, 1989 (Exhibit 10(e) to HECO’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1990, File No. 1-4955).

10.3(c) First Amendment to Amended and Restated Power Purchase Agreement by and between A&B-Hawaii, Inc., through its division, Hawaiian Commercial & Sugar Company, and MECO, dated November 1, 1990, amending the Amended and Restated Power Purchase Agreement dated November 30, 1989 (E xhibit 10(f) to HECO’s Quarterly Report on Form 10- Q for the quarter ended September 30, 1990, File No. 1-4955).

10.3(d) Termination Notice dated December 27, 1999 for Amended and Restated Power Purchase Agreement by and between A&B Hawaii, Inc., through its division, Hawaiian Commercia l & Sugar Company, and MECO, dated November 30, 1989, as amended (Exhibit 10.2 to HECO’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2000, File No. 1-4955).

10.3(e) Rescission dated January 23, 2001 of Termination Notice for Amended and Restated Power Purchase Agreement by and between A&B Hawaii, Inc., through its division, Hawaiian Commercial & Sugar Company, and MECO, dated November 30, 1989, as amended (Exhibit 10.4(f) to HE CO’s Annual Report on Form 10-K for the fiscal year ended December 31, 2000, File No. 1-4955).

10.3(f) Letter agreement dated July 2, 2007 to not issue a notice of termination of Amended and Restated Power Purchase Agreement Between A&B-Hawaii, Inc., through its division, Hawaiian Commercial & Sugar Company, and MECO dated November 30, 1989, as Amended on November 1, 1990 (Exhibit 10.3(f) to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 2010, File No. 1-4955).

10.4(a) Purchase Power Contract between HELCO and Therma l Power Company dated March 24, 1986 (Exhibit 10(a) to HECO’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1989, File No. 1-4955).

10.4(b) Firm Capacity Amendment between HELCO and Puna Geothermal Venture (assignee of AMOR VIII, who is the assignee of Thermal Power Company) dated July 28, 1989 to Purchase Power Contract between HELCO and Thermal Power Company dated March 24, 1986 (Exhibit 10(b) to HECO’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1989, File No. 1-4955).

10.4(c) Amendment made in October 1993 to Purchase Power Contract between HELCO and Puna Geothermal Venture dated March 24, 1986, as amended (Exhibit 10.5(b) to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1997, File No. 1-4955).

10.4(d) Third Amendment dated March 7, 1995 to the Purchase Power Contract between HELCO and Puna Geothermal Venture dated March 24, 1986, as amended (Exhibit 10.5(c) to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1997, File No. 1-4955).

10.4(e) Performance Agreement and Fourth Amendment dated February 12, 1996 to the Purchase Power Contract between
HELCO and Puna Geothermal Venture dated March 24, 1986, as amended (Exhibit 10.5(b) to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1995, File No. 1-4955).

*10.4(f) Fifth Amendment dated February 7, 2011 to the Pu rchase Power Contract between HELCO and Puna Geothermal
Venture dated March 24, 1986, as amended.

*10.4(g) Power Purchase Agreement between Puna Geot hermal Venture and HELCO dated February 7, 2011.

10.5(a) Purchase Power Contract between HECO and the City and County of Honolulu dated March 10, 1986 (Exhibit 10.9 to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1989, File No. 1-4955).

10.5(b) Amendment No. 1 to Purchase Power Contract between HECO and the City and County of Honolulu dated March 10, 1986 (Exhibit 10.6(a) to HECO’s Annual Report on Form 10-K for fiscal year ended December 31, 2001, File No. 1-4955).

10.5(c) Firm Capacity Amendment, dated April 8, 1991, to Purchase Power Contract, dated March 10, 1986, by and between HECO and the City & County of Honolulu (Exhibit 10 to HECO’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1991, File No. 1-4955).

10.5(d) Amendment No. 2 to Purchase Power Contract Between HECO and City and County of Honolulu dated March 10, 1986 (Exhibit 10.6(c) to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1997, File No. 1-4955).Exhibit no. Description 10.6(a) Power Purchase Agreement between Encogen Hawaii, L.P. and HELCO dated October 22, 1997 (but with the following attachments omitted: Attachment C, “Selected portions of the North American Electric Reliability Council Generating Availability Data System Data Reporting Instructions dated October 1996” and Attachment E, “Form of the Interconnection Agreement between Encogen Hawaii, L.P. and HE LCO,” which is provided in final form as Exhibit 10.6(b)) (Exhibit 10.7 to HECO’s Annual Report on Form 10 -K for the fiscal year ended December 31, 1997, File No. 1- 4955).

10.6(b) Interconnection Agreement between Encogen Hawaii, L. P. and HELCO dated October 22, 1997 (Exhibit 10.7(a) to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1997, File No. 1-4955).

10.6(c) Amendment No. 1, executed on January 14, 1999, to Power Purchase Agreement between Encogen Hawaii, L.P. and HELCO dated October 22, 1997 (Exhibit 10.7(b) to HECO ’s Annual Report on Form 10-K for the fiscal year ended December 31, 1998, File No. 1-4955).

10.6(d) Power Purchase Agreement Novation dated November 8, 1999 by and among Encogen Hawaii, L.P., Hamakua Energy Partners and HELCO (Exhibit 10.7(c) to HECO’s Annual R eport on Form 10-K for fiscal year ended December 31, 2001, File No. 1-4955).

10.6(e) Consent and Agreement Concerning Certain Assets of Black River Energy, LLC By and Among Great Point Power Hamakua Holdings, LLC, Hamakua Energy Partners, L.P. and HELCO dated April 19, 2010 (Exhibit 10.6(e) to HECO’s Annual Report on Form 10-K for the fiscal y ear ended December 31, 2010, File No. 1-4955).

10.6(f) Guarantee Agreement between Great Point Power Hamakua Holdings, LLC and HELCO dated June 4, 2010 (Exhibit 10.6(f) to HECO’s Annual Report on Form 10-K for t he fiscal year ended December 31, 2010, File No. 1-4955).

10.7(a) Low Sulfur Fuel Oil Supply C ontract by and between Chevron and HECO dated as of November 14, 1997 (confidential treatment has been requested for portions of this exhibit) (E xhibit 10.8 to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1997, File No. 1-4955).

10.7(b) First Amendment to Low Sulfur Fuel Oil Supply Contract by and between Chevron and HECO entered into as of April 12, 2004 (confidential treatment has been requested for portions of this exhibit, which has been redacted accordingly) (Exhibit 10(c) to HECO’s Current Report on Form 8-K, dated May 28, 2004, File No. 1-4955).

10.7(c) Second Amendment to Low Sulfur Fuel Oil Supply C ontract by and between Chevron and HECO entered into as of December 2, 2009 (confidential treatment has been granted through December 31, 2014 for portions of this exhibit, which has been redacted accordingly) (Exhibit 10.7(c) to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 2009, File No. 1-4955).

10.8(a) Inter-Island Industrial Fuel Oil and Diesel Fuel Su pply Contract by and between Chevron and HECO, MECO, HELCO, HTB and YB dated as of November 14, 1997 (confidential trea tment has been requested for portions of this exhibit) (Exhibit 10.9 to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1997, File No. 1-4955).

10.8(b) Amendment to Inter-Island Industrial Fuel Oil and Dies el Fuel Supply Contract by and between Chevron and HECO, MECO and HELCO entered into as of April 12, 2004 (confi dential treatment has been requested for portions of this exhibit, which has been redacted accordingly) (Exhibit 10(d) to HECO’s Current Report on Form 8-K, dated May 28, 2004, File No. 1-4955).

10.9 Facilities and Operating Contract by and between Chevr on and HECO dated as of November 14, 1997 (confidential treatment has been requested for portions of this exhibit, which has been redacted accordingly) (Exhibit 10.10 to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1997, File No. 1-4955).

10.10(a) Low Sulfur Fuel Oil Supply Cont ract by and between BHP Petroleum Americas Refining Inc. and HECO dated as of November 14, 1997 (confidential treatment has been request ed for portions of this exhibit, which has been redacted accordingly) (Exhibit 10.11 to HECO’s Annual Report on Fo rm 10-K for the fiscal year ended December 31, 1997, File No. 1-4955).

10.10(b) First Amendment to Low Sulfur Fuel Oil Supply Contract by and between Tesoro Hawaii Corporation, formerly known as BHP Petroleum Americas Refining Inc., and HECO dated Ma rch 29, 2004 (confidential treatment has been requested for portions of this exhibit, which has been redacted accordingly) (Exhibit 10(a) to HECO’s Current Report on Form 8-K, dated May 28, 2004, File No. 1-4955).

10.10(c) Second Amendment to Low Sulfur Fuel Oil Supply C ontract By and Between BHP Petroleum Americas Refining Inc. (nka, Tesoro Hawaii Corporation) and HECO entered into as of May 5, 2010 (confidential treatment has been granted through December 31, 2014 for portions of this exhibit, whic h has been redacted accordingly) (Exhibit 10.4 to Quarterly Report on Form 10-Q for the quarter ended March 31, 2010, File No. 1-4955).Exhibit no. Description 10.11(a) Inter-Island Industrial Fuel Oil and Diesel Fuel Supply Contract by and between BHP Petroleum Americas Refining Inc. and HECO, MECO and HELCO dated November 14, 1997 (confidential treatment has been requested for portions of this exhibit, which has been redacted accordingly) (Exhibit 10.12 to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1997, File No. 1-4955).

10.11(b) First Amendment to Inter-Island Industrial Fuel Oil and Diesel Fuel Supply Contract by and between Tesoro Hawaii Corporation, formerly known as BHP Petroleum Am ericas Refining Inc., and HECO, MECO and HELCO dated March 29, 2004 (confidential treatment has been requested for portions of this exhibit, which has been redacted accordingly) (Exhibit 10(b) to HECO’s Current Re port on Form 8-K, dated May 28, 2004, File No. 1-4955).

10.12 Contract of private carriage by and between HITI and HELCO dated December 4, 2000 (Exhibit 10.13 to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 2000, File No. 1-4955).

10.13 Contract of private carriage by and between HITI and MECO dated December 4, 2000 (Exhibit 10.14 to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 2000, File No. 1-4955).

10.14 Energy Agreement among the State of Hawaii, Division of Consumer Advocacy of the Department of Commerce and Consumer Affairs, and the Hawaiian Electric Companies (Exhib it 10.12 to Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, File No. 1-4955).

10.15 Credit Agreement, dated as of May 7, 2010, among HECO, as Borrower, the Lenders Party Hereto and Bank of Hawaii, as Co-Syndication Agent, and U.S. Bank, National Associ ation, as Co-Syndication Agent, and Wells Fargo Bank, National Association, as Co-Syndication Agent, and Bank of America, N.A., as Co-Documentation Agent, and Union Bank, N.A., as Co-Documentation Agent, and JPMorgan Chase Bank, N.A., as Administrative Agent and Issuing Bank, and J.P. Morgan Securities Inc., as Sole Lead Arranger and So le Book Runner (Exhibit 10.3 to Quarterly Report on Form 10-Q for the quarter ended March 31, 2010, File No. 1-4955).

10.16 Amendment No. 1, dated as of December 5, 2011, to the Credit Agreement, dated as of May 7, 2010, among HECO, as Borrower, the Lenders Party Hereto and Bank of Hawaii, as Co-Syndication Agent, and U.S. Bank National Association, as Co-Syndication Agent, and Wells Fargo Bank, National Associ ation, as Co-Syndication Agent, and Bank of America, N.A., as Co-Documentation Agent, and Union Bank, N.A ., as Co-Documentation Agent, and JPMorgan Chase Bank, N.A., as Administrative Agent and Issuing Bank, and J.P. Mo rgan Securities Inc., as Sole Lead Arranger and Sole Book Runner (Exhibit 10.2 to HECO’s Current Report on Fo rm 8-K dated December 5, 2011, File No. 1-4955).

11 Computation of Earnings Per Share of Common Stock (See note on HECO’s Item 6. Selected Financial Data on page 4 of HECO Exhibit 99.2).

*12 Computation of Ratio of Earnings to Fixed Charges.

*21 Subsidiaries of HECO.

*31.3 Certification Pursuant to 13a-14 of the Securities Exchange Act of 1934 of Richard M. Rosenblum (HECO Chief Executive Officer).

*31.4 Certification Pursuant to 13a-14 of the Securities Exc hange Act of 1934 of Tayne S. Y. Sekimura (HECO Chief Financial Officer).

*32.3 Written Statement of Richard M. Rosenblum (HECO Chie f Executive Officer) Furnished Pursuant to 18 U.S.C. Section 1350, as Adopted by Section 906 of the Sarbanes-Oxley Act of 2002.

*32.4 Written Statement of Tayne S. Y. Sekimura (HECO Ch ief Financial Officer) Furnished Pursuant to 18 U.S.C. Section 1350, as Adopted by Section 906 of the Sarbanes-Oxley Act of 2002.

*99.1 Reconciliation of electric utility operating income per HEI and HECO Consolidated Statements of Income.

*99.2 Forward-Looking Statements, Selected Financial Data , HECO’s MD&A, HECO’s Quantitative and Qualitative Disclosures about Market Risk and HECO’s Consolidated 2011 Financial Statements (with Reports of Independent Registered Public Accounting Firms thereon).HEI Exhibit 11

Hawaiian Electric Industries, Inc.

COMPUTATION OF EARNINGS PER SHARE

OF COMMON STOCK
Years ended December 31, 2011, 2010, 2009, 2008 and 2007

(in thousands, except per share amounts) 2011 2010 2009 2008 2007

Net income for common stock $138, 230 $113,535 $83,011 $90,278 $84,779

Weighted-average number of

common shares outstanding 95,510 93,421 91,396 84,631 82,215

Adjusted weighted-average

number of common shares outstanding 95,820 93,693 91,516 84,720 82,419

Basic earnings per common

share $1.45 $1.22 $0.91 $1.07 $1.03

Diluted earnings per common

share $1.44 $1.21 $0.91 $1.07 $1.03HEI Exhibit 12 (page 1 of 2)

Hawaiian Electric Industries, Inc.

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

2011 2010 2009 Years ended December 31 (1) (2) (1) (2) (1) (2) (dollars in thousands)

Fixed charges Total interest charges (3) $87,592 $ 96,575 $87,191 $101, 887 $85,827 $119,873 Interest component of rental s 4,757 4,757 4,282 4,282 5,339 5,339 Pretax preferred stock dividend

requirements of subsidiaries 2,914 2,914 3,001 3,001 2,868 2,868

Total fixed charges $95,263 $104,246 $94,474 $109,170 $94,034 $128,080

Earnings Pretax income from continuing

operations $214,162 $214,162 $181,357 $181,357 $126,934 $126,934 Fixed charges, as shown 95,263 104,246 94,474 109,170 94,034 128,080 Interest capitalized (2,498) (2,498) (2,558) (2,558) (5,268) (5,268)

Earnings available for fixed

charges $306,927 $315,910 $273,273 $287,969 $215,700 $249,746

Ratio of earnings to fixed charges 3.22 3.03 2.89 2.64 2.29 1.95

(1) Excluding interest on ASB deposits.

(2) Including interest on ASB deposits.

(3) Interest on nonrecourse debt from leveraged leases is not included in total interest charges nor in interest expense in HEI’s consolidated statements of income.HEI Exhibit 12 (page 2 of 2)

Hawaiian Electric Industries, Inc.

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

Continued

2008 2007 Years ended December 31 (1) (2) (1) (2) (dollars in thousands)

Fixed charges Total interest charges (3) $120,083 $181,566 $156,575 $238,454 Interest component of r entals 5,354 5,354 5,367 5,367 Pretax preferred stock dividend

requirements of subsidiaries 2,894 2,894 2,899 2,899

Total fixed charges $128,331 $189,814 $164,841 $246,720

Earnings Pretax income from continuing oper ations $139,256 $139, 256 $131,057 $131,057 Fixed charges, as shown 128,331 189,814 164,841 246,720 Interest capitalized (3,741) (3,741) (2,552) (2,552)

Earnings available for fixed charges $263,846 $325,329 $293,346 $375,225

Ratio of earnings to fixed charges 2.06 1.71 1.78 1.52

(1) Excluding interest on ASB deposits.

(2) Including interest on ASB deposits.

(3) Interest on nonrecourse debt from leveraged leases is not included in total interest charges nor in interest expense in HEI’s consolidated statements of income.HEI Exhibit 21

Hawaiian Electric Industries, Inc.

SUBSIDIARIES OF THE REGISTRANT

The following is a list of all direct and indirect subsidia ries of the registrant as of February 17, 2012. The state/place of incorporati on or organization is noted in parentheses and subsidiaries of intermediate parent companies are designated by indentations.

Hawaiian Electric Company, Inc. (Hawaii) Maui Electric Company, Limited (Hawaii) Hawaii Electric Light Company, Inc. (Hawaii) Renewable Hawaii, Inc. (Hawaii) Uluwehiokama Biofuels Corp. (Hawaii) HECO Capital Trust III (Delaware) American Savings Holdings, Inc. (Hawaii) American Savings Bank, F.S.B. (federally chartered) Pacific Energy Conservation Services , Inc. (Hawaii) (dissolved in 2011) HEI Properties, Inc. (Hawaii) Hawaiian Electric Industries Capital Trust II (a statutory trust) (Del aware) (potential financing entity) Hawaiian Electric Industries Capital Trust III (a statutory trust) (Del aware) (potential financing entity) The Old Oahu Tug Service, Inc. (Hawaii)HEI Exhibit 23.1

CONSENT OF INDEPENDENT REGIST ERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by referenc e in the Registration Stat ements on Forms S-3 (Nos. 333- 158999 and 333-177750) and S-8 (N os. 333-02103, 333-105404, 333- 159000, 333-166737 and 333-174131) of Hawaiian Electric Industries, Inc. of our reports dated February 17, 2012 relating to the financial statements,

financial statement schedules and the effectiveness of internal control ov er financial reporting, which appears in

this Form 10-K.

/s/ PricewaterhouseCoopers LLP Los Angeles, California February 17, 2012HEI Exhibit 23.2

Consent of Independent Regist ered Public Accounting Firm

The Board of Directors
Hawaiian Electric Industries, Inc.:

We consent to incorporation by reference in R egistration Statement Nos. 333-158999 and 333-177750 on Form S-3 and Registration Statement Nos. 333-02103, 333-105404, 333-159000, 333-166737, and 333-174131 on Form S-8 of Hawaiian Electric Industries, Inc., of our report dated February 19, 2010, with re spect to the consolidated statements of income, changes in shareh olders’ equity, and cash flows of Hawa iian Electric Industries, Inc. and subsidiaries for the year ended December 31, 2009, and our report dated February 19, 2010 on all related financial statement schedules, which reports appear in the 2011 annual report on Form 10-K of Hawaiian Electric Industries,

Inc.

/s/ KPMG LLP
Honolulu, Hawaii February 17, 2012HEI Exhibit 31.1

Certification Pursuant to Section 13a-14 of the Securities Exchange Act of 1934 of Constance H. Lau (HEI Chief Executive Officer)

I, Constance H. Lau, certify that:

1. I have reviewed this report on Form 10-K for the year ended December 31, 2011 of Hawaiian Electric Industries, Inc. (“registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circ umstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financia l statements, and other financ ial information included in this report, fairly present in all material respects the financial condition, resu lts of operations and cash flow s of the registrant as of, and for, the periods pres ented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Ru les 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15 (f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensur e that material information relati ng to the registrant, including its
consolidated subsidiaries, is made know n to us by others within those ent ities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial repor ting, or caused such internal control over financial reporting to be designed under our supervision, to prov ide reasonable assurance r egarding the reliability of financial reporting and the pr eparation of financial statements for exte rnal purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s di sclosure controls and procedures and presented in this report our conclusions about the effectiveness of the di sclosure controls and proce dures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fou rth fiscal quarter in the case of an annual report) that has materially affect ed, or is reasonably likely to materia lly affect, the regi strant’s internal control over financial reporting; and

5. The registrant’s other certifying o fficer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to t he registrant’s auditors and the audit co mmittee of the regi strant’s board of directors (or persons performi ng the equivalent functions):

(a) All significant deficiencies and material weaknesse s in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not materi al, that involves management or ot her employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 17, 2012

/s/ Constance H. Lau

Constance H. Lau

President and Chief Executive OfficerHEI Exhibit 31.2

Certification Pursuant to Secti on 13a-14 of the Securities Exchange Act of 1934 of James A. Ajello (HEI Chief Financial Officer)

I, James A. Ajello, certify that:

1. I have reviewed this report on Form 10-K for the year ended December 31, 20 11 of Hawaiian Electric Industries, Inc. (“registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circ umstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financia l statements, and other financ ial information included in this report, fairly present in all material respects the financial condition, resu lts of operations and cash flow s of the registrant as of, and for, the periods pres ented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Ru les 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15 (f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensur e that material information relati ng to the registrant, including its
consolidated subsidiaries, is made know n to us by others within those ent ities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial repor ting, or caused such internal control over financial reporting to be designed under our supervision, to prov ide reasonable assurance r egarding the reliability of financial reporting and the pr eparation of financial statements for exte rnal purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s di sclosure controls and procedures and presented in this report our conclusions about the effectiveness of the di sclosure controls and proce dures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s four th fiscal quarter in the case of an annual report) that has materially affect ed, or is reasonably likely to materia lly affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying o fficer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to t he registrant’s auditors and the audit co mmittee of the regi strant’s board of directors (or persons performi ng the equivalent functions):

(a) All significant deficiencies and material weaknesse s in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not materi al, that involves management or ot her employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 17, 2012

/s/ James A. Ajello James A. Ajello
Executive Vice President,

Chief Financial Officer and TreasurerHEI Exhibit 32.1

Hawaiian Electric Industries, Inc.

Written Statement of Chief Executi ve Officer Furnished Pursuant to
18 U.S.C. Section 1350, as Adopted by Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Annual Report of Hawaiian Electr ic Industries, Inc. (HEI) on Form 10-K for the year
ended December 31, 2011 as filed with the Securities and Exchange Commission (the Report), I, Constance H. Lau, Chief Executive Officer of HEI, certify, pursuant to 18 U.S.C. Section 1350, as adopted by Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

(1) The Report fully complies with the requirements of se ction 13(a) of the Securi ties Exchange Act of 1934; and

(2) The consolidated information contained in the Report fairly presents, in all material respects, the financial condition as of December 31, 2011 and results of oper ations for the year ended De cember 31, 2011 of HEI and

its subsidiaries.

/s/ Constance H. Lau

Constance H. Lau

President and Chief Executive Officer Date: February 17, 2012

A signed original of this written st atement required by Section 906 has been provided to Hawaiian Electric Industries, Inc. and will be retained by Hawaiian Electric Industries, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.HEI Exhibit 32.2

Hawaiian Electric Industries, Inc.

Written Statement of Chief Financia l Officer Furnished Pursuant to
18 U.S.C. Section 1350, as Adopted by Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Annual Report of Hawaiian Electr ic Industries, Inc. (HEI) on Form 10-K for the year
ended December 31, 2011 as filed with the Securities and Exchange Commission (the Repo rt), I, James A. Ajello, Chief Financial Officer of HEI, certify, pursuant to 18 U.S.C. Section 1350, as adopted by Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

(1) The Report fully complies with the requirements of se ction 13(a) of the Securi ties Exchange Act of 1934; and

(2) The consolidated information contained in the Report fairly presents, in all material respects, the financial condition as of December 31, 2011 and results of oper ations for the year ended De cember 31, 2011 of HEI and

its subsidiaries.

/s/ James A. Ajello James A. Ajello
Executive Vice President,

Chief Financial Officer and Treasurer Date: February 17, 2012

A signed original of this written st atement required by Section 906 has been provided to Hawaiian Electric Industries, Inc. and will be retained by Hawaiian Electric Industries, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.HECO Exhibit 12

Hawaiian Electric Company, Inc.

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

Years ended December 31 2011 2010 2009 2008 2007 (dollars in thousands)

Fixed charges Total interest charges $60,031 $61,510 $57,944 $54,757 $53,268 Interest component of rent als 2,152 1,857 2,499 2,211 2,250 Pretax preferred stock dividend

requirements of subsidiaries 1,468 1,461 1,452 1,458 1,438

Total fixed charges $63,651 $64,828 $61, 895 $58,426 $56,956

Earnings Net income attributable to HECO $101, 066 $ 77,669 $ 80,526 $ 93,055 $ 53,236 Fixed charges, as shown 63, 651 64,828 61,895 58,426 56,956 Income taxes (see note below) 61, 584 46,868 47,776 55,763 30,937 Allowance for borrowed funds used during

construction (2,498) (2,558) (5,268) (3,741) (2,552)

Earnings available for fixed charges $223,803 $186,807 $184, 929 $203,503 $138,577

Ratio of earnings to fixed charges 3.52 2.88 2.99 3.48 2.43

Note: Income taxes is comprised of the following:

Income tax expense relating to operating

income from regulated activities $65,988 $48,053 $48,212 $56,307 $34,126

Income tax benefit rela ting to results from

nonregulated activities (4,404) (1,185) (436) (544) (3,189)

$61,584 $46,868 $47, 776 $55,763 $30,937HECO Exhibit 21

Hawaiian Electric Company, Inc.

SUBSIDIARIES OF THE REGISTRANT

The following is a list of all subsidiaries of the r egistrant as of February 17, 2012. The state/place of incorporation or organizati on is noted in parentheses.

Maui Electric Company, Limited (Hawaii)

Hawaii Electric Light Co mpany, Inc. (Hawaii)

Renewable Hawaii, Inc. (Hawaii)

Uluwehiokama Biofuels Corp. (Hawaii)

HECO Capital Trust III (a statutory trust) (Delaware) (unconsolidated)HECO Exhibit 31.3

Certification Pursuant to Section 13a-14 of the Securities Exchange Ac t of 1934 of Richard M. Rosenblum (HECO Chief Executive Officer)

I, Richard M. Rosenblum, certify that:

1. I have reviewed this report on Form 10-K for the year ended December 31, 2011 of Hawaiian Electric Company, Inc. (“registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circ umstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financia l statements, and other financ ial information included in this report, fairly present in all material respects the financial condition, resu lts of operations and cash flow s of the registrant as of, and for, the periods pres ented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Ru les 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15 (f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensur e that material information relati ng to the registrant, including its
consolidated subsidiaries, is made know n to us by others within those ent ities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial repor ting, or caused such internal control over financial reporting to be designed under our supervision, to prov ide reasonable assurance r egarding the reliability of financial reporting and the pr eparation of financial statements for exte rnal purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s di sclosure controls and procedures and presented in this report our conclusions about the effectiveness of the di sclosure controls and proce dures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s four th fiscal quarter in the case of an annual report) that has materially affect ed, or is reasonably likely to materia lly affect, the regi strant’s internal control over financial reporting; and

5. The registrant’s other certifying o fficer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to t he registrant’s auditors and the audit co mmittee of the regi strant’s board of directors (or persons performi ng the equivalent functions):

(a) All significant deficiencies and material weaknesse s in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not materi al, that involves management or ot her employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 17, 2012

/s/ Richard M. Rosenblum

Richard M. Rosenblum

President and Chief Executive OfficerHECO Exhibit 31.4

Certification Pursuant to Section 13a-14 of the Securities Exchange Act of 1934 of Tayne S. Y. Sekimura (HECO Chief Financial Officer)

I, Tayne S. Y. Sekimura, certify that:

1. I have reviewed this report on Form 10-K for the year ended December 31, 2011 of Hawaiian Electric Company, Inc. (“registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circ umstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financia l statements, and other financ ial information included in this report, fairly present in all material respects the financial condition, resu lts of operations and cash flow s of the registrant as of, and for, the periods pres ented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Ru les 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15 (f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensur e that material information relati ng to the registrant, including its
consolidated subsidiaries, is made know n to us by others within those ent ities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial repor ting, or caused such internal control over financial reporting to be designed under our supervision, to prov ide reasonable assurance r egarding the reliability of financial reporting and the pr eparation of financial statements for exte rnal purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s di sclosure controls and procedures and presented in this report our conclusions about the effectiveness of the di sclosure controls and proce dures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s four th fiscal quarter in the case of an annual report) that has materially affect ed, or is reasonably likely to materia lly affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying o fficer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to t he registrant’s auditors and the audit co mmittee of the regi strant’s board of directors (or persons performi ng the equivalent functions):

(a) All significant deficiencies and material weaknesse s in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not materi al, that involves management or ot her employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 17, 2012

/s/ Tayne S. Y. Sekimura Tayne S. Y. Sekimura

Senior Vice President and Chief Financial OfficerHECO Exhibit 32.3

Hawaiian Electric Company, Inc.

Written Statement of Chief Executi ve Officer Furnished Pursuant to
18 U.S.C. Section 1350, as Adopted by Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Annual Report of Hawaiian Electr ic Company, Inc. (HECO) on Form 10-K for the year
ended December 31, 2011 as filed with the Securiti es and Exchange Commission (the HECO Report), I,
Richard M. Rosenblum, Chief Executive Officer of HECO , certify, pursuant to 18 U. S.C. Section 1350, as adopted by Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

(1) The HECO Report fully complies with the requirements of section 13(a) of the Securi ties Exchange Act of 1934;

and

(2) The HECO consolidated information cont ained in the HECO Report fairly present s, in all material respects, the

financial condition as of December 31, 2011 and results of operations for the year ended December 31, 2011 of

HECO and its subsidiaries.

/s/ Richard M. Rosenblum

Richard M. Rosenblum

President and Chief Executive Officer Date: February 17, 2012

A signed original of this written st atement required by Section 906 has been provided to Hawaiian Electric Company, Inc. and will be retained by Hawaiian Electric Company, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.HECO Exhibit 32.4

Hawaiian Electric Company, Inc.

Written Statement of Chief Financia l Officer Furnished Pursuant to
18 U.S.C. Section 1350, as Adopted by Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Annual Report of Hawaiian Electr ic Company, Inc. (HECO) on Form 10-K for the year
ended December 31, 2011 as filed with the Securiti es and Exchange Commission (the HECO Report), I, Tayne S. Y. Sekimura, Chief Financial Officer of HECO, ce rtify, pursuant to 18 U.S.C. Section 1350, as adopted by Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

(1) The HECO Report fully complies with the requirements of section 13(a) of the Securi ties Exchange Act of 1934;

and

(2) The HECO consolidated information cont ained in the HECO Report fairly present s, in all material respects, the

financial condition as of December 31, 2011 and results of operations for the year ended December 31, 2011 of

HECO and its subsidiaries.

/s/ Tayne S. Y. Sekimura Tayne S. Y. Sekimura

Senior Vice President and Chief Financial Officer Date: February 17, 2012

A signed original of this written st atement required by Section 906 has been provided to Hawaiian Electric Company, Inc. and will be retained by Hawaiian Electric Company, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.HECO Exhibit 99.1

Hawaiian Electric Company, Inc.

RECONCILIATION OF ELECTR IC UTILITY OPERATING

INCOME PER HEI AND HECO CONSOLIDATED

STATEMENTS OF INCOME

Years ended December 31 2011 2010 2009 (in thousands)

Operating income from regulat ed and nonregulated activities before income taxes (per HEI Conso lidated Statements of Income) $215,134 $178,388 $169,671

Deduct:

Income taxes on regulated activi ties (65,988) (48,053) (48,212) Revenues from nonregulated activiti es (4,926) (14,925) (8,337)

Add:

Expenses from nonregulated ac tivities 11,015 4,431 1,286

Operating income from regulated ac tivities after income taxes (per

HECO Consolidated St atements of Income) $155,235 $119,841 $114,408