HAWAIIAN ELECTRIC CO INC - Annual Report: 2011 (Form 10-K)

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

[ ] 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:

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 (QUIPSSM) of HECO Capital Trust III	New York Stock Exchange

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 Industries, 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 Company, 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 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 Industries, Inc. has submitted electronically and posted on its corporate 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). Yes X No

Indicate by check mark whether Registrant Hawaiian Electric Company, Inc. has submitted electronically and posted on its corporate 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). Yes X No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ]

Indicate by check mark whether Registrant Hawaiian Electric Industries, Inc. is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. Large accelerated filer X Accelerated filer Non-accelerated filer (Do not check 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, a non-accelerated filer or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. Large accelerated filer Accelerated filer Non-accelerated filer X (Do not check if a smaller reporting company) Smaller reporting company

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

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

	Aggregate market value of the voting and non- voting 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)

DOCUMENTS INCORPORATED BY REFERENCE

HECO’s Exhibit 99.2, consisting of:

HECO’s Consolidated Selected Financial Data—Part II

HECO’s Management’s Discussion and Analysis of Financial Condition and Results of Operations—Parts I and II

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

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

Selected sections of Proxy Statement of HEI for the 2012 Annual Meeting of Shareholders to be filed—Part III

This combined Form 10-K represents separate filings by Hawaiian Electric Industries, Inc. and Hawaiian Electric Company, Inc. Information contained herein relating to any individual registrant is filed by each registrant on its own behalf. HECO makes no representations as to any information not relating to it or its subsidiaries.

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 Stockholder Matters and Issuer Purchases of Equity Securities	39
Item 6.	Selected Financial Data	40
Item 7.	Management’s Discussion and Analysis of Financial 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	182
Item 13.	Certain Relationships and Related Transactions, and Director Independence	184
Item 14.	Principal Accounting Fees and Services	186

PART IV

Item 15.	Exhibits and Financial 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		196

GLOSSARY OF TERMS

Defined below are certain terms 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 subsidiary 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. sections, “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 financing entities); and The Old Oahu Tug Service, Inc. (formerly Hawaiian Tug & Barge Corp.). When used in Hawaiian Electric Company, Inc. sections, “Company” refers to Hawaiian Electric Company, Inc. and its direct subsidiaries.
Consumer Advocate	Division of Consumer Advocacy, Department of Commerce 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 amended

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 subsidiary 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 Hawaii, Inc. and Uluwehiokama Biofuels Corp.
HECO’s Consolidated Financial Statements	Hawaiian Electric Company, Inc.’s Consolidated Financial 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 Discussion 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 company of Hawaiian Electric Company, Inc., American Savings Holdings, Inc., HEI Properties, Inc., Hawaiian 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, Inc.’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 Financial 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 formerly 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 utility 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, HTB sold substantially all of its operating assets and the stock of Young Brothers, Limited, and changed 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 plan

iii

GLOSSARY OF TERMS (continued)

Terms	Definitions

MBtu	Million British thermal unit
MD&A	Management’s Discussion and Analysis of Financial Condition and Results of Operations
MECO	Maui Electric Company, Limited, an electric utility 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-owned 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 reference 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 Americas Refining Inc., a fuel oil supplier
TOOTS	The Old Oahu Tug Service, Inc., a wholly-owned subsidiary of Hawaiian Electric Industries, Inc.
UBC	Uluwehiokama Biofuels Corp., a non-regulated subsidiary of Hawaiian Electric Company, Inc.
UST	Underground storage tank
VIE	Variable interest entity

Forward-Looking Statements

This report and other presentations made by Hawaiian Electric Industries, Inc. (HEI) and Hawaiian Electric Company, Inc. (HECO) and their subsidiaries contain “forward-looking statements,” which include statements that are predictive in nature, depend upon or refer to future events or conditions, and usually include words such as “expects,” “anticipates,” “intends,” “plans,” “believes,” “predicts,” “estimates” or similar expressions. In addition, any statements concerning future financial performance, ongoing business strategies or prospects or possible future actions are also forward-looking statements. Forward-looking statements are based on current expectations and projections about future events and are subject to risks, uncertainties and the accuracy of assumptions concerning HEI and its subsidiaries (collectively, the Company), the performance of the industries in which they do business and economic and market factors, among other things. These forward-looking statements are not guarantees of future performance.

Risks, uncertainties and other important factors that could cause actual results to differ materially from those described in forward-looking statements and from historical results include, but are not limited to, the following:

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

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

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

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

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

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

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

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

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

· capacity and supply constraints or difficulties, especially if generating units (utility-owned or IPP-owned) fail or measures such as demand-side management (DSM), distributed generation (DG), combined heat and power or other firm capacity supply-side resources fall short of achieving their forecasted benefits or are otherwise insufficient to reduce or meet peak demand;

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

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

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

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

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

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

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

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

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

· decisions by the PUC in rate cases and other proceedings (including the risks of delays in the timing of decisions, adverse changes in final decisions from interim decisions and the disallowance of project costs as a result of adverse regulatory audit reports or otherwise);

· decisions by the PUC and by other agencies and courts on land use, environmental and other permitting issues (such as required corrective actions and restrictions and penalties that may arise, such as with respect to environmental conditions or renewable portfolio standards (RPS));

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

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

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

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

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

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

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

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

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

· the risks of suffering losses and incurring liabilities that are uninsured (e.g., damages to the utilities’ transmission and distribution system and losses from business interruption) or underinsured (e.g., losses not covered as a result of insurance deductibles or other exclusions or exceeding policy limits); and

· other risks or uncertainties described elsewhere in this report (e.g., Item 1A. Risk Factors) and in other reports previously and subsequently filed by HEI and/or HECO with the Securities and Exchange Commission (SEC).

Forward-looking statements speak only as of the date of the report, presentation or filing in which they are made. Except to the extent required by the federal securities laws, HEI, HECO, ASB and their subsidiaries undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

PART I

ITEM 1. BUSINESS

HEI Consolidated

HEI and subsidiaries and lines of business. HEI was incorporated in 1981 under the laws of the State of Hawaii and is a holding company with its principal subsidiaries engaged in electric utility and banking businesses operating primarily in the State of Hawaii. HEI’s predecessor, HECO, was incorporated under the laws of the Kingdom of Hawaii (now the State of Hawaii) on October 13, 1891. As a result 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, Hawaii Electric Light Company, Inc. (HELCO) and Maui Electric Company, Limited (MECO), are regulated electric public utilities. HECO also owns all the common securities of HECO Capital Trust III (a Delaware statutory trust), which was formed to effect the issuance of $50 million of cumulative quarterly income preferred securities in 2004, 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 investments 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 currently owns directly or indirectly the following subsidiaries: American Savings Holdings, Inc. (ASHI) (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 financial institutions in the State of Hawaii with assets of $4.9 billion as of December 31, 2011.

HEIPI, whose predecessor company was formed in February 1998, holds venture capital investments with a carrying value of $0.6 million as of December 31, 2011.

TOOTS administers certain employee and retiree-related benefit programs and monitors matters related to its predecessor’s former maritime freight transportation operations.

For additional information about the Company required 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 Market Risk” and HEI’s Consolidated Financial Statements, and also see HECO’s “Management’s Discussion and Analysis of Financial Condition and Results of Operations” (HECO’s MD&A) and HECO’s “Quantitative and Qualitative Disclosures About Market Risk” and HECO’s Consolidated Financial Statements, which are incorporated 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 except 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, quarterly reports on Form 10-Q, current 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 furnished to, the SEC. HEI and HECO intend to continue to use HEI’s website as a means of disclosing additional information. Such disclosures will be included on HEI’s website in the Investor Relations section. Accordingly, investors should routinely monitor such portions 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 the PUC website is incorporated 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 Financial Statements.”

Regulation. HEI and HECO are each holding companies within the meaning of the Public Utility Holding Company Act of 2005 and implementing regulations (2005 Act). The 2005 Act 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 HEI and HECO a waiver from its record retention, accounting and reporting requirements, 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 periodic financial information and other reports concerning intercompany transactions and other matters. It also prohibits the electric utilities from loaning funds to HEI or its nonutility subsidiaries and from redeeming common stock of the electric utility subsidiaries without PUC approval. Further, the PUC could limit the ability of the electric utility subsidiaries to pay dividends on their common stock. See “Restrictions on dividends and other distributions” and “Electric utility—Regulation” below.

HEI and ASHI are subject to Federal Reserve Board (FRB) registration, supervision and reporting requirements as savings and loan holding companies. As a result of the enactment of the Dodd-Frank Act, supervision and regulation of HEI and ASHI, as thrift holding companies, moved to the FRB, and supervision and regulation of ASB, as a federally 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 financial safety, soundness or stability of ASB, the OCC is authorized to impose certain restrictions on HEI, ASHI and/or any of their subsidiaries. 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 activities 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 enumerated 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 satisfy the QTL test in the future could 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 requiring shareholder “say on pay” and “say on pay frequency” votes, mandating additional disclosures concerning executive compensation and compensation consultants and advisors, further restricting proxy 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 proxy solicitation materials. See “Bank—Legislation and regulation” in HEI’s MD&A for a discussion of the effects 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 significant operations of its own, HEI’s principal sources of funds are dividends or other distributions from its operating subsidiaries, borrowings and sales of equity. The rights of HEI and, consequently, its creditors and shareholders, to participate in any distribution of the assets of any of its subsidiaries are subject to the prior claims of the creditors and preferred shareholders of such subsidiary, except to the extent that claims of HEI in its capacity as a creditor are recognized as primary.

The abilities of certain of HEI’s subsidiaries to pay dividends or make other distributions to HEI are subject to contractual and regulatory restrictions. Under the PUC Agreement, in the event that the consolidated common stock equity of the electric utility subsidiaries falls below 35% of the total capitalization of the electric utilities (including the current maturities of long-term debt, but excluding short-term borrowings), the electric utility subsidiaries would, absent PUC approval, be restricted 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 provides 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 consolidated common stock equity of HEI’s electric utility subsidiaries was 56% of their total capitalization (as calculated for purposes of the PUC

Agreement). As of December 31, 2011, HECO and its subsidiaries had common stock equity of $1.4 billion of which approximately $588 million was not available for 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 that do not result in any decrease in ASB’s capital and would improve ASB’s financial condition, ASB is prohibited from declaring any dividends, making any other capital distributions, or paying a management fee to a controlling person if, following the distribution or payment, ASB would be deemed to be undercapitalized, significantly undercapitalized or critically undercapitalized. See “Bank—Regulation—Prompt corrective action.” All capital 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 covenants, 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 “Liquidity 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 period 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 lowering, suspension or withdrawal of any rating may have an adverse effect on the market price or marketability 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 effects 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 unsecured obligations of HECO and its subsidiaries under loan agreements and notes issued to the Department, including HECO’s guarantees of its subsidiaries’ obligations. The payment of principal and interest due on revenue bonds currently outstanding and issued prior to 2009 are insured, but the ratings of several of these insurers 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 subsidiaries, other than the electric utilities, are not covered by any collective bargaining agreement. A substantial number of employees of HECO and its subsidiaries are covered by collective bargaining agreements. 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 building 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.

Electric utility

HECO and subsidiaries and service areas. HECO, HELCO and MECO are regulated operating electric public utilities engaged in the production, purchase, transmission, distribution and sale of electricity on the islands of Oahu; Hawaii; and Maui, Lanai and Molokai, 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 Molokai 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 operations. The state has granted HECO, HELCO and MECO nonexclusive franchises, which authorize 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 “Quantitative 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	Electric 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 subsidiaries 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 increased 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, from 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 conservation goals for federally funded programs, (2) goals were set to reduce federal agencies’ energy consumption by 3% per year up to 30% by fiscal year 2015 relative to fiscal year 2003, and (3) renewable energy goals 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 reduction and renewable energy objectives.

Energy Agreement, energy efficiency and decoupling. On October 20, 2008, the Governor, the Hawaii Department of Business Economic Development and Tourism, the Consumer Advocate and the utilities entered into an Energy Agreement pursuant to which they 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. The 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 implementation of new programs intended to secure greater energy efficiency and conservation. See Note 3 of HEI’s Consolidated Financial Statements. One of the initiatives under the Energy Agreement was advanced when, in 2009, the state legislature enacted Act 155, which gave the PUC the authority to establish an Energy Efficiency Portfolio Standard (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 approving

a framework for EEPS that set 2008 as the initial base year for evaluation and linearly allocated the 2030 goal to interim incremental reduction goals of 1,375 GWH 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 (TWG) for consideration by the PUC. The interim and final reduction goals will be allocated among contributing entities by the EEPS TWG. The PUC may establish penalties in the future. Another of the initiatives was advanced when the PUC approved the implementation of revenue decoupling for HECO and HELCO under which HECO (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 implementation of revenue decoupling could have an impact on sales. However, neither HEI nor HECO management can predict with certainty the impact 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.

Selected consolidated electric 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 attributable to the removal of distributed generation units at substations.

2 Sum of the net peak demands on all islands served, noncoincident and nonintegrated.

Generation statistics. The following table contains certain generation statistics as of, and for the year ended, December 31, 2011. The net generating and firm purchased capability available for operation at any given time may be more or less than shown because of capability restrictions or temporary outages for inspection, maintenance, repairs or unforeseen circumstances.

	Island of Oahu- HECO		Island of Hawaii- HELCO		Island of Maui- MECO		Island of Lanai- MECO		Island of Molokai- MECO		Total

Net generating and firm purchased capability (MW) as of December 31, 20111
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 power2	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 Venture, 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 separate 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 maintains 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 electric demands, to provide for scheduled maintenance of generating units (including the units operated by IPPs relied upon for firm capacity) and to allow for the forced outage of the largest generating unit in the system.

See “Adequacy of supply” in HEI’s MD&A under “Electric utility.”

Nonutility generation. The Company has supported state and federal energy policies which encourage the development of renewable energy sources that reduce the use of fuel oil as well as the development of qualifying facilities. The Company’s renewable energy sources and potential sources range from wind, solar, photovoltaic, geothermal, wave and hydroelectric power 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 as-available 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, HECO entered into a PPA with AES Barbers 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 utilizes

a “clean coal” technology and is designed to sell sufficient steam to be a “Qualifying Facility” (QF) under the Public Utility Regulatory Policies Act of 1978 (PURPA).

In October 1988, HECO entered into an agreement with 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 capacity for a period of 25 years beginning in May 1991 and terminating in May 2016. The 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 filed 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 the 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 the agreement with Kalaeloa pending the PUC’s decision.

HECO also entered into a PPA in March 1986 and a firm capacity amendment in April 1991 with the City and County of Honolulu with respect to a refuse-fired plant (HPower). The HPower facility currently supplies HECO with 46 MW of firm capacity. Under the amendment, HECO will purchase firm capacity until mid-2015. HECO is currently in negotiations with the City and County 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 (including 4 MW of system protection) of firm capacity.

HELCO has a 35-year PPA with Puna Geothermal Venture (PGV) for 30 MW of firm capacity from its geothermal steam facility, which will expire on December 31, 2027. In February 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, dispatchable capacity from the facility. 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 years, expiring on December 31, 2030. The dual-train combined-cycle DTCC facility, which primarily burns naphtha, consists of two oil-fired combustion turbines and a steam turbine that utilizes waste heat from the combustion turbines.

MECO has a PPA with Hawaiian Commercial & Sugar Company (HC&S) for 16 MW of firm capacity. The HC&S generating units primarily burn bagasse (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, subject 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 electric 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 paid for fuel oil and certain components of purchased power, and the relative amounts of company-generated power 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 policies–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 (biodiesel). 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 mixtures of LSFO and crude palm oil.

MECO’s and HELCO’s steam generating units burn medium sulfur fuel oil (MSFO) and HELCO’s and MECO’s Maui and Molokai combustion turbine and diesel engine generating units burn 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 completed a biodiesel test fire project.

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 fuel oil consumed to generate electricity 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 expensive fuels and the price of LSFO falls in-between on a per-barrel basis. In 2011, the prices of all petroleum fuels trended strongly higher through the spring and were generally stable thereafter. In 2011, the prices 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 contracts of private carriage with Hawaiian Interisland Towing, Inc. (HITI) for the employment of a double-hull tank barge for the shipment of MSFO and diesel supplies from their fuel suppliers’ facilities on Oahu to storage locations on the islands of Hawaii and Maui, respectively, commencing January 1, 2002. The contracts 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 fuel, 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 clean-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 avoided 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 generate and purchase in 2012 will be generated from the burning of fossil fuel oil. HECO generally maintains an average system 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 certain minimum fuel inventory levels.

Rates. HECO, HELCO and MECO are subject to the regulatory jurisdiction of the PUC with respect to rates, issuance of securities, accounting and certain other matters. See “Regulation” below.

Rate schedules of HECO and its subsidiaries contain 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 required for each rate change pursuant to automatic rate adjustment clauses previously approved by the PUC. All other rate increases require the prior approval of the PUC after public and contested case hearings. PURPA requires the PUC to periodically review the ECACs of electric and gas utilities in the state, and such clauses, as well as the rates charged by the utilities generally, are subject to change.

See “Electric utility–Most recent rate proceedings, “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 policies–Revenues” in HEI’s MD&A and “Interim increases” and “Major projects” under “Commitments and contingencies” in Note 3 to HEI’s Consolidated Financial 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 Representative. 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 was the Executive Director of the Division of Consumer Advocacy.

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

Competition. See “Electric utility–Certain factors that may affect future 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 organization 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 monitor the ongoing research and continue to participate in utility industry funded studies on EMF and, where technically feasible and economically reasonable, continue to pursue a policy of prudent avoidance in the design and installation of new transmission 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 greenhouse gas emissions reduction. The Company shares the concerns of many regarding the potential effects of global warming and the human contributions to this phenomenon, including burning of fossil fuels for electricity production, transportation, manufacturing and agricultural activities, as well as deforestation. Recognizing that effectively addressing global warming requires commitment by the private sector, all levels of government, and the public, the Company is committed to taking direct action to mitigate greenhouse gas emissions from its operations. See “Environmental regulation—Global climate change and greenhouse gas emissions reduction” under “Commitments and contingencies” in Note 3 to HEI’s Consolidated Financial Statements.

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

Commitments and contingencies. See “Selected contractual obligations and commitments” in HECO’s MD&A and “Electric utility–Certain factors that may affect future results 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 commitments and contingencies.

Regulation. The PUC regulates the rates, issuance of securities, accounting and certain other aspects of the operations of HECO and its electric utility subsidiaries. See the previous discussion under “Rates” and the discussions under “Electric utility–Results of operations–Most recent rate 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 prolonged 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 Agreement (see “Hawaii Clean Energy Initiative” under “Commitments and contingencies” in Note 3 to HEI’s Consolidated Financial Statements) setting forth goals, objectives and actions with the purpose of decreasing Hawaii’s dependence on imported fossil fuels through substantial increases in the use of renewable energy and implementation 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 December 31, 2010, 2015, 2020 and 2030, respectively. Energy savings resulting from energy efficiency programs will not count toward the RPS after 2014 (only electrical generation using renewable energy as a source will count). The amended RPS law is consistent with the commitment 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 subject to regulation by the PUC. All contracts of $300,000 or more in a calendar year for management, supervisory, construction, engineering, accounting, legal, financial and similar services and for the sale, lease or transfer 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 “affiliated contracts” for capital expenditures (except for real property) must be accompanied by comparative price quotations from two nonaffiliates, unless the quotations cannot be obtained without substantial expense. Moreover, 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 interest, the utility must either revise the contract or risk disallowance of payments under the contract 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 operations 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 Agreement (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 holding 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 such effects from the cost of capital. 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 capital did not suffer as a result of HEI’s involvement in nonutility activities and that HEI’s diversification did not permanently raise 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 utilities, and Title VII of the Energy Policy Act of 1992, which

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 Powerplant 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 regulatory agencies, including agencies responsible for the regulation of water quality, air quality, hazardous and other waste, and hazardous materials. These inspections may result in the identification of items needing corrective or other action. When the corrective or other necessary action is taken, no further regulatory action is expected. Except as otherwise disclosed in this report (see “Certain factors that may affect future results 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, which are incorporated herein by reference), the Company believes that each subsidiary has appropriately responded to environmental conditions requiring action and that, as a result of such actions, such environmental conditions will not have a material 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 Elimination System (governing point source discharges, including wastewater and storm water discharges), Underground Injection Control (regulating disposal of wastewater into the subsurface), the Spill Prevention, Control and Countermeasure (SPCC) program, the Oil Pollution Act of 1990 (OPA), and other regulations associated with discharges of oil and other substances to surface water.

OPA governs actual or threatened oil releases and establishes strict and joint and several liability for responsible parties for (1) oil removal costs incurred by the federal government or the state, and (2) damages to natural resources and real or personal property, as well as compensation 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 respective subsidiary or the Company.

EPA regulations under OPA also require certain facilities that use or store petroleum to prepare and implement SPCC Plans in order to prevent releases of petroleum to navigable waters 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 facility and whether a release of petroleum could 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 governing 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 electric utility industry has been affected by the 1990 amendments to the Clean Air Act (CAA), changes to the National Ambient Air Quality Standard (NAAQS) for ozone, adoption of a NAAQS for fine particulate matter, and the EPA’s 1-hour NAAQS for nitrogen 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 fossil-fuel fired steam electrical generating units (see “Environmental regulation” in Note 3 to HEI’s “Notes to Consolidated Financial Statements”).

The EPA has also required HELCO (for its Hill Power 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 decree, 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 cost of compliance for HELCO and MECO could be significant.

The CAA amendments of 1990, among other things, established a federal operating permits program (in Hawaii known as the Covered Source Permit program) 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 Deterioration (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 electric utility and former freight transportation subsidiaries of HEI are subject to EPA regulations that implement provisions of the Resource Conservation and Recovery Act (RCRA), the Superfund Amendments and Reauthorization Act (SARA) and the Toxic Substances Control Act (TSCA).

RCRA underground storage tank (UST) regulations require all facilities with USTs used for storing petroleum products to comply with leak detection, spill prevention and new tank standard retrofit requirements. All HECO, HELCO and MECO USTs currently 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 the public in the event of hazardous chemical releases. All HECO, HELCO and MECO facilities are in compliance with applicable annual reporting requirements to the State Emergency Planning Commission, 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 requirements. All HECO, HELCO and MECO facilities are in compliance with TRI reporting requirements.

The TSCA regulations specify procedures for the 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 the environment. HECO, HELCO and MECO have instituted procedures to monitor compliance with these regulations and have implemented a program to identify and replace PCB transformers and capacitors in their systems. Management believes that all HECO, HELCO and MECO facilities are currently in compliance with PCB regulations. In April 2010, the EPA issued an Advance Notice of Proposed Rule Making announcing its 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 hazardous 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-containing equipment such as USTs, piping and transformers. In a few instances, small amounts of PCBs have been identified in the leaking equipment. Each subsidiary reports releases from such equipment when and as required by applicable law and addresses impacts due to the releases in compliance with applicable regulatory requirements.

Research and development. HECO and its subsidiaries expensed approximately $4.3 million, $4.0 million and $4.4 million in 2011, 2010 and 2009, respectively, for research and development (R&D). In 2011, 2010 and 2009, the electric utilities’ contributions to the Electric Power Research Institute accounted for approximately half of the R&D expenses. There were also 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).

Properties.

HECO owns and operates four generating plants on the island of Oahu at Honolulu, Waiau, Kahe and Campbell Industrial Park (CIP). These plants have an aggregate net generating capability of 1,321.6 MW as of December 31, 2011. The four plants are situated on HECO-owned land having a combined area of 535 acres and one 3.5-acre parcel of land under a lease expiring December 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 approximately 11.6 acres of land located in Honolulu which houses its operating, engineering and information services departments and a warehousing center. It also leases an office building and certain office space in Honolulu. The lease for the office building 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 fuel 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 storage 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 storage at CIP to fuel storage facilities at HECO’s generating stations at Waiau and Kahe. HECO also owns a fuel storage facility at Iwilei, which receives fuel trucked from the central storage facility, with a combined usable capacity of 76,735 barrels, 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 island of Hawaii, two at Hilo and one at each of Waimea, Keahole and Puna, along with distributed generators at substation sites. These plants have an aggregate net generating capability of 197.1 MW as of December 31, 2011 (excluding several small run-of-river hydro units). The plants are situated on HELCO-owned land having a combined area of approximately 44 acres. The distributed generators are located within HELCO-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 storage capacity for HELCO-owned fuel off-site at Chevron Products Company (Chevron)-owned terminalling facilities. HELCO pays a storage fee to Chevron and has no other interest in the property, tanks or other infrastructure situated on Chevron’s property. HELCO also owns 6 acres of land in Kona, which is used for a baseyard, and one acre of land in Hilo, which houses its accounting, customer services and administrative offices. HELCO also leases 3.7 acres of land for its baseyard in Hilo under a lease expiring in 2030. In addition, HELCO owns a total of approximately 100 acres of land, and leases a total of approximately 8.5 acres 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 the restrictions do not materially interfere with the use of the sites for public utility purposes.

MECO owns and operates two generating plants on the island of Maui, at Kahului and Maalaea, with an aggregate net generating capability of 246.3 MW as of December 31, 2011. The plants are situated on MECO-owned land having a combined area of 28.6 acres. MECO also 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 agricultural purposes by the former 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 for utility purposes, or until July 31, 2013, whichever occurs first.

MECO’s administrative offices and engineering and distribution departments are located on 9.1 acres of MECO-owned land in Kahului.

MECO also owns and operates smaller distribution systems, generation systems (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. Electric lines are located over or under public and nonpublic properties. Lines are added when 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 constructed 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 the 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 charter in January 1987. Prior to that time, ASB had operated since 1925 as the Hawaii division of American Savings & 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 billion. 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 approximately 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 required from time to time by regulation. Under the agreement, HEI’s obligation to contribute additional capital to ensure that ASB would have the capital level required by the OTS was limited to a maximum aggregate amount of approximately $65.1 million. As of December 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 receive a letter of non-objection 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 investment 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 securities sold under agreements to repurchase). Other factors affecting ASB’s operating results include its provision for loan losses, fee income, other noninterest income (including gains and losses on sales of loans, securities and notes and other-than-temporary impairments of securities) and noninterest expenses.

For additional information about ASB, see the sections under “Bank” in HEI’s MD&A, HEI’s “Quantitative and Qualitative Disclosures about Market Risk” and Note 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		72

All of the foregoing ratios and returns for 2009 were adversely affected by losses related to the sale of the private-issue mortgage-related securities portfolio and other-than-temporary impairment charges on ASB’s securities portfolio, and for 2010 and 2011 were positively affected by the reduction in 2009 in ASB’s common equity, earning assets and costing liabilities.

Asset/liability management. See HEI’s “Quantitative and Qualitative 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 year 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 fee 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 composition 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	)
Allowance 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 to

lower production and ASB’s decision to sell a portion of the residential loan production. 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 lines 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 collateralized 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 estate market, business conditions, 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 the lower of the appraised value 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 residential and commercial properties. Construction loan projects are typically short term in nature. Construction and development financing generally involves a higher degree of credit risk than long-term financing on improved, occupied real estate. Accordingly, construction and development loans are generally priced higher than loans collateralized by completed structures. ASB’s underwriting, monitoring and disbursement practices with respect to construction and development financing are designed to ensure sufficient funds are available to complete construction projects. See “Loan portfolio risk elements” and “Multifamily residential and commercial real estate lending” below.

Multifamily residential and commercial real estate lending. ASB provides permanent financing and construction and development financing collateralized by multifamily residential properties (including apartment buildings) and collateralized by commercial and industrial properties (including office buildings, shopping

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 originate and fund. As a result, production results can vary significantly from period to period.

Consumer lending. ASB offers a variety of secured and unsecured consumer loans. Loans collateralized by deposits are limited to 90% of the available account balance. ASB offers 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 commercial loans to business entities. This lending activity is part of ASB’s strategic transformation 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 settlement a loan origination fee 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 required payment on a loan and does not cure the delinquency promptly, the loan is classified 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 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 estate acquired in settlement of loans.

In addition to delinquent loans, other significant lending risk elements include: (1) loans which accrue interest and are 90 days or more past due as to principal or interest, (2) loans accounted for on a nonaccrual basis (nonaccrual loans), and (3) loans on which various concessions are made with respect to interest rate, maturity, or other terms due to the inability of the borrower to service the obligation under the original terms of the agreement (troubled debt restructured 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:

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 interest 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 terms 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 classified and placed on nonaccrual status. The increase in troubled debt restructured loans was due to two commercial loans that were renegotiated. In 2010, nonaccrual loans decreased by $6.5 million due to a decrease 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 primarily 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 reclassification 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 residential and consumer loan portfolios.

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 assigned to it. Partly offsetting these decreases was an

increase in the allowance for loan losses for the commercial real estate portfolios due to a higher average loan balance. The levels of delinquencies and losses 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 prior year’s provision for loan losses. Although the economy had gradually recovered 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 loans. Although ASB’s loan quality 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 experiencing higher levels of loan delinquencies and losses, which were concentrated in the vacant land portfolio and on the neighbor islands. ASB’s 2010 provision for loan losses was $20.9 million. While a mild recovery 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 land and home equity lines of credit delinquencies and increases in the historical loss ratios for these loan types. ASB’s loan quality weakened in 2009, although not to the same level of decline in loan quality seen in many mainland U.S. markets. The slowdown in the economy, both nationally and locally, had caused increased levels of financial 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 commercial loan that was subsequently sold.

Investment activities. Currently, ASB’s investment portfolio consists 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 Association (FNMA), Federal Home Loan Mortgage Corporation (FHLMC) and Government National Mortgage Association (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 investment is in excess of that requirement. See “FHLB of Seattle stock” in HEI’s MD&A. Also, see “Regulation—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 “Investment and mortgage-related securities” in Note 4 to HEI’s Consolidated Financial Statements for a discussion of other-than-temporarily impaired securities.

The following table summarizes ASB’s investment portfolio (excluding stock of the FHLB 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%

Deposits and other sources of funds.

General. Deposits traditionally have been the principal source 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-related securities, borrowings from the FHLB of Seattle, securities sold under agreements to repurchase 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 year-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 calculated 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 Corporation (FICO) assessments, see “Regulation—Deposit insurance coverage” below.

Other borrowings. See “Other borrowings” in Note 4 to HEI’s Consolidated Financial Statements. ASB may obtain advances from the FHLB of Seattle provided that certain standards related to creditworthiness have been met. Advances are collateralized by a blanket pledge of certain notes held by ASB and the mortgages securing them. To the extent that advances exceed the amount of mortgage loan collateral 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 and 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 time 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 condition—Competition” in HEI’s MD&A.

Competition for deposits comes primarily from other savings institutions, commercial banks, credit unions, money market and mutual funds and other investment alternatives. As of December 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 firms, commercial banks, other savings institutions, insurance companies and real estate investment trusts.

Regulation. ASB, a federally chartered savings bank, and its 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—Regulation” above and “Bank—Certain factors that may affect future results and financial condition—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 insurance coverage of deposit accounts. In July 2010, the Dodd-Frank Act permanently raised the current standard maximum deposit insurance amount 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 applying the insurance limit.

See “Federal Deposit Insurance Corporation restoration plan” in Note 4 to HEI’s Consolidated Financial Statements for a discussion of FDIC deposit insurance 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 assessment on deposits to service the interest on FICO bond obligations. ASB’s annual FICO assessment is 0.66 cents per $100 of deposits as of December 31, 2011.

Federal thrift charter. See “Bank—Certain factors that may affect 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 would 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 standards 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., CAMELS 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 required 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 framework have been adopted for institutions that are much larger in size than ASB or that have substantial foreign exposures. ASB is not currently required to be, and has elected not to be, governed by these other standards.

Affiliate transactions. Significant restrictions apply to certain 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 purchase 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 use interest rate swaps to manage interest rate risk

(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 involvement of the ASB Board of Directors.

With the transfer of the regulatory jurisdiction from the OTS to the OCC, ASB has adopted terminology and IRR assessment, measurement and management practices consistent with OCC guidelines. Management believes ASB’s IRR processes are aligned with the Interagency Advisory on Interest 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 customer 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 Seattle and securities sold under agreements to repurchase from broker/dealers. ASB is approved by the FHLB of Seattle to borrow an amount of up to 35% of assets to the extent it provides qualifying collateral and holds sufficient FHLB of Seattle 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 securities 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, undisbursed loan funds and unused lines and letters of credit of $1.3 billion. Management believes ASB’s current sources of funds will enable it to meet these obligations while maintaining liquidity at satisfactory levels.

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

Prompt corrective action. The FDICIA establishes a statutory framework that is triggered by the capital level of a financial institution and subjects it to progressively more stringent restrictions and supervision as capital levels decline. The OCC rules implement the system of prompt corrective action. In particular, the rules define the relevant capital measures for the categories of “well capitalized”, “adequately capitalized”, “undercapitalized”, “significantly undercapitalized” and “critically undercapitalized.”

A financial institution that is “undercapitalized” or “significantly undercapitalized” is subject to additional mandatory supervisory actions and a number of discretionary actions if the OCC determines that any of the actions is necessary to resolve the problems of the association at the least possible long-term cost to the Deposit Insurance Fund. A financial institution that is “critically undercapitalized” must be placed in conservatorship or receivership within 90 days, unless 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 undercapitalized to offer interest rates on deposits that are significantly higher than the rates offered by competing institutions. As of December 31, 2011, ASB was “well capitalized” and thus not subject to these interest rate restrictions.

Qualified thrift lender test. In order to satisfy the QTL test, ASB must maintain 65% of its assets in “qualified thrift investments” on a monthly average basis in 9 out of the previous 12 months. Failure to satisfy the QTL test would subject ASB to various penalties, including 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 System, 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 served as the central liquidity facilities for savings

associations and sources of long-term funds for financing housing. At such time as an advance is made to ASB or renewed, it must be collateralized by collateral from one of the following categories: (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 collateral 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 Housing Finance Board (Board) regulations require each FHLB to maintain a minimum total capital leverage ratio of 5% of total assets and include risk-based capital standards requiring each FHLB to maintain permanent capital in an amount sufficient to meet credit risk and market risk. In June 2001, the FHLB of Seattle formulated a capital plan to meet these new minimum capital standards, which plan was approved by the Board. The capital 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 outstanding 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 December 31, 2011, ASB was required 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 for 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 low- and moderate-income areas, consistent with safe and sound lending practices. The 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 currently holds an “outstanding” CRA rating.

Other laws. ASB is subject to federal and state consumer protection laws which affect lending activities, such as the Truth in Lending Act, the Truth in Savings Act, the Equal Credit Opportunity Act, the Real Estate Settlement Procedures Act, the Home Mortgage Disclosure Act and several federal and state financial privacy acts intended to protect consumers’ personal information and prevent identity theft, such as the Gramm Act and the Fair and Accurate Transactions Act. ASB is also subject 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 Foreign 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 adopted by the FRB under the Gramm Act, which regulate “networking” relationships under which a financial institution refers customers 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 the 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 Liability 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 exempt persons whose ownership in a facility is held primarily to protect a security interest, provided that they do not participate in the 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, the Company believes the

risk is not as great for ASB as it may be for other depository institutions 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 Technology 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 improvements 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 leases have extension provisions.

As of December 31, 2011, ASB owned 119 automated teller machines.

ITEM 1A. RISK FACTORS

The businesses of HEI and its subsidiaries involve numerous 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 the Company and its operations, see “Forward-Looking Statements” above and HEI’s MD&A, HEI’s “Quantitative and Qualitative Disclosures about Market Risk”, HEI’s Consolidated Financial Statements, HECO’s MD&A, HECO’s “Quantitative and Qualitative Disclosures About Market Risk” and HECO’s Consolidated Financial Statements.

Holding Company and Company-Wide Risks.

HEI is a holding company that derives its income from its operating subsidiaries and depends on the ability of those subsidiaries to pay dividends or make other distributions to HEI and on its own ability to raise capital. HEI is a legal entity separate and distinct 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 receipt of dividends or other distributions from its operating subsidiaries and its ability to issue common stock or other equity securities 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 contractual and regulatory restrictions, 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 dividends to HEI in the event that the consolidated common stock equity of the electric public utility subsidiaries falls below 35% of total capitalization of the electric utilities;

· the provisions of an HEI agreement entered into with federal bank regulators in connection with its acquisition of its bank subsidiary, ASB, which require 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 capital at the level required by regulation;

· the minimum capital and capital distribution regulations of the OCC that are applicable to ASB;

· the receipt of a letter from the OCC and FRB stating it has no objection to the payment of any dividend ASB proposes to declare and pay to HEI; and

· the provisions of preferred stock resolutions and debt instruments of HEI and its subsidiaries.

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 retirement benefit plan funding requirements, declines in electric utility KWH sales, declines in ASB’s interest rate margins and investment 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 tourism and the federal government (including the military). Because the core businesses of HEI’s subsidiaries 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 California) 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 Afghanistan) on federal government spending in Hawaii. For example, the turmoil in the financial markets and declines in the national and global 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 uncollected billings of HECO and its subsidiaries, higher delinquencies in ASB’s loan portfolio and other adverse 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 consolidated net income in future periods. 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 capital or other expenditures.

Changes in the U.S. capital markets can also have significant effects on the Company. For example, pension funding requirements are affected 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 obligations. The electric utilities’ pension tracking mechanisms help moderate pension expense; however, the significant decline in 2008 in the value of the Company’s defined benefit pension plan assets resulted in a substantial gap between the projected benefit obligations under the plans and the value of plan assets, resulting in increases in funding requirements.

Because the earnings of ASB depend primarily on net interest 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 rates on the electric utilities’ rates of return. Interest rates are sensitive to many factors, including general economic conditions and the policies of government and regulatory authorities. HEI cannot predict future changes in interest rates, nor be certain that interest rate risk management strategies it or its subsidiaries have implemented will be successful in managing interest 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 interest 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 residential mortgage delinquencies and defaults may result in decreases in the fair value of ASB’s investment securities and an impairment that is other-than-temporary, 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 entity that have an implicit guarantee from the U.S. government.

HEI and HECO and their subsidiaries may incur higher retirement benefits expenses and have and will likely continue to recognize substantial 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 markets, trends in interest rates and health care costs, plan amendments, new laws relating to pension funding and changes in accounting principles. For the electric utilities, however, retirement benefits expenses, as adjusted by the pension and postretirement benefits other than pensions (OPEB) tracking mechanisms, have been an allowable 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 interruptions at the electric utilities or higher default rates on loans held by ASB. The business of HECO and its electric utility subsidiaries is concentrated on the individual islands they serve in the State of Hawaii. Their operations are more vulnerable to service interruptions than are many U.S. mainland utilities 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 typical for U.S. mainland utilities to help ensure reliable service. Service interruptions, including in particular extended interruptions that could result from a natural disaster or terrorist activity, could adversely impact the KWH sales of some or all of the electric utility subsidiaries.

Substantially all of ASB’s consumer loan customers are Hawaii residents. 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 (whose economies have been weaker than Oahu during the recent economic downturn). Substantially all of the real estate underlying ASB’s residential and commercial real estate loans are located in Hawaii. These assets may be subject to a greater risk of default than other comparable assets held by financial institutions with other geographic concentrations in the event of adverse economic, political or business developments or natural disasters affecting Hawaii and the ability of ASB’s customers to make payments of principal and interest on their loans.

Increasing competition and technological advances could 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 success of HEI’s subsidiaries in meeting 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 institutions in the state, is in direct competition for deposits and loans not only with two larger institutions that have substantial capital, technology and marketing resources, but also with smaller Hawaii institutions 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 technology could render the operations of ASB less competitive or obsolete.

· HECO and its subsidiaries face competition from IPPs and customer self-generation, with or without cogeneration. With the exception of certain identified projects, the utilities are required to use competitive bidding to acquire a future generation resource 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 utilities 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 commercial development of energy storage, may render the operations of HEI’s electric utility subsidiaries less competitive or outdated.

The Company may be subject to information technology system failures, network disruptions and breaches in data security that could adversely affect its businesses and reputation. The Company is subject to cyber security risks and the potential for cyber incidents, including potential incidents at ASB branches and at the HECO, HELCO and MECO plants and the related electricity transmission and distribution infrastructure, and incidents at data processing centers they use, to the extent not prevented by intrusion detection and prevention systems, anti-virus software, firewalls and other general information technology controls. 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 place to protect their businesses against natural disasters, security breaches, military or terrorist actions, power or communication failures or similar events. 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 uninsured due to a lack of affordable insurance coverage, unavailability of insurance coverage or limitations on the insurance coverage the Company does have. In the ordinary course of business, HEI and its subsidiaries purchase insurance coverages (e.g., property and liability coverages) to protect against loss of, or damage to, their properties and against claims made by third parties and employees for property damage or personal injuries. However, the protection provided by such insurance is limited in significant respects and, in some instances, there is no coverage. Certain of the insurance has substantial deductibles or has limits on the maximum amounts that may be recovered. For example, the electric utilities’ overhead and underground transmission and distribution systems (with the exception of substation buildings and contents) have a replacement value roughly estimated at $5 billion and are not insured against loss or damage because the amount of transmission and distribution system insurance available is limited and the premiums are cost prohibitive. Similarly, the electric utilities have no business interruption insurance as the premiums for such insurance would be cost prohibitive, particularly since the utilities are not interconnected to other systems. If a hurricane or other uninsured 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 interruption, the lost revenues and repair expenses could result in a significant decrease in HEI’s consolidated net income or in significant net losses for the affected periods.

ASB generally does not obtain credit enhancements, such 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 bankruptcies, special hazard losses not covered by the required insurance and the insurance company’s inability to pay claims on existing policies.

Increased federal and state environmental regulation will require an increasing commitment of resources and funds and could result in construction delays 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 facilities and the proper cleanup and disposal of hazardous waste and toxic substances. Compliance with these legal requirements requires HEI’s utility subsidiaries to commit significant resources and funds toward environmental monitoring, installation of pollution control equipment and payment of emission fees. These laws and regulations, among 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 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. 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, significant regulatory uncertainty exists regarding the impact of federal or state greenhouse gas emission limits and reductions.

If HEI or its subsidiaries fail to comply with environmental laws and regulations, 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 challenge a tax return position taken by HEI or its subsidiaries and, if the taxing authorities 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 uninsured losses in excess of its accruals for litigation matters. HEI and its subsidiaries are involved in routine litigation in the ordinary 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 routine or involves claims that may not be covered by insurance. Because of the uncertainties associated with litigation, there is a risk that litigation against 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 established in HEI’s consolidated financial statements.

Changes in accounting principles and estimates could 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 accepted in the U.S. Changes in these principles, or changes in the Company’s application of existing accounting principles, could materially affect the financial statement presentation of HEI’s or the electric utilities’ consolidated results of operations and/or financial condition. Further, in preparing the consolidated financial statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities, the 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 securities; property, plant and equipment; pension and other postretirement benefit obligations; contingencies and litigation; income taxes; regulatory assets and liabilities; electric utility revenues; and allowance for loan losses.

HECO and its subsidiaries’ financial statements reflect assets and costs based on cost-based rate-making regulations. Continued accounting in this manner requires that certain criteria relating to the recoverability of such costs through rates be met. If events or circumstances should change so that the criteria are no longer satisfied, the electric utilities’ regulatory assets (amounting to $669 million as of December 31, 2011) may need to be charged to expense, which could result in significant 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 HEI’s consolidated financial statements. For example, if management determines that a PPA requires the consolidation of the IPP in HECO’s consolidated financial statements, the consolidation could have a material effect on HECO’s and HEI’s consolidated financial statements, including the recognition of a significant amount of assets and liabilities and, if such a consolidated IPP were operating at a loss and had insufficient 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 the recognition of significant capital assets and lease obligations.

Electric Utility Risks.

Actions of the PUC are outside the control of the electric utility subsidiaries and could result in inadequate or untimely rate increases, in rate reductions or refunds 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 important items influencing the electric utilities’ results of operations, financial condition and liquidity. The PUC has broad discretion over the rates that the electric utilities charge their customers. The electric utilities currently have rate cases pending before the PUC. In addition, as part of the decoupling mechanism that the electric utilities have or will be implementing, each of the electric utilities 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 equity or rate base found to be reasonable, the potential consequences of exceeding or not meeting such returns, or any prolonged delay in rendering a decision in a rate or other proceeding, could have a material adverse effect on HECO’s consolidated 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 mechanisms 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 interest, 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 agencies. Difficulties in obtaining, or the inability to obtain, the necessary approvals or permits, or any adverse decision or policy made or adopted, or any prolonged delay in rendering a decision, by an agency with respect 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 and consequent delay, increased costs and a subsequent partial write-off of costs in the fourth quarter of 2011. In the event a project does not proceed, or if the PUC disallows 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.

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 weighted-average price paid for fuel oil and certain components 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 existing ECACs will continue, but subject to periodic review by the PUC. The Energy Agreement also 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 alternative 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 material adverse effect on the electric utilities.

Electric utility operations are significantly influenced by weather conditions. The electric utilities’ results of operations can be affected by the weather. 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 become 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.

Electric utility operations depend 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 agreements. Approximately 76% of the net energy generated or purchased by the electric utilities in 2011 was generated from the burning of fossil fuel oil, and purchases of power by the electric utilities provided about 40% of their total net energy generated and purchased for 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 addition, as these contractual agreements end, the electric utilities may not be able to purchase fuel and power on terms equivalent to the current contractual agreements. 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 facility shutdowns or power interruptions due to insufficient generation or a breakdown or failure of equipment or processes or interruptions in fuel supply, inability to negotiate satisfactory collective bargaining agreements when existing agreements expire or other labor disputes, inability to comply with regulatory or permit 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 facilities 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 generation, 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 Hawaii Legislature periodically consider legislation that could have uncertain or negative effects on the electric utilities and their customers. The Hawaii Legislature has adopted a number of measures 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 efficiency programs will not count toward the RPS after 2014. The utilities are committed to achieving these goals and met the 2010 RPS; however, due to the exclusion of energy savings in calculating RPS after 2014 and risks such as potential delays in IPPs being able to deliver contracted renewable energy, it is possible the electric utilities may not attain the required renewable percentages in the future, and management cannot predict the future 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.

Renewable energy. In 2007, a measure was passed by the Hawaii legislature stating 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 from the renewable source, resulting in higher costs.

Global climate change and greenhouse gas emissions reduction. National and international concern about climate change and the contribution of greenhouse gas (GHG) emissions to global warming have led to action by the state of Hawaii and federal legislative and regulatory proposals to reduce GHG emissions.

In July 2007, Act 234, which requires a statewide reduction of GHG emissions by January 1, 2020 to levels at or below the statewide GHG emission 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 emissions from motor vehicles under the CAA, the EPA has accelerated rulemaking addressing GHG emissions from both mobile and stationary sources. On September 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 monitor 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 published. 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 the utilities’ operations.

At this time, it is not possible to predict with certainty 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 the commitments and objectives of the HCEI Energy Agreement. On October 20, 2008, 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 State of Hawaii Department of Commerce and Consumer Affairs and the electric utilities (collectively, the parties), signed an Energy Agreement setting forth the 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 State of Hawaii’s dependence on imported fossil fuels through substantial increases in the use of renewable energy and implementation of new programs intended to secure greater energy efficiency and conservation.

The far-reaching nature of the Energy Agreement, including the extent of renewable energy commitments, presents 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 unsuccessful in negotiating purchased power agreements with such IPPs or if a major IPP fails to deliver the anticipated capacity in its purchased power agreement, could impact the utilities’ achievement of its commitments under the Energy Agreement and/or the utilities’ ability to deliver reliable service; (2) delays in acquiring 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 installed or does not operate effectively; (4) the likelihood that the utilities may need to make substantial investments in related infrastructure, which could result in increased borrowings and, therefore, materially impact the financial condition and liquidity of the utilities; and (5) the commitment to support a variety of initiatives, which, if approved by the PUC, may have a material impact on the results of operations and financial condition of the utilities depending on their design and implementation. Programs include, but are not limited to, decoupling revenues from sales; implementing feed-in tariffs to encourage development of renewable energy; removing the system-wide caps on net energy metering (but studying distributed generation interconnections on a per-circuit basis); and developing an Energy Efficiency Portfolio Standard. Management cannot predict the ultimate impact or outcome of the implementation of these or other HCEI programs on the results of operations, financial condition and liquidity of the electric utilities.

Bank Risks.

Fluctuations in interest rates could result in lower 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 income 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 rate risk arises when earning assets mature or when their interest rates change in a time frame different from that of the costing 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 strategy designed to mitigate its risk from changes in market interest rates, unfavorable movements in interest 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 risk-adjusted returns, which resulted in a negative impact 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 perception that an increase may occur, could adversely affect ASB’s ability to originate new loans and grow. An increase in market interest rates, especially a sudden increase, could also adversely affect the ability of ASB’s adjustable-rate borrowers to meet their higher payment obligations. If this occurred, it could cause an increase in nonperforming assets and charge-offs. Conversely, a decrease in interest rates or a mismatching of maturities of interest sensitive financial instruments could result in an acceleration in the prepayment of loans and mortgage-related 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 level 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 adversely affected by various other factors, such as:

· local and other economic and political conditions that could result in declines in employment and real estate values, which in turn could adversely affect the ability of borrowers to make loan payments and the ability of ASB to recover the full 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 prepayments that can cause an acceleration of the amortization of premiums on loans and investments and the impairment of mortgage servicing assets of ASB;

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

· technological disruptions affecting ASB’s operations or financial or operational difficulties experienced by any outside vendor on whom ASB relies to provide key components of its business operations, such as business processing, 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 overdraft, interchange and credit card fees, which will have a negative impact on noninterest income;

· public opinion about ASB and financial institutions in general, which, if negative, could impact the public’s trust and confidence in ASB and adversely affect ASB’s ability to attract and retain customers and expose ASB to adverse legal and regulatory consequences;

· increases in operating costs, inflation and other factors, that exceed increases 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 significant 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 regulatory authorities have extensive discretion in connection with their supervisory and enforcement activities and examination policies to address not only ASB’s compliance with applicable banking laws and regulations, but also capital adequacy, asset quality, management ability and performance, earnings, liquidity and various other factors.

Under certain circumstances, including any determination that ASB’s relationship with HEI results in an unsafe and unsound banking practice, these regulatory authorities have the authority to restrict the ability of ASB to transfer assets and to make distributions to its 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, including 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 required divestiture of ASB. In the event of a required divestiture, federal law substantially limits the types of entities that could potentially acquire ASB.

Recent legislative and regulatory initiatives could have an adverse effect on ASB’s business. The Dodd-Frank 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 framework 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 Consumer Financial Protection Bureau that has the responsibility for setting and enforcing clear, consistent 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 sanctions by regulatory agencies, civil 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 collateralized 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 approximately 78% of ASB’s loan portfolio was comprised of loans primarily collateralized by real estate, most of which was concentrated 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 policies of the federal and state government and other significant external events. A deterioration of the economic environment in Hawaii, including a material 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 timely

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 real 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 estate loans have shorter terms to maturity and earn higher spreads than residential mortgage loans. Only the assets of the business typically secure commercial loans. In such cases, upon default, any collateral repossessed may not be sufficient to repay the outstanding loan balance. In addition, loan collections are dependent on the borrower’s continuing financial stability and, thus, are more likely to be affected by current economic conditions and adverse business developments.

ASB has grown its national syndicated lending portfolio where ASB is a participant in credit facilities agented by established and reputable national lenders. Management selectively chooses each deal based on conservative credit criteria to ensure a high quality, well diversified portfolio.

Commercial real estate properties tend to be unique and are more difficult to value than residential real estate properties. Commercial real estate loans may not be fully amortizing, meaning 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, are 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 protection of bankruptcy laws, which could result in termination of the tenant’s lease.

In addition to the inherent risks of commercial and commercial real estate lending described above, the expansion of these new lines of business present execution risks, including the ability of ASB to attract personnel experienced in underwriting such loans and the 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,” “Electric utility” and “Bank” in Item 1. Business above.

ITEM 3. LEGAL PROCEEDINGS

HEI and HECO: HEI subsidiaries (including HECO and its subsidiaries and ASB) may be involved in ordinary routine PUC proceedings, environmental proceedings and/or litigation incidental to their respective businesses. See the descriptions of legal proceedings (including judicial proceedings and proceedings before the PUC and environmental and other administrative agencies) in “Item 1. Business,” in HEI’s MD&A and in the Notes 3 and 4 to HEI’s Consolidated Financial Statements. Management believes that, other than these proceedings, the likelihood that HEI or its subsidiaries would incur material losses or write-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 remote. Nevertheless, the outcomes of litigation and administrative proceedings are necessarily uncertain and there is a risk that the outcome of such matters could have a material adverse effect on the financial position, results of operations or liquidity of HEI or one or more of its subsidiaries for a particular 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 officers of HEI under SEC Rule 3b-7 promulgated under the 1934 Exchange Act. HEI executive officers serve from the date of their initial appointment until the annual meeting of the HEI Board (or applicable HEI 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. HEI executive officers may also hold offices with HEI subsidiaries and affiliates in addition to their current positions listed below.

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 President, Chief Financial Officer and Treasurer since 5/11 · HEI Senior Financial Vice President, Treasurer 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, General Counsel, Secretary and Chief Administrative Officer since 5/11 · HEI Senior Vice President, General Counsel, 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 executive officer and any other HEI executive officer or any HEI director or director nominee. There are no arrangements or understandings between any HEI executive officer and any other person pursuant to which such executive officer was selected.

PART II

ITEM 5. MARKET FOR REGISTRANTS’ COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

HEI:

Certain of the information required by this item is incorporated herein by reference to Note 13, “Regulatory restrictions on net assets” and Note 16, “Quarterly information (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 dividends and other distributions” and that description is incorporated herein by reference. HEI’s common stock 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 reflected 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 purchased 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 brokers 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 shares 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. Accordingly, 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 other restrictions on dividends or other 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.

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 **	18.3		x	18.7		x	23.0		x	20.7		x	22.1		x
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

* At 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 Discussion 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) under 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 earnings 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, for both unvested restricted stock awards and unrestricted common stock. For 2011, 2010, 2009, 2008 and 2007, under the two-class method of computing 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.

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 Industries, Inc.’s (HEI’s) consolidated financial statements and accompanying notes. 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 electric utility and banking sectors. HEI’s strategy is to build fundamental earnings and profitability of its electric utilities and bank in a controlled risk manner to support its current dividend and improve operating and capital efficiency 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 Electric 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 aggressive strategies to set both the 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 continued to make major progress on these strategies (see segment discussions below). Together, HEI’s unique combination 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 providing an attractive dividend 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 slightly higher losses for the “other” segment and the effects of the 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 increases and decoupling revenue adjustments. Key to results for 2012 will be the impacts of actions taken under the Hawaii Clean Energy Initiative (HCEI) and Energy Agreement, including the steps taken toward the integration of new generation from a variety of renewable energy sources into the utility systems, and managing O&M expenses to the levels included in rates.

ASB’s earnings in 2011 of $60 million increased $1 million over prior year 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 interest rate environment, the quality of ASB’s loan portfolio, and the ongoing results of the performance improvement project.

HEI’s “other” segment had a net loss in 2011 of $22 million, comparable to the net loss in 2010. HEI’s consolidated effective tax rate was 35% in 2011 compared to 37% in 2010. The decrease in the effective tax rate was due primarily to additional low income housing credits and tax-free income from municipal bonds and bank-owned life insurance at ASB, and a favorable IRS appeals settlement related to foreign losses at HEI in 2011.

Shareholder dividends are declared 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 indicated dividend yield as of December 31, 2011 was 4.7%. The dividend payout ratios 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, including but not limited to the Company’s results of operations, the long-term prospects for the Company, and current and expected future economic conditions.

HEI’s subsidiaries from time to time consider various strategies designed to enhance their competitive positions and to maximize shareholder value. These strategies may include the formation of new subsidiaries or the acquisition or disposition of businesses. The Company may from time to time be engaged in preliminary discussions, either internally or with third parties, regarding potential transactions. 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 third-party sources (e.g., Department of Business, Economic Development and Tourism (DBEDT); University of Hawaii Economic Research Organization (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 significant driver of Hawaii’s economy, maintained 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 rates remain higher year-over-year. The outlook for the visitor industry remains positive with the Hawaii Tourism 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 rate of 8.5% in December 2011. Hawaii’s unemployment rate has slowly worsened since June 2011 while the national 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 2011 median prices were 3% lower than 2010.

The price of a barrel of West Texas Intermediate (WTI) crude oil reached $113.93 on April 29, 2011, its highest level since 2008, but declined somewhat to average $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 international markets, have remained high, owing in part to the disruption occasioned by the tragic earthquake and tsunami in Japan in March 2011. The dramatic reduction in nuclear production has increased regional demand for oil and the utilities’ oil prices have remained consistently high for most of 2011.

The Federal Open Market Committee (FOMC) 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 through late 2014 based on the current economic outlook and continued its program announced in September 2011 to extend the average maturity of the System Open Market Account portfolio to support a stronger economic recovery.

Overall, Hawaii’s economy is expected to see only 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 Insurance 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 million for 2012, primarily attributable to the utilities. In addition, the 2010 Act provided for a 2% reduction in the Social Security tax on employees and self-employed individuals for 2011. The Temporary Payroll Tax Cut Continuation Act of 2011 extended this 2% reduction through February 29, 2012.

In December 2011, the Internal Revenue Service (IRS) issued temporary regulations, which provide a framework for determining whether expenditures are deductible as repairs. Although labeled “temporary,”

these regulations have the binding effect of final regulations and are effective January 1, 2012. The IRS is expected to issue additional revenue procedures containing 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		%

NMNot meaningful.

See “Executive overview and strategy” above and the “Other segment,” “Electric utility” and “Bank” sections below for discussions of results of operations.

Retirement benefits. The Company’s reported costs of providing retirement benefits are dependent upon numerous factors resulting from actual plan experience 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 provisions 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 expected to decrease ongoing costs through a reduction in service cost. (See Note 9 of HEI’s “Notes to Consolidated Financial Statements.”) Costs may also be significantly affected by changes in key actuarial assumptions, 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 also adjusted to account for the impact of decisions by the Public Utilities Commission of the State of Hawaii (PUC). Changes in obligations 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 remaining average service period of plan participants.

The assumptions used by management in making benefit 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 retirement benefit plans’ assets generated 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 the retirement benefit plans’ assets for both December 31, 2011 and 2010 was $983 million.

The Company intends to make contributions to the qualified retirement plan for HEI and HECO equal to the calculated net periodic pension cost for the year. However, if the minimum required contribution determined under the Employee Retirement Income Security Act of 1974 (ERISA), as amended by the Pension Protection Act of 2006, for the year is greater than the net periodic pension cost, then the Company

will contribute the minimum required contribution and the utilities’ difference between the minimum required contribution and the net periodic pension cost will increase 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 may not be applied against the ERISA minimum required contribution.

The ERISA minimum required contribution is expected 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 differ substantially from these estimates.

Based on various assumptions in Note 9 of HEI’s “Notes to Consolidated Financial Statements” and assuming no further changes in retirement benefit plan provisions, information regarding consolidated HEI’s, consolidated HECO’s and ASB’s retirement 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 projected benefit obligation (PBO) and accumulated postretirement benefit obligation (APBO) as of December 31, 2011, associated with a change in certain actuarial assumptions, were as follows and constitute “forward-looking statements.”

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)

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 utilities of pension and postretirement 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.

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.

NMNot meaningful.

The “other” business segment includes results of the stand-alone corporate operations of HEI and American Savings Holdings, Inc. (ASHI), both holding companies; HEI Properties, Inc. (HEIPI), a company holding passive, venture capital investments (venture capital investments valued at $0.6 million as of December 31, 2011); and The Old Oahu Tug Service, Inc. (TOOTS), a maritime freight transportation company that ceased operations in 1999, HEI Investments, Inc. (HEIII), a company previously holding investments in leveraged leases but whose wind-down was substantially completed during 2009; Pacific Energy Conservation Services, Inc. (PECS), a contract services company which provided windfarm operational and maintenance services to an affiliated electric utility until the windfarm 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 were $15 million in 2011 compared to $13 million in each of 2010 and 2009. In 2011, expense increased primarily due to the accrual of $3 million of contributions to be made to the HEI Charitable Foundation 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 dismantle a windfarm in 2010.

The “other” segment’s interest expenses were $22 million in 2011, $20 million 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 benefits 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 settlement 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 measured 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 operations. Inflation increases operating costs and the replacement cost of assets. Subsidiaries with significant physical assets, such as the electric utilities, replace assets at much higher costs and must request 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 Consolidated Financial Statements.”

Liquidity and capital resources.

Selected contractual obligations and commitments. Information about payments under the specified contractual obligations and commercial 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 liabilities1	$ 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 commitments, such as deferred taxes, trade payables, amounts that will become payable in future periods under collective bargaining and other employment agreements and employee benefit plans, obligations that may arise under indemnities provided to purchasers of discontinued operations and potential 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 retirement benefit plans did not exceed the retirement benefit plans’ benefit obligation. Minimum funding requirements for retirement benefit plans have not been included in the tables above; however, see “Retirement benefits” above for estimated minimum required contributions for 2012 and 2013.

See Note 3 of HEI’s “Notes to Consolidated Financial Statements” for a discussion of fuel and power purchase commitments.

The Company believes that its ability to generate cash, 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 expected retirement benefit plan contributions and other cash requirements 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.

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 line 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 credit 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—Liquidity 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 commercial 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 short-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 requirements, to repay long-term and short-term indebtedness and for other corporate purposes.

In November 2011, HEI filed an omnibus registration statement to register an indeterminate amount of debt and equity securities. Under Securities and Exchange 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 million 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 notes 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 customary representation and warranties, affirmative and negative covenants, and events of default (the occurrence of which may result in some or all of the notes then outstanding becoming immediately due and payable) and provisions requiring the maintenance by HEI of certain financial ratios generally consistent with those in HEI’s revolving noncollateralized credit 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 December 31, 2011, as calculated under the agreement) or “Consolidated Net Worth” of at least $975 million (Net Worth of $1.6 billion as of December 31, 2011, as calculated under the agreement). The Note Agreement also requires that HEI offer to prepay the Notes upon a change of control or certain dispositions of assets (as defined in the Note Agreement).

HEI has a line of credit facility of $125 million. See Note 7 of HEI’s “Notes to Consolidated Financial Statements.” The credit agreement, amended in December 2011, contains provisions for revised pricing in the event of a ratings change. For example, a ratings downgrade of HEI’s Issuer Rating (e.g., from BBB/Baa2 to

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 interest rate increase of 25 basis points on any drawn amounts. On the other 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 decrease of 25 basis points on any drawn amounts. The agreement contains customary conditions 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 the ability of the subsidiaries to pay dividends to, or to repay borrowings from, HEI). In addition to customary defaults, HEI’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, 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 December 31, 2011, as calculated under the agreement) and “Consolidated Net Worth” of at least $975 million (Net Worth 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 ability 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 analysis 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) ratings and stable outlook, indicating that the ratings reflect the relatively stable earnings and cash flow historically provided by its vertically integrated utility businesses and banking 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 ROE will approach authorized returns over time and (2) the expectation that profitability initiatives at ASB will produce fairly predictable 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 transformation contemplated under the HCEI, including all elements of the decoupling mechanism 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 March 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 (commercial paper) rating of “A-3”, stable outlook and “aggressive” financial profile. The stable outlook reflects S&P’s view that despite anticipated weaker cash flow metrics in 2012 and 2013, the consolidated credit profile will remain consistent 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 total debt to less than 10% and FFO interest 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 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 securities; such ratings may be subject to revision or withdrawal at any time by the rating agencies; and each rating should be evaluated independently of any other rating.

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 facility instead, and the costs of such borrowings could increase under the terms of the credit agreement as a result of any such ratings

downgrades. Similarly, if HEI’s long-term debt ratings were to be downgraded, it could be more difficult and/or expensive for HEI to issue long-term debt. Such limitations and/or increased 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 Industries Retirement Savings Plan (HEIRSP) and the ASB 401(k) Plan (which was split off from HEIRSP in 2009) provided new capital of $24 million (approximately 1.0 million shares) in 2011, $43 million (approximately 1.9 million shares) in 2010 and $32 million (approximately 2.0 million shares) in 2009. From April 16, 2009 through September 3, 2009 and from August 18, 2011 to December 31, 2011, HEI satisfied the share purchase requirements 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 investing activities was primarily due to purchases of investment and mortgage-related securities, HECO’s consolidated capital expenditures (net of contributions in aid of construction) and a net increase in loans held for investment, partly offset 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 increases in deposits and short-term borrowings and proceeds from the issuance of common stock under HEI plans, offset by the net decrease in long-term debt and other bank borrowings and the payment of common and preferred stock dividends. Other than capital contributions from their parent company, intercompany 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 restructuring 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 distributions 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 are not expected to significantly affect the operations of HEI, its ability to pay dividends on its common stock or its 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 investing 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’ construction programs (see “Electric utility–Liquidity and capital resources”), approximately $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, other medium- or long-term debt, common stock issued under Company plans and/or dividends from subsidiaries. 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 the construction of capital projects of the utilities, unanticipated utility capital expenditures that may be required by the HCEI or new environmental laws and regulations, unbudgeted acquisitions or investments in new businesses, significant increases in retirement benefit funding requirements and higher tax payments that would result if certain tax positions taken by the Company do not prevail or if taxes are increased by federal or state legislation. In addition, existing debt

may be refinanced prior to maturity (potentially at more favorable rates) with additional debt or equity financing (or both).

As further explained in “Retirement benefits” above and Notes 1 and 9 of HEI’s “Notes to Consolidated Financial Statements,” the Company maintains pension and other postretirement 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 the Pension Protection Act of 2006. The Company also made additional voluntary contributions to these plans in 2011, 2010 and 2009. Contributions to the retirement benefit plans totaled $75 million in 2011 (comprised of $73 million by the utilities, $2 million by HEI and nil by ASB), $32 million in 2010 and $25 million in 2009 and are expected to total $107 million in 2012 ($104 million by the utilities, $3 million by HEI 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 performance of the assets held in the plans’ trusts and numerous other factors, additional contributions may be required in the 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-balance sheet arrangements, management has determined that it has no off-balance sheet arrangements that either have, or are reasonably likely to have, a current or future effect on the Company’s financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures 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 market risk support to that entity for such assets,

(3) obligations under derivative 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 development 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 numerous factors, many of which are beyond its control and could cause future results of operations to differ materially from historical results. The following is a discussion of certain of these factors. Also see “Forward-Looking Statements” above and “Certain factors that may affect future results and financial condition” in each of the electric utility and bank segment discussions below.

Economic conditions, U.S. capital markets 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 results 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 tourism, by the impact of interest rates, particularly on the construction and real estate industries, and by the impact of world conditions 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 the Company, HEI’s and HECO’s ability to borrow and raise capital could be constrained and their future borrowing costs would likely increase.

pension cost and value obligations. The electric utilities’ 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 the Company’s pension plans and result in increases in future funding requirements.

Because the earnings of ASB depend primarily on net interest 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 rates on the electric utilities’ 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. HEI cannot predict future changes in interest rates, nor be certain that interest rate risk management strategies it or its subsidiaries have implemented will be successful in managing interest 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 increased. These disruptions negatively impacted the fair value of ASB’s investment portfolio in 2009. However, with the fourth quarter 2009 sale of ASB’s remaining private-issue mortgage-related securities portfolio and substantial residential loan production in 2009 and 2010, the Company’s exposure to credit and interest rate risks have been reduced.

Limited insurance. In the ordinary course of business, the 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 property damage or personal injuries. However, the protection provided by such insurance is limited in significant respects and, in some instances, the Company has no coverage. HECO, HELCO and MECO’s transmission and distribution systems (excluding substation buildings and contents) have a replacement value 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 business 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 maximum amounts that may be recovered. Insurers also have exclusions or limitations 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 available insurance were substantially exceeded, the Company could incur uninsured losses in amounts that would have a material 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 construction and operation of new facilities and the proper cleanup and disposal of hazardous waste and toxic substances. 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. Obtaining 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 affect the reported amounts of assets and liabilities, the 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 securities; property, plant and equipment; pension and other postretirement benefit obligations; contingencies and litigation; income taxes; regulatory assets and liabilities; electric utility revenues; and allowance for loan losses. Management considers an accounting

estimate to be material if it requires 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 operations or financial condition.

In accordance with SEC Release No. 33-8040, “Cautionary Advice Regarding Disclosure About Critical Accounting Policies,” management has identified 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 portrayal of the Company’s results of operations and financial condition, and currently require management’s most difficult, subjective or complex judgments. The policies affecting both of the Company’s two principal segments are discussed below and the policies affecting just one segment are discussed in the respective segment’s section of “Material estimates and critical accounting policies.” Management has reviewed the material estimates and critical accounting policies with the HEI Audit Committee and, as applicable, the HECO Audit Committee.

For additional discussion of the Company’s accounting 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 postretirement benefits obligations. For a discussion of material estimates related to pension and other postretirement benefits (collectively, retirement benefits), including costs, major assumptions, plan assets, other factors affecting costs, accumulated other comprehensive income (loss) (AOCI) charges and sensitivity analyses, see “Retirement benefits” in “Consolidated—Results of operations” above and Notes 1 and 9 of HEI’s “Notes to Consolidated Financial Statements.”

Contingencies and litigation. The Company is subject to proceedings (including PUC proceedings), lawsuits and other claims. Management assesses the likelihood of any adverse judgments in or outcomes of these matters as well as potential ranges of probable losses, including costs of investigation. A determination of the amount of reserves required, if any, for these contingencies is based on an analysis of each individual case or proceeding often with the assistance 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 contamination 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 capitalized if the costs extend the life, increase the capacity, or improve the safety or efficiency of property; the costs mitigate or prevent future environmental contamination; or the costs are incurred in preparing 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 are realized or settled. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible.

Management evaluates its potential exposures from tax positions taken that have or could be challenged by taxing authorities. These potential exposures result because taxing authorities may take positions that differ from those taken by management in the interpretation and application of statutes, regulations and rules. Management considers the possibility of alternative 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 for 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.

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 activities—modernizing and adding needed infrastructure through capital investment, placing emphasis on energy efficiency and conservation, pursuing renewable energy generation (including the use of biofuels) and taking 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 biodiesel fuel and has completed the first phase and is currently constructing the remaining phase of the East Oahu Transmission Project (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 to provide reliable power to customers. A three-pronged strategy supports attainment of the requirements and goals of the State of Hawaii Renewable Portfolio Standards (RPS), the Hawaii Global Warming 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 significant progress in implementing their clean energy strategies and the PUC issued several important regulatory 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 “Most recent rate proceedings” below). Additional PUC decisions are needed that will allow the utilities to recover 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 facilitate meeting the State’s goals to transition to a clean energy economy and achieve an aggressive renewable portfolio standard. The decoupling model implemented in Hawaii delinks revenues from sales and includes annual revenue adjustments 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 reduction of rates between rate cases in the event the utility exceeds the return on average common equity (ROACE) 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 existed 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 February 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 cover O&M requirements and rate base items not included in the RAMs.

Effective March 1, 2011, as part of the decoupling implementation, HECO established the RBA and started recording the difference between target revenues from its HECO 2009 rate case and actual revenues. Beginning June 1, 2011, HECO began accruing and collecting 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” below). Under the decoupling tariff

order, in future non-general rate case years, HECO will accrue and collect 7/12ths of the annual RAM adjusted revenues in one year and the remaining 5/12ths in the following year. HECO had expected to be able to accrue RAM-adjusted revenues from January 1 of each RAM period.

Also critical to improving earnings 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 regulatory 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 base growth. The utilities’ five-year 2012-2016 forecast reflects net capital expenditures of $3.0 billion and a compounded annual rate base growth rate of approximately 7% to 9%. Many of the major initiatives within this forecast are expected to be completed beyond the 5-year period. Major initiatives which comprise 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 the timing and technical requirements 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 PUC-allowed 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.

· 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 million) 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 costs, 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 includes 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 Transmission 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 rate 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 expense

· 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 costs, 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, including 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, including 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 management (DSM) program expenses) to maintain system reliability
(6)		Lower KWH sales
(8)		Lower allowance for funds used during construction (AFUDC)
27		Interim rate increases
6		Interest income due to a federal tax settlement

Most recent rate proceedings. The electric utilities initiate PUC proceedings 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 reliability. 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 increase is determined at the discretion 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 utility’s most recent rate cases, including the details of the increases requested, whether the utility and the Consumer Advocate reached a settlement that they proposed to the PUC, and the details of increases granted in interim and final PUC D&Os or whether an interim or final PUC D&O remains pending.


Test year	Date (applied/ imple- mented)	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 (2nd, 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 for the rate proceeding. All other line items reflect the effective 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 million less in annual revenues, HECO refunded $2.1 million to customers (including interest) in February 2011.

3 HECO filed a request with the PUC for a general rate increase of $113.5 million, based on a 2011 test year and without the then estimated impacts of the implementation of decoupling as proposed in the PUC’s separate decoupling proceeding and depreciation rates and methodology as proposed by HECO in a separate depreciation proceeding. Including the 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 major capital projects and higher O&M costs to maintain and improve service reliability and to recover the costs for several proposed programs to help reduce Hawaii’s dependence on imported oil, and to further increase reliability and fuel security.

The $53.2 million interim increase includes $15 million in annual revenues already being recovered through the decoupling RAM.

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

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

6 MECO's interim increase, effective August 1, 2010, was based on a stipulated agreement reached with the Consumer Advocate and temporary approval of new depreciation rates and methodology in a separate 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 MECO and the Consumer Advocate to submit a revised stipulated agreement by March 15, 2012 to provide them the opportunity to incorporate the applicable rulings and decisions in D&Os issued in related proceedings since the first stipulation was filed, including the final decoupling D&O, the final D&Os in the MECO 2007, HECO 2009, and HELCO 2010 test year rate cases

(including the findings related to ROACE with the implementation of decoupling), the interim D&O in the HECO 2011 test year rate case and the final D&O in MECO's depreciation proceeding.

7 MECO’s request is required to pay for O&M expenses and additional investments in plant and equipment required to maintain and improve system reliability and to cover the increased costs to support the integration of more renewable energy generation. The request is for an increase over rates 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 case, 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 testimony 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 total 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 Revenue Adjustment Mechanism (RAM). The interim increase is based on, and is substantially the same as, the increase proposed in the settlement 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 depreciation 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 did not approve the portion of the settlement agreement to allow deferral of certain costs amounting to approximately $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 findings and conclusions on the deferral of these costs. On November 30, 2011, the parties filed a joint motion to adjust the interim increase granted 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 increase the interim increase that became effective on July 26, 2011 by $5 million, to be effective March 1, 2012, based on the additional revenue requirements reflecting all remaining EOTP Phase 1 costs not previously included in rates or agreed to be written 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 expenses by $0.4 million in lieu of the PUC’s downward adjustments to the labor costs and employee benefits included in the interim D&O.

HELCO will file final revenue requirements, which will reflect the slightly lower depreciation rates and methodology approved in a separate depreciation proceeding. The heat rates (by fuel type) that establish the fuel efficiency targets will reflect the current complement of HELCO units, and the heat rate deadband will be implemented with the effective date of the final rates in this proceeding. HELCO expects the final annual revenue requirements may be slightly lower than the interim increase currently in effect due to factors such as the lower depreciation rates and the lower ROACE. HELCO 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 proceeding D&O when the final rates in this proceeding become effective.

Clean energy strategy. The utilities’ policy is to support efforts to increase renewable energy in Hawaii. The utilities believe their actions will help stabilize customer bills over time as they become less dependent on costly and price-volatile fossil fuel. The utilities’ clean energy strategy will also allow 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.

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 Pono-Ka’u LLC to supply 16 million gallons of biodiesel per year with initial consumption to begin by 2015. In September 2011, however, the PUC denied the utilities’ requested approval of the contract citing the higher cost of the biofuel over 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 the purchase of energy and capacity 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 initial increments expected to come on line in the 2015 and 2016 timeframes, respectively.

· In 2008, HECO issued an Oahu Renewable Energy 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 produce energy to be imported from Lanai and Molokai to Oahu via a yet-to-be-built undersea transmission cable 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, subject to PUC approval, with Pacific Biodiesel to supply at least 250,000 gallons of locally produced 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, subject 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, subject 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 biodiesel per year for CIP CT-1. If approved, 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.

Other regulatory matters. In addition to the items below, also see “Hawaii Clean Energy Initiative” and “Major projects” in Note 3 of HEI’s “Notes to Consolidated Financial Statements.”

Adequacy of supply.

HECO. In February 2011, HECO filed its 2011 Adequacy of Supply (AOS) 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 demands 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 capacity shortfalls if no more firm generating capacity is added to the system. Also, four existing generating units may be retired within the next 10 years because of their age or more stringent environmental regulations. 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 Venture. HELCO is currently negotiating with one independent power producer (IPP) to supply additional firm renewable generating 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 foreseeable future. HELCO, however, may choose to add additional renewable generating capacity to replace existing nonrenewable generation. 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 letter, which indicated that MECO’s generation capacity through 2014 is sufficient to meet the forecasted demands on the islands of Maui, Lanai and Molokai, but also stated that additional 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 December 31, 2014. Also, in January 2011, MECO filed a request to open a new docket related to MECO’s plan to proceed with a competitive bidding process to acquire up to approximately 50 MW of new, renewable firm dispatchable capacity generation resources on the island of Maui, with the initial increment expected 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 letter until March 2012. The additional 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. These revised forecasts may reduce HECO’s and MECO’s estimates of future firm generating capacity requirements.

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

Legislation and regulation. Congress and the Hawaii legislature periodically consider legislation that could have positive or negative effects on the utilities and their customers. Also see “Hawaii Clean Energy Initiative” and “Environmental regulation” in Note 3 of HEI’s “Notes 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 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 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 water heaters in residences constructed after January 1, 2010, but allows for limited variances in cases where installation of solar water heating is deemed inappropriate. The measure establishes standards for quality and performance of such systems. Also in

2008, a Hawaii law was enacted that is intended to facilitate the permitting of larger (200 MW or greater) renewable energy projects. The Energy Agreement includes several undertakings by the utilities to integrate solar energy into the electric grid.

In 2009, a bill became Hawaii law (Act 185) that authorizes 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 consideration in determining a just and reasonable rate for non-fossil fuel generated electricity. This will allow 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 authority to allow those electric utilities that aggregate their renewable portfolios to achieve the RPS (e.g., HECO, HELCO and MECO) to distribute the costs and expenses of renewable energy projects among those utilities. The bill also 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 energy 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 program with the Hawaii Department of Agriculture to encourage the production in Hawaii of energy feedstock (i.e., raw materials for biofuels).

In 2008, a Hawaii law was enacted that encourages the development of biofuels by authorizing the Hawaii Board of Land and Natural Resources to lease public lands to growers or producers 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 connect 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 environmental legislation and regulations, see “Environmental regulation” in Note 3 of HEI’s “Notes to Consolidated Financial Statements.” At this time, it is not possible to predict with certainty the impact of the foregoing legislation 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 Financial Statements.”

Recent accounting pronouncements. See “Recent accounting pronouncements and interpretations” in Note 1 of HEI’s “Notes to Consolidated Financial Statements.”

Liquidity and capital resources. Management believes that HECO’s ability, and that of its subsidiaries, to generate cash, both internally from operations and externally 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, retirement 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	%

HECO’s short-term borrowings (other than from HELCO and MECO), HECO’s line of credit facility, the principal amount of SPRBs that have been authorized by the Hawaii legislature for future issuance by the State of Hawaii Department of Budget and Finance (DBF) 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 borrowings1
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 commercial paper, its line of credit facility was undrawn, it had no borrowings from HEI and it had borrowings of $41 million and $9 million from HELCO and MECO, respectively.

HECO utilizes short-term debt, typically commercial paper, to support normal operations, to refinance short-term debt and for other temporary 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 statements. HECO and its subsidiaries periodically utilize long-term debt, historically borrowings of the proceeds of SPRBs issued by the DBF to finance the utilities’ capital improvement projects, or to repay short-term borrowings 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. See Note 7 of HEI’s “Notes to Consolidated Financial Statements.” The credit agreement, amended in December 2011, contains provisions for revised pricing in the event of a ratings change. For example, a ratings downgrade of HECO’s long-term rating (e.g., from BBB/Baa2 to BBB-/Baa3 by S&P and Moody’s, respectively) would result in a commitment fee increase of 5 basis points and an interest rate increase of 25 basis points on any drawn amounts. On the other 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 decrease of 25 basis points on any drawn amounts. The agreement contains customary conditions that must be met in order to draw on it, including compliance with several covenants (such as covenants preventing its subsidiaries from entering into agreements that restrict the ability of the subsidiaries to pay dividends to, or to repay borrowings from, HECO, 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 “Consolidated 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 defaults, 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, it

is an event of default if HECO fails to maintain a “Consolidated 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 the ability of HECO 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 (e.g., assessment of business risk that incorporates an analysis 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 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 framework being introduced, and a conservative financial management. Moody’s indicated the rating could be downgraded if the Hawaii PUC does not follow through with the regulatory transformation 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 sustainable 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 its long-term ratings for HECO, HELCO and MECO of “BBB-” and stable outlook. In addition, S&P maintained its “A-3” short-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 rate adjustment mechanisms, the utilities had yet to make meaningful strides in closing the significant 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 Capital 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

* 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 ratings 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 level equal to the higher of the rating of the guarantor (if rated at the investment grade level) or the published underlying rating. The insurance 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 tighten, it could be more difficult and/or expensive to sell commercial paper or secure other short-term borrowings. Similarly, 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 for DBF and/or the Company to sell SPRBs and other debt securities, respectively, for the benefit of the utilities in the future. Such limitations and/or increased costs could materially adversely affect the results of operations, financial condition and liquidity of HECO and its subsidiaries.

The PUC must approve issuances, if any, of equity and long-term debt securities 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 their repayment is the unsecured obligations 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, Financial 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 ratings of AAA and Aaa, respectively, based on the ratings at the time of issuance of the applicable 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 ratings 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 December 2010, HELCO and MECO sold $23 million and $3 million, respectively, of their common stock to HECO, and HECO sold $4 million of its common stock to HEI. In December 2011, HECO sold $40 million of its common stock to HEI.

On November 1, 2011, the PUC 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 (including repaying short-term indebtedness incurred to fund capital expenditures) and to repay $57.5 million of outstanding 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 and/or refunding SPRBs through December 31, 2012 to refinance certain series of outstanding SPRBs. The PUC also approved the use of the expedited approval procedure for the approval of additional refinancings by HECO, HELCO and MECO during the period 2013 through 2015, subject to certain conditions.

Operating activities provided $161 million in net cash during 2011. Investing activities used net cash of $202 million, primarily for capital expenditures, net of contributions in aid of construction. Financing activities used net cash of $33 million for the payment of common and preferred stock dividends of $73 million, partly offset by $40 million net proceeds from issuance of common stock.

For the five-year period 2012 through 2016, the utilities forecast $3.0 billion of net capital expenditures, approximately 38% of which is for transmission and distribution projects and 13% for generation projects, 10% for general plant and other projects, with the remaining 39% anticipated for major initiatives (including environmental compliance and infrastructure investments for fuel and to integrate renewables into the system), which could change with time based upon external factors, including timing and technical requirements for environmental compliance. HECO’s consolidated 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 preferred 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 required 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 the

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, cash 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 approximately $45 million for general plant and other projects. Consolidated net capital expenditures for HECO and subsidiaries 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 sales and peak load, the availability of purchased power and changes in expectations concerning the construction and ownership of future generation units, the availability of generating sites and transmission 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 Agreement, 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” above. The electric utilities were required to make contributions of $71 million for 2011 and $19 million for 2010, but 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 the Pension Protection Act of 2006. The electric utilities made additional voluntary contributions in 2011, 2010 and 2009. Contributions by the electric utilities to the retirement benefit plans for 2011, 2010 and 2009 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 than $1 million of benefits in 2009 and expect to pay less than $1 million of benefits in 2012. Depending on the performance of the assets held in the plans’ trusts and numerous other factors, additional contributions may be required in the future to meet the minimum funding requirements of ERISA or to pay benefits to plan participants. 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 that may affect future 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, including the extent of renewable 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 unsuccessful in negotiating purchased power agreements with such IPPs or if a major IPP fails to deliver the anticipated capacity in its purchased power agreement, could impact the utilities’ achievement of their commitments under the Energy Agreement and/or the utilities’ ability to deliver reliable service; (2) delays in acquiring 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 installed or does not operate effectively; (4) the likelihood that the utilities may need to make substantial investments in related infrastructure, 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 initiatives, which, if approved by the PUC, may have a material impact on the results of operations and financial condition of the utilities depending on their design and implementation. These initiatives include, but are not limited to, decoupling revenues from sales; implementing feed-in tariffs to

encourage development of renewable energy; removing the system-wide caps on net energy metering (but studying DG interconnections on a per-circuit basis); and developing an Energy Efficiency Portfolio Standard. Management cannot predict the ultimate impact or outcome of the implementation of these or other HCEI programs on the results of operations, financial condition and liquidity of the electric utilities.

Regulation of electric utility rates. The rates the electric utilities are allowed to charge for their services, and the timeliness of permitted rate increases, are among the most important items influencing their results of operations, financial condition and liquidity. The PUC has broad 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 reasonable, the potential consequences of exceeding or not meeting such returns, or any prolonged delay in rendering a decision in a rate or other proceeding could have a material adverse effect on the Company’s and HECO’s consolidated 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 filing a completed application if the evidentiary 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 pending or future rate cases will be rendered or the amount of any interim or final rate 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 the total net energy generated and purchased in 2011, 2010 and 2009.

Failure or delay by the electric utilities’ oil suppliers 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 materially adversely affecting the Company’s results of operations and financial condition. HECO generally maintains an average system fuel inventory level equivalent to 35 days of forward consumption. HELCO and MECO generally maintain an inventory level equivalent to one month’s supply of both medium sulfur fuel oil and diesel fuel. Some, but not all, of the electric utilities’ PPAs require that the IPPs maintain minimum fuel inventory levels and all of the firm capacity PPAs include provisions imposing substantial penalties for 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, when 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 electric utilities expect to incur costs to facilitate the safe, reliable integration of more renewables to the separate island 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 vary 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 higher than originally planned after full assessments of the repair work are performed. HECO’s implementation of decoupling mechanisms has mitigated some of the negative net income impact of rising other O&M expenses.

Other regulatory and permitting contingencies. Many public utility projects require PUC approval and various permits (e.g., environmental and land use permits) 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 written off in amounts that could have a material adverse effect on the Company. Two major capital improvement utility projects, the Keahole project (consisting of CT-4, CT-5 and ST-7) and the East Oahu Transmission Project, encountered opposition and were seriously delayed before being placed in service, with a writedown being required for both the Keahole and EOTP projects. See Note 3 of HEI’s “Notes to Consolidated Financial Statements” for a discussion of additional regulatory contingencies.

Competition. Although competition in the generation sector in Hawaii has been moderated by the scarcity of generation sites, various permitting processes 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 proceedings on two specific issues (competitive bidding and distributed generation (DG)) to move toward a more competitive electric industry environment under cost-based regulation.

Competitive bidding proceeding. In December 2006, the PUC issued 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 future generation resource or a block of generation resources unless the PUC finds bidding to be unsuitable; (2) the framework does not apply in certain situations identified in the framework; (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 project 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 bidding does not apply (due to waiver or exemption), the utility retains its traditional obligation to offer to purchase capacity and energy from a Qualifying Facility (QF) at avoided cost upon reasonable terms and conditions approved by the PUC.

Management cannot currently predict the ultimate effect of the framework on the ability of the utilities to acquire or build additional generating capacity in the future.

The utilities received approval for waivers from the competitive framework to negotiate modifications to existing PPAs that generate electricity from renewable resources. Also, certain renewable energy projects were “grandfathered” from the competitive bidding process. The PUC can also grant waivers on its own volition to renewable energy projects that are not exempt from the Competitive 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 market structure that assures DG is available 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 affirmed 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 development of a competitive market for customer-sited DG. The D&O allows the utility to provide DG services on a customer-owned site as a regulated service when (1) the DG resolves a legitimate 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 comparable 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 Health (DOH) and, in a limited number of cases, by the federal Environmental Protection Agency (EPA). The 2004 Hawaii State Legislature passed legislation that requires an environmental assessment for proposed waste-to-energy facilities, landfills, oil refineries, power-generating facilities greater than 5 MW and wastewater facilities, except individual wastewater systems. Meeting this requirement results in increased project costs.

The 1990 amendments to the Clean Air Act (CAA), changes 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 significant 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 the utilities’ facilities (e.g., Regional Haze Rule), if currently proposed legislation, rules 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 impact HECO’s steam generating 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 compliance costs are expected to be incurred as a result of the initiatives called for in the Energy Agreement, including permitting and siting costs for new facilities and testing and permitting costs related to changing 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 allowed 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 from renewable sources) may impact the electric utility’s future competitive position, results of operations, 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 reported at cost. Self-constructed electric utility plant includes engineering, supervision, and administrative and general costs, and an allowance for the cost of funds used during the construction period. These costs are recorded in construction 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. Upon the retirement or sale of electric utility plant, no gain or loss is recognized. The cost of the plant retired is charged to accumulated depreciation. Amounts collected from customers for cost of removal (expected 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 arrangements 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 the IPP and lease obligations needed to be recorded.

Management believes that the PUC will allow recovery of property, plant and equipment in its electric rates. If the PUC does not allow recovery of any such costs, the electric utility would 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 Statements” concerning costs of major projects 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 recognition of revenues, expenses, assets and liabilities.

Regulatory liabilities represent amounts collected from customers 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 rates is probable. As of December 31, 2011, the consolidated regulatory liabilities and regulatory assets of the utilities amounted to $315 million 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 HEI’s “Notes to Consolidated Financial Statements.”

Management continually assesses whether 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 existing as of the last rate case and rates 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 assumes continuation of the 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 criteria are no longer satisfied, the electric utilities expect that the regulatory 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, financial condition and liquidity may result if regulatory assets have to be charged to expense or if regulatory liabilities are required 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 customers. As of December 31, 2011, revenues applicable to energy consumed, but not yet billed to customers, amounted to $138 million.

Revenue amounts recorded pursuant to a PUC interim order are subject to refund, with interest, pending a final order. The rate schedules of the electric utilities include ECACs under which electric rates are adjusted for changes in the weighted-average price paid for fuel oil and certain 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 result 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 impact of applying accounting standards for consolidation to its relationships with IPPs with whom the utilities execute new PPAs or execute amendments of existing PPAs. A possible outcome of the analysis is that HECO or its subsidiaries may be found to meet the definition of a primary beneficiary of a VIE which finding may result in the consolidation of the IPP in HECO’s consolidated financial statements. The consolidation of IPPs could have a material effect on HECO’s consolidated financial statements, including the recognition of a significant amount of assets and liabilities, and, if such a consolidated IPP were operating at a loss and had insufficient 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.”

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 million. 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 reduction in asset size and a concomitant improvement in profitability and capital efficiency. ASB ended 2011 with assets of $4.9 billion and net income of $60 million, compared to assets of $4.8 billion as of December 31, 2010 and net income of $58 million in 2010. ASB improved its interest rate risk by selling substantially all of its salable fixed rate residential loan production during 2009 and a portion of its fixed 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 building core franchise value, ASB continues to develop and introduce new products and services in order to meet the needs of those markets. Additionally, the banking industry is constantly changing and ASB is making the investments in people and technology necessary to adapt and remain competitive. ASB’s ongoing challenge is to continue 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 impacted the new loan production rates and made it challenging to find investments with adequate risk-adjusted returns, which resulted in a negative impact 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.

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 Qualitative Disclosures about Market Risk”). ASB then employs strategies to limit the impact of changes in interest rates on net interest income. ASB’s key strategies include:

(1) attracting and retaining low-cost, core deposits, 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 duration or variable rate securities.

Although ASB’s loan quality improved in 2011, there are 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 delinquencies and losses, which were concentrated in the residential land portfolio and on the neighbor islands. The residential land portfolio has declined, which has enabled ASB to release some loan loss reserves on that portfolio. Although ASB’s provision for loan losses had decreased in 2011 compared to 2010, it is still at an elevated 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 outlook for the Hawaii economy 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 expected. Continued financial stress on ASB’s customers may result in higher levels of loan delinquencies and losses.

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 securities 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 primarily 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 result 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 income 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 income

· 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 the 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 securities 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 products, 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 experienced 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-related securities and other-than-temporary impairment (OTTI) charges in 2009
(4	)	Lower fee income on deposits as a result 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 improved 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 totaling 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 Financial Statements” for a discussion of guarantees and further information about ASB.

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.

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 primarily on net interest income, which is the difference between interest earned on earning assets and interest paid on costing liabilities. The current interest rate environment is impacted by disruptions in the financial markets and these conditions may have a negative impact on ASB’s net interest margin.

Loan originations and mortgage-related securities are 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 billion 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 classified 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 securing 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.

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 environment 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 allocation 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 reserves 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 issued by Federal National Mortgage Association (FNMA), Federal Home Loan Mortgage Corporation (FHLMC) or Government National Mortgage 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 securities issued by FNMA, FHLMC and GNMA are guaranteed by the issuer, and the securities carry implied AAA ratings.

The unrealized gains on ASB’s investment in federal 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 held to increase above the carrying book value. All contractual cash flows of those investments 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 its PMRS portfolio and had no OTTI as of December 31, 2009.

Deposits and other borrowings. Deposits continue to be the largest source of funds for ASB and are affected by market interest rates, competition and management’s responses to these factors. Deposit retention and growth will remain challenging in the current environment due to competition for deposits and the low level of short-term interest rates. Advances from the FHLB of Seattle 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 composition of ASB’s deposit liabilities and other borrowings.

Other factors. Interest rate risk is a significant 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 the fair value of those instruments, respectively. In addition, changes in credit spreads also impact 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 securities (including securities pledged for repurchase agreements) in AOCI of $10 million and $4 million, respectively. See “Quantitative and qualitative disclosures about market risk.”

Legislation and regulation. ASB is subject to extensive regulation, principally by the Office of the Comptroller of the Currency (OCC) and the Federal Deposit Insurance Corporation (FDIC). Depending on ASB’s level of regulatory capital and other 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 Corporation restoration plan” and “Deposit insurance coverage” in Note 4 of HEI’s “Notes to Consolidated Financial Statements.”

Dodd-Frank Wall Street Reform and Consumer 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 Dodd-Frank Act, which became law in July 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 generally 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 OCC. HEI will for the first 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 requires 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 institution level on the date the Act became effective, although there will be a phase-in period for meeting these standards. In addition, HEI will 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 should it fail to remain a qualified thrift lender.

More stringent affiliate transaction rules now apply to ASB in the securities lending, repurchase agreement and derivatives areas. Standards were raised with respect to the ability of ASB to merge with or acquire another institution. In reviewing a potential merger or acquisition, the 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. banking or financial system.”

The Dodd-Frank Act establishes a Consumer Financial 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 also be subject to new state regulation because of a provision in the Dodd-Frank Act.

ASB may also be subject to new state regulation because of a provision in the Dodd-Frank Act that acknowledges that a federal savings bank 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 a

discriminatory effect on the bank compared 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 state law is preempted by another federal law.

The Dodd-Frank Act also adopts a number of provisions 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 steps to ensure that consumers will have the capability to repay loans they may obtain, as well as provisions imposing new disclosure 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 consumer 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 processing costs incurred. In June 2011, the FRB issued a final rule establishing standards for debit card interchange fees and prohibiting network exclusivity arrangements and routing restrictions. Under the final rule, effective October 1, 2011, the maximum permissible interchange fee that an issuer may receive for an electronic 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 will exempt banks like ASB, that, along with their affiliates, have less than $10 billion in assets. However, market pressures could 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 regulation, or the application thereof.

Overdraft rules. On November 12, 2009, the Board of Governors of the Federal Reserve System announced that it amended Regulation E (which implements the Electronic Fund Transfer Act) to limit the ability of a financial institution to assess an overdraft fee for paying automated teller machine or one-time debit card transactions that overdraw a consumer’s account, unless the consumer affirmatively consents, or opts in, to the institution’s payment of overdrafts 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 originators employed by banks must register with the Nationwide Mortgage Lending System and Registry to obtain a unique identifier from the Registry, and maintain that registration. The initial period for this federal registration 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 only be redeemed at par. There is a minimum required investment in such stock based on measurements of ASB’s capital, assets and/or borrowing levels, and ASB’s investment is substantially in excess of that requirement. 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 Seattle 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 Stipulation 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 capital stock and begin paying dividends. ASB does not believe that the Consents will affect the FHLB of Seattle’s ability to meet ASB’s liquidity and funding needs. The FHLB of Seattle did not pay any cash dividends in 2009, 2010 or 2011.

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

Recent accounting pronouncements. See “Recent accounting pronouncements and interpretations” in Note 1 of HEI’s “Notes to Consolidated Financial Statements.”

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 ratios and healthy liquidity position that is supported by good core deposit funding. In December 2011, S&P affirmed ASB’s issuer credit ratings of BBB/Stable/A-2 based on strong capital and earnings, moderate risk position, above average funding 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 securities; such ratings may be subject to revision or withdrawal at any time by the rating agencies; and each rating should be evaluated independently of any other rating.

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 borrowings are advances from the FHLB and securities sold under agreements to repurchase from broker/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 qualifying collateral and holds sufficient FHLB 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 totaled $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 maturing 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 whose loan terms have been modified in troubled debt restructurings. Management believes ASB’s current sources of funds will enable 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, respectively. As of December 31, 2011 and 2010, ASB had $7.3 million and $4.3 million, respectively, of real estate acquired in settlement of loans.

In 2011, operating activities provided cash of $101 million. 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 offset by repayments of investment and mortgage-related securities and proceeds from the sale 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 regulatory 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 regulations 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 significantly higher than the rates offered by competing institutions. As of December 31, 2011, ASB was well-capitalized (see “Regulation—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 Financial Statements.”

Certain factors that may affect future results and financial condition. Also see “Forward-Looking Statements” and “Certain factors that may affect future results and financial condition” for Consolidated HEI above.

Competition. The banking industry in Hawaii is highly competitive. 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 smaller institutions that are heavily promoting 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 securities 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 operation and perceptions of the institution’s financial soundness and safety. To meet competition, ASB offers a variety of savings and checking accounts at competitive rates, convenient business hours, convenient 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 and 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 interest rates and loan fees it charges, the type of mortgage loan programs it offers and the efficiency and quality of the 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-spread, shorter-duration consumer, commercial and commercial real estate loans. The origination of consumer, commercial and commercial real estate loans involves risks and other considerations different from those associated with originating residential real estate loans. For example, the sources and level of competition 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 strategic sales of its private-issue mortgage-related securities in the fourth quarter of 2009, substantially all of its salable residential loan production during 2009 and a portion of its residential loan production in 2010 and 2011 helped to reduce its exposure to credit risk and interest rate risk.

Interest rate risk is a significant 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, resulting 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 environment persists, the potential for compression of ASB’s net interest margin will continue. ASB also manages the credit risk associated with its lending and securities portfolios, but a deep and prolonged recession led by a material decline in housing prices could materially impair the value of its portfolios. See “Quantitative 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 environmental risks and potential cleanup liability. In the event of default and foreclosure of a loan, ASB may become the owner of the mortgaged

property. For that reason, ASB seeks to avoid lending upon the security of, or acquiring through foreclosure, any property with significant potential environmental risks; however, there can be no assurance that ASB will successfully avoid all such environmental risks.

Regulation. ASB is subject to examination and comprehensive 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 these agencies focuses in large measure on the adequacy of ASB’s capital and the results of periodic “safety and soundness” examinations conducted by the OCC.

Capital requirements. The OCC, which is ASB’s principal regulator, administers two sets of capital standards—minimum regulatory capital requirements and prompt corrective action requirements. The FDIC also has prompt corrective action capital requirements. 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 and FDIC capital regulations, as follows:

· ASB met applicable minimum regulatory capital requirements (noted in parentheses) as of December 31, 2011 with a tangible capital ratio of 9.0% (1.5%), a core capital 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 leverage ratio of 9.0% (5.0%), a Tier-1 risk-based capital ratio of 11.9% (6.0%) and a total risk-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 stringent mandatory and discretionary regulatory consequences. Capital levels may decline for any number of reasons, including reductions that would result if there were losses from operations, deterioration in collateral values or the inability to dispose of real estate owned (such as by foreclosure). The regulators have substantial discretion in the corrective actions they might direct and could include restrictions on dividends and other distributions 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 could 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 “safety and soundness” examinations and other examinations by the OCC. In conducting its examinations, the OCC utilizes the Uniform Financial Institutions Rating System adopted by the Federal Financial Institutions Examination Council, which system utilizes the “CAMELS” criteria for rating financial institutions. The six components in the rating system are: Capital adequacy, Asset quality, Management, Earnings, Liquidity and Sensitivity to market risk. The OCC examines and rates each CAMELS component. An overall CAMELS rating is also given, after taking into account all of the component ratings. A financial institution may be subject to formal regulatory or administrative direction or supervision such as a “memorandum of understanding” 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 soundness examination or the component and overall CAMELS rating to any person or organization not officially connected with the institution 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 Reinvestment Act measurement criteria.

The Federal Deposit Insurance Act, as amended, addresses the safety and soundness of the deposit insurance system, supervision of depository institutions and improvement of accounting standards. Pursuant to this Act, federal banking agencies have promulgated regulations that affect the operations of ASB and its holding companies (e.g., standards for safety and soundness, 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 rates offered by competing institutions. As of December 31, 2011, ASB was “well-capitalized” and thus not subject to these restrictions.

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 maintain at least 65% of its assets in “qualified thrift investments,” which include housing-related loans (including mortgage-related securities) as well as certain small business loans, education loans, loans made through credit card accounts and a basket (not exceeding 20% of total assets) of other consumer loans and other assets. 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 restrictions if ASB failed to maintain its QTL status, and a failure or inability to comply with those restrictions could effectively result in the required divestiture of ASB. As of December 31, 2011, approximately 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 array of financial services. Although the Gramm Act further restricted the creation of so-called “unitary savings and loan holding companies” (i.e., companies 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 among 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 Act, any proposed sale of ASB would have to satisfy applicable statutory and regulatory requirements and potential acquirers of ASB would most likely be limited to companies that are already qualified 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 and 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 whether an investment security is temporarily or other-than-temporarily impaired as a critical accounting policy since the estimate is susceptible to significant change from period to period because it requires management to make significant judgments, assumptions and estimates in the preparation of its consolidated financial statements.

See “Investment and mortgage-related securities” in Note 1 of HEI’s “Notes to Consolidated Financial Statements” for a discussion of securities impairment assessment and other-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 market-based valuation techniques. The price of these securities is generally based on observable inputs, which includes market liquidity, credit considerations of the underlying collateral, the levels of interest rates, expectations of prepayments and defaults, limited investor base, market sector 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 that were received from the initial third party pricing service. If the pricing differential between the two pricing sources exceeds an established threshold, the security price will be re-evaluated by sending a re-pricing request to both independent 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 market place. The third party price selected 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.

Allowance for loan losses. See Note 1 of HEI’s “Notes to Consolidated Financial Statements” and the discussion above under “Earning assets, costing liabilities and other factors.” As of December 31, 2011, ASB’s allowance for loan losses was $37.9 million and 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 loan portfolio at any given point in time. A sensitivity analysis provides insight regarding the impact that adverse 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 category move to the 60-89 days delinquent category and 1% of the loans in the 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” category 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 factors considered in determining 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 the Hawaii economy or real estate market), 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 QUALITATIVE DISCLOSURES ABOUT MARKET RISK

HEI:

The Company manages various market risks in the ordinary course of business, including credit risk and liquidity risk. The Company believes the electric utility 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 issuers 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 functions in these lending areas and adequate allowance for loan losses. Credit risk associated with the securities portfolio is mitigated 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 sensitivity analysis. See “Allowance for loan losses” above.

Liquidity risk for ASB is the risk that the bank will not meet its obligations when they become due. Liquidity risk is mitigated by ASB’s asset/liability management process, on-going analytical analysis, monitoring and reporting information such as weekly cash-flow analyses and maintenance of liquidity contingency plans.

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 their rate schedules. The Company currently has no hedges against its commodity price risk. The Company currently has no exposure to market risk from trading activities nor foreign currency exchange rate risk.

The Company considers interest rate risk to be a very significant market risk as it could potentially have a significant effect on the Company’s results of operations, financial condition and liquidity, especially as it relates to ASB, but also as it may affect the discount rate used to determine retirement benefit liabilities, the market value of retirement benefit plans’ assets and the electric utilities’ allowed rates of return. Interest rate risk can be defined as the exposure of the Company’s earnings 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 mismatches 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 liabilities 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 preferences, and competition for loans or deposits.

ASB’s Asset/Liability Management Committee (ALCO), 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 Financial Statements” for a discussion of the use of rate lock commitments on loans held for sale and forward sale contracts to manage some interest rate risk associated with ASB’s residential 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 enhanced with a mortgage prepayment model and a collateralized mortgage obligation database. The simulation software is capable of generating scenario-specific cash flows for all instruments using the specified 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 twelve-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 period, in increments of +/- 100 basis points. The simulation model forecasts scenario-specific principal and interest 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, assumptions are made about the prepayment behavior of mortgage-related assets, future pricing spreads for new assets and liabilities, and the speed and magnitude with which deposit rates change in response to changes in the overall level of interest rates. 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) assessment, 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) replacing the OTS’ net portfolio value (NPV) ratio and

sensitivity measures. EVE is a similar measurement conceptually as NPV and represents the theoretical market value of ASB’s net worth and is defined as the present 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 contracts. Key assumptions used in the calculation of ASB’s EVE include the prepayment behavior of loans and investments, the possible distribution of future interest rates, pricing spreads for assets and liabilities in the alternate 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 current yield curve. Alternate 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 into the IRR profile, additional analysis is periodically performed in alternate scenarios including rate shifts of greater magnitude, yield curve twists and changes in key balance sheet drivers.

ASB’s interest-rate risk sensitivity measures as of December 31, 2011 and 2010 constitute “forward-looking 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 risk 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 fully 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 rising scenarios as of December 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, changes in core deposit assumptions and the large drop in rates during 2011, which shortened the duration of mortgage-related assets.

The computation of the prospective effects of hypothetical interest rate changes on the NII sensitivity and the percentage change in EVE is based on numerous assumptions, 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 twelve-month, pretax NII in alternate interest rate scenarios, and is intended to help management identify potential exposures in ASB’s current balance sheet and formulate appropriate strategies for managing interest rate risk. The simulation does not contemplate any actions that ASB management might undertake in response to changes in interest rates. Further, the changes in NII vary in the twelve-month simulation period and are not necessarily evenly distributed over the period. These analyses are for analytical purposes only and do not represent management’s views of future market movements, the level of future earnings, or the timing of any changes 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.

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 debt) and preferred securities. As of December 31, 2011, management believes the Company is exposed to “other than bank” interest rate risk because of its periodic borrowing requirements, 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 Financial Statements”) and the possible effect of interest rates on the electric utilities’ allowed rates of return (see “Electric utility—Certain factors that may affect future results and financial condition—Regulation of electric utility rates”). Other than these exposures, management believes its exposure to “other than bank” interest rate risk is not material. The Company’s longer-term debt, in the form of borrowings of proceeds of revenue bonds, registered Medium-Term Notes and privately-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 item is set forth in HECO’s Quantitative and Qualitative Disclosures about Market Risk, incorporated herein by reference to page 3 of HECO Exhibit 99.2.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

HEI:

Index to Consolidated Financial Statements

Page

Reports of Independent Registered Public Accounting Firms

Consolidated Financial Statements

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of
Hawaiian Electric Industries, Inc.:

In our opinion, the accompanying consolidated balance sheets as of December 31, 2011 and 2010 and the related consolidated statements of income, changes in shareholders’ 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, Inc. and its subsidiaries (the “Company”) at December 31, 2011 and 2010 and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2011 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal 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 statements, for maintaining effective internal 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 Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk 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 necessary 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 changed 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 financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted 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 disposition 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 effectiveness 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.

/s/ PricewaterhouseCoopers LLP

Los Angeles, California

February 17, 2012

Report of Independent Registered 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 subsidiaries for the year ended December 31, 2009. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial 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 Hawaiian 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, 2010

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.

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.

Consolidated Statements of Changes in Shareholders’ Equity

Hawaiian Electric Industries, Inc. and Subsidiaries

Common stock

Retained

Accumulated
other
comprehensive

(in thousands, except per share amounts)

Amount

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 recognition, 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 arising during the period, net of taxes of $8,543

–

12,938

Less: reclassification adjustment for net realized losses included in net income, net of tax benefits of $18,882

–

28,596

Retirement benefit plans:

Net transition asset arising during the period, net of taxes of $4,172

–

6,549

Prior service credit arising during the period, net of taxes of $921

–

1,446

Net gains arising during the period, net of taxes of $41,218

–

64,547

Less: amortization of transition obligation, prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits of $6,861

–

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 arising 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 during the period, net of taxes of $3,001

–

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 periodic benefit cost, net of tax benefits of $2,566

–

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

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 arising during the period, net of taxes of $4,343

–

6,578

Less: reclassification adjustment for 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

–

)

Less: reclassification adjustment to net income , net of tax benefits of $115

181

Retirement benefit plans:

Prior service credit arising during the period, net of taxes of $4,422

–

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 periodic benefit cost, net of tax benefits of $5,976

–

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

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 Retirement 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.

Consolidated Statements 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
Adjustments 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
Allowance 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
Available-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.

Notes to Consolidated Financial Statements

1 · Summary of significant accounting policies

General

Hawaiian Electric Industries, Inc. (HEI) is a holding 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 consolidated financial statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities and the reported amounts of revenues and expenses. Actual results could differ significantly from those estimates.

Consolidation. The consolidated financial statements include the 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 have been eliminated in consolidation.

See Note 5 for information regarding unconsolidated VIEs. In June 2009, the Financial Accounting Standards Board (FASB) issued a standard that eliminated exceptions to consolidating qualifying special-purpose entities, contained new criteria for determining the primary beneficiary, and increased the frequency of required reassessments to determine whether a company is the primary beneficiary of a VIE. The Company adopted this standard as of January 1, 2010 and the adoption did not impact the Company’s financial condition, results of operations or liquidity, 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 accounts, certificates of deposit, short-term commercial paper of non-affiliates, reverse repurchase agreements and liquid investments (with original maturities of three months or less) to be cash and cash equivalents.

Investment and mortgage-related securities. Debt securities that the Company intends to and has the ability to hold to maturity are classified as held-to-maturity securities 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-to-maturity or trading securities are classified 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, individual 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 value at the financial statement date. When a security is impaired, the Company determines whether this impairment is temporary or other-than-temporary. If the Company does not expect to recover the entire amortized cost basis of the 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 must be recognized in earnings. If the Company does not intend to sell the security and it is not more likely than not that the Company will be required to sell the security before recovery

of its amortized cost, the OTTI shall be separated into the amount representing the credit loss and the amount related to all other factors. The amount of OTTI related to the credit loss is recognized in earnings while the remaining OTTI is recognized in other comprehensive 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 amortized cost basis equal to the previous amortized cost basis less the OTTI recognized in earnings. The difference between the new amortized cost basis and the cash flows expected to be collected is accreted in accordance with existing applicable guidance as interest income. Any discount or reduced premium recorded for the security will be amortized 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 flows 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 method is used in determining realized gains and losses on the sales of securities. Discounts and premiums on investment securities are accreted or amortized over the remaining lives of the securities, adjusted for actual portfolio prepayments, using the interest method. Discounts and premiums on mortgage-related securities are accreted or amortized over the remaining lives of the securities, adjusted based on changes in anticipated prepayments, 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 policies and investments in unconsolidated subsidiaries (e.g. HECO Capital Trust III) are accounted 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-than-temporary impairment. Also see “Variable interest entities” below.

Property, plant and equipment. Property, plant and equipment are reported at cost. Self-constructed electric utility plant includes engineering, supervision, administrative and general costs and an allowance for the cost of funds used during the construction period. These costs are recorded in construction 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 capacity are also capitalized. Upon the retirement or sale of electric utility plant, generally no gain or loss is recognized. The cost of the plant retired is charged to accumulated depreciation. Amounts collected from customers for cost of removal (expected to exceed salvage value in the future) are included in regulatory liabilities.

Depreciation. Depreciation is computed primarily using the straight-line method over the estimated lives of the assets being depreciated. Electric utility plant additions in the current year are depreciated 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’ composite 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 and 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 Committee administering the Plans on the advice of an enrolled actuary. The participating employers contribute amounts to a master pension trust for the Plans in accordance with the funding requirements of the Employee Retirement Income Security Act of 1974, as

amended (ERISA), including changes promulgated by the Pension 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 mechanism 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 mechanism. Hawaii Electric Light Company, Inc. (HELCO) and Maui Electric Company, Limited (MECO) will generally fund the greater of the minimum level required under the law or net periodic pension cost. Future decisions in rate cases could further impact funding amounts.

Certain health care and/or life insurance benefits are provided to eligible retired employees and the employees’ beneficiaries and covered dependents. The 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 the 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 cases could further impact funding amounts.

The Company recognizes on its balance sheet the funded status of its defined 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 environmental 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 recovered in future rates, in which case such costs would be capitalized as regulatory assets. Also, environmental costs are capitalized if the costs extend the life, increase the capacity, or improve the safety or efficiency of property; the costs mitigate or prevent future environmental contamination; or the costs are incurred in preparing the property for sale. Environmental costs are either capitalized or charged to expense when environmental 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 the 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 term of the related debt. Unamortized financing costs and premiums or discounts on HECO and its subsidiaries’ long-term debt retired prior to maturity are classified as regulatory assets (costs and premiums) or liabilities (discounts) and are amortized on a straight-line basis over the remaining original term of the retired debt. The method and periods for amortizing financing costs, premiums and discounts, including the treatment of these items when long-term debt is retired 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-credit 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 assets and liabilities at federal and state tax rates expected to be in effect when such deferred tax assets or liabilities are realized or settled. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible.

Generally, federal and state investment tax credits are deferred and amortized over the estimated useful lives of the properties which qualified for the credits.

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 deferred 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” recognition threshold and measurement standard for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. As of December 31, 2011, the valuation allowance for deferred tax benefits is not significant.

Earnings per share. Basic earnings per share (EPS) is computed 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 include 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 antidilutive effect of stock appreciation rights (SARs) on 450,000 shares of common stock (for which the SARs’ exercise prices were greater than the closing market price of HEI’s common stock) was not included in the 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 assumption. See Note 10.

Impairment of long-lived assets and long-lived assets to be disposed of. The Company reviews long-lived 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. Recoverability 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 impairment 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 value, less costs to sell.

Recent accounting pronouncements and interpretations.

Repurchase agreements. In April 2011, the FASB issued Accounting Standards Update (ASU) No. 2011-03, “Transfers and Servicing (Topic 860): Reconsideration of Effective Control for Repurchase Agreements,” which is intended to improve the financial reporting of repurchase agreements 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 criterion requiring the transferor to have the ability to repurchase or redeem the financial assets. 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 IFRSs,” which represents the converged guidance of the FASB and the International Accounting Standards Board (the Boards) on fair value measurement. This ASU includes the Boards’ common requirements for measuring fair value and for disclosing information about fair value measurements, including a consistent meaning of the term “fair value.” The Boards have concluded the common requirements will result in greater comparability of fair value measurements presented and disclosed

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 condition 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 presented in either a single continuous statement of comprehensive income or in two separate, but consecutive, statements—a net income statement and a total comprehensive income statement.

The Company expects to retrospectively adopt this standard during the first quarter of 2012 using a two-statement approach.

Reclassifications. Certain reclassifications have been made to prior 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 the invoiced amount. The electric utilities generally assess a late payment charge on balances unpaid 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 income, based on its historical write-off experience. Account balances are charged off against the allowance after collection efforts have been exhausted and the potential for recovery is considered remote.

Contributions in aid of construction. The electric utilities receive contributions from customers for special construction requirements. As directed by the PUC, contributions 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 accounting period but not yet billed to the customers. Revenues related to the sale of energy are generally recorded 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 weighted-average price paid for fuel oil and certain components of purchased power, and the relative amounts of company-generated power and purchased power. The rate schedules of HECO include a purchased 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 Hawaii 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 payments to the taxing authorities are based on the prior years’ revenues. For 2011, 2010 and 2009, HECO and its subsidiaries included approximately $264 million, $211 million and $181 million, respectively, of revenue taxes in “operating revenues” and in “taxes, other than income taxes” expense.

Power purchase agreements. If a power purchase agreement (PPA) falls within the scope of Accounting Standards Codification (ASC) Topic 840, “Leases,” and results in the classification of the agreement as a capital lease, the electric utility would recognize a capital asset and a lease obligation. Currently, none of the PPAs are required to be recorded as a capital lease.

The utilities evaluate PPAs to determine if the PPAs are VIEs, if the utilities are primary beneficiaries and if consolidation is required. See Note 5.

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 construction are credited on the statement of income and charged to construction in progress on the balance sheet. 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 fees 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 direct loan origination costs) are deferred and recognized as an adjustment in yield over the life of the loan using the interest method or taken into income when the loan is paid off or sold. Nonrefundable commitment fees (net of direct loan origination costs, if applicable) received for commitments to originate or purchase loans are deferred and, if the commitment is exercised, recognized as an adjustment of yield over the life of the loan using the interest method. Nonrefundable commitment fees received for which the commitment expires unexercised 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 value is based on the fair value of the 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 allocated basis of the loans sold.

ASB capitalizes mortgage servicing assets or liabilities when the related loans are sold with servicing rights retained. Accounting for the servicing of financial assets requires that mortgage servicing assets or liabilities resulting from the sale or securitization of loans be initially measured at fair value at the date of transfer, and permits a class-by-class election between fair value and the lower 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 sale 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 servicing assets for impairment based on fair value at each reporting date. Such amortization is reflected as a component of revenues on the consolidated statements of income. The fair value of mortgage servicing assets, for the purposes of impairment, is calculated by discounting expected net income streams using discount rates that reflect industry pricing for similar assets. Expected net income streams are 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 associated 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, historical loss experience, changes in collateral values and current conditions (e.g., economic conditions, real estate market conditions and interest rate environment). Adverse changes in any of these factors could result in higher charge-offs and provision for loan losses.

Commercial and commercial real estate loans are defined as non-homogeneous loans and ASB utilizes a ten-point risk rating system for evaluating the credit quality of the loans. 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 are categorized into the regulatory asset quality classifications – Pass (Risk Rating 1 to 6), Special Mention (Risk Rating 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 net 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 the contractual terms of the loan agreement. Once a loan is deemed impaired, ASB applies a valuation methodology to determine whether there is an impairment shortfall. The measurement of impairment 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 collateral, net of costs to sell. For all loans collateralized by real estate whose repayment is dependent on the sale 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 future cash flows of the loans may also be used to measure impairment as these loans are expected to perform according to their restructured 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 charged off, with the loan written down by the amount of the confirmed loss.

Residential, consumer and credit scored business loans are considered homogeneous loans, which are typically underwritten based on common, uniform standards, and are generally classified 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 for loan loss allocations for these loan types uses historical loss ratio analyses based on actual net charge-offs. For residential loans, the loan portfolio is segmented by loan categories and geographic location within the State of Hawaii. 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. 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 considers 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 developments 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 impaired loans that are not accruing interest. While the majority of consumer loans are subject to ASB’s policies regarding nonaccrual loans, all past due unsecured

consumer loans may be charged off upon reaching a predetermined 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 may 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 differ from management’s estimates, and 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 financial difficulties, ASB makes certain concessions to the borrower that it would not otherwise consider. Modifications may include interest rate reductions, forbearance, and other actions intended to minimize economic loss and to provide alternatives to foreclosure or repossession of collateral. Generally, a nonaccrual loan that has been modified in a TDR remains on nonaccrual status until the borrower has demonstrated sustained repayment performance for a period of six consecutive months. However, performance prior to the modification, or significant events that coincide with the modification, are included in assessing whether the borrower can meet the new terms and may result in the loan being returned to accrual status 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 there is reasonable doubt over the full collectability of principal and interest, the loan remains on nonaccrual status.

Real estate acquired in settlement of loans. ASB records real estate acquired in settlement of loans at the lower of cost or fair value, less estimated selling expenses. ASB obtains appraisals based on recent comparable sales to assist management in estimating the fair value of real estate acquired in settlement of loans. Subsequent declines in value are charged to expense through a valuation allowance. 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, respectively, of real estate acquired 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 respective estimated useful lives to their estimated residual values, and reviewed for impairment in accordance with ASC 350, “Intangibles—Goodwill and other” (ASC 350).

Goodwill. At December 2011 and 2010, the amount of goodwill was $82.2 million, which is the Company’s only intangible asset with an indefinite useful life and is tested for impairment 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 likelihood 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-step goodwill impairment test. An entity has an unconditional option to bypass the qualitative assessment and proceed directly to performing the first step of the goodwill 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 relevant events and circumstances such as:

1. Macroeconomic conditions such as a deterioration in general economic conditions, limitations on accessing capital, or other developments in equity and credit markets;

2. Industry and market considerations such as a deterioration 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 effect 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 results of relevant prior periods;

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 carrying amount of its net assets;

7. If applicable, a sustained decrease in share price (consider 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 amount, 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 that the fair value of ASB was less than its carrying value. The most recent Step 1 goodwill impairment analysis under ASC 350 was performed as of September 30, 2010 and the estimated fair value of ASB exceeded its book value by 35%. For the three years 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

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 for mortgage servicing assets for 2012, 2013, 2014, 2015 and 2016 are $1.3 million, $1.1 million, $0.9 million, $0.8 million and $0.7 million, respectively.

ASB capitalizes mortgage servicing assets acquired through either the purchase 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 being serviced for others which increases the value of mortgage servicing assets, whereas declining interest rates typically result in faster prepayment speeds which decrease the value of mortgage servicing assets and increase the amortization of the mortgage servicing assets. In 2011, 2010 and 2009, mortgage servicing 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 amounted 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.

100

2 · Segment financial information

The electric utility and bank segments are strategic business units of the Company that offer different products and services and operate in different regulatory environments. The accounting policies of the segments are the same as those described 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 prices. Intersegment revenues consist primarily of interest, rent and preferred stock dividends.

Electric utility

HECO and its wholly-owned operating subsidiaries, HELCO and MECO, are public electric utilities in the business of generating, purchasing, transmitting, distributing 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 refining 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 Hawaii. ASB is subject to examination and comprehensive regulation by the Office of the Comptroller of the Currency (OCC) (previously 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 Board 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.

101

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 utilities 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 such sales is nominal and the elimination of electric sales revenues and expenses could distort segment operating income and net income for common stock.

Bank fees that ASB charges the electric utility and “other” segments are not eliminated because those segments would pay fees to another financial institution if they were to bank with another institution, the profit on such fees is nominal and the elimination of bank fee income and expenses could distort segment operating income and net income for common stock.

102

3 · Electric utility subsidiary

Selected financial information

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statements of Income Data

Years ended December 31	201	1	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		$ 79,446

103

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 980, “Regulated Operations,” HECO and its subsidiaries’ financial statements reflect assets, liabilities, revenues and expenses based on current cost-based rate-making regulations. Their continued accounting 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 rates can be charged to and collected 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 satisfied, the electric utilities expect that the regulatory 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, management believes that a material adverse 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 PUC-authorized periods. Generally, HECO and 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 liabilities represent amounts included in rates and collected from ratepayers for costs expected to be incurred in the future. 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 required to apply interest to certain 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.

104

Regulatory assets were as follows:

December 31	2011	2010
(in thousands)
Retirement benefit plans (balance primarily varies 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 relating to retirement benefit plans was created as a result of pension and OPEB tracking mechanisms adopted by the PUC in rate case decisions for HECO, MECO and HELCO in 2007 (see Note 9).

Cumulative preferred stock. The cumulative preferred stock of HECO 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 contractual agreements to purchase 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 animal fat feedstocks in the U.S. Midwest. Based on the average price per barrel as of December 31, 2011, the estimated cost of minimum purchases under the fuel supply contracts is $1.0 billion in 2012, $0.5 billion in 2013 and $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 subsidiaries purchased $1.3 billion, $1.0 billion and $0.7 billion of fuel under contractual agreements in 2011, 2010 and 2009, respectively.

HECO and Chevron Products Company (Chevron), a division of Chevron 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 supply contract (LSFO contract). The term of the amended agreement runs through April 30, 2013 and may automatically 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 amendment to the pricing formula in their fuel contract. The amendment could result in higher fuel prices for Kalaeloa, which would in turn increase the energy charge paid by HECO to Kalaeloa. HECO consented to the amendment on September 7, 2010.

105

The costs incurred under the utilities’ fuel contracts are included in their respective ECACs, to the extent such costs are not recovered through 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 capacity. Purchases from these six independent power producers (IPPs) and all other IPPs totaled $0.7 billion, $0.5 billion and $0.5 billion for 2011, 2010 and 2009, respectively. The PUC allows rate recovery for energy and firm capacity payments to IPPs under these agreements. Assuming that each of the agreements remains in place for its current term and the minimum availability criteria in the PPAs are met, aggregate minimum fixed 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 their payments under the PPAs upon available capacity and actually supplied energy and they are generally not required to make payments for capacity if the contracted capacity is not available, and payments are reduced, under certain conditions, if available capacity drops below contracted levels. In general, the payment rates for capacity have been predetermined for the terms of the agreements. Energy payments will vary 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. Title to the facilities does not pass to HECO or its subsidiaries upon expiration of the agreements, and the agreements do not contain bargain purchase 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 other 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 are 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 Hawaii (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, HELCO and MECO (collectively, the parties), signed an agreement setting forth goals and objectives under the HCEI 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 substantial increases in renewable energy and programs intended to secure greater energy efficiency and conservation. Many of the actions and programs included in the Energy Agreement require approval of the PUC.

Renewable energy projects. HECO and its subsidiaries continue to negotiate with developers of proposed projects to integrate power into its grid from a variety of renewable 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 the 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, including any required utility system connections or interfaces with the cable and the windfarm facility. In December 2009, the PUC allowed HECO to defer the costs of studies 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 studies 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 Oahu from any of the Hawaiian islands. In October 2011, HECO filed the draft RFP with the PUC. In November 2011, HECO and MECO filed their application to seek PUC approval to defer for later recovery approximately $0.6 million for additional studies to address whether an inter-island

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cable system that ties the Oahu, Maui, Molokai and Lanai electrical systems would be operationally beneficial and cost-effective.

Interim increases. As of December 31, 2011, HECO and its subsidiaries had recognized $40 million of revenues with respect to interim orders related to general rate increase requests. Revenue amounts recorded pursuant to interim orders are subject to refund, with interest, if they exceed amounts allowed in a final order.

Major projects. Many public utility projects require PUC approval and various permits from other governmental agencies. Difficulties in obtaining, or the inability to obtain, the necessary 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 probable the PUC will disallow 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 include those described below.

In May 2011, based upon recommendations by the Consumer Advocate in HECO’s 2009 test year rate case, the PUC ordered independently conducted regulatory audits on the reasonableness of costs incurred for HECO’s East Oahu Transmission Project (EOTP), Campbell Industrial Park (CIP) combustion turbine No. 1 (CT-1) project, and Customer Information System Project. The PUC confirmed that any revenue requirements arising from project costs being audited shall either remain interim and subject to refund until audit completion, or remain within regulatory deferral accounts. In the Interim D&O in the 2011 test year rate case, issued in July 2011, the PUC approved the portion of the settlement agreement 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 interim order in HECO’s 2011 test year 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 are completed and allowed the remaining project costs that were not deferred to be included in electric rates. For accounting purposes, HECO will recognize the equity portion of the carrying charge when it is allowed in electric rates. The PUC did not approve the agreement to defer expenses (subject to a limit to which the parties had agreed) associated with the yet-to-be completed Customer Information System. Pursuant to the PUC’s order in HECO’s 2009 test year rate case, HECO and the Consumer Advocate submitted proposals for the scope, timing, management and structure for the regulatory audits for the PUC’s review and consideration, however, the 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 million of AFUDC. HECO’s current rates reflect recovery of project costs of $163 million. See “Major projects” above regarding the regulatory audit process that must be completed in connection with determining recovery of the remaining costs for this project. Management believes no adjustment to project costs is required as of December 31, 2011.

East Oahu Transmission Project. HECO had planned a project to construct 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 using 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 whether 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 million of EOTP Phase 1 costs and related depreciation

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expense in determining revenue requirements. See “Major projects” above regarding the regulatory audit that is to be conducted before the PUC determines the recoverability of the remaining costs for EOTP Phase 1.

On February 3, 2012, HECO, the Consumer 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 costs. The parties agreed that, in lieu of a regulatory audit, HECO would write-off $9.5 million of gross plant in service costs associated with EOTP Phase 1, and associated adjustments in the accumulated depreciation, deferred depreciation expense, accumulated deferred income taxes, unamortized state investment tax credits and carrying charges. In deciding to enter into the agreement HECO took into account a number of considerations, including (1) the significant 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 regulatory 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 Information 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 March 1, 2012, based on additional revenue requirements reflecting all remaining EOTP costs not previously included in rates or agreed to be written 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 allows 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 Recovery 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 incurred costs for the Modified Phase 2 project 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 required 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 project 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 deferral period, amortize the 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 implementation 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 undergo a regulatory audit, which likely will not be planned until the CIS project is complete and the CIS is operational. Management believes no adjustment to CIS project costs is required as of December 31, 2011.

Environmental regulation. HECO and its subsidiaries are subject to environmental laws and regulations that regulate the operation of existing facilities, the construction and operation of new facilities and the proper cleanup and disposal of hazardous waste and toxic substances. 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 significantly and management anticipates that such activity will continue.

On April 20, 2011, the Federal Register published the federal Environmental Protection Agency’s (EPA’s) proposed regulations required by section 316(b) of the CWA designed to protect aquatic organisms from adverse impacts associated with existing power plant cooling water intake structures. The proposed regulations would apply to the cooling water systems for the steam generating units at the utilities’ Honolulu,

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Kahe and Waiau power plants on the island of Oahu. Although the proposed regulations provide some flexibility, management believes they do not adequately focus on site-specific conditions and cost-benefit factors and, if adopted as proposed, would require significant capital and annual O&M expenditures. As proposed, the regulations would require facilities to come into compliance within 8 years 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), applies to the 14 EGUs at HECO’s Honolulu, Kahe and Waiau power plants. MATS establishes the Maximum Achievable Control Technology standards for the control of hazardous air pollutants emissions from new and existing EGUs. The final rule is under review and a compliance plan and schedule are under development. Depending on the specifics of the compliance plan, MATS may require significant capital and annual expenditures 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 facilities may be granted two 1-year extensions to install emission control technology. In view of the isolated nature of HECO’s electrical system and the potential requirement to install control equipment on all HECO EGUs while maintaining system reliability, the MATS compliance schedule poses a significant challenge to HECO.

Depending upon the final outcome of the CWA 316(b) regulations, possible changes in CWA effluent standards, the specifics of the MATS compliance plan, the tightening of the National Ambient Air Quality Standards, and the Regional Haze rule under the CAA, HECO and its subsidiaries 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 earlier than anticipated.

HECO, HELCO and MECO, like other utilities, periodically experience petroleum or other chemical releases into the environment associated with current operations and report and take action on these releases when and as required by applicable law and regulations. Except as otherwise disclosed herein, HECO and its subsidiaries believe the costs of responding to their releases identified to date will not have a material adverse effect, individually or in the aggregate, on HECO’s consolidated results of operations, financial condition or liquidity.

Global climate change and greenhouse gas emissions reduction. National and international concern about climate change and the contribution 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 reduction 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 Agreement. Because the regulations implementing Act 234 have not yet been promulgated, management 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 monitor and report GHG emissions. The utilities’ reports for 2010 were submitted to the EPA. In December 2009, the EPA made the finding that motor vehicle GHG emissions endanger public health or welfare. Since then, the 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 may need to increase fees to cover the increased level of activity caused by this rule. Effective January 2, 2011, under the Prevention of Significant Deterioration program, permitting of

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new or modified stationary sources (such as utility electrical 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 January 2011, the EPA announced that it plans to defer, for three years, GHG permitting requirements for carbon dioxide (CO2) emissions from biomass-fired and other biogenic sources. The utilities are evaluating the impact of this deferral on their generation 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, burning renewable biodiesel in HECO’s CIP CT-1, using biodiesel for startup and shutdown of selected MECO generation units, and testing biofuel blends in other HECO and MECO generating units. Management is unable to evaluate the 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 electric utilities’ carbon footprint and meeting GHG reduction goals that will ultimately emerge.

While the timing, extent and ultimate effects of climate change cannot be determined with any certainty, climate change is predicted to result in sea level rise, which could potentially impact coastal and other low-lying areas (where much of the utilities’ electric infrastructure is sited), and could cause erosion of beaches, saltwater intrusion into aquifers and surface ecosystems, higher water tables and increased flooding and storm damage due to heavy rainfall. The effects of climate 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 the electric utilities. For example, severe weather could cause significant harm to the electric utilities’ physical facilities.

Asset retirement obligations. Asset retirement obligations (AROs) represent legal obligations associated with the retirement of certain tangible long-lived assets, are measured as the present value of the projected costs for the future retirement 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 subsidiaries’ 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 subsidiaries relate to obligations to retire plant and equipment, including removal of asbestos and other hazardous materials. In September 2009, HECO recorded an estimated ARO of $23 million related to removing retired 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 removal project. In August 2010, HECO recorded a similar estimated ARO of $12 million related to removing retired generating units at HECO’s Waiau power plant.

Changes to the ARO liability included in “Other liabilities” 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 International Brotherhood of Electrical Workers, AFL-CIO, Local 1260, which is the only union representing employees of the electric utilities. On March 11, 2011, the utilities’ bargaining unit employees ratified a new collective bargaining agreement and a new benefit agreement. The new collective bargaining agreement covers 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 contributions and changes to retirement benefits for employees.

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4 · Bank subsidiary

Selected financial information

American Savings Bank, F.S.B. and Subsidiaries

Consolidated Statements of Income Data

Years ended December 31	201	1	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 (includes $32,167 of other-than-temporary impairment losses, net of $16,723 of non-credit losses recognized in other comprehensive income, for 2009)	–		–	(15,444	)
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	$ 21,767

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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 National Mortgage Association (GNMA) and municipal bonds.

In the past, ASB owned private-issue mortgage-related securities (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 investment portfolio distribution was 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.

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which includes market liquidity, credit considerations of the underlying collateral, the levels of interest rates, expectations of prepayments and defaults, limited investor base, market sector 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 that were received from the initial third party pricing service. If the pricing differential between the two pricing sources exceeds an established threshold, the security price will be re-evaluated by sending a re-pricing request to both independent 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 market place. The third party price selected will be based on the value that best reflects the data and observable characteristics of the security.

December 31, 2011

Gross

Estimated

Gross unrealized losses

Amortized

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 contractual terms to maturity. Mortgage-related securities have contractual terms to maturity, but require periodic payments to reduce principal. In addition, expected maturities will differ from contractual maturities because borrowers have the right to prepay the underlying mortgages (see contractual maturities table below).

The contractual maturities of available-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 maturities (e.g. callable debentures and mortgage-related securities) are disclosed based upon the bond’s contractual maturity. Actual maturities will likely differ from these contractual maturities because borrowers may have the right to call or prepay obligations with or without call or prepayment penalties.

In 2011, 2010 and 2009, proceeds from sales of available-for-sale mortgage-related securities were $30.7 million, nil and $185.1 million, resulting in gross realized gains of $0.4 million, nil and $0.8 million and

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gross realized losses of nil, nil and $32.9 million, respectively. In 2011, proceeds 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, 2011 and 2010, respectively, as collateral for public funds deposits, automated clearinghouse transactions with Bank of Hawaii, and deposits in ASB’s bankruptcy and treasury, tax, and loan accounts 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 redeemed at par and it is a required investment based on measurements of ASB’s capital, assets and/or borrowing levels. Periodically and as conditions warrant, ASB reviews its investment in the stock of the FHLB of Seattle for impairment. ASB evaluated its investment in FHLB stock for OTTI as of December 31, 2011, consistent with its accounting 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 Seattle to make payments required by law 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 institutions 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 financial 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 these 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 recovering the amortized cost of the position was determined. If ASB’s intent is to hold positions determined to be other-than-temporarily impaired, credit losses, which are recognized in earnings, are quantified using the position’s pre-impairment discount rate and the net present value of cash flows expected to be collected from the security. Non-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 December 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 losses prior to March 31, 2009 and were subsequently recharacterized from retained earnings as a result of the adoption of new accounting standards

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for OTTI recognition effective April 1, 2009. Additions to this balance include new securities in which initial credit impairments have been identified and incremental increases of credit 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 commitments to originate loans, including the undisbursed portion of loans in process, approximated $95.4 million and $77.6 million, respectively. Commitments to extend credit are agreements to lend to a customer as long as there is no violation of any condition established in the commitments. Commitments generally have fixed expiration dates or other termination clauses and may require payment of a fee. Since certain of the commitments are expected to expire without being drawn upon, the total commitment amounts do not necessarily represent future cash requirements. ASB minimizes its exposure to loss under these commitments by requiring that customers meet certain 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 receivable, inventory and property, plant and equipment.

As of December 31, 2011 and 2010, ASB had commitments 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 interest 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 commitments on loans intended to be sold in the secondary market are derivative instruments, but have not been designated as hedges. Rate lock commitments are carried at fair value and adjustments are recorded in “Other income,” with 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 million, respectively. To offset the impact of changes in market interest rates on the rate lock commitments on loans held for sale, ASB utilizes short-term forward sale contracts. Forward sales contracts are also derivative instruments, 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, commercial and banker’s acceptance letters of credit totaled $10.8 million and $16.3 million, respectively. Letters of credit are conditional commitments issued by ASB to guarantee payment and performance of a customer to a third party. The credit risk involved in issuing letters of credit is essentially the same as that involved in extending loan facilities to customers. ASB holds collateral supporting those commitments for which collateral is deemed necessary. As of December 31, 2011 and 2010, undrawn consumer lines of credit, including credit cards, totaled

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$943.1 million and $856.7 million, respectively, 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 billion as of December 31, 2011, 2010 and 2009, respectively), which are not included 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 servicing costs to expense as incurred.

As of December 31, 2011 and 2010, ASB had pledged loans with an amortized cost of approximately $1.1 billion and $1.4 billion, respectively, as collateral to secure advances from the FHLB of Seattle.

As of December 31, 2011 and 2010, the aggregate amount of loans to directors and executive officers of ASB and its affiliates and any related interests (as defined in Federal Reserve Board (FRB) Regulation O) of such individuals, was $62.1 million 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 million. 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 loans 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 associated 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 are loans that are typically underwritten based on common, uniform standards, and are generally classified as to the level of loss exposure based on delinquency status. Commercial loans and commercial real estate (CRE) loans are defined as non-homogeneous loans and ASB utilitizes a uniform ten–point risk rating system for evaluating 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 than just delinquency performance.

In the second level of segmentation, the loan portfolios are further stratified into individual products with common risk characteristics. For residential 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. For commercial loans, the portfolio is differentiated by separating Commercial & Industrial (C&I) loans and C&I loans guaranteed by Small Business 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, loans are categorized into the regulatory asset quality classifications – Pass, Substandard, and Loss for homogeneous loans based primarily 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 that 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. Generally, impairment amounts derived under this method are immediately charged off.

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Consumer. The consumer loan portfolio specific allocation 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 determined 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 qualitative factor considerations.

Commercial and CRE. Pooled allocation for pass, special mention, substandard, and doubtful grade commercial and CRE loans that share common risk characteristics and properties are determined using a historical loss rate analysis and qualitative 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 losses inherent in the current portfolio. To estimate the level of adjustments, management considers factors including levels and trends in problem loans, volume and term of loans, changes in risk from changes in lending policies and practices, management expertise, economic conditions, industry trends, and the effect of credit concentrations.

Unallocated allowance. ASB’s allowance incorporates an unallocated 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 precision of the estimation process. These risk factors, in addition to micro- and macro- economic factors, past, current and anticipated 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.

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The allowance for loan losses was comprised of the following:

	Residential		Commercial real	Home equity line	Residential		Commercial	Residential		Commercial		Consumer
(in thousands)	1-4 family		estate	of credit	land		construction	construction		loans		loans		Unallocated		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 credit quality problems so that appropriate 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 determine 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, operating cash flow, debt service capacity, asset and liability structure,

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competitive issues, experience and quality of management, financial 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	$965

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The credit risk profile based on nonaccrual loans and accruing 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 principal balance of impaired loans was as follows:

December 31	2011					2010
(in thousands)	Recorded investment	Unpaid principal balance	Related Allowance	Average recorded investment	Interest income recognized	Recorded investment	Unpaid principal balance	Related allowance	Average 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	$5,286

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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 difficulty. 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 status 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 demonstrated both the willingness and the ability to handle the modified terms. TDR loans are considered an alternative 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 payments, 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 principal 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 payment 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 the same or higher interest rate. Commercial loan modifications generally involve extensions of maturity dates, amendment or waiver of financial covenants, and to a lesser extent temporary deferral of principal payments. ASB does not reduce the interest rate on commercial loan TDR modifications. Occasionally, additional collateral and/or guaranties are obtained.

All TDR loans are classified impaired and are segregated and reviewed separately when assessing the adequacy of the allowance for loan losses based on the appropriate method of measuring impairment: (1) present value of expected future cash flows discounted at the loan’s original effective interest rate, (2) fair value of collateral less costs to sell, or (3) observable market price. The financial 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 thereof are uncollectible (confirmed 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	$1,327

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The residential land loan TDR that subsequently defaulted 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 accounts of $100,000 or more totaled $119 million and $153 million, respectively.

The approximate amounts of term certificates outstanding as of December 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 repurchase with a rate of 4.75% and maturity date over 90 days is callable quarterly at par until maturity.

The securities underlying the agreements to repurchase 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 accounted for as financing transactions and the obligations to repurchase these securities are recorded as liabilities in the consolidated balance sheets. The securities underlying the agreements to repurchase continue to be reflected in ASB’s asset accounts.

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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 Advances, Security and Deposit Agreement (Advances Agreement), which applies to currently outstanding and future advances, and governs the terms and conditions under which ASB borrows and the FHLB of Seattle makes loans or advances 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 occurrence 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 Advances Agreement or other credit arrangements between the parties), the FHLB of Seattle may, at its option, declare all indebtedness and accrued interest thereon, including any prepayment fees or charges, to be immediately due and payable. Advances from the FHLB of Seattle are collateralized by loans and stock in the FHLB of Seattle. ASB is required to obtain and hold a specific number of shares of capital stock of the FHLB of Seattle. ASB was in compliance with all Advances Agreement requirements as of December 31, 2011 and 2010.

Common stock equity. In 1988, HEI agreed with the OTS predecessor regulatory agency at the time, to contribute additional capital to ASB up to a maximum aggregate amount of approximately $65.1 million (Capital Maintenance Agreement). As of December 31, 2011, as a result of capital contributions in prior years, HEI’s maximum obligation to contribute additional capital 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 distributed 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 result of a restructuring of Visa U.S.A. Inc. in preparation 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 arising from any potential adverse judgment or negotiated settlements related to indemnified litigation involving Visa. As of December 31, 2011, ASB had accrued $1.1 million related to the agreement. Because the extent of ASB’s obligations under this agreement depends

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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 Corporation (FDIC) approved a restoration plan that required banks to prepay, by December 30, 2009, their estimated quarterly, risk-based assessments for 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 risk-based premium schedule adopted earlier in 2009. The prepaid assessment rate for 2011 and 2012 was the current 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 exhausted, 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 change 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 financial 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 level 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 Act permanently raised the current standard maximum deposit insurance amount to $250,000. Previously, the standard maximum deposit insurance amount of $100,000 had been temporarily raised to $250,000 through December 31, 2013.

Litigation. In March 2011, a purported class action lawsuit was filed in the First Circuit Court of the state of Hawaii by a customer who claimed that ASB had improperly charged overdraft 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 reasonably possible loss are not determinable.

ASB is subject in the normal course of business 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 position. However, ASB cannot rule 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 (Trust 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 aggregate liquidation preference) to the public and trust common securities ($1.5 million aggregate liquidation preference) to HECO, (ii) investing 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 mandatorily 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 the obligations of HECO, HELCO and MECO under an expense agreement and HECO’s obligations under its trust guarantee and its guarantee of

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the obligations of HELCO and MECO under their respective debentures, are the sole assets of Trust III. Trust III has at all times been an unconsolidated subsidiary 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 accounting 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 million of trust common securities. Trust III’s income statement for 2011 consisted of $3.4 million of interest income received from the 2004 Debentures; $3.3 million of distributions to holders of the Trust Preferred Securities; and $0.1 million of common dividends on the trust common securities to HECO. So long as the 2004 Trust Preferred Securities are outstanding, HECO is not entitled to receive any funds from Trust III other than pro-rata distributions, 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 Guarantees, or in the event HECO, HELCO or MECO elect to defer payment of interest on any of their respective 2004 Debentures, 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 purchases from AES Hawaii, Kalaeloa, HEP and HPOWER totaling $133 million, $310 million, $59 million and $62 million, respectively.

Some of the IPPs provided sufficient information for HECO to determine that the IPP was not a VIE, or was either a “business” or “governmental organization” (e.g., HPOWER), 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 applicability of accounting standards for VIEs.

Since 2004, HECO has continued its efforts to obtain from the IPPs the 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 required information. All of these IPPs declined to provide the necessary information, except that Kalaeloa provided the information pursuant to the amendments to its PPA (see below) and an entity owning a wind farm provided 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 interests in the entities because the PPAs do not require them to absorb any variability of the entities.

If the requested information is ultimately received from the remaining IPPs, a possible outcome of future analyses of such information is the consolidation of one or more of such IPPs in HECO’s consolidated financial statements. The consolidation of any significant IPP could have a material effect on the Company’s and HECO’s consolidated financial statements, including the recognition of a significant amount of assets and liabilities and, if such a consolidated IPP were operating at a loss and had insufficient equity, the potential recognition of such losses. If HECO and its subsidiaries determine they are 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, HECO and Kalaeloa entered into 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.

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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 Utility Regulatory Policies Act of 1978.

Pursuant to the current accounting standards for VIEs, HECO is deemed to have 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 consolidated 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 the PPA as compared to the facility’s remaining useful life. Although HECO absorbs fuel price variability for the remaining term of the PPA, the PPA does not currently expose HECO to losses as the fuel and fuel related energy payments 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 better 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 the notional amount over a five-year period. The outstanding FSS were designated and accounted for as cash flow hedges and had a negative fair value of $2.8 million as of December 31, 2010 (recorded in “Other” liabilities). Changes in fair value 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 other bank borrowings” for any portion considered ineffective.

In 2011, HEI settled the FSS for payments totaling $5.2 million, of which $3.3 million was the ineffective portion ($0.8 million and $2.5 million recognized in 2010 and 2011, respectively) and $1.9 million being amortized to interest expense over five years beginning 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 maintained 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 facilities are collateralized.

Credit agreements. Effective December 5, 2011, HEI and a syndicate of eight financial institutions entered into an amendment to their revolving unsecured credit agreement. The amendment revised the pricing of HEI’s $125 million line of credit facility (with a letter of credit sub-facility) and extended the term of the facility to 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 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 affect 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 order to draw on it, including compliance with its covenants.

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The facility will be maintained to support the issuance of commercial paper, but also may be drawn to repay HEI’s short-term and long-term indebtedness, to make 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 agreement. The amendment revised the pricing of HECO’s $175 million line of credit facility (with 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 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 affect 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 order to draw on it, including compliance 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 million in 2013, $111 million in 2014, nil in 2015 and $75 million in 2016.

9 · Retirement benefits

Defined benefit plans. Substantially all of the employees of HEI and the electric utilities participate in the Retirement Plan for Employees of Hawaiian Electric Industries, Inc. and Participating 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) until it was frozen on December 31, 2007. The HEI/HECO Pension Plan and the ASB Pension Plan (collectively, the Plans) are qualified, noncontributory defined benefit

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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 former executives and directors of HEI and its subsidiaries participate in noncontributory, nonqualified plans (collectively, Supplemental Plans). In general, benefits are based on the employees’ or directors’ years of service and compensation.

The continuation of the Plans and the Supplemental Plans and the payment of any contribution thereunder are not assumed as contractual obligations by the participating employers. The Supplemental Plan for directors has been frozen since 1996. The ASB Pension Plan was frozen as of December 31, 2007. The HEI Supplemental Executive Retirement Plan and ASB Supplemental Executive Retirement, Disability, and Death Benefit Plan (noncontributory, nonqualified, defined benefit plans) were frozen as of December 31, 2008. No participants have accrued any benefits under these plans after the respective plan’s freeze and the plans will be terminated at the time all remaining benefits have been paid.

Each participating employer reserves the right to terminate its participation in the applicable plans at any time, and HEI and ASB reserve the right to terminate their 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 the termination of the Plans, assets would be distributed to affected participants in accordance with the applicable allocation provisions of ERISA and any excess assets that exist would be paid to the participating employers. Participants’ benefits in the Plans are covered up to certain limits under insurance provided by the Pension Benefit Guaranty Corporation.

To determine pension costs for HEI and its subsidiaries under the Plans and the Supplemental Plans, it is necessary to make complex calculations and estimates based on numerous assumptions, including the assumptions identified below.

Postretirement benefits other than pensions. HEI and the electric utilities provide eligible employees health and life insurance benefits upon retirement under the Postretirement Welfare Benefits Plan for Employees of Hawaiian Electric Company, Inc. and participating employers (HECO Benefits Plan). Eligibility of employees and dependents are based on eligibility to retire at termination, the retirement date and the date of hire. The plan was amended in 2011, changing eligibility for certain bargaining unit employees hired prior to May 1, 2011, based on new minimum age and service requirements effective January 1, 2012, per the collective bargaining agreement, and certain management employees hired prior to May 1, 2011 based on new eligibility minimum age and service requirements effective January 1, 2012. The minimum age and service requirements for management and bargaining 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/HECO Pension Plan but may not be eligible for postretirement welfare benefits if the different eligibility requirements are not met.

The executive death benefit plan was frozen on September 10, 2009 to participants and benefit levels as of that date. The electric discount was eliminated for management employees 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 bargaining agreement. The Company’s cost for OPEB has been adjusted to reflect the plan amendment, which reduced benefits. The elimination of the electric discount benefit will generate credits through other benefit costs over the next few years as the total amendment credit is amortized.

Each participating employer reserves the right to terminate its participation 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 status of defined benefit pension and other postretirement benefit plans with an offset to AOCI in shareholders’ equity (using the projected benefit obligation (PBO), to calculate the funded status).

The PUC allowed the utilities to adopt pension and OPEB tracking mechanisms in recent 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 mechanisms, any actual costs determined in accordance with U.S. generally accepted accounting principles that are over/under amounts

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allowed in rates are charged/credited to a regulatory asset/liability. The regulatory asset/liability for each utility will then be amortized over 5 years beginning with the respective utility’s next rate case. Accordingly, all retirement benefit expenses (except for executive life and nonqualified pension plan expenses, which amounted to $1.6 million in 2011) determined in accordance with U.S. generally accepted accounting principles will be recovered.

Under the tracking mechanisms, amounts that would otherwise be recorded in AOCI (excluding amounts for executive life and nonqualified pension plans), which amounts include the prepaid pension asset, net of taxes, as well as other pension and OPEB 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 asset charges for retirement benefits that would otherwise be recorded in AOCI (amounting to the elimination of a potential 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 regulatory asset in the amount of $12.8 million (representing HELCO’s prepaid pension asset and reflecting the accumulated pension contributions to its pension fund in excess of accumulated NPPC), which is included in rate base, and allowed recovery of that asset over a period of five years. HELCO is required to make contributions to the pension trust 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 their pension fund in excess of accumulated NPPC), in their rate bases. However, under the tracking mechanisms, HECO and MECO are required to fund only the minimum level required under the law until their pension assets are reduced 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 requirements or the maximum contribution limitations on deductible contributions imposed by the Internal Revenue Code.

The PUC’s exclusion of HECO’s and MECO’s pension 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 rates. 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 actuarially calculated NPBC, except when limited by material, adverse consequences imposed by federal regulations.

Retirement benefits expense for the electric 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 retirement 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 elective deferrals by such employees through the defined contribution plan (under the Hawaiian Electric Industries Retirement Savings Plan (HEIRSP)). In addition, new eligibility rules and contribution levels applicable to existing and new HEI and utility employees were adopted for postretirement welfare benefits. In general, defined pension benefits are based on the employees’ years of service and compensation.

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Defined benefit and pension and other postretirement benefit plans information. The changes in the obligations and assets of the Company’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 December 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 gains (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 defined 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 aggregate 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 pension 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 estimated 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 sum distribution option and a Social Security level income option) under the HEI Retirement Plan became 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 restrictions are expected to continue through 2012.

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The Company estimates that the cash funding for the qualified defined benefit 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 requirements of the utilities pension tracking mechanisms and the Plan’s funding policy. The Company’s current estimate of contributions to the qualified defined benefit plans and all other retirement benefit plans in 2012 is $107 million.

As of December 31, 2011, the benefits expected to be paid under the retirement 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 the 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 amount outside the range will be recognized immediately in the calculation of annual NPBC.

A primary goal of the plans is to achieve long-term asset growth sufficient to pay future benefit obligations at a reasonable level of risk. The investment 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 defined 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 were 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 discount rate for 2012 NPBC and December 31, 2011 disclosure on a cash flow matching analysis that utilized 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 for 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 rates for 2011 and future years were as follows: medical, 9%, grading down to 5% for 2019 and thereafter; dental, 5%; and vision, 4%.

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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 obligation for defined benefit pension plans that will be amortized from AOCI or regulatory assets into net periodic pension benefit cost during 2012 are $(0.3) million, $25.7million and de minimis, respectively. The estimated prior service cost (gain), net actuarial loss and net transitional obligation for other benefit plans that will be amortized from AOCI or regulatory assets into net periodic other than pension benefit cost during 2012 are $(1.8) million, $1.8 million and nil, respectively.

The Company recorded pension expense of $32 million, $32 million and $27 million 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 million, 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 sharing contribution (AmeriShare).

Changes to retirement benefits for HEI and utility employees commencing employment after April 30, 2011 include a reduction of benefits provided through the defined benefit plan 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 Retirement Savings Plan).

For 2011, 2010 and 2009, the Company’s expense for its defined contribution pension 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.

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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 stock units, performance shares 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 the EIP as four shares for 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 every share issued when issued 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 common stock (based on various assumptions, including LTIP awards at maximum levels and the use of the December 31, 2011 market price of shares as the price on the exercise/payment dates) were outstanding 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 SOIP. 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 stock 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 accordance 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 the grant date and are forfeited to the extent they have not become unrestricted for terminations of employment during the vesting period, except accelerated vesting is provided for terminations by reason of death, disability and termination without cause. Restricted stock awards under the SOIP generally become unrestricted four years after the date of grant and are forfeited for terminations of employment during the vesting period, except that pro-rata vesting is provided for terminations by reason of death, disability or termination without cause. Restricted shares and restricted stock awards compensation expense has been recognized in accordance with the fair-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 anniversaries of the grant date and are forfeited to the extent they have not become vested for terminations of employment during the vesting period, except that pro-rata vesting is provided for terminations due to death, disability and retirement. Restricted 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 vesting period, except that pro-rata vesting is provided for terminations due to death, disability and retirement. Restricted stock units expense has been recognized in accordance with the fair-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 the 2009-2011, 2010-2012 and 2011-2013 LTIPs entitle the grantee to shares of common stock with dividend equivalent 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 the performance period, except that pro-rata participation is provided for terminations due to death, disability and retirement based upon completed months of service after a minimum of 12 months of service in the performance period. Compensation expense for the stock

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performance awards portion of the LTIP has been recognized in accordance with the fair-value-based measurement method of accounting for performance shares.

The Company’s share-based compensation 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 NQSOs 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 exercisable 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 price

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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 equivalents) 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 distributed 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 exceeds the exercise price of the right.

Section 409A. As a result of the changes enacted in Section 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 compensation, 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 2½ months after the end of the calendar year. Upon retirement, an SOIP participant may elect to take distributions 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 value at December 31, 2009; thus, no distribution was made in 2010. No further dividend equivalents are intended to be paid in accordance with this Section 409A modified distribution.

Restricted shares and restricted 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 or 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 related 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.

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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 expected to be recognized over a weighted-average period of 2.7 years.

LTIP payable in stock. The 2011-2013 LTIP provides for performance 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 date the grants are made subject to the achievement of specified performance 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 total 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 return 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 based 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 grant date and estimated future stock volatility and dividends of HEI and its peers over the remaining three-year performance period. The expected stock volatility assumptions for HEI and its peer group were based on the three-year historic stock 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 resulting fair value of LTIP granted:

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	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) were made payable in 113,831 shares of HEI common stock (based on the grant date prices of $24.95 and $26.25 and target performance levels relating to performance goals other than TRS), with a weighted-average grant date fair 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		$43,923

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A reconciliation of the amount of income taxes computed 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 low 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 amortization to net income, which was reduced by ASB’s losses from sales of mortgage-related securities and other-than-temporary impairments.

The tax effects of book and tax basis differences that give 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 assets is dependent upon the generation of future taxable income during the periods in which those temporary differences are deductible. Based upon historical taxable income and projections for future taxable income, management believes it is more likely than not the Company will realize substantially all of the benefits of the deferred tax 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 self-constructed assets. In 2011, 2010 and 2009, interest expense/(credit adjustments to interest expense) on income taxes was reflected in “Interest expense – other than on deposit liabilities and other bank borrowings” in the amount of $(1.2) million, $(0.9) million 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 dividends payable” was $1.5 million and $2.7 million, respectively.

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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 relating to the deductibility of costs incurred to repair generation property. The Company believes that it is reasonably possible that the IRS may issue guidance on the deductibility of these repair costs 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 costs 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 tax 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 Taxation of the State of Hawaii. HEI Investments, Inc., which owned leveraged lease investments in other states prior to its dissolution in 2008, is also subject to examination by those state tax authorities for tax years 2005 to 2007.

As of December 31, 2011, the disclosures above present the Company’s accrual for potential tax liabilities and related interest. Based on information currently available, the Company believes this accrual has adequately provided for potential income tax issues with federal and state tax authorities and related interest, and that the ultimate resolution of tax issues for all open tax periods will not have a material adverse effect on its results of operations, 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 director and officer compensatory plans	8		4	2
Electric utility property, plant and equipment
AFUDC-equity	6		6	12
Estimated fair value of noncash contributions 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.

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13 · Regulatory restrictions on net assets

As of December 31, 2011, HECO and its subsidiaries could not transfer approximately $588 million of net assets to HEI in the form of dividends, loans or advances without PUC approval.

ASB is required to file a notice with the FRB and OCC prior to making any capital distribution to HEI. Generally, the FRB and OCC may disapprove or deny ASB’s notice of intention to make a capital distribution if the proposed distribution will cause 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 December 31, 2011, ASB could transfer approximately $107 million of net assets to HEI in the form of dividends and still maintain its “well-capitalized” position.

HEI management expects that the regulatory restrictions will not materially affect the operations of the Company nor HEI’s ability to pay common stock dividends.

14 · Significant group concentrations of credit risk

Most of the Company’s business activity is with customers 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 measurement date. The fair value estimates are generally determined based on assumptions 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 assumptions about market participant assumptions based on the best information available in the circumstances. These valuations are estimates at a specific point in time, based on relevant market information, information about the financial instrument and judgments regarding future expected loss experience, economic conditions, risk characteristics of various financial instruments and other factors. These estimates do not reflect any premium or discount that could result if the Company were to sell its entire holdings of a particular financial instrument at one time. Because no active trading market exists for a portion of the Company’s financial instruments, fair value estimates cannot be determined with precision. Changes in the underlying assumptions used, including discount rates and estimates of future cash flows, could significantly affect the estimates. Fair value estimates are provided for certain financial instruments without attempting to estimate the value of anticipated future business and the value of assets and liabilities that are 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 assets 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.

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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 estimate that value:

Cash and cash equivalents and short-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 similar 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 the swaps, using the contractual terms of the swaps, including the period to maturity, and observable market-based 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		52,500

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As of December 31, 2011 and 2010, loan commitments 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, respectively. As of December 31, 2011 and 2010, loans serviced by ASB for others had notional 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 exchanges 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 similar market transactions, even in situations where trading volume may be low when compared with prior periods as has been the case during the recent market disruption. Inputs to these valuation techniques reflect the assumptions that consider credit and nonperformance risk that market participants would use in pricing the asset based on market data obtained from independent sources. Available-for-sale securities were 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
(in thousands)	Quoted prices in active markets for identical assets (Level 1)	Significant other observable inputs (Level 2)	Significant unobservable inputs (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, the 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 individual assets. ASB does not record loans at fair value on a recurring basis. However, from time to time, ASB records nonrecurring fair value adjustments to loans to reflect specific reserves on loans based on the current appraised 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 measure 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 market-observable risk-free rates as adjusted by HECO’s credit spread (also see Note 3).

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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 for 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
(in millions)	December 31	Quoted prices in active markets for identical assets (Level 1)	Significant other observable inputs (Level 2)	Significant unobserv- able inputs (Level 3)	December 31	Quoted prices in active markets for identical assets (Level 1)	Significant other observable inputs (Level 2)	Significant unobserv- able inputs (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 shown 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 market participants at that date. Those fair value measurements maximize the use of observable inputs. However, in situations where there is little, if any, market activity for the asset or liability at the measurement date, the fair value 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 Company based on the best information available in the circumstances.

In connection with the adoption of the fair value measurement standards, the Company adopted the provisions of ASU No. 2009-12, “Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent),” which allows for the estimation of the fair value of investments in investment companies for

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which the investment does not have a readily determinable fair value, using net asset value per share or its equivalent as a practical expedient.

The Company used the following valuation methodologies for assets measured 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. Treasury 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 based on yields currently available on comparable securities of issuers with similar credit ratings. Equity securities and pooled and mutual funds include commingled equity funds and other closed funds, respectively, that are not open to public investment and are valued at the net asset value per share. Certain other investments are valued based on discounted cash flow analyses.

Other (Level 3). The venture capital and limited 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		$ 5

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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 recorded an adjustment of $6 million to revenues 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) shown are as reported on the NYSE Composite Tape.

5 The fourth quarter of 2010 includes $6 million of interest income (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.

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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 DISAGREEMENTS WITH ACCOUNTANTS 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 Exchange Act of 1934, as amended) were effective in ensuring that information required to be disclosed by HEI in reports HEI files or submits under the Securities Exchange Act of 1934:

(1) is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission rules and forms, and

(2) is accumulated and communicated to HEI management, 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 Internal Control Over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) and Rule 15d-15(f) promulgated under the Securities Exchange Act of 1934, as amended. The Company’s internal control over financial reporting was designed to provide reasonable assurance to management and the Board of Directors regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

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 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.

The effectiveness of the Company’s internal control over financial reporting as of December 31, 2011 has been audited by PricewaterhouseCoopers 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 control over financial reporting during the quarter ended December 31, 2011 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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HECO:

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Richard M. Rosenblum, HECO Chief Executive Officer, and Tayne S. Y. Sekimura, HECO Chief Financial Officer, have evaluated the disclosure controls and procedures of HECO 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 Exchange Act of 1934, as amended) were effective in ensuring that information required to be disclosed by HECO in reports HECO files or submits under the Securities Exchange Act of 1934:

(1) is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission rules and forms, and

(2) is accumulated and communicated to HECO management, 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 Internal Control Over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined 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 management and the Board of Directors regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

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 Sponsoring 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 control 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 indemnify and hold KPMG LLP (KPMG) harmless against and from any and all legal costs and expenses 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 statements included in this Form 10-K.

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

HEI:

Information regarding HEI’s executive officers is provided 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 terms expire at the 2015 Annual Meeting”

· “Continuing Class II directors whose terms expire at the 2013 Annual Meeting”

· “Continuing Class III directors whose terms expire at the 2014 Annual Meeting”

· “Committees of the Board” (portions 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 identifying audit committee financial experts who serve on the HEI Audit Committee only; no other portion of the Audit Committee Report is incorporated herein by reference)

Family relationships; director arrangements

There are no family relationships between any HEI director or director nominee and any other HEI director or director nominee or any HEI executive officer. There are no arrangements or understandings 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 Conduct 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 website at www.hei.com. HEI elects to disclose 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 available on this website for at least a 12-month period.

Section 16(a) beneficial ownership reporting compliance

Information required to be reported under this caption is incorporated herein by reference to the “Stock Ownership Information—Section 16(a) Beneficial Ownership Reporting Compliance” 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 officers of HECO under SEC Rule 3b-7 promulgated under the 1934 Exchange Act. HECO executive officers serve from the date of their initial appointment until the annual meeting 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.

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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 President 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 & Property 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, Administration and Corporate Secretary, 4/05 to 9/09 · HEI Vice President, Administration, 1/05 to 4/05 · HECO Vice President, Corporate Excellence, 3/98 to 1/05 · HECO Manager, Environmental, 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	MECO 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 5/88

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HECO Board

The directors of HECO are listed below. HECO directors are elected annually by HEI, as sole common shareholder of HECO, taking into account recommendations made by the HEI Nominating and Corporate Governance Committee. Below is information regarding 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 experience, qualifications, attributes and skills that led to the HECO Board’s conclusion at the time of this Form 10-K that each of the directors should serve on the HECO Board in light of HECO’s current 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 experience as President and Vice President, Finance of Oceanic Cable.

· Experience with oversight of executive compensation, compensation programs and finance matters from serving as Chair of the Compensation Committee for Island Insurance Company, Ltd., a member of the Compensation Committees of HEI and Pacific Guardian Life, and as a member of the ASB Audit Committee.

· In-depth knowledge of issues facing HECO gained from 15 years as a director for HECO’s parent company, HEI.

· Strong understanding of concerns of the communities HECO serves from 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 Member, J.F. Lehman & Company (private equity firm), since 2008

· Owner, Fargo Associates, LLC (defense and homeland/national security consultancy), since 2005

· Chief Executive Officer, Hawaii Superferry, Inc. (interisland ferry), 2008-2009

· President, Trex Enterprises Corporation (defense research and development firm), 2005-2008

· Commander, U.S. Pacific Command, 2002-2005

· Chairman of the Board and Compensation and Governance Committee Member, Huntington Ingalls Industries, Inc., since 2011

· Director, Alexander & Baldwin, Inc., since 2011

· Director, Northrop Grumman 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-financial risk assessment skills developed over 39 years of leading 9 organizations ranging in size from 130 to 300,000 people and managing budgets up to $8 billion.

· Experience with corporate governance, including audit, compensation and governance committees, from service on several public and private company boards.

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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, Portland General Electric Company (PGE), 2009

· President and Chief Executive Officer, PGE, 2000-2008

· Director, HEI (parent company of HECO), since 2011

· Director, Umpqua Holdings Corporation, since 2009, and Chair 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 passage 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 Energy Laboratory for selling more renewable power to residential customers than any other utility in the U.S. for several years during her tenure as PGE’s CEO.

· Proven management, leadership and analytical skills, including crisis management, risk assessment, strategic planning and public relations skills, demonstrated especially by her leadership of PGE after the 2001 bankruptcy of its parent company, Enron Corp., through its independence from Enron in 2006.

· Expertise in financial oversight, regulatory compliance 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 Holdings from 1999 to 2003, when it also filed for bankruptcy protection. The case was procedurally consolidated with the Enron bankruptcy, but Enron’s bankruptcy reorganization plan did not expressly pertain to Portland General Holdings. The Portland General Holdings bankruptcy case was 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 stewardship 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), Chairperson of the Hawaii State

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Board of Land and Natural Resources (1999-2000), Director of the Hawaii State Department of Land and Natural Resources (1999-2000) and Vice President 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, from 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 Grove Farm Company, Inc. (privately-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 tours 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, Kobayashi 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 downtown Honolulu, Hawaii to a country club on the island of Maui, and experience with executive management, marketing and government relations.

· Organizational governance and financial oversight experience from his current service as a director or trustee for two mutual funds (Pacific Capital Funds of Cash Assets and Hawaiian Tax Free Trusts, both from the Aquila Group of Funds), East-West Center Foundation, Nature Conservancy of Hawaii and GIFT Foundation of Hawaii, 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 Director, HEI (parent company of HECO), since 2006

· Chairman of the Board, HECO, since 2006

· Chairman of the Board, ASB (affiliate 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 Power Corp. (former affiliate of HECO), 1997-1999

· Treasurer, HECO and Assistant 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 from serving in various chief executive, chief operating and other executive, finance and legal positions at HEI and its major operating subsidiaries,

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HECO and ASB, over the last 28 years.

· Familiarity with current management and corporate governance practices from her service as a director and Audit Committee member for Alexander & Baldwin, Inc. and as a director of the Associated Electric & Gas Insurance Services, Inc.

· Experience with financial oversight and expansive knowledge of the Hawaii business community and the local communities that compose the customer bases of HECO and its subsidiaries from serving as a director for various local industry, business development, educational 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 Electric Institute and the Electric Power Research Institute.

· Nationally recognized leader in the fields of infrastructure, banking and energy, demonstrated by her appointment by President Obama to the National Infrastructure Advisory Council, her appointment to the Federal Reserve Board of San Francisco’s 12th District Community Depository Institutions Advisory Council and her receipt of the 2011 Woman of the Year 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 Nuclear Officer, Southern California Edison Company, 2005-2008

Skills and qualifications for HECO Board service

· 34 years of experience in all phases of electric utility operations, including 32 years at Southern California Edison Company, one of California’s largest electric utilities, and experience leading renewable energy efforts, including initiating 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 Edison 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 Technical 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 Nominating and Corporate Governance Committee Chair, HEI (parent company of HECO)

Skills and qualifications for HECO Board service

· Executive management experience with responsibility for overseeing more than $500 million in charitable assets as President and Chief Executive Officer of the Hawaii Community Foundation.

· Proficiency in risk assessment, strategic planning and organizational leadership as well as marketing and public relations obtained from his current position at the Hawaii Community Foundation and his prior experience as Vice President and Executive Director 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 prior 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 Foundation and through publishing articles and lecturing on governance of

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tax-exempt organizations.

Audit Committee of the HECO Board

HECO has a guarantee with respect to 6.50% cumulative 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 HEI, 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 listing standards 303A.04, 303A.05 and 303A.06, which require listed companies to have nominating/corporate 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 requirements 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 committee 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 controls, (2) the performance of HECO’s internal auditor, (3) risk assessment and risk management policies set by management and (4) the Corporate Code of Conduct compliance program for HECO and its subsidiaries. In addition, 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 procedures for receiving and reviewing confidential reports to the HECO Audit Committee of potential accounting and auditing concerns.

In 2011, the HECO Audit Committee held four meetings. At each meeting, the committee held executive sessions without management present with the independent registered public accounting firm that audits HEI’s consolidated financial statements and the internal auditor.

Attendance at HECO Board 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 meetings of the HECO Board and the HECO Audit Committee (for those who served on such committee).

Family relationships; executive officer and director arrangements

There are no family relationships between any executive officer, director or director nominee of HECO and any other executive officer, director or director nominee of HECO. There 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, director or director nominee was selected.

Code of Conduct

The HEI Board has adopted a Corporate Code of Conduct that applies to all of HEI’s subsidiaries, including HECO, and which includes a code of ethics applicable to, among others, HECO’s principal executive officer, principal financial officer and principal accounting officer. The Corporate Code of Conduct is available on HEI’s website at www.hei.com. HECO elects to disclose 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 available on this website for at least a 12-month period.

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Section 16(a) beneficial ownership 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 equity 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 solely 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 believes that each of the persons 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 securities, 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 compensation in the HEI 2012 Proxy Statement.

HECO:

As Richard M. Rosenblum was deemed an executive officer of HEI and certain directors 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 information 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 Interlocks 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 Transactions—Compensation Committee Interlocks and Insider Participation” section in the HEI 2012 Proxy Statement.

HECO:

The HECO Board does not have a separate compensation committee. Rather, the entire HECO Board serves as HECO’s compensation committee and oversees HECO executive compensation matters. In addition, as part of its responsibility to oversee compensation programs at HEI and its subsidiaries, the HEI Compensation Committee assists the HECO Board by reviewing and making recommendations 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 representative of the HECO Board.

During the last fiscal year, the following HECO officers, who are also directors of HECO, participated in deliberations of the HECO Board regarding HECO executive 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 Executive Officer and other HECO named executive officers.

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deliberations of the HEI Compensation 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 that follows. Based on such review and discussion, the HEI Compensation Committee recommended 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 COMPENSATION COMMITTEE OF

THE HEI BOARD OF DIRECTORS

Thomas B. Fargo, Chairperson

A. Maurice Myers

Jeffrey N. Watanabe

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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 President and Chief Information Officer.

5. Patricia U. Wong, HECO Senior Vice President, Corporate Services.

Executive Summary

Objectives and Compensation Components. Our executive compensation program is designed to: (i) pay for performance in metrics that address shareholder, customer, employee and regulator considerations, (ii) align the interests of executives with those of our shareholders, (iii) attract, motivate and retain talented executives who can drive HECO’s success and (iv) ensure that the cost of executive compensation is reasonable.

The primary components of executive compensation 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-year periods) and service-based grants of restricted stock units (RSUs) vesting over four years. Other named executive officer benefits include 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 Analysis and under “Executive Compensation” below.

2011 Program Changes. The HECO Board and HEI Compensation Committee made the following changes in 2011 to further strengthen our executive compensation 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. This 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 Expense Management was added as a metric for evaluating annual performance of HECO executives. This metric is part of HECO’s balanced scorecard of performance metrics and incentivizes executives to seek better methods to perform operations and maintenance projects.

2011 Performance. In 2011, HECO continued to focus on its critical role in achieving the state’s clean energy goals, among the most aggressive in the nation. HECO successfully implemented 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 goals. In July 2011, HECO obtained an interim decision in its 2011 rate case, resulting in an annualized revenue increase of $53.2 million, largely to help recover costs and investments to increase the use of clean energy sources and maintain and improve reliable service to its customers. In addition, HECO and its subsidiaries completed additional power 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 achieve its goal of 40% of energy produced from renewable sources by 2030.

Please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” above for a more detailed description of our 2011 results.

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Pay for Performance. The compensation our named executive officers earned for 2011 reflects the strong performance summarized above as well as our performance over the three-year period that ended December 31, 2011:

· HECO Consolidated Net Income, HECO Operations & Expense Management, Safety, HECO Consolidated Customer Satisfaction and Hawaii Clean Energy Initiative were the key metrics for 2011 HECO named executive officer annual incentives. 2011 performance was between minimum and target for two metrics, at maximum for one metric, below minimum for one metric, and at target for one metric, resulting, in the aggregate, in payment of annual cash incentives 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 portion of each HECO named executive officer’s compensation. For the three-year period that ended December 31, 2011, the primary HECO named executive officer performance metrics were HEI 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 over the three-year period was slower than originally anticipated and performance in these two metrics was below minimum, while HEI TRS performance was at minimum. As a result, the HECO named executive officer 2009-2011 incentives paid out at 31.5% of target. For further detail, please see “What was HECO’s 2009-2011 long-term incentive plan and were there any payouts?” below.

The HECO Board and HEI Compensation Committee believe that our executive compensation program reflects best practices and is structured to encourage participants to build long-term value in the Company for the benefit of our shareholders and all stakeholders.

Compensation Process

Does the HECO Board have a designated compensation committee?

The HECO Board does not have a separate compensation committee. Rather, the entire HECO Board serves as HECO’s compensation committee and oversees HECO executive compensation matters. As part of its responsibility to oversee compensation programs at HEI and its subsidiaries, the HEI Compensation Committee assists the HECO Board by reviewing and making recommendations 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 representative of the HECO Board.

During the last fiscal year, the following HECO officers, who are also directors of HECO, participated in deliberations of the HECO Board regarding HECO executive compensation matters:

· HECO President and Chief Executive Officer Richard 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 performance goals and subjective measures, which evaluations were used by the HEI Compensation Committee in recommending, and by the HECO Board in determining, compensation for those officers. 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 participate in deliberations of the HECO Board to determine the compensation of the other HECO named executive officers.

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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 terminate any incentive program or other executive compensation program, or any individual executive’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 requirements 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 are designed to comply with Section 162(m), although the HECO Board and HEI Compensation Committee reserve the right to award compensation even when not deductible if it is reasonable and appropriate to do so.

In making compensation determinations, the HECO Board and the HEI Compensation Committee will consider financial accounting and tax consequences, if appropriate. For instance, as noted above, the HECO Board and HEI Compensation Committee take into account tax deductibility in establishing executive compensation. As another example, the HECO Board and HEI Compensation Committee may determine that there should not be any incentive payout that would result solely from a new way of accounting for a financial measure.

How do HECO’s compensation policies and practices relate to HECO’s risk management?

HECO has an Enterprise Risk Management function that 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 significant risk to the HEI Board and designated board committees. As a result, all HECO and HEI directors, including those that comprise the HEI Compensation Committee, are apprised of risks that could have a material 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 executive compensation program described in this Compensation Discussion and Analysis. The Enterprise Risk Management function conducts an annual risk review of HECO’s executive compensation program and findings from this review are considered by the HEI Compensation Committee in designing the next year’s compensation program. The HEI Compensation Committee has concluded that the HECO executive compensation program does not encourage unnecessary or excessive risk-taking and reported such conclusion to the HECO Board.

HECO’s compensation policies and practices are designed to focus executives on initiatives that benefit shareholders and other stakeholders, including customers, employees and regulators, and to discourage decisions that introduce risks that may have a material adverse effect on the Company. Because the executive officers are in a position to directly influence 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 long-term incentive plan. In addition, 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 following elements and practices to ensure prudent decision-making without encouraging employees to take unnecessary or excessive risks:

· Financial performance objectives for the annual cash incentive program are linked to approved budget guidelines and nonfinancial measures are aligned with the 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 performance-based compensation paid to executives found personally responsible for fraud, gross negligence or intentional misconduct that causes a restatement of HECO’s financial statements.

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· 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 risks faced by the enterprise, through 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 employees, customers and regulators. The specific goals that satisfy this objective are:

· To attract and retain talented executives;

· To motivate that talent through rewards aligned to the creation of sustainable value; and

· To satisfy these attraction and alignment goals at a reasonable cost.

How are the programs designed and what are they designed to reward?

The compensation programs’ objectives of attraction, alignment and cost are designed to be mutually distinct and collectively complete.

· Total compensation is levelized at approximately the competitive market median of the relevant peer group of companies to promote executive recruitment, retention and motivation, while at a reasonable cost.

· Compensation elements are designed to incent individual and group performance toward achieving the Company’s strategic goals.

· Compensation components are proportionally balanced between cash and equity to ensure an appropriate level of alignment of executives’ compensation with shareholders’ interests.

· Multiple metrics are established that focus executives on long-term value creation and risk management consideration, with Company performance measured against its peers.

· In making executive compensation decisions, the HECO Board and HEI Compensation Committee consider how changes in one element impact other compensation elements as well as the overall pay mix for each executive.

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Compensation Program

What is each element of executive compensation and how does it fit HECO’s compensation objectives?

The following chart summarizes the components of HECO’s executive compensation program and their connection to the Company’s executive compensation objectives. Each compensation element is described in further detail in the pages that follow and in the charts and notes under “Executive Compensation” below.

Element	Description	Objectives
CURRENT YEAR PERFORMANCE
Base Salary	Fixed level of cash compensation targeted to peer group median (but may vary based on performance, experience, responsibilities and other factors).	Attract and retain talented executives by providing market-competitive base salary.
Annual Incentive	Cash award based on achievement of Company goals during the year. Awards are at risk because they depend on pre-set performance goals. Poor performance yields no incentive payment. Combined with base salary, target 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 COMPENSATION
Long-term Performance-based Awards	Long-term incentive award opportunity based on meeting performance objectives over rolling three-year periods. Awards are at risk because they depend on pre-set performance goals. Poor performance 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 with 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.
Annual Stock-based Grant	Annual 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.	Align 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 through 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.	Attract and retain talented leaders by providing retirement income and enhancing long-term employee well-being.
HEI Deferred Compensation Plans	Enable HEI and HECO executives to defer portions of cash compensation, with certain limitations.	Attract and retain talented leaders by providing an additional method of saving for retirement and enhancing long-term employee well-being.
OTHER BENEFITS
Double Trigger Change-in-control Agreements	Double-trigger agreements, with 1 times to 2 times payment multiples. (Double-trigger = change in control followed by qualifying loss of employment.)	Attract and retain qualified leaders capable of a high level of performance that creates value for shareholders and other stakeholders. Encourage focused attention of executives in the change-in-control 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 well-being.

How does HECO determine the amount for each element?

Peer Benchmarking. The HECO Board and HEI Compensation Committee focus heavily on peer group comparisons to determine the appropriate compensation for named executive officers. The HECO Board

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and HEI Compensation Committee benchmark the elements of named executive officer compensation toward the median of HECO’s peer group, while allowing individual differences based on an executive’s importance to the organization, individual competency and performance, length of time in the position, execution of strategy, competitive options and retention and succession considerations.

Peer companies are, in the aggregate, similar in financial scope and valuation, provide similar products and services and are sources for talented employees. Peer companies are selected by the HEI Compensation Committee’s independent compensation consultant and are reviewed and approved by the HEI Compensation Committee and HECO Board.

In late 2010, Frederic W. Cook & Co., Inc. (Fred 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 companies 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 total direct compensation (i.e., annual cash compensation plus long-term incentive awards) of Messrs. Rosenblum and McMenamin and Ms. Wong is approximately at the median level. Ms. Sekimura’s total direct compensation is below the 25th percentile and the total direct compensation for Mr. Alm is between the 25th 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 Compensation Committee believe that the comparative compensation among the named executive officers is fair, considering job scope, experience, value to the organization and duties relative to the other named executive 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 executive team and market comparisons.

What are the base salaries of the HECO named executive officers?

Base salaries for our named executive officers are 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 each 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 complex 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%	$295,000

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What was HECO’s 2011 annual incentive plan and were there any payouts?

HECO named executive officers have the opportunity 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 nonfinancial goals important to HECO’s stakeholders and (iii) motivate executives and encourage 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 officer award ranges established by the HECO Board and HEI Compensation Committee in February 2011, shown 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, which 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, target and maximum goals and results for 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%)

52nd percentile

54th percentile

56th percentile

21st 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%)

52nd percentile

54th percentile

56th percentile

21st 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 Compensation Committee and HECO Board approved an adjustment to HECO GAAP net income to exclude the impact of a charge to net income of approximately $6 million, which related to HECO’s write off of $9.5 million in project costs with respect to Phase 1 of the East Oahu Transmission Project (EOTP). For further detail on the EOTP Phase 1 write off and the resulting charge to net income, see Note 3 to HEI’s Consolidated Financial Statements.

(2) Operations and Maintenance Expense Management encourages utility executives to seek better ways to perform operations and maintenance projects. Demand-side management expenses were excluded for purposes of this metric.

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(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 Administration recordable cases × 200,000 productive hours divided by the total number of productive hours for the year, with the lower the TCIR the better.

(4) Hawaii Clean Energy Initiative (HCEI) focuses executives on projects intended to obtain renewable energy from wind, photovoltaics, biomass, geothermal, ocean and other sources to help the utilities meet their commitments under the HCEI, an agreement between the state of Hawaii and 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 objectives set as goals for the HCEI metric. Specified milestones were achieved or exceeded with respect to: contracting to purchase renewable energy, biofuels contracting, continued development of Smart Grid and Advanced Metering Infrastructure projects and the interisland cable project.

(5) HECO Consolidated Customer Satisfaction focuses on customers, is based on customer surveys conducted by a third party vendor, and compares utility performance to the national utility industry. This metric is an indicator of how satisfied customers are with the utilities’ service, reliability and pricing relative to other utilities.

(6) Individual goals are based on achievement of objectives specific to the executive’s area of responsibility. Ms. Sekimura achieved her individual goal at the target level. Mr. McMenamin had two individual goals, evenly weighted at 2.5%, one was achieved at the minimum threshold level and one 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 February 2012 the HECO Board and HEI Compensation Committee approved payment of the following 2011 EICP awards 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 long-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 exceeding performance goals over rolling three-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-year performance periods encourage sustained high levels of performance because at any one time three separate potential awards are 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 Compensation Committee approved the following award ranges for Messrs. Rosenblum and Alm and for Ms. Sekimura. At the time the 2009-2011 LTIP was approved, Ms. Wong was serving as HEI Vice President – Administration 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 employed at HECO after the start of this performance period. The award ranges below are shown as a percentage of annual base salary 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 the metrics, weightings, minimum 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 Compensation Committee in February 2009 because they were believed to provide the necessary incentives to align executive compensation with shareholder value while considering key HECO stakeholders, including customers, 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 worthy 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 September 2009), Ms. Wong served as Vice President – Administration and

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Corporate Secretary at HEI. In September 2009, Ms. Wong transferred to HECO as its Senior Vice President, Corporate Services and assumed HECO goals at the same award ranges established 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%)

30th percentile

50th percentile

70th percentile

31st 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%)

30th percentile

50th percentile

70th percentile

31st 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%)

30th percentile

50th percentile

70th percentile

31st 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 Institute (EEI) Index. TRS is the sum of the growth in the price per share of HEI Common Stock from the beginning of the performance period to the end, plus dividends paid during the period, assuming reinvestment, divided by the beginning price of HEI Common Stock. The EEI is an association of U.S. shareholder-owned electric companies that are representative of comparable investment alternatives to HEI. The EEI’s members serve 95% of the ultimate customers in the shareholder-owned segment of the industry and represent approximately 70% of the U.S. electric power industry. The following companies were in the three-year EEI Index in 2011:

ALLETE

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 income (which is HEI GAAP net income, adjusted for any exclusions authorized by the HEI Compensation Committee and HECO Board) over the three-year performance period divided by average common equity as measured from the beginning to the end 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 common equity as determined by the PUC for the three-year performance period.

In February 2009, when the 2009-2011 LTIP award opportunities were established, the HECO Board and HEI Compensation Committee approved that, if earned, the 2009-2011 LTIP awards for Ms. Sekimura and Mr. Alm would be paid 100% in cash. In recognition of Mr. Rosenblum’s ability to impact HEI’s performance, and because Ms. Wong was still employed by HEI at the time the 2009-2011 LTIP award opportunities were established, the 2009-2011 LTIP award opportunities for Mr. Rosenblum and Ms. Wong were defined 60% in cash and 40% in HEI Common Stock, with the number of shares of HEI stock determined based on the price of HEI stock on the date the 2009-2011 award opportunities were established. In accordance with these determinations, the 2009-2011 LTIP award payouts for Ms. Sekimura and Mr. Alm were entirely in cash and the payouts for Mr. Rosenblum and Ms. Wong included both cash and stock (plus accrued dividends less applicable taxes). Ms. Wong’s total 2009-2011 LTIP payout (both the cash and stock portions) is based on her HEI and HECO goals and was prorated for the period that she served at each company.

Despite HECO and HEI’s strong performance in 2011, the improvement in HEI ROACE and HECO Consolidated ROACE over the three-year 2009-2011 LTIP period was slower than originally anticipated.

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Based on the achievement of the performance levels indicated in the chart 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. Rosenblum 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 December 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 applicable 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 market 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 price of the shares at payout, encourages even greater alignment of executive incentives with long-term value creation.

Award ranges. In February 2011, the HECO 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 maximum 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%)	30th percentile	50th percentile	75th 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 million

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The HECO Board and HEI Compensation Committee 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 earnings 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 for 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 authorized 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 challenges in the 2011-2013 LTIP performance period. Extraordinary leadership on the part of the named executive officers will be needed to achieve the long-term strategic objectives required for them to earn the incentive payouts. 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 investments 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 challenging 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 receive annual equity-based grants in the form of restricted stock units (RSUs) that vest over four years. RSUs offer executives the opportunity to receive shares of HEI Common Stock on the date the restrictions lapse, generally 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 stakeholders and encourage retention.

In February 2011, RSUs were granted to all of the HECO named executive officers. The HECO Board and HEI Compensation Committee determined the number of RSUs to be awarded in consultation with its independent compensation consultant and considering peer practices. The RSUs granted in 2011 vest in equal annual installments over a four-year period and accrue dividend equivalents, which are paid in conjunction with the annual installment vesting. The 2011 RSU grants are summarized in the 2011 Grants of Plan-Based Awards table and related notes below.

What retirement benefits do HECO named executive officers have?

HECO provides retirement benefits to named executive officers to promote financial security in recognition of years of service and to attract and retain high-quality leaders. HECO employees, including named executive officers, who joined the Company before 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 tax-deferred basis through HEI’s 401(k) Plan, which does not provide matching contributions for participants who joined the Company before May 1, 2011. In 2011, revisions were made to reduce the

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pension benefit under the HEI Retirement Plan and to provide for limited Company matching contributions under the HEI 401(k) Plan, but only for 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. 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 and on the amount of annual benefits that can be paid from qualified retirement plans. This allows those participating in the HEI Excess Pay Plan the same general percentage of final average pay benefit 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 named executive officers may participate in the HEI Deferred Compensation Plan, a nonqualified deferred compensation plan implemented in 2011 that allows deferral of portions of the participants’ cash compensation, with certain limitations, and provides investment opportunities that are substantially similar to those available under the HEI 401(k) Plan. There are no matching contributions under the HEI Deferred Compensation 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 compensation plan. No HECO named executive 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 Participating Subsidiaries, which provides death benefits to an executive’s beneficiaries in the event 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 salary increases after September 9, 2009). Under the Executive Death Benefit Plan contracts with participants in effect before 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 insurance and traditionally life insurance proceeds have been tax-exempt. Death benefits are discussed in further detail in the 2011 Pension Benefits table and related notes below.

Do HECO named executive officers have change-in-control agreements?

Mr. Rosenblum and Ms. Wong are the only HECO named executive officers who are parties to a change-in-control agreement.

The HECO Board and HEI Compensation Committee view change-in-control agreements to be an appropriate tool to recruit executives as an expected part of their compensation package, to encourage the continued attention of key executives to the performance of their duties without distraction in the event of a potential change in control and to assist in retaining 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 employment 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 payment 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 applied to the sum of the executive’s annual base salary and annual incentive compensation (determined to be the greater of the current target incentive compensation or the largest actual incentive compensation during the preceding

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three fiscal years). Aggregate payments under these agreements 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 terms 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 change 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, tender offer or similar transaction. Mr. Rosenblum’s agreement also defines a change in control as a change in ownership of HECO. Change-in-control benefits are discussed in further detail in the Potential Payments upon Termination or Change in Control section and related notes below.

What other benefits do HECO named executive officers have?

HECO provides limited other compensation 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 executives, such as relocation expenses or extra weeks of vacation, or because of legacy programs that are no longer available to new participants. HECO may, from time to time, reimburse for reasonable business-related expenses.

HECO has eliminated nearly all tax gross-ups for named executive officers. There are no tax gross-ups allowed on club membership initiation or membership fees, or in the change-in-control agreements for Mr. Rosenblum or Ms. Wong. As discussed under “Do HECO named executive officers have executive death benefits?,” tax gross-ups of death benefits have been restricted to the executives who participated in the Executive Death Benefit Plan prior to September 9, 2009 (the date the plan was frozen).

In 2011, Mr. Rosenblum had a club membership for the primary purpose of business entertainment expected of executives in his position.

As part of his employment offer, Mr. Rosenblum received a signing bonus upon his hire by HECO in 2009, subject to monthly pro-rata reimbursement in the event of a voluntary termination or termination for cause prior to the completion of 36 months of service. This reimbursement period ended as of January 2012. In addition, as part of his recruitment, Mr. Rosenblum was extended a special severance agreement that provided that, in the event his employment was terminated without cause 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 agreement for Mr. Rosenblum has now expired, there are no separate severance agreements for any named executive officers. The named executive officers would participate in the same manner as all HECO non-bargaining unit employees in HECO’s standard severance policy based on years of service.

As part of Mr. Rosenblum’s recruitment, 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 more than a new employee would usually receive. Mr. McMenamin, who joined HECO in September 2009, is eligible for reimbursement for temporary 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, which is more than a new employee would usually receive.

For further description of the amounts described above see footnote 5 to the 2011 Summary Compensation Table below.

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Summary Compensation Table

The following summary compensation table shows the base salary, bonus (if applicable), grant date fair value of stock awards, non-equity incentive compensation, change in pension value and nonqualified deferred compensation earnings and all other compensation and benefits paid or awarded to the HECO named executive officers during 2009, 2010 and 2011 (as applicable). All compensation amounts presented for Mr. Rosenblum are the same amounts that will be presented for him in the HEI 2012 Proxy Statement.

2011 SUMMARY COMPENSATION TABLE

Name and 2011 Principal Positions	Year	Salary ($)	Bonus ($) (1)	Stock Awards ($) (2)	Non-Equity Incentive Plan Compen- sation ($) (3)	Change in Pension Value and Nonqualified Deferred Compensation Earnings ($) (4)	All Other Compen- sation ($) (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 non-equity 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 officers. Assuming achievement of the highest level of performance conditions, the maximum value of the performance award 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 Statements.

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(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 the year following the three-year cycle ending on December 31 of the applicable plan year. In the table below, the payments shown for the 2009-2011 LTIP for Ms. Sekimura and Mr. Alm represent their respective total awards. For Mr. Rosenblum and Ms. Wong, the amounts shown for 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 number and value of the shares vested and awarded, and the dividend equivalents on those shares (which were paid in cash), are not reported 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, 2011, December 31, 2009 to December 31, 2010 and December 31, 2008 to December 31, 2009, respectively. For a further discussion of these 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 deferred 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 to 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 value, nonqualified deferred compensation, and other compensation can be found in the Compensation Discussion and Analysis above.

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Grants of Plan-Based Awards

The following table relates to awards to the HECO named executive officers in 2011 under the annual EICP tied to performance in 2011 and under the LTIP 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)

All Other
Stock
Awards:
Number

Grant Date

Name

Grant
Date

Thres-
hold ($)

Target
($)

Maximum
($)

Thres-
hold (#)

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 upon 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 Discussion 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 equal 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 allow for pro-rata vesting. The primary purpose of the RSUs is retention and there are no conditions to vesting other than the four-year graded 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 discussion 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 closing sales prices of HEI Common Stock on the New York Stock Exchange on the date of the grant of the award.

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Outstanding Equity Awards 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

Exer-
ciseable
(#)

Unexer-
ciseable
(#)

Unexercised
Unearned
Options (#)

Option
Exercise
Price ($)

Expira-
tion
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 anniversary 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, 2011.

(3) Represents shares of stock that would be issued under the 2010-2012 LTIP and 2011-2013 LTIP based upon achievement of performance goals at the minimum threshold level at the end of the three-year performance periods.

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Option Exercises and Stock Vested

2011 OPTION EXERCISES AND STOCK VESTED

	Option Awards		Stock Awards
	Number of	Value	Number of Shares
	Shares Acquired on	Realized on	Acquired on	Value Realized on
Name	Exercise (#)	Exercise ($)	Vesting (#)	Vesting ($)
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 HEI 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 stock issued on April 12, 2007 and vesting on April 12, 2011.

(3) The options exercised by Mr. Alm and Ms. Wong were granted 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

		Number of	Present Value of	Payments During
		Years Credited	Accumulated	the Last Fiscal
Name	Plan Name	Service (#)	Benefit ($) (4)	Year ($)
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 before May 1, 2011, including the named executive officers, are calculated based on a formula of 2.04% × Credited Service (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 other participating companies (Hawaiian Electric Company, Maui Electric Company and Hawaii Electric Light Company). Additional credited service of up to eight months is

174

used to calculate benefits for participants who retire at age 55 or later with respect to unused sick leave from the current year and prior two years. Credited service is also granted to disabled participants who are vested at the time of disability for the period of disability. The normal form of benefit is a joint and 50% survivor annuity for married participants and a single life annuity for 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 payable as an annuity. At early retirement, the single sum distribution option is not actuarially equivalent to the other forms of benefit. Retirement benefits are increased by an amount equal to approximately 1.4% of the initial benefit every twelve months following retirement. Effective April 1, 2011, accelerated distribution options (the $50,000 single sum distribution option and a Social Security level income option) under the HEI Retirement Plan became 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 restrictions are expected to continue through 2012. The plan provides benefits at early 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 service requirements at ages 50-64. Early retirement benefits are reduced 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 retirement 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 Retirement Savings Plan (HEIRSP). In addition, new eligibility rules and contribution levels applicable to certain HEI and Utility employees hired prior to May 1, 2011 and all employees hired after April 30, 2011 were adopted for postretirement welfare 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 for 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 average compensation over three consecutive calendar 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 benefit 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 the HEI Excess Pay Plan 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 and have no vested interest in amounts reported above because they have not satisfied the minimum five-year service period that is required before vesting occurs.

(3) Messrs. Rosenblum and Alm and Mses. Wong and Sekimura are 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 dies 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 paid 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 Death 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:

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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 pension benefit payments in order to reflect the probability of survival to any given future date. For the calculation of the 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 assumed 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 refer 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 calculation 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 Discussion and Analysis above, no HECO named executive officer deferred any amount, and no HECO named executive officer had an account balance under those plans during 2011.

176

Potential Payments Upon Termination or Change in Control

The table below reflects the amount of potential payments to each HECO named executive officer in the event of retirement, voluntary termination, termination for cause, termination without cause and qualifying termination following a change in control, assuming termination occurred on December 31, 2011. The amounts listed below are estimates; actual amounts to be paid would depend on the actual date of termination and circumstances existing at that time. 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 year-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 amounts would have vested without regard to retirement since December 31, 2011 was the end of their performance periods. In addition 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 table 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 the 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 unvested

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	restricted stock, unvested restricted shares, unvested restricted 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 December 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 long-term 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 violation 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 restricted stock, unvested restricted stock units and participation in incentive plans. The executive’s participation 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 Compensation Committee’s right to amend, suspend or terminate any incentive award or any portion of it at any time. Termination without cause results in the pro rata vesting of restricted stock (based on service to date compared to original vesting period) and forfeiture of unvested restricted stock units. In the case of 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. “Change 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 the majority of the composition of the HEI Board following the consummation of a merger, tender offer or similar transaction. 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 (determined to be the greater of the current target incentive compensation or the largest actual incentive compensation during 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 period. Mr. Rosenblum and Ms. Wong would also receive the greater of current target or actual projected short- and long-term incentive compensation, prorated if termination occurs during the first half of the applicable performance period and the 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. Executives would receive financial, tax planning and outplacement services, capped at 15% of annual base salary. Payment would generally be delayed for six months following termination of employment to the extent required to avoid an additional tax under Section 409A of the Internal Revenue Code. Interest would accrue during the six-month delay period at the prevailing six-month certificate of deposit rate and payments would be set aside during that period in a grantor (rabbi) trust. All the 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, provided 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, disability or retirement, participants who terminate during the plan 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, executives continue to participate in each on-going LTIP cycle at a prorated amount, provided there has been a minimum service 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 termination. 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 scenarios other than a change in control, participants who terminate during the plan cycle for reasons other than death, disability or retirement forfeit any accrued long-term incentive award. Long-term incentive

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	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 cause 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 unvested restricted stock units are forfeited. The amount shown is based on the 2011 year-end closing price of vested shares. Restricted stock and restricted stock unit severance payments in the event of a change in control are described in footnote 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 salary 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 eligible 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 competitive compensation package is necessary to attract and retain individuals with the experience, skills and qualifications needed for the challenging role of serving as a director on the board of a regulated electric utility. Based on the recommendations of the HEI Compensation Committee, which is responsible for recommending nonemployee director compensation for the boards of HEI and its subsidiary companies, and taking into consideration the recommendations of the HEI Compensation Committee’s independent compensation consultant who periodically reviews directors’ compensation, the HECO Board chooses to compensate nonemployee directors using a mix of cash and HEI Common Stock to allow for an appropriate level of compensation for services, including stock awards designed to align the interests of HECO directors with the interests of HEI shareholders.

In 2010, the HEI Compensation Committee asked its independent compensation consultant, Fred Cook & Co., to conduct an evaluation of HECO’s nonemployee director 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 the assessments used in its executive compensation review, which is described under “Compensation Discussion and Analysis—Compensation Program—How does HECO determine the amount for each element?” above. The 2010 analysis took into consideration the duties and scope of responsibilities of directors. The HEI Compensation Committee reviewed the analysis in determining its recommendations to the HECO Board concerning the appropriate nonemployee director compensation, including cash retainers, stock awards and meeting fees, and the HECO Board approved the HEI Compensation Committee’s recommendations 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 their service as directors. Nonemployee directors of HECO who are not also nonemployee directors of HEI receive compensation in the form of a cash retainer and an HEI stock grant. Don E. Carroll, Timothy E. Johns and Bert A. Kobayashi, Jr. are the nonemployee directors of HECO who are not also directors 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 the HEI Board. Nonemployee directors of HECO who are also nonemployee directors of HEI do not receive any additional compensation for serving on the HECO Board. Thomas B. Fargo, Peggy Y. Fowler and 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 value equal to $40,000 as an annual grant under the HEI 2011

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Nonemployee Director Stock Plan, which was approved by HEI 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 was determined based on the closing 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 annually on the last business day in June.

Cash retainers. The following is the 2011 cash retainer schedule for nonemployee directors of HECO for 2011, which was paid in quarterly installments. Nonemployee directors of HECO who also serve as a member or chairperson of the HECO Audit Committee or as a non-voting HECO Board representative to attend meetings of the HEI Compensation Committee receive additional retainer amounts, as indicated below.

		2011
HECO Director (who is not also an HEI director)		$40,000
HECO Audit Committee Chairman		$10,000
HECO Audit Committee Member		$4,000
HECO Non-Voting Representative to HEI Compensation Committee		$6,000

Further, the HECO Board has approved meeting fees of $750 per meeting payable to a director who is a member or chair of the HECO Audit Committee after attending a minimum of eight HECO Audit Committee meetings during the calendar year and $1,500 per meeting payable to the HECO Board’s non-voting representative after attending six meetings of the HEI Compensation Committee.

The boards of HECO subsidiaries HELCO and MECO are 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 Directors’ Deferred Compensation Plan, as amended January 1, 2009, and the HEI Deferred Compensation Plan 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 limitations. No HECO director currently participates in either plan. Directors, at their election and at their cost, may also participate in the group employee medical, vision and dental plans generally made available to all HECO employees. Mr. Oshima was the only HECO director who participated in the program during 2011.

Information concerning the compensation paid to directors 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 compensation for her 2011 service on the HECO Audit Committee and (ii) for Mr. Taniguchi, compensation for his 2011 service on the HECO Audit Committee.

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2011 HECO DIRECTOR COMPENSATION TABLE

The following director compensation table shows 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 ($)	Non-Equity Incentive Plan Compen- sation ($)	Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)	All Other Compen- sation ($) (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	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 incorporated 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 compensation 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:

			HECO Nonvoting
Name	HECO Board Retainer ($)	HECO Audit Committee Retainer ($)	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	–	–	–	–

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

HEI:

Security Ownership of Certain Beneficial Owners

The information required under this item is incorporated herein by reference to the “Stock Ownership Information—Security Ownership of Certain Beneficial Owners” and “Stock Ownership Information—Does HEI have stock ownership and retention guidelines for directors and officers and does it have a policy regarding hedging the risk of ownership?” sections 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	Nonqualified stock options plus accrued dividend equivalents
5,900	–	5,900	Stock appreciation rights plus accrued dividend equivalent rights
69,000	178,286	247,286	Restricted stock units *
18,577	–	18,577	Shares issued in February 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 authorized for issuance as four shares for every share issued. Accordingly, the 178,286 RSU shares in the table are counted 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 relates to the outstanding 55,500 nonqualified stock options and 282,000 stock appreciation rights. Excluded from the weighted average exercise 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 December 31, 2011 for future awards, including 2,846,497 shares available for future awards under the EIP and 265,092 shares available for future awards under the 2011 Nonemployee Director Plan. As of May 11, 2010, no new awards may be granted under the SOIP.

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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 HECO Preferred Stock have been issued and are outstanding. Shares of HECO Preferred Stock are not considered voting securities, but upon certain defaults in dividend payments holders of HECO Preferred Stock may have the right to elect a majority of the directors of HECO. HEI owns 100,000 shares of HECO Preferred Stock, or approximately 9% of the 1,114,657 shares of HECO Preferred Stock outstanding. No HECO directors, executive officers or named executive officers (as listed in the 2011 Summary Compensation Table above) 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 directors and executive officers as a group as of February 7, 2012.

Amount and Nature of Beneficial Ownership of HEI Common Stock

Stock

Shared Voting

Other

Options/

Sole Voting or

Beneficial

Restricted

Name of Individual

Investment

Ownership

Stock Units

or Group

Power (1)

Power (2)

(3)

(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 directors 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 the home of the director or officer in which the director or officer disclaims personal interest.

(4) Includes the number of shares that the individuals named above had a right to acquire as of or within 60 days after February 7, 2012 pursuant to (i) stock options, stock appreciation rights and related dividend equivalent rights thereon and

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(ii) restricted stock units. These shares are included for purposes 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 include any shares subject to stock appreciation rights (SARs) granted in 2005 and held by Mses. Lau, Sekimura and Wong and Mr. Alm. 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 shares 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 average of the high and low sales prices on the NYSE on that date. As of February 7, 2012, the fair market value of HEI Common 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 market 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 officers 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 director 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 transaction policy that is specifically 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 such 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 material interest. Under the policy, the HEI Board, acting through the HEI Nominating and Corporate 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 inconsistent 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 subsidiaries 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% cumulative quarterly income preferred securities series 2004 (QUIPS) listed on the New York Stock Exchange (NYSE). Because HEI has common stock listed on NYSE and HECO is a wholly-owned subsidiary of HEI, 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 listing standards 303A.01 and 303A.02 regarding director independence.

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Although HECO is exempt from NYSE listing standards 303A.01 and 303A.02, HECO voluntarily endeavors to comply with these standards for director independence. The HEI Nominating and Corporate Governance Committee assists the HECO Board 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 director does not have any direct or indirect material relationship with HECO or its parent or subsidiaries apart from his or her service as a director. The NYSE listing standards also specify circumstances under which a director may not be considered independent, such as when the director has been an employee of the Company within the last three fiscal years, if the director has had certain relationships with the Company’s external or internal auditor within the last three fiscal years or when the Company has made or received payments for goods or services to entities with which the director or an immediate family member (as defined by NYSE) of the director has specified affiliations and the aggregate amount of such payments in any year within the last three fiscal years exceeds the greater of $1 million or 2% of such entity’s consolidated gross revenues for the last fiscal year.

The HEI Nominating and Corporate Governance Committee and the HECO Board considered the information below, which was provided by HECO directors 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 directors or immediate family members have certain affiliations. Based on its consideration of the relationships described below and the recommendations of the HEI Nominating and Corporate Governance Committee, the HECO Board determined that all of the nonemployee directors of HECO (Messrs. 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 the HECO Board for part of 2011, were independent. The remaining directors of HECO, Ms. Lau and Mr. Rosenblum, are employee directors.

· With respect to Mr. Johns, the HECO Board considered 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 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). The HECO Board also considered that HECO is the sole source of electric power on the island of Oahu and that the rates HECO charges for electricity are fixed by state regulatory authority. Since purchasers of electricity from HECO have no choice as to supplier and no ability to negotiate rates or other terms, the HECO Board determined that these relationships do not impair the independence of Mr. Johns.

· With respect to Messrs. Johns and Taketa, the HECO Board considered the amount of charitable contributions during the last three fiscal years from HEI and its subsidiaries to nonprofit organizations where these directors serve or served as executive officers. No Company donations exceeded $300,000 per entity in any single fiscal year during the last three fiscal years. In determining that none of these relationships affected 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 pre-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 considered other director or officer positions held by those directors at entities for which a HECO officer serves or served as a director and determined that none of these relationships affected the independence of these directors. None of these relationships resulted in a compensation committee interlock or would automatically preclude independence under the NYSE standards.

185

· With respect to Mr. Johns, the HECO Board considered 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 considered the fact that the relationship between HECO and the entity by which Mr. Johns is employed was established several decades before Mr. Johns’ employment by such entity.

· With respect to Mr. Kobayashi, Jr., the HECO Board 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 ACCOUNTING FEES AND SERVICES

HEI:

The information required under this item is incorporated herein by reference to the relevant information in the Audit Committee Report in the HEI 2012 Proxy Statement (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 payable to PricewaterhouseCoopers LLP (HECO’s independent registered public accounting firm) relating to the audit of HECO’s 2011 consolidated 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 fees associated with the audit of the consolidated financial statements and internal 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 HECO Audit Committee provides input to the HEI Audit Committee regarding pre-approval of all audit and permitted non-audit services of the independent registered public accounting firm engaged to audit HEI’s consolidated financial statements with respect to HECO, such as with respect to the audit of HECO’s consolidated financial statements. The HECO Audit Committee may delegate this responsibility to one or more of its members, provided that such member or members report to the full committee at its next regularly scheduled meeting any such 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 reflected in the table above.

186

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)(1) Financial statements

See Item 8 for the financial statements 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 Public Accounting Firms		5
	Consolidated Statements of Income, Years ended December 31, 2011, 2010 and 2009		7
	Consolidated Balance Sheets, December 31, 2011 and 2010		8
	Consolidated Statements of Capitalization, December 31, 2011 and 2010		9-10
	Consolidated Statements of Changes 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 Financial 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 Information 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 Qualifying Accounts, Years ended December 31, 2011, 2010 and 2009	195	195
NA Not applicable.

Certain schedules, other than those listed, are omitted because they are not required, or are not applicable, or the required information is shown in the consolidated financial statements (including the notes) included in HEI’s and HECO’s Consolidated Financial Statements.

187

[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 financial statements and of the effectiveness of internal control over financial reporting referred to in our report dated February 17, 2012, which 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 related consolidated financial statements.

/s/ PricewaterhouseCoopers LLP

Los Angeles, California

February 17, 2012

188

[KPMG LLP letterhead]

Report of Independent Registered 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 included in the Company’s annual report on Form 10-K for the year 2011. In connection with our audits of the aforementioned 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 responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statement 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, 2010

189

[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 Company, 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 incorporated 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 statement schedule as of and for the year ended December 31, 2011 presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.

/s/ PricewaterhouseCoopers LLP

Los Angeles, California

February 17, 2012

190

[KPMG LLP letterhead]

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholder

Hawaiian Electric Company, Inc.:

Under date of February 19, 2010, we reported on the consolidated statements of income, changes in common stock equity and cash flows of Hawaiian Electric Company, Inc. (a subsidiary of Hawaiian Electric Industries, Inc.) and subsidiaries for the year ended December 31, 2009. These consolidated financial statements and our report thereon are incorporated by reference in the Company’s annual report on Form 10-K for the year 2011. In connection with our audit of the aforementioned consolidated financial statements, we also audited the related financial statement schedule as listed in the accompanying index under Item 15.(a)(2). The financial statement schedule is the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statement 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 respects, the information set forth therein.

/s/ KPMG LLP

Honolulu, Hawaii

February 19, 2010

191

Hawaiian Electric Industries, Inc.

SCHEDULE I — CONDENSED FINANCIAL 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, authorized 200,000,000 shares; issued and outstanding: 96,038,328 shares and 94,690,932 shares	1,349,446		1,314,199
Retained earnings	201,640		181,910
Accumulated other comprehensive 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 instruments of guarantee and any renewals or extensions thereof executed by SAFECO or Travelers, including, but not limited to, a $0.2 million self-insured United States Longshore & Harbor bond and a $0.5 million self-insured automobile bond.

192

Hawaiian Electric Industries, Inc.

SCHEDULE I — CONDENSED FINANCIAL INFORMATION 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 subsidiaries	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, plant 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 allocations 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 consolidated financial reporting income tax provision is charged or credited to HEI’s separate tax provision.

193

Hawaiian Electric Industries, Inc.

SCHEDULE I — CONDENSED FINANCIAL INFORMATION 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 share-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 postretirement 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 subsidiaries 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-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		)
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 Purchase 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 HEI 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 September 3, 2009 and from August 18, 2011 through December 31, 2011) by acquiring for cash its common shares through open market purchases rather than by issuing additional shares.

194

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	Balance at begin- ning 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.

195

(a)(3) and (b) Exhibits

The Exhibit Index attached to this Form 10-K is incorporated 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 report by registrant Hawaiian Electric 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 Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrants and in the capacities indicated on February 17, 2012. The execution of this report by each of the undersigned who signs this report solely in such person’s capacity as a director or officer of Hawaiian Electric Company, Inc. 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 the 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)

196

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 Myers

197

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. Watanabe

198

EXHIBIT INDEX

The exhibits designated by an asterisk (*) are filed herewith. The exhibits not so designated are incorporated by reference to the indicated filing. A copy of any exhibit may be obtained upon written request for a $0.20 per page charge from the HEI Shareholder Services Division, P.O. Box 730, Honolulu, Hawaii 96808-0730.

Exhibit no.	Description
HEI:
3(i)	HEI’s Amended and Restated Articles of Incorporation (Exhibit 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 Trustee (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 Statement 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 Statement 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 Purchasers 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, restatement 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 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, 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 Agreement (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 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 June 30, 2002, File No. 1-8503).

4.6(g)	Sixth Amendment dated as of January 1, 2002, to Trust 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 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, 2002, File No. 1-8503).

4.6(i)	Eighth Amendment dated as of September 1, 2003, to Trust 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 Trust 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 Trust 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 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 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 (Exhibit 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 Trustee (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 Trust 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 Reinvestment 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 Registration 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 Loan 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 Regulatory 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 compensatory plans or arrangements required to be filed as exhibits pursuant to Item 15(b) of this report. HEI Exhibits 10.4 through 10.18 are also management contracts or compensatory plans or arrangements with HECO participants.

10.4	HEI Executive Incentive Compensation Plan amended and restated as of February 23, 2009 (Exhibit 10.4 to HEI’s Annual Report on Form 10-K for the fiscal year 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 and Incentive Plan, as amended and restated November 16, 2010 (Exhibit 10.6 to HEI’s Annual Report on Form 10-K for the 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 Equity 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 the quarter ended June 30, 2008, File No. 1-8503).

10.7(a)	Form of Hawaiian Electric Industries, Inc. Stock Option Agreement with Dividend Equivalents (Exhibit 10.7(b) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2004, File No. 1-8503).

10.7(b)	Form of Hawaiian Electric Industries, Inc. Stock Appreciation Right Agreement with Dividend Equivalents (Exhibit 10.2 to HEI’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2004, File No. 1-8503).

10.7(c)	Form of Hawaiian Electric Industries, Inc. Stock Appreciation 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 restated 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 Retirement 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 (Exhibit 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 (Exhibit 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 (Exhibit 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 effective 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 Subsidiaries 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 quarter 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 year 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 quarter ended September 30, 2008, File No. 1-8503).

10.20	American Savings Bank Supplemental Executive Retirement, 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 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 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 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 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 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 Accounting Firm (PricewaterhouseCoopers LLP).

*23.2	Consent of Independent Registered Public Accounting Firm (KPMG LLP).

*31.1	Certification Pursuant to 13a-14 of the Securities Exchange 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 Executive 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 Incorporation (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 effective August 6, 2009 (Exhibit 3(i).4 to Quarterly Report on Form 10-Q for the quarter ended June 30, 2009, File No. 1-4955).

3(ii)	HECO’s Amended and Restated Bylaws (as last amended August 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 define the rights of holders of certain long-term debt of HECO, HELCO and MECO (Exhibit 4.1 to HEI’s Annual Report on Form 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 Trustee, 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 Debenture, 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 York, as Trust Guarantee Trustee, and HECO dated as of March 1, 2004 (Exhibit 4(l) to HECO’s Current Report 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 Report 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 Report on Form 8-K dated March 16, 2004, File No. 1-4955).

4.10	6.500% Junior Subordinated Deferrable Interest Debenture, 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 Debenture, 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 Capital 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 quarter 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 Lessor, and HECO, as Lessee, dated February 27, 1989 (Exhibit 10(d) to HECO’s Quarterly Report on Form 10-Q for 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 Report 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 for 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 quarter 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, Inc. 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 for 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 Acceptance to AES Barbers Point, Inc. dated January 15, 1990 (Exhibit 10.3(c) to HECO’s Annual Report on Form 10-K for the fiscal year 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 & Sugar 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 (Exhibit 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 Commercial & 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 HECO’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 Thermal 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 Purchase Power Contract between HELCO and Puna Geothermal Venture dated March 24, 1986, as amended.

*10.4(g)	Power Purchase Agreement between Puna Geothermal 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 HELCO,” 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 Report 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 year 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 the fiscal year ended December 31, 2010, File No. 1-4955).

10.7(a)	Low Sulfur Fuel Oil Supply Contract by and between Chevron and HECO dated as of November 14, 1997 (confidential treatment has been requested for portions of this exhibit) (Exhibit 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 Contract 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 Supply Contract by and between Chevron and HECO, MECO, HELCO, HTB and YB dated as of November 14, 1997 (confidential treatment 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 Diesel Fuel Supply Contract by and between Chevron and HECO, MECO and HELCO entered into as of April 12, 2004 (confidential 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 Chevron 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 Contract by and between BHP Petroleum Americas Refining Inc. and HECO dated as of November 14, 1997 (confidential treatment has been requested for portions of this exhibit, which has been redacted accordingly) (Exhibit 10.11 to HECO’s Annual Report on Form 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 March 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 Contract 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, which 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 Americas 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 Report 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 (Exhibit 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 Association, 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 Sole 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 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 Sole Book Runner (Exhibit 10.2 to HECO’s Current Report on Form 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 Exchange Act of 1934 of Tayne S. Y. Sekimura (HECO Chief Financial Officer).

*32.3	Written Statement of Richard M. Rosenblum (HECO Chief 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 Chief 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).