HAWAIIAN ELECTRIC INDUSTRIES INC - Annual Report: 2012 (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, 2012

[ ] 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 the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Hawaiian Electric Industries Inc. Yes X No

Hawaiian Electric Company, Inc. Yes No X

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Hawaiian Electric Industries Inc. Yes No X

Hawaiian Electric Company, Inc. Yes No X

Indicate by check mark whether the registrant (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.

Hawaiian Electric Industries Inc. Yes X No

Hawaiian Electric Company, Inc. Yes X No

Indicate by check mark whether the registrant 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).

Hawaiian Electric Industries Inc. Yes X No

Hawaiian Electric Company, Inc. Yes X No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (section 229.405 of this chapter) 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 the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Hawaiian Electric Industries Inc.

Large accelerated filer X

Accelerated filer

Non-accelerated filer

(Do not check if a smaller reporting company)

Smaller reporting company

Hawaiian Electric Company, Inc.

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 the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Hawaiian Electric Industries Inc. Yes No X	Hawaiian Electric Company, Inc. 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, 2012	June 30, 2012	February 7, 2013

Hawaiian Electric Industries, Inc. (HEI)	$2,767,100,181	97,023,148 (Without par value)	98,101,019 (Without par value)

Hawaiian Electric Company, Inc. (HECO)	None	14,233,723 ($6 2/3 par value)	14,665,264 ($6 2/3 par value)

DOCUMENTS INCORPORATED BY REFERENCE

HECO’s Exhibit 99.2, consisting of:

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 Selected Financial Data—Part II

HECO’s Consolidated 2012 Financial Statements—Parts I, II, III and IV

HECO’s Exhibit 99.3, consisting of:

HECO’s Directors, Executive Officers and Corporate Governance—Part III

HECO’s Executive Compensation—Part III

HECO’s Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters—Part III

HECO’s Certain Relationships and Related Transactions, and Director Independence—Part III

HECO’s Principal Accounting Fees and Services—Part III

Selected sections of Proxy Statement of HEI for the 2013 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	35
Item 2.	Properties	35
Item 3.	Legal Proceedings	35
Item 4.	Mine Safety Disclosures	36
Executive Officers of the Registrant (HEI)		36

	PART II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	37
Item 6.	Selected Financial Data	38
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	39
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	82
Item 8.	Financial Statements and Supplementary Data	84
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	148
Item 9A.	Controls and Procedures	148
Item 9B.	Other Information	149

	PART III

Item 10.	Directors, Executive Officers and Corporate Governance	149
Item 11.	Executive Compensation	150
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	151
Item 13.	Certain Relationships and Related Transactions, and Director Independence	152
Item 14.	Principal Accounting Fees and Services	152

	PART IV

Item 15.	Exhibits and Financial Statement Schedules	153
Report of Independent Registered Public Accounting Firm - HEI		154
Report of Independent Registered Public Accounting Firm - HECO		155
Index to Exhibits		160
Signatures		160

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 clause
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 2013 Proxy Statement		Selected sections of Hawaiian Electric Industries, Inc.’s 2013 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
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 or HECO Exhibit 99.3 as if fully set forth herein (or means refer to the referenced section in this document or the referenced exhibit or other 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, state and international responses to those conditions, and the potential impacts of global developments (including global economic conditions and uncertainties, 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;

· 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 the Company’s pension and other retirement plan assets and ASB’s 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, 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;

· 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 continued availability to the electric utilities of other cost recovery mechanisms, including the purchased power adjustment clauses (PPACs), revenue adjustment mechanisms (RAMs) and pension and postretirement benefits other than pensions (OPEB) tracking mechanisms, and the continued decoupling of revenues from sales;

· 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 (including resulting compliance costs and risks of fines and penalties), 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 $5.0 billion as of December 31, 2012.

HEIPI, whose predecessor company was formed in February 1998, holds venture capital investments with a carrying value of $0.5 million as of December 31, 2012.

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 2012; 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, 2012, 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, 2012, HECO and its subsidiaries had common stock equity of $1.5 billion of which approximately $637 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 prior approval 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	2012	2011	2010	2009	2008
HEI	42	40	34	34	41
HECO and its subsidiaries	2,658	2,518	2,317	2,297	2,203
ASB and its subsidiaries	1,170	1,096	1,075	1,119	1,313
Other subsidiaries	–	–	–	3	3
	3,870	3,654	3,426	3,453	3,560

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 of HEI’s Consolidated Financial Statements.

Properties. HEI leases office space from nonaffiliated lessors in downtown Honolulu under leases that expire in March 2016 and December 2017. Until April 2012, HEI subleased office space in a downtown Honolulu building leased by HECO. 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 2012, 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 92% and 72% in 2011, and approximately 89% and 67% in 2010, respectively.

The islands of Oahu, Hawaii, Maui, Lanai and Molokai have a combined population estimated at 1.3 million, or approximately 95% of the total population of the State of Hawaii, and comprise a service area of 5,815 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.

Sales of electricity.

Years ended December 31	2012		2011		2010
	Customer	Electric sales	Customer	Electric sales	Customer	Electric sales
(dollars in thousands)	accounts*	revenues	accounts*	revenues	accounts*	revenues
HECO	297,529	$2,216,675	296,800	$2,103,859	296,422	$1,645,328
HELCO	81,792	439,249	81,199	443,189	80,695	371,746
MECO	68,922	436,836	68,230	417,451	67,739	343,562
	448,243	$3,092,760	446,229	$2,964,499	444,856	$2,360,636

* 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%, 11% and 10% of their operating revenues in 2012, 2011 and 2010, 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 the utilities under which they 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	2012	2011	2010	2009	2008
KWH sales (millions)
Residential	2,582.0	2,769.7	2,830.0	2,893.3	2,924.7
Commercial	3,074.4	3,203.8	3,185.0	3,221.7	3,326.3
Large light and power	3,499.8	3,503.4	3,512.8	3,524.5	3,632.9
Other	49.8	50.0	50.8	50.2	52.3
	9,206.0	9,526.9	9,578.6	9,689.7	9,936.2

KWH net generated and purchased (millions)
Net generated	5,601.7	6,022.2	6,053.6	6,117.6	6,261.8
Purchased	4,093.2	4,009.7	4,062.8	4,119.8	4,248.2
	9,694.9	10,031.9	10,116.4	10,237.4	10,510.0

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

Energy supply (December 31)
Net generating capability—MW 1	1,787	1,787	1,785	1,815	1,687
Firm purchased capability—MW	545	540	540	532	540
	2,332	2,327	2,325	2,347	2,227

Net peak demand—MW 2	1,535	1,530	1,562	1,618	1,590
Btu per net KWH generated	10,533	10,609	10,617	10,753	10,700
Average fuel oil cost per Mbtu (cents)	2,210.4	1,986.7	1,404.8	1,026.4	1,840.0

Customer accounts (December 31)
Residential	392,025	390,133	388,307	385,886	383,042
Commercial	54,005	53,904	54,374	54,527	55,243
Large light and power	577	567	548	558	543
Other	1,636	1,625	1,627	1,613	1,583
	448,243	446,229	444,856	442,584	440,411

Electric revenues (thousands)
Residential	$ 952,159	$ 946,653	$ 781,467	$ 690,656	$ 935,061
Commercial	1,060,983	1,024,725	814,109	694,087	973,048
Large light and power	1,062,226	976,949	752,056	623,159	921,321
Other	17,392	16,172	13,004	10,721	15,069
	$3,092,760	$2,964,499	$2,360,636	$2,018,623	$2,844,499
Average revenue per KWH sold (cents)	33.60	31.12	24.65	20.83	28.63
Residential	36.88	34.18	27.61	23.87	31.97
Commercial	34.51	31.99	25.56	21.54	29.25
Large light and power	30.35	27.89	21.41	17.68	25.36
Other	34.93	32.37	25.63	21.36	28.81

Residential statistics
Average annual use per customer account (KWH)	6,596	7,117	7,317	7,523	7,640
Average annual revenue per customer account	$2,432	$2,433	$2,021	$1,796	$2,443
Average number of customer accounts	391,437	389,160	386,767	384,600	382,821

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, 2012. 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, 20121
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		94.6		16.0		–		–		544.6
	1,755.6		291.7		262.3		10.1		11.8		2,331.5

Net peak demand (MW)	1,141.0		189.3		194.8		4.6		5.5		1,535.2	3
Reserve margin	58.1	%	54.1	%	34.6	%	120.0	%	115.4	%	56.0	%
Annual load factor	73.1	%	70.6	%	67.7	%	64.7	%	68.6	%	72.1	%
KWH net generated and purchased (millions)	7,311.0		1,170.4		1,154.4		26.1		33.0		9,694.9

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: 34.6 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 the electric utilities contain ECACs and purchased power adjustment clauses (PPACs) that allow them to recover purchase power expenses. The PUC approved the PPACs for HECO, HELCO and MECO in March 2011, February 2012 and May 2012, respectively.

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 programs. The electric utilities also receive renewable energy from customers under its Net Energy Metering programs.

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, 2012. 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 August 2012, 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 negotiate an amendment to the PPA to purchase 186 MW of firm capacity, extend the PPA term until September 2032, and amend the energy pricing formula in the PPA. The PUC has not yet issued a declaratory order, but HECO has begun preliminary discussions with AES Hawaii.

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 January 2011, HECO initiated renegotiation of the agreement with Kalaeloa (exempt from the rules under the PUC’s Competitive Bidding Framework).

HECO also entered into a PPA in March 1986 and a firm capacity amendment in April 1991 (the original PPA) with the City and County of Honolulu with respect to a refuse-fired plant (HPower). Under the amended PPA, the HPower facility currently supplies HECO with 46 MW of firm capacity. In May 2012, HECO entered into an amended and restated PPA with the City and County of Honolulu to purchase a total of 73 MW of firm capacity (including the current 46 MW) from the expanded HPower facility for a term of 20 years from the commercial operation date, which will occur once certain conditions precedent and further requirements have been satisfied. The PPA was approved by the PUC in January 2013.

HELCO and MECO firm capacity PPAs. As of December 31, 2012, HELCO has PPAs for 98 MW (of which 94.6 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. PGV’s expansion became commercially operational in March 2012 for a total facility capacity of 34.6 MW.

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 by either party on or after December 31, 2014, with two years’ prior written notice, except that the parties have agreed that notice of termination on December 31, 2014 may be given on or before June 30, 2013.

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 biofuel.

MECO’s and HELCO’s steam generating units burn medium sulfur fuel oil (MSFO) and HELCO’s and MECO’s Maui combustion turbine generating units burn diesel. HELCO’s and MECO’s Maui, Molokai and Lanai diesel engine generating units burn ultra-low-sulfur diesel and biodiesel. 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 of 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 2012, 2011 and 2010:

	HECO		HELCO		MECO		Consolidated
	$/Barrel	¢/MBtu	$/Barrel	¢/MBtu	$/Barrel	¢/MBtu	$/Barrel	¢/MBtu
2012	139.14	2,195.5	129.27	2,112.5	138.60	2,327.4	138.09	2,210.4
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

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
2012	99%	1%	59%	41%	22%	78	%
2011	99	1	56	44	22	78
2010	99	1	58	42	24	76

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 2012, prices of all petroleum fuels trended higher through the spring, peaked in early summer and then moved gradually lower through the remainder of the year. Though prices ended 2012 slightly lower than at the end of the previous year, on average the prices of LSFO, MSFO and diesel were higher in 2012 as a whole, increasing by approximately 8%, 7% and 4%, respectively. The per-unit price of biodiesel exhibited a trend similar to petroleum fuels but peaked in late summer 2012, before falling steadily through the end of the year. The average price for 2012 was approximately comparable to the prior year after the retroactive application of the $1 per gallon federal blenders credit enacted in early 2013.

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 certain older 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 Asian fuel oil 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 generate or purchase will come from fossil fuel in 2013. 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 PPACs. 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 of 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 M. 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), who previously was a senior energy consultant and a senior executive with DTE Energy, and Lorraine H. Akiba (for a term that will expire in June 2018), an attorney in private practice who previously served as the Director of the State Department of Labor and Industrial Relations.

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 (GHG) 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 GHG emissions from its operations. See “Environmental regulation–Global climate change and greenhouse gas emissions reduction” under “Commitments and contingencies” in Note 3 of 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 of 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 of 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. 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 of 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 2012 and 2013 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.

Air quality controls. 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 $4.0 million, $4.3 million and $4.0 million in 2012, 2011 and 2010, respectively, for research and development (R&D). In 2012, 2011 and 2010, 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 2012, 2011 and 2010 related to new technologies, biofuels, energy storage, demand response, seawater cooling traveling screens, electric and hybrid plug in vehicles and other renewables (e.g., wind and solar power integration and solar resource evaluation).

Additional information. 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.

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, 2012. The four plants are situated on HECO-owned land having a combined area of 535 acres and three parcels of land totaling 5.5 acres under leases expiring between June 30, 2016 and December 31, 2018, with options to extend to June 30, 2026. 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 house 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 August 31, 2013 through July 31, 2025 with options to extend to various dates through July 31, 2030.

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 954,036 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, 2012 (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 usable storage capacity of 51,500 barrels of bunker oil and 81,802 barrels of diesel. There are an additional 19,200 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, 2012. 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 81,272 barrels of bunker oil, and 94,586 barrels of diesel. 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, 2012) 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, 2012, ASB was one of the largest financial institutions in the State of Hawaii based on total assets of $5.0 billion and deposits of $4.2 billion. In 2012, ASB’s revenues and net income amounted to approximately 8% and 42% of HEI’s consolidated revenues and net income, respectively, compared to approximately 8% and 43% in 2011 and approximately 11% and 51% in 2010, 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, 2012, 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.

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

Years ended December 31	2012	2011	2010
Common equity to assets ratio
Average common equity divided by average total assets	10.14%	10.24%	10.34%
Return on assets
Net income for common stock divided by average total assets	1.18	1.23	1.20
Return on common equity
Net income for common stock divided by average common equity	11.68	11.99	11.62
Tangible efficiency ratio
Total noninterest expense, less amortization of intangibles, divided by net interest income and noninterest income	59	57	56

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)	2012 vs. 2011						2011 vs. 2010
Increase (decrease) due to	Rate		Volume		Total		Rate		Volume		Total
Income from earning assets
Other investments	$ –		$ (73	)	$ (73	)	$ (23	)	$ (256	)	$ (279	)
Available-for-sale investment and mortgage-related securities	(375	)	(298	)	(673	)	(1,794	)	1,695		(99	)
Loans
Residential 1-4 family	(4,351	)	(6,501	)	(10,852	)	(4,260	)	(9,933	)	(14,193	)
Commercial real estate	(1,941	)	2,417		476		(131	)	1,400		1,269
Home equity line of credit	(947	)	3,118		2,171		(1,633	)	3,000		1,367
Residential land	255		(1,137	)	(882	)	(89	)	(1,603	)	(1,692	)
Commercial loans	(4,077	)	3,570		(507	)	(3,701	)	5,507		1,806
Consumer loans	(390	)	1,556		1,166		262		474		736
Total loans	(11,451	)	3,023		(8,428	)	(9,552	)	(1,155	)	(10,707	)
Total increase (decrease) in net interest income from earning assets	(11,826	)	2,652		(9,174	)	(11,369	)	284		(11,085	)
Expense from costing liabilities
Savings	687		(59	)	628		578		(72	)	506
Interest-bearing checking	77		(4	)	73		160		(15	)	145
Money market	220		111		331		298		(64	)	234
Time certificates	724		804		1,528		2,638		2,190		4,828
Advances from Federal Home Loan Bank	(241	)	618		377		(7	)	20		13
Securities sold under agreements to repurchase	203		37		240		73		81		154
Total increase (decrease) in net interest income from costing liabilities	1,670		1,507		3,177		3,740		2,140		5,880
Total increase (decrease) in net interest income	$(10,156	)	$ 4,159		$ (5,997	)	$ (7,629	)	$ 2,424		$ (5,205	)

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	2012			2011			2010			2009			2008
(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	$1,866,450		49.2	$1,926,774		52.2	$2,087,813		58.9	$2,332,763		62.9	$2,812,177		66.5
Commercial real estate	375,677		9.9	331,931		9.0	300,689		8.5	255,716		6.9	243,109		5.8
Home equity line of credit	630,175		16.6	535,481		14.5	416,453		11.7	326,896		8.8	271,780		6.4
Residential land	25,815		0.7	45,392		1.2	65,599		1.8	96,515		2.6	126,963		3.0
Commercial construction	43,988		1.2	41,950		1.1	38,079		1.1	68,174		1.9	71,579		1.7
Residential construction	6,171		0.2	3,327		0.1	5,602		0.2	16,705		0.5	34,768		0.8
Total real estate loans, net	2,948,276		77.8	2,884,855		78.1	2,914,235		82.2	3,096,769		83.6	3,560,376		84.2

Commercial loans	721,349		19.0	716,427		19.4	551,683		15.5	545,622		14.7	597,234		14.1
Consumer loans	121,231		3.2	93,253		2.5	80,138		2.3	64,360		1.7	72,524		1.7
	3,790,856		100.0	3,694,535		100.0	3,546,056		100.0	3,706,751		100.0	4,230,134		100.0
Less: Deferred fees and discounts	(11,638	)		(13,811	)		(15,530	)		(19,494	)		(24,631	)
Allowance for loan losses	(41,985	)		(37,906	)		(40,646	)		(41,679	)		(35,798	)
Total loans, net	$3,737,233			$3,642,818			$3,489,880			$3,645,578			$4,169,705
Total loans as a % of assets	74.1	%		74.2	%		72.8	%		73.8	%		76.7	%

1 Includes renegotiated loans.

The increase in the loans receivable balance in 2012 and 2011 was primarily due to growth in commercial, commercial real estate, consumer and home equity lines of credit loans as ASB targeted these portfolios because of their shorter duration and/or variable rates. In 2012, ASB ranked No. 1 in Hawaii for home equity line of credit loan production. Offsetting these loan portfolio increases was a decrease in the residential loan portfolio. Although ASB produced nearly $1.0 billion of new, long-term residential loans in 2012, nearly double the level for 2011, it sold more than half those loans to control interest rate risk and repayments were also higher than in 2011. 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 following table summarizes ASB’s loans receivable held for investment based upon contractually scheduled principal payments and expected prepayments allocated to the indicated maturity categories:

December 31	2012				2011
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	$488	$ 912	$ 393	$1,793	$440	$ 965	$ 450	$1,855
Residential loans - Adjustable	36	33	4	73	37	32	3	72
Total residential loans	524	945	397	1,866	477	997	453	1,927

Commercial real estate loans-Fixed	19	64	39	122	13	54	15	82
Commercial real estate loans-Adjustable	56	100	142	298	56	113	123	292
Total commercial real estate loans	75	164	181	420	69	167	138	374

Consumer loans – Fixed	49	74	21	144	51	62	1	114
Consumer loans – Adjustable	48	68	529	645	49	85	431	565
Total consumer loans	97	142	550	789	100	147	432	679

Commercial loans – Fixed	62	107	36	205	48	116	26	190
Commercial loans – Adjustable	220	266	30	516	212	268	46	526
Total commercial loans	282	373	66	721	260	384	72	716

Total loans - Fixed	618	1,157	489	2,264	552	1,197	492	2,241
Total loans - Adjustable	360	467	705	1,532	354	498	603	1,455
Total loans	$978	$1,624	$1,194	$3,796	$906	$1,695	$1,095	$3,696

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 of 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, clean energy loans, 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 residential mortgage 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 of 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 real estate 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, 2012, 2011 and 2010, ASB had $6.1 million, $7.3 million and $4.3 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, 2012, 2011, 2010, 2009 and 2008 were immaterial or nil. The following table sets forth certain information with respect to nonaccrual and troubled debt restructured loans:

December 31	2012			2011			2010			2009			2008
(dollars in thousands)
Nonaccrual loans—
Real estate
Residential 1-4 family	$	26,721		$	28,298		$	36,420		$	31,848		$	7,468
Commercial real estate	6,750			3,436			–			344			–
Home equity line of credit	2,349			2,258			1,659			2,755			759
Residential land	8,561			14,535			15,479			25,164			7,652
Residential construction	–			–			–			326			326
Total real estate loans	44,381			48,527			53,558			60,437			16,205
Consumer loans	284			281			341			715			523
Commercial loans	20,222			17,946			4,956			4,171			2,766
Total nonaccrual loans	$	64,887		$	66,754		$	58,855		$	65,323		$	19,494
Nonaccrual loans to end of period loans	1.7		%	1.8		%	1.7		%	1.8		%	0.5		%
Troubled debt restructured loans not included above—
Real estate
Residential 1-4 family	$	6,759		$	5,029		$	5,150		$	1,986		$	1,913
Commercial real estate	–			–			1,963			513			–
Residential land	11,090			24,828			27,689			15,665			2,125
Total real estate loans	17,849			29,857			34,802			18,164			4,038
Commercial loans	43			15,386			4,035			2,904			4,612
Total troubled debt restructured loans	$	17,892		$	45,243		$	38,837		$	21,068		$	8,650
Nonaccrual and troubled debt restructured loans to end of period loans	2.2		%	3.1		%	2.8		%	2.3		%	0.7		%

ASB realized $3.0 million, $6.3 million and $3.6 million of interest income on nonaccrual and troubled debt restructured (TDR) loans in 2012, 2011 and 2010, respectively. If these loans would have earned interest in accordance with their original contractual terms ASB would have realized $6.7 million, $9.9 million and $3.8 million in 2012, 2011 and 2010, respectively.

In 2012, nonaccrual loans decreased by $1.9 million due to improved credit quality in the residential 1-4 family and consumer portfolios (residential 1-4 family lower by $1.6 million and residential land loans lower by $5.9 million), partially offset by higher nonaccrual commercial real estate and commercial loans of $5.6 million. The improvement is attributed to stabilized or increasing property values, more financial flexibility of borrowers, and overall general economic improvement in the State of Hawaii. TDR loans decreased by $27.4 million due to decreases of $15.3 million and $13.7 million of commercial loans and residential land loans, respectively, classified as TDR. ASB evaluates the loan transaction to determine if the borrower is in financial difficulty and if the restructured terms are considered concessions—typically terms that are out of market, beyond normal or reasonable standards, or otherwise not available to a non-troubled borrower in the normal market place. A loan classified as TDR must meet both criteria of financial difficulty and concession. 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.

Allowance for loan losses. See “Allowance for loan losses” in Note 1 of HEI’s Consolidated Financial Statements.

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

(dollars in thousands)	2012		2011		2010		2009		2008
Allowance for loan losses, January 1	$37,906		$40,646		$41,679		$35,798		$30,211

Provision for loan losses	12,883		15,009		20,894		32,000		10,334

Charge-offs
Residential 1-4 family	3,183		5,528		6,142		3,129		51
Home equity line of credit	716		1,439		2,517		2,331		21
Residential land	2,808		4,071		6,487		4,217		282
Total real estate loans	6,707		11,038		15,146		9,677		354
Commercial loans	3,606		5,335		6,261		14,853		3,447
Consumer loans	2,517		3,117		3,408		2,436		1,825
Total charge-offs	12,830		19,490		24,815		26,966		5,626
Recoveries
Residential 1-4 family	1,328		110		744		151		46
Home equity line of credit	108		25		63		–		–
Residential land	1,443		170		63		–		–
Total real estate loans	2,879		305		870		151		46
Commercial loans	649		869		1,537		404		548
Consumer loans	498		567		481		292		285
Total recoveries	4,026		1,741		2,888		847		879
Allowance for loan losses, December 31	$41,985		$37,906		$40,646		$41,679		$35,798
Ratio of allowance for loan losses, December 31, to end of period loans	1.11	%	1.03	%	1.15	%	1.12	%	0.84	%
Ratio of provision for loan losses during the year to average loans outstanding	0.35	%	0.42	%	0.58	%	0.81	%	0.25	%
Ratio of net charge-offs during the year to average loans outstanding	0.24	%	0.49	%	0.61	%	0.66	%	0.11	%

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	2012			2011			2010
(dollars in thousands)	Balance	Allowance to loan receivable %	Loan receivable % of total	Balance	Allowance to loan receivable %	Loan receivable % of total	Balance	Allowance to loan receivable %	Loan receivable % of total
Real estate
Residential 1-4 family	$ 6,068	0.33	49.2	$ 6,500	0.34	52.2	$ 6,497	0.31	58.9
Commercial real estate	2,965	0.79	9.9	1,688	0.51	9.0	1,474	0.49	8.5
Home equity line of credit	4,493	0.71	16.6	4,354	0.81	14.5	4,269	1.03	11.7
Residential land	4,275	16.56	0.7	3,795	8.36	1.2	6,411	9.77	1.8
Commercial construction	2,023	4.60	1.2	1,888	4.50	1.1	1,714	4.50	1.1
Residential construction	9	0.15	0.2	4	0.12	0.1	7	0.12	0.2
Total real estate loans, net	19,833	0.67	77.8	18,229	0.63	78.1	20,372	0.70	82.2
Commercial loans	15,931	2.21	19.0	14,867	2.08	19.4	16,015	2.90	15.5
Consumer loans	4,019	3.32	3.2	3,806	4.08	2.5	3,325	4.15	2.3
	39,783	1.05	100.0	36,902	1.00	100.0	39,712	1.12	100.0
Unallocated	2,202			1,004			934
Total allowance for loan losses	$41,985			$37,906			$40,646

December 31	2009			2008
(dollars in thousands)	Balance	Allowance to loan receivable %	Loan receivable % of total	Balance	Allowance to loan receivable %	Loan receivable % of total
Real estate
Residential 1-4 family	$ 5,522	0.24	62.5	$ 4,024	0.14	66.2
Commercial real estate	861	0.34	6.9	2,229	0.92	5.7
Home equity line of credit	4,679	1.43	8.8	548	0.20	6.4
Residential land	4,252	4.41	2.6	1,953	1.54	3.0
Commercial construction	3,068	4.50	1.8	1,748	2.44	1.7
Residential construction	19	0.11	0.5	88	0.25	0.8
Total real estate loans, net	18,401	0.59	83.1	10,590	0.30	83.8
Commercial loans	19,498	3.57	14.6	22,294	3.73	14.0
Consumer loans	2,590	4.02	2.3	2,190	3.02	2.2
	40,489	1.09	100.0	35,074	0.83	100.0
Unallocated	1,190			724
Total allowance for loan losses	$41,679			$35,798

In 2012, ASB’s allowance for loan losses increased by $4.1 million due to growth in the loan portfolios (2.6% growth or $96.3 million increase in outstanding balances) and higher impairment reserves for the commercial and commercial real estate loan portfolios. Although overall loan quality improved, a number of commercial borrowers experienced financial stress during the year. A loan is deemed impaired when it is probable (more likely than not) that the bank will be unable to collect all amounts due according to the loan’s original contractual terms. In 2012, delinquencies significantly improved in the residential 1-4 family and consumer loan portfolios, while total bank net loan charge-offs of $8.8 million was about half the level in 2011, reflecting the gradual improvement in the local economy including a recovery of the housing market. ASB’s provision for loan losses was $12.9 million in 2012, compared to $15.0 million in 2011.

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 stabilized, the housing market remained stagnant.

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. The weighted-average yield on investments during 2012, 2011 and 2010 was 1.99%, 2.01% and 2.18%, respectively. ASB did not maintain a portfolio of securities held for trading during 2012, 2011 and 2010.

As of December 31, 2012, 2011 and 2010, ASB’s investment in stock of the FHLB of Seattle amounted to $96 million, $98 million and $98 million, respectively. 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. In third and fourth quarters of 2012, the FHLB of Seattle was granted authority to repurchase excess stock from its members. ASB’s pro-rata share of the repurchase amount was $2 million. 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 of 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, 2012, 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	$ 75	$ 74	$ 14	$ 5	$ 168
Mortgage-related securities - FNMA, FHLMC and GNMA	118	186	76	21	401
Municipal bonds	–	16	55	–	71
	$193	$276	$145	$26	$640
Weighted average yield	2.50%	1.69%	2.29%	2.36%

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 $160 million in 2012 compared to an inflow of $95 million in 2011 and an outflow of $83 million in 2010.

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	2012			2011			2010
(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	$1,727,754	41.9%	0.07%	$1,672,033	41.5%	0.11%	$1,608,650	40.2%	0.14%
Checking	1,672,750	40.6	0.01	1,510,848	37.5	0.01	1,392,698	34.8	0.02
Money market	202,539	4.9	0.16	250,682	6.2	0.26	232,809	5.8	0.38
Certificate	517,752	12.6	0.94	598,360	14.8	1.07	768,991	19.2	1.46
Total deposits	$4,120,795	100.0%	0.16%	$4,031,923	100.0%	0.22%	$4,003,148	100.0%	0.37%

As of December 31, 2012, ASB had $105.9 million in certificate accounts of $100,000 or more, maturing as follows:

(in thousands)		Amount
Three months or less		$ 22,265
Greater than three months through six months		13,237
Greater than six months through twelve months		23,791
Greater than twelve months		46,563
		$105,856

This compares with $119.2 million in such certificate accounts in 2011.

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 of 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 2012 compared to 2011 was due to a decrease in retail repurchase agreements. 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.

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, 2012, 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 are subject to the regulatory supervision of the OCC and FRB, respectively, 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 of 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, 2012.

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, 2012, ASB was in compliance with all of the minimum standards with a core capital ratio of 9.1% (compared to a 4.0% requirement), a tangible capital ratio of 9.1% (compared to a 1.5% requirement) and total risk-based capital ratio of 12.8% (based on risk-based capital of $496.3 million, $185.3 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, 2012, 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, 2012, ASB’s unused FHLB of Seattle borrowing capacity was approximately $0.9 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, 2012, ASB had loan commitments, undisbursed loan funds and unused lines and letters of credit of $1.5 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, 2012, 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, 2012, 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 2012, ASB was in compliance with the QTL test. As of December 31, 2012, 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, 2012, 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 $96 million, or $82 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 deposit and 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.

Additional information. 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 of HEI’s Consolidated Financial Statements.

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, 2012		Owned	Leased	Total
Oahu		7	32	39
Maui		3	4	7
Kauai		2	2	4
Hawaii		2	4	6
Molokai		–	1	1
		14	43	57

As of December 31, 2012, the net book value (NBV) of branches and office facilities is $46 million ($39 million NBV of the land and improvements for the branches and office facilities owned by ASB and $7 million represents the NBV of ASB’s leasehold improvements). The leases expire on various dates through February 2033, but many of the leases have extension provisions.

As of December 31, 2012, ASB owned 118 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, 2012) 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, 2011 and 2012), 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, 2012, 88% 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 results of competitive bidding, competition from IPPs, customer self-generation and the rate at which technological developments facilitating non-utility generation of electricity occur may adversely affect the utilities and the results of their operations.

· 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 $6 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 GHG 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 accounting principles (including the possible adoption of International Financial Reporting Standards or new U.S. accounting standards), 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 $865 million as of December 31, 2012) 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 $322 million as of December 31, 2012) 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 implemented, each of the electric utilities will 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 pension and OPEB tracking mechanisms, and more recently a decoupling mechanism, a PPAC, and a renewable energy infrastructure program surcharge. A change in, or the elimination of, any of these cost recovery mechanisms could have a material adverse effect on the electric utilities.

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. Also, in January 2013, the utilities and the Consumer Advocate signed a settlement agreement, subject to approval by the PUC, to write off $40 million of costs in lieu of conducting PUC-ordered regulatory audits of the CIP CT-1 and the CIS projects. 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 73% of the net energy generated or purchased by the electric utilities in 2012 was generated from the burning of fossil fuel oil, and purchases of power by the electric utilities provided about 42% 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 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.

The foregoing legislation or legislation that now is, or may in the future be, proposed present risks and uncertainties for the utilities.

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. These initiatives include, but are not limited to, 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. The implementation of these or other HCEI programs may adversely impact 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 47% of ASB’s loan portfolio as of December 31, 2012 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 2010, 2011 and 2012 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, 2012 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 18% during 2012 and now comprises 21% 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 of 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	60	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	59	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

Chester A. Richardson	64	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

Richard M. Rosenblum	62	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	50	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, and Korea Exchange Bank, Chairman and Chief Executive Officer, 4/07 to 3/09

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 REGISTRANT’S 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)” of 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 7, 2013, was 8,831.

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 2012 and 2011 were as follows:

Quarters ended	2012	2011
March 31	$18,260,844	$17,639,622
June 30	18,260,844	17,639,622
September 30	18,260,844	17,639,622
December 31	18,260,844	17,639,622

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 of HEI’s Consolidated Financial Statements.

ITEM 6. SELECTED FINANCIAL DATA

HEI:

Hawaiian Electric Industries, Inc. and Subsidiaries
Years ended December 31	2012			2011			2010			2009			2008
(dollars in thousands, except per share amounts)

Results of operations
Revenues	$	3,374,995		$	3,242,335		$	2,664,982		$	2,309,590		$	3,218,920
Net income for common stock	$	138,658		$	138,230		$	113,535		$	83,011		$	90,278
Basic earnings per common share	$	1.43		$	1.45		$	1.22		$	0.91		$	1.07
Diluted earnings per common share	$	1.42		$	1.44		$	1.21		$	0.91		$	1.07
Return on average common equity	8.9		%	9.2		%	7.8		%	5.9		%	6.8		%
Financial position *
Total assets	$	10,149,132		$	9,594,477		$	9,087,409		$	8,925,002		$	9,296,828
Deposit liabilities	4,229,916			4,070,032			3,975,372			4,058,760			4,180,175
Other bank borrowings	195,926			233,229			237,319			297,628			680,973
Long-term debt, net	1,422,872			1,340,070			1,364,942			1,364,815			1,211,501
Preferred stock of subsidiaries – not subject to mandatory redemption	34,293			34,293			34,293			34,293			34,293
Common stock equity	1,593,865			1,528,706			1,480,394			1,438,405			1,386,211
Common stock
Book value per common share *	$	16.28		$	15.92		$	15.63		$	15.55		$	15.31
Market price per common share
High	29.24			26.79			24.99			22.73			29.75
Low	23.65			20.59			18.63			12.09			20.95
December 31	25.14			26.48			22.79			20.90			22.14
Dividends per common share	1.24			1.24			1.24			1.24			1.24
Dividend payout ratio	87		%	86		%	102		%	137		%	116		%
Market price to book value per common share *	154		%	166		%	146		%	134		%	144		%
Price earnings ratio **	17.6		x	18.3		x	18.7		x	23.0		x	20.7		x
Common shares outstanding (thousands) *	97,928			96,038			94,691			92,521			90,516
Weighted-average	96,908			95,510			93,421			91,396			84,631
Shareholders ***	31,349			32,004			32,624			33,302			33,588
Employees *	3,870			3,654			3,426			3,453			3,560

* At December 31. The Company has revised its electric utilities’ previously issued financial statements to correct an error that resulted in the understatement of franchise taxes, net of tax benefits, that should have been recorded in years prior to 2008. See “Reclassifications and revisions” in Note 1 of HEI’s “Notes to Consolidated Financial Statements.”

** 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. Represents registered shareholders plus participants in the HEI Dividend Reinvestment and Stock Purchase Plan (DRIP) who are not registered shareholders. As of February 7, 2013, HEI had 8,831 registered shareholders (i.e., holders of record of HEI common stock), 27,284 DRIP participants and total shareholders of 31,294.

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 2012, 2011, 2010, 2009 and 2008, 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 $0.19, $0.21, $(0.02), $(0.33) and $(0.17) per share, respectively, for both unvested restricted stock awards and unrestricted common stock. For 2012, 2011, 2010, 2009 and 2008, 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 $0.18, $0.20, $(0.03), $(0.33) and $(0.17) per share, respectively, for both unvested restricted stock awards and unrestricted common stock.

HECO:

The information required by this Item 6 for HECO 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 and HECO (in the case of HECO, only the information related to HECO and its subsidiaries):

The following discussion should be read in conjunction with Hawaiian Electric Industries, Inc.’s (HEI’s) consolidated financial statements and accompanying notes and, in the case of HECO, in conjunction with HECO’s consolidated financial statements and accompanying notes which are incorporated by reference to pages 5 to 47 of HECO Exhibit 99.2. 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. 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 2012, net income for HEI common stock was $139 million, up slightly from $138 million in 2011 due to lower losses for the “other” segment, partly offset by slightly lower earnings for the electric utility and bank segments. Basic earnings per share were $1.43 per share in 2012, down 1% from $1.45 per share in 2011 due to the effects of the higher weighted average number of shares outstanding.

The electric utilities’ strategic focus has been to meet Hawaii’s energy needs by modernizing and adding needed infrastructure through capital investment, placing emphasis on energy efficiency and conservation, pursuing renewable energy generation and taking the necessary steps to secure regulatory support for their plans. Electric utility net income for common stock in 2012 of $99 million decreased 1% from the prior year due primarily to a writedown of $24 million (net of taxes) of project costs in lieu of conducting regulatory audits, partly offset by higher rate increases. Key to results for 2013 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 continues to develop and introduce new products and services in order to meet the needs of both consumer and commercial customers. Additionally, ASB is making the investments in people and technology necessary to adapt to a constantly changing banking industry and remain competitive. ASB’s earnings in 2012 of $58.6 million decreased $1.2 million compared to prior year net income due primarily to lower net interest income and higher noninterest expenses, partly offset by higher noninterest income and a lower provision for loan losses. ASB’s future financial results will continue to be impacted by the interest rate environment and the quality of ASB’s loan portfolio.

HEI’s “other” segment had a net loss in 2012 of $19 million, compared to the net loss of $22 million 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, 2012 was 4.9%. The dividend payout ratios based on net income for common stock for 2012, 2011 and 2010 were 87%, 86% and 102%, 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; Honolulu Board of REALTORS® Bureau of Economic Analysis and national and local newspapers).

Hawaii’s tourism industry, a significant driver of Hawaii’s economy, set new records in 2012. State visitor arrivals grew by 9.6% in 2012 over 2011. Total State visitor arrivals reached a new record in 2012. State visitor expenditures also continued to grow, increasing by 18.7% in 2012 over 2011, achieving another record for the State. Hotel occupancies and room rates also continued to rise. The outlook for the visitor industry remains positive with the Hawaii Tourism Authority expecting a 9.4% increase in airline seat capacity for the first quarter of 2013 over 2012.

Hawaii’s unemployment rate was 5.2% in December 2012, lower than the state’s 6.6% rate in December 2011 and the December 2012 national unemployment rate of 7.8%. Hawaii’s unemployment rate has slowly improved after reaching a high of 7.1% in 2009.

Hawaii real estate activity improved in 2012 as indicated by the home resale market. The median sales price for single family residential homes on Oahu increased by 7.8% and home sales increased 6.5% over 2011. The 2012 median sales price for Oahu condominiums rose 5.8% above 2011 and closed sales increased 8.2%.

Hawaii’s petroleum product prices reflect supply and demand in the Asia-Pacific region and the price of crude oil in international markets. The dramatic reduction in Japan’s nuclear production following the tragic earthquake and tsunami in March 2011 has increased regional demand for energy supplies, including petroleum, and the prices of the utilities’ fuels have accordingly remained at the elevated 2011 level throughout 2012.

Based on the current moderate economic outlook, the Federal Open Market Committee (FOMC) maintained their efforts to stimulate the U.S. economy in a meeting on December 11-12, 2012. The FOMC held the federal funds rate target at 0% to 0.25% and expects to maintain the record low rates at least as long as the unemployment rate is above 6.5% and inflation remains under control. The FOMC will continue to purchase additional agency mortgage-backed securities out of concern that economic growth may not be strong enough to generate sustained improvement in labor market conditions. In an effort to assist broader accommodative financial conditions, the FOMC announced it will initially purchase $45 billion per month of longer-term Treasury securities after its program to extend the average maturity of its holdings is completed at the end of 2012. The FOMC stated it will closely monitor economic information in the coming months and may take additional steps to improve the labor market in a context of price stability.

Overall, Hawaii’s economy is expected to see only modest growth in 2012 and 2013 with local economic growth supported by moderate improvement in the U.S. economy and impeded by continued uncertainty in global economies. Based on updated economic projections and expectations of renewable self-generation and energy-efficiency additions, the electric utilities’ 2013 kilowatthour sales are expected to decline slightly from 2012 levels and then remain relatively flat until 2022.

Recent tax developments. The Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010 contained major tax provisions that impacted the Company through 2012, including the 50% and 100% bonus depreciation provisions for qualified property that resulted in an estimated net increase in federal tax depreciation of $116 million for 2012, primarily attributable to the utilities. In January 2013, the American Taxpayer Relief Act of 2012 was signed into law and provided a one year extension of 50% bonus depreciation, which is estimated to increase the Company’s federal tax depreciation for 2013 by $138 million, primarily attributable to the utilities.

In December 2011, the Internal Revenue Service (IRS) issued regulations that provide a framework for determining whether expenditures are deductible as repairs, effective January 1, 2012. But in December 2012, the IRS delayed the effective date of these regulations until January 1, 2014. The Company will review these regulations and will analyze any subsequently issued transitional rules and guidance for their impacts and for the opportunities they present for 2012 and future years.

Health care reform. On June 28, 2012, the US Supreme Court upheld the Patient Protection and Affordable Care Act, the 2010 health care reform law. Currently, Hawaii’s Prepaid Health Care Act generally provides greater benefits to employees and dependents because of cost sharing limitations. The Company will continue to comply with its obligations under these laws and to monitor the interaction of the state and federal laws.

Results of operations.

(dollars in millions, except per share amounts)	2012		% change	2011		% change	2010

Revenues	$	3,375	4	$	3,242	22	$	2,665
Operating income	284		(2)	290		13	256
Net income for common stock	139		–	138		22	114
Net income (loss) by segment:
Electric utility	$	99	(1)	$	100	31	$	77
Bank	59		(2)	60		2	58
Other	(19)		NM	(22)		NM	(21)
Net income for common stock	$	139	–	$	138	22	$	114
Basic earnings per share	$	1.43	(1)	$	1.45	19	$	1.22
Diluted earnings per share	$	1.42	(1)	$	1.44	19	$	1.21
Dividends per share	$	1.24	–	$	1.24	–	$	1.24
Weighted-average number of common shares outstanding (millions)	96.9		1	95.5		2	93.4
Dividend payout ratio	87%			86%			102%

NM Not 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 2012, the Company’s retirement benefit plans’ assets generated a gain of 13.9%, net of investment management fees, resulting in net earnings and unrealized gains of $140 million, compared to net losses and unrealized losses of $7 million for 2011 and net earnings and unrealized gains of $145 million for 2010. The

market value of the retirement benefit plans’ assets for December 31, 2012 and 2011 were $1.1 billion and $983 million, respectively.

The Company intends to make contributions to the qualified pension 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 net periodic pension cost is expected to be higher than the ERISA minimum required contribution for 2013. Therefore, to satisfy the requirements of the electric utilities’ pension tracking mechanism, net periodic pension cost will be the basis of the cash funding for 2013. Based on plan assets as of December 31, 2012 and various assumptions in Note 9 of HEI’s “Notes to Consolidated Financial Statements,” the Company estimates the net periodic pension cost contribution to be $85 million ($2 million for HEI and $83 million for the utilities).

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)	2012	2011	(Estimated) 2013	2012	2011	2010	2012	2011	2010
Consolidated HEI	$36	$28	$26	$22	$22	$24	$68	$66	$64
Consolidated HECO	1	–	23	20	21	24	63	61	60
ASB	24	19	1	–	–	(1)	3	3	3

Based on various assumptions in Note 9 of HEI’s “Notes to Consolidated Financial Statements”, sensitivities of the projected benefit obligation (PBO) and accumulated postretirement benefit obligation (APBO) as of December 31, 2012, 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	$(114)/$129
Other benefits
Discount rate	+/– 50	(13)/14
Health care cost trend rate	+/– 100	6/(6)

The impact on 2013 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)	2012	% change	2011	% change	2010

Revenues 1	$ –	NM	$ (1)	NM	$ –
Operating loss	(17)	NM	(17)	NM	(15)
Net loss	(19)	NM	(22)	NM	(22)

1 Including writedowns of and net gains and losses from investments.

NM Not 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 $0.5 million as of December 31, 2012); The Old Oahu Tug Service, Inc. (TOOTS), a maritime freight transportation company that ceased operations in 1999; and 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 $16 million in 2012 compared to $15 million in 2011 and $13 million in 2010. In 2012, HEI had higher executive compensation and employee benefits expenses, including retirement benefits. In 2011, expense increased primarily due to the accrual of $3 million of contributions to be made to the HEI Charitable Foundation in 2012.

The “other” segment’s interest expenses were $16 million in 2012, $22 million in 2011 and $20 million in 2010. In 2012, HEI had lower average borrowings and interest rates. 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 forward starting swaps. Also in 2010, there was a higher level of borrowings. The “other” segment’s income tax benefits were $15 million in 2012, $17 million in 2011 and $13 million in 2010. 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 2.1% in 2012, 3.2% in 2011 and 1.6% in 2010. Hawaii inflation, as measured by the Honolulu CPI, was 3.7% in 2011, 2.1% in 2010 and 0.5% in 2009. The Department of Business, Economic Development and Tourism estimates average Honolulu CPI to have been 2.5% in 2012 and forecasts it to be 2.4% for 2013.

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 of HEI and its subsidiaries was as follows:

December 31, 2012	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	$ 4,230	$4,040	$ 134	$ 46	$ 10
Other bank borrowings	196	96	–	100	–
Long-term debt	1,423	50	111	75	1,187
Interest on certificates of deposit, other bank borrowings and long-term debt	1,162	80	144	129	809
Operating leases, service bureau contract and maintenance agreements	125	28	44	24	29
Open purchase order obligations 2	110	84	17	9	–
Fuel oil purchase obligations (estimate based on December 31, 2012 fuel oil prices)	2,643	921	1,315	407	–
Power purchase obligations–minimum fixed capacity charges	1,255	118	249	195	693
Liabilities for uncertain tax positions	1	–	1	–	–
Total (estimated)	$11,145	$5,417	$2,015	$985	$2,728

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, 2012		Total
(in millions)
Other commercial commitments to ASB customers Loan commitments (primarily expiring in 2012)	$	31
Loans in process		67
Unused lines and letters of credit		1,416
Total	$	1,514

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, 2012, 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 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 $10.1 billion as of December 31, 2012 and $9.6 billion as of December 31, 2011.

The consolidated capital structure of HEI (excluding deposit liabilities and other bank borrowings) was as follows:

December 31	2012		2011
(dollars in millions)

Short-term borrowings—other than bank	$ 84	3%	$ 69	2%
Long-term debt, net—other than bank	1,423	45	1,340	45
Preferred stock of subsidiaries	34	1	34	1
Common stock equity	1,594	51	1,529	52
	$3,135	100%	$2,972	100%

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

	Year ended December 31, 2012
(in millions)		Average balance	End-of-period balance	December 31, 2011
Short-term borrowings 1
Commercial paper		$ 47	$ 84	$ 69
Line of credit draws		–	–	–
Undrawn capacity under HEI’s line of credit facility (expiring December 5, 2016)			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 7, 2013, HEI’s outstanding commercial paper balance was $93 million and its line of credit facility was undrawn. The maximum amount of HEI’s short-term borrowings in 2012 was $99 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, 2012. 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.

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.

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, 2012, Moody’s maintained HEI’s long-term and short-term (commercial paper) ratings and stable outlook, indicating that the long-term rating reflects the relatively stable earnings and cash flow historically provided by its vertically integrated utility businesses and banking operation, improving financial performance, particularly at the utility which has helped to lower the dividend payout ratio. 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% (16.5% last twelve months as of March 31, 2012 – latest reported by Moody’s) and its cash flow coverage of interest fell below 3.3 times (4.3 times last twelve months as of March 31, 2012 – latest reported by Moody’s) on a sustainable basis. On November 29, 2012, S&P maintained HEI’s long-term and corporate credit rating of “BBB-”, short-term (commercial paper) rating of “A-3”, stable outlook, “strong” business risk profile and “aggressive” financial risk profile. The stable outlook reflects S&P’s view that the consolidated credit profile will remain consistent with the HEI “BBB-” ratings and incorporates the benefits of decoupling, expectations of supportive rate case outcomes and a balanced funding approach that supports the current capital structure. S&P indicated the corporate credit rating would be lowered if HEI’s financial performance weakens so that funds from operations (FFO) to total debt is less than 12% and debt to capital approaches 60% on a consistent basis.

As of February 7, 2013, 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 provided new capital of $47 million (approximately 1.8 million shares) in 2012, $24 million (approximately 1.0 million shares) in 2011 and $43 million (approximately 1.9 million shares) in 2010. From August 18, 2011 to January 8, 2012, 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 $235 million in 2012, $250 million in 2011 and $341 million in 2010. Investing activities used net cash of $427 million in 2012, $327 million in 2011 and $279 million in 2010. In 2012, 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 $142 million in 2012, $16 million in 2011 and $(235) million in 2010. In 2012, net cash provided by financing activities included net increases in deposits, long-term debt and short-term borrowings and proceeds from the issuance of common stock under HEI plans, offset by the net decrease in retail repurchase agreements 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 2012, HECO and ASB (via ASHI) paid cash dividends to HEI of $73 million and $45 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 55% at December 31, 2012), 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 2013 through 2015 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 $150 million will be required during 2013 through 2015 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 and/or dividends from subsidiaries. Medium-term notes of $50 million maturing in March 2013 are expected to be replaced with new debt. In addition, HECO special purpose revenue bonds (SPRBs) totaling $11 million will be maturing during 2013 through 2015 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 2013 through 2015 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 OPEB plans. The Company’s contributions to the retirement benefit plans totaled $78 million in 2012 ($63 million by the utilities, $2 million by HEI and $13 million by ASB), $75 million in 2011 ($73 million by the utilities, $2 million by HEI and nil by ASB) and $32 million in 2010 ($31 million by the utilities, $1 million by HEI and nil by ASB) and are expected to total $86 million in 2013 ($84 million by the utilities, $2 million by HEI and nil by ASB). These contributions satisfied the minimum funding requirements pursuant to ERISA, including changes promulgated by the Pension Protection Act of 2006, and the requirements of the electric utilities’ pension and OPEB tracking mechanisms. In addition, the Company paid directly $1 million of benefits in 2012, $2 million in 2011 and $2 million in 2010 and expects to pay $2 million of benefits in 2013. 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” and “Risk Factors” 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 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.

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, 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, 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. Changes in interest rates and credit spreads also affect the fair value of ASB’s investment and mortgage-related securities. 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.

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 $6 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 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 both phases 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) embracing energy efficiency and load management programs.

Utility strategic progress. In 2012, 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, decoupling was implemented by HECO on March 1, 2011, by HELCO on April 9, 2012 and by MECO on May 4, 2012. Decoupling is a regulatory model that is intended to facilitate meeting the State of Hawaii’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 certain O&M expenses and rate base changes. 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 revenues between rate cases in the event the utility exceeds the ROACE allowed in its most recent rate case. Decoupling provides for more timely cost recovery and earning on investments. The implementation of decoupling has resulted in an improvement in the utilities’ 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.

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

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

2. managing O&M expenses relative to authorized O&M adjustments; and

3. regulatory outcomes that cover O&M requirements and rate base items not included in the RAMs.

In January 2013, the utilities and Consumer Advocate signed a settlement agreement, subject to PUC approval, to write off $40 million of CIS project costs, in lieu of conducting regulatory audits of two major projects. See “Subsequent event” in Note 3 of HEI’s “Notes to Consolidated Financial Statements.”

Future earnings growth is also dependent on rate base growth. The utilities’ five-year 2013-2017 forecast reflects net capital expenditures of $2.9 billion and a compounded annual rate base growth rate in the range of 5% to 10%. Many of the major initiatives within this forecast are expected to be completed beyond the 5-year period. Major initiatives which comprise approximately 35% 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 more energy from renewables into the system. Estimates for these initiatives could change over time, based on external factors such as the timing and scope of environmental regulations, unforeseen delays in permitting and the outcome of competitive bidding for new generation.

Actual and PUC-allowed returns were as follows:

%	Return on rate base (RORB)*			ROACE**
Year ended December 31, 2012	HECO	HELCO	MECO	HECO	HELCO	MECO
Utility returns	8.15	6.99	5.95	7.6	5.9	5.4
PUC-allowed returns	8.11	8.31	7.91	10.0	10.0	10.0
Difference	0.04	(1.32)	(1.96)	(2.4)	(4.1)	(4.6)

* 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 2012.

The approval of decoupling by the PUC will help the utilities to gradually improve their ROACEs beyond 2012, which will facilitate the utilities’ ability to effectively raise capital for needed infrastructure investments. However, the utilities continue to expect an ongoing gap between their PUC-allowed ROACEs and the ROACEs they actually achieve. The timing of general rate case decisions, the effective date of the RAMs and the PUC’s consistent exclusion of certain expenses from rates are estimated to have a consolidated ROACE impact of 120 to 150 basis points per year. In addition, there are other items that are not covered by the annual RAMs that could also have an ongoing impact on the ROACEs actually achieved by the utilities. For example, investments in software projects, O&M in excess of indexed escalations and changes in fuel inventory must be addressed in a general rate case. While the specific magnitude of the impact can fluctuate depending on the size of the projects and exogenous factors, the utilities anticipate that these items could incrementally impact consolidated ROACE by 50 to 75 basis points in each of the next two years.

As part of decoupling, HECO also tracks its rate-making ROACE as calculated under the earnings sharing mechanism and which includes only items considered in establishing rates. Earnings over and above the ROACE allowed by the PUC are shared between HECO and its ratepayers on a tiered basis. For 2012, HECO’s rate-making ROACE was 10.56%, which was above the PUC allowed 10% ROACE and triggered its earnings sharing mechanism. As a result, HECO will credit its customers $2 million for their portion of the earnings sharing. HECO’s 2012 rate-making ROACE of 10.56% included various adjustments to HECO’s actual ROACE of 7.6% such as the exclusion of the partial writedown of CIS project costs to reflect the settlement agreement, subject to PUC approval, and of other expenses not considered in establishing electric rates (e.g., executive bonuses and advertising). HELCO’s rate-making ROACE was 7.79% and MECO’s rate-making ROACE was 6.69%, which did not trigger the earnings sharing mechanism.

Decoupling implementation. 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. Under the decoupling tariff order 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’s 2012 annual decoupling filing for the tariff that is effective June 1, 2012 through May 31, 2013 reflects a RAM adjustment of $7.0 million ($3.7 million for O&M costs and $3.3 million for invested capital). The filing also includes the collection of the accrued RBA balance as of December 31, 2011 and associated revenue taxes of $22.4 million. Under the January 2013 settlement agreement with the Consumer Advocate, subject to PUC approval, the parties agreed that, starting in 2014, HECO will be allowed to record RAM revenues starting January 1 of each year through 2016. See “Subsequent event” in Note 3 of HEI’s “Notes to Consolidated Financial Statements.”

HELCO and MECO began tracking their target revenues and actual recorded revenues via RBAs on April 9, 2012 and May 4, 2012, respectively, when their 2010 test year final rates went into effect.

HELCO’s tariff for its annual RAM for 2012 reflects a revenue adjustment that results in a reduction in annual revenues of $2.1 million, effective through May 31, 2013. MECO filed its 2012 RAM (calculated to be $0.1 million) for informational purposes only since the pending interim D&O for its 2012 test year rate case was anticipated to be issued shortly. MECO’s interim D&O for its 2012 test year rate case was issued on May 21, 2012.

Results of operations.

· 2012 vs. 2011

2012	2011	Increase (decrease)		(dollar in millions, except per barrel amounts)
$3,109	$2,979	$130		Revenues. Increase largely due to:
			82	Higher fuel oil and purchased energy costs partially offset by lower KWH sales adjusted for decoupling mechanisms and revenue taxes thereon
			32	Rate increases granted to HECO for the 2011 test year, partly offset by the 2011 test year refund
			7	Interim rate increases granted to MECO for the 2010 test year

1,297	1,265	32		Fuel oil expense. Increase largely due to higher fuel prices, partly offset by lower KWHs generated

725	690	35		Purchased power expense. Increase largely due to higher purchased energy costs and KWHs purchased

272	257	15		Other operation expense. Increase largely due to:
			11	Higher customer service expenses
			3	Increase in general liability reserve for an environmental matter
			(3)	Regulatory decision allowing reversal of previously expensed interisland wind project support costs

122	121	1		Maintenance expense. Increase largely due to higher overhaul costs at HELCO and MECO

480	431	49		Other expenses. Increase largely due to:
			16	Higher taxes, other than income taxes, primarily resulting from higher revenues
			40	Partial write-off of the Customer Information System (CIS) project to reflect the settlement agreement with the Consumer Advocate, subject to PUC approval
			(9)	Partial writedown of the East Oahu Transmission Project Phase 1 costs in December 2011
			2	Increase in depreciation and amortization expense resulting from changes in rates implemented in conjunction with the most recent D&Os

213	215	(2)		Operating income. Decrease largely due to the partial write-off of the CIS project, partially offset by interim and final rate increases for HECO and MECO.

11	8	3		Allowance for funds used during construction

99	100	(1)		Net income for common stock. Decrease largely due to:
			22	Interim & final rate increases
			(24)	Partial write-off of the CIS project costs
			6	Partial writedown of the East Oahu Transmission Project Phase 1 costs in 2011
			(9)	Higher O&M expense, net of DSM
6.9%	7.3%		(0.4)%	Return on average common equity
138.09	123.63		14.46	Average fuel oil cost per barrel 1
9,206	9,527		(321)	Kilowatthour sales (millions) 2
4,532	4,954		(422)	Cooling degree days (Oahu)
2,658	2,518		140	Number of employees (at December 31)

2011 vs. 2010

2011	2010	Increase (decrease)		(in millions)
$2,979	$2,382	$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

1,265	900	365		Fuel oil expense. Increase largely due to higher fuel costs, partly offset by less KWHs generated

690	549	141		Purchased power expense. Increase largely due to higher purchased energy costs, partly offset by less KWHs purchased

257	251	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

121	127	(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

431	377	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

215	178	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.

8	9	(1)		Allowance for funds used during construction

100	77	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
7.3%	5.8%		1.5%	Return on average common equity
123.63	87.62		36.01	Average fuel oil cost per barrel 1
9,527	9,579		(52)	Kilowatthour sales (millions) 2
4,954	4,661		293	Cooling degree days (Oahu)
2,518	2,317		201	Number of employees (at December 31)

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 2012 were lower than 2011 due largely to cooler, less humid weather, continued conservation efforts and increasing levels of customer-sited renewable generation. KWH sales for 2011 were lower than 2010 due largely to cooler, less humid weather and continued conservation efforts by customers.

Most recent rate proceedings. Unless otherwise agreed or ordered, each electric utility may initiate a PUC proceeding every third year (on a staggered basis) 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, the details of any granted interim and final PUC D&O increases, and whether an interim or final PUC D&O remains pending.

Test year (dollars in millions)	Date (applied/ imple- mented)	Amount	% over rates in effect	ROACE (%)	RORB (%)	Rate base	Common equity %	Stipulated agreement reached with Consumer Advocate	Reflects decoupling
HECO
2009
Request 1	7/3/08	$97.0	5.2	11.25	8.81	$1,408	54.30	Yes	No
Interim increase	8/3/09	61.1	4.7	10.50	8.45	1,169	55.81		No
Interim increase (adjusted)	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
Interim increase (adjusted)	4/2/12	58.2	3.4	10.00	8.11	1,385	56.29		Yes
Interim increase (adjusted)	5/21/12	58.8	3.4	10.00	8.11	1,386	56.29		Yes
Final increase	9/1/12	58.1	3.4	10.00	8.11	1,386	56.29		Yes
HELCO
2010 4
Request	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	4/9/12	4.5	1.3	10.00	8.31	465	55.91		Yes
2013
Request 5	8/16/12	$19.8	4.2	10.25	8.30	$455	57.05		Yes
MECO
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	5/4/12	4.7	1.5	10.00	8.15	387	56.86		Yes
2012
Request 7	7/22/11	$27.5	6.7	11.00	8.72	$393	56.85	Yes	Yes
Interim increase	6/1/12	13.1	3.2	10.00	7.91	393	56.86		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, $58.2 million, and $58.8 million interim increases, and the $58.1 million final increase, include the $15 million in annual revenues that were being recovered through the decoupling RAM prior to the first interim increase.

4 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, and on February 21, 2012, HELCO filed its revised tariffs to reflect the increase in rates. On April 4, 2012, the PUC issued an order approving the revised tariffs, which became effective April 9, 2012. HELCO implemented the decoupling mechanism and began tracking the target revenues and actual recorded revenues via a revenue balancing account. HELCO also reset the heat rates and implemented heat rate deadbands and the PPAC, which provides a surcharge mechanism that more closely aligns cost recovery with costs incurred. The revised tariffs reflect a lower increase in annual revenue requirement compared to the interim increase due to factors that became effective concurrently with the revised tariffs (lower depreciation rates and lower ROACE) and therefore, no refund to customers was required.

5 HELCO’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. Also see “Subsequent event” in Note 3 of HEI’s Consolidated Financial Statements.

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 to incorporate the applicable rulings and decisions in D&Os issued in related proceedings since the first stipulation was filed. On March 29, 2012, MECO and the Consumer Advocate filed an updated agreement on all material issues in MECO’s 2010 test year rate case proceeding. On May 2, 2012, the PUC issued a final D&O, which approved the updated agreement, and on May 4, 2012, the tariffs implementing the D&O became effective. MECO implemented the decoupling mechanism and began tracking the target revenues and actual recorded revenues via a revenue balancing account. MECO also reset the heat rates and implemented heat rate deadbands and the PPAC, which provides a surcharge mechanism that more closely aligns cost recovery with costs incurred. The revised tariffs reflect a lower increase in annual revenue requirement than the interim increase due to factors that became effective concurrently with the revised tariffs (lower depreciation rates and lower ROACE) and therefore, no refund was required.

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. See the discussion below on interim decision and subsequent proposed adjustments to the interim increase.

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, which became 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 reflected the new depreciation rates and methods approved by the PUC in a separate proceeding, which resulted 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 with the Consumer Advocate allowing deferral of certain costs and HECO filed a motion for clarification and/or partial reconsideration of the interim D&O’s findings and conclusions on the deferral of costs.

On February 24, 2012, the PUC issued an order which: (1) approved the deferral of interisland wind project support costs of up to $5.89 million; (2) denied HECO’s request to defer certain consultant expenses associated with the Enterprise Resource Planning/Enterprise Asset Management (ERP/EAM) system costs, but allowed HECO to include $552,000 in its 2011 test year expenses for such costs; and (3) granted HECO’s request to defer Customer Information System (CIS) project operation and maintenance (O&M) expenses (limited to $2,258,000 per year in 2011 and 2012 under the settlement agreement) that are to be subject to a regulatory audit of project costs, and allowed HECO to accrue AFUDC on these deferred costs until the completion of the regulatory audit. As a result of the order, HECO reflected in the first quarter of 2012 the deferral of $2.3 million ($1.4 million for the interisland wind project support costs and $0.9 million for CIS project O&M expenses) incurred from July 22, 2011 through December 31, 2011 that were previously expensed and deferred any 2012

costs incurred up to the limitations stated in the order. For a discussion of a January 2013 settlement agreement resulting in the write off of $40 million of CIS project costs, see “Subsequent event” in Note 3 of HEI’s Consolidated Financial Statements.

On February 3, 2012, the parties reached a settlement agreement on the EOTP Phase 1 project costs, agreeing that, in lieu of a regulatory audit, HECO would write off $9.5 million of gross plant in service EOTP Phase 1 costs and associated adjustments and carrying charges. The settlement agreement resulted in an after-tax charge to net income in the fourth quarter of 2011 of approximately $6 million. The parties also agreed to stipulate 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 and offset by other minor adjustments to the interim increase that became effective on July 26, 2011. On March 29, 2012, the PUC approved the settlement agreement, and ordered that the regulatory audit for EOTP Phase 1 need not be conducted. A revised tariff to reflect an increase in the interim increase became effective April 2, 2012.

On May 14, 2012, the PUC approved HECO’s requested adjustment of $607,000 (i.e., $552,000 grossed up for revenue taxes) to its interim increase to include the ERP/EAM system evaluation costs in its 2011 test year expenses. Revised rates became effective May 21, 2012.

On June 29, 2012, the PUC issued a final D&O in HECO’s 2011 test year proceeding, which finalized approval of the previous interim increases already in effect. It also approved a second stipulated settlement agreement entered into on June 27, 2012 by HECO, the Consumer Advocate and the Department of Defense (parties in the proceeding) to reflect an additional reduction in the test year rate increase of $755,000 to remove parent company non-incentive executive compensation and administrative costs.

On September 1, 2012, the final revised tariffs reflecting the final D&O became effective. Since the final rate increase as a result of the second stipulated supplement to the settlement agreement was lower than the interim increase then currently in effect, HECO refunded to customers, effective September 1, 2012 through September 30, 2012, approximately $0.9 million (which included accrued interest since July 26, 2011).

MECO 2012 test year rate case. On May 21, 2012, the PUC issued an interim D&O in MECO’s 2012 test year rate case, which became effective June 1, 2012. The D&O authorized MECO to reset its target heat rates by fuel type to 2012 test year levels for the purpose of calculating the energy cost adjustment clause (ECAC) adjustment factor, which will help to ensure MECO’s continuing recovery of its fuel costs. The interim increase is based on MECO’s updated stipulated agreement with the Consumer Advocate filed on May 14, 2012. On July 20, 2012, MECO and the Consumer Advocate filed a stipulated supplement to the stipulated agreement to reduce the test year revenue requirement by $0.1 million in administrative and general expenses and requested that the final D&O for this rate case incorporate the adjustment into the final 2012 test year revenue requirement.

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. Through September 2012, HECO achieved an RPS without DSM energy savings of 13.3%, primarily through a comprehensive portfolio of renewable energy power purchase agreements, net energy metering programs and biofuels. The utilities believe they are on track to meet the 2015 RPS.

Recent developments in the utilities’ clean energy strategy include the following (also see the projects discussed under “Renewable Energy Projects” in Note 3 of HEI’s “Notes to Consolidated Financial Statements”):

· 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 2015 and 2017, respectively. Due to a

subsequent lowering of MECO’s forecasted peaks, the projected capacity need date on the island of Maui has been deferred to 2019 and the capacity requirement has been reduced to 30 MW. Due to a subsequent lowering of HECO’s forecasted sales and peaks, the projected capacity need and the timing will be dependent on the possible retirement of generating units. MECO and HECO plan to file draft Requests for Proposals (RFPs) for future capacity with the PUC in 2013.

· 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 2011, HECO also signed other contracts, subject to PUC approval, for lesser amounts of biocrude and for biodiesel for testing or operations.

· In September 2011, the PUC denied the utilities’ requested approval of HELCO’s contract with AKP citing the higher cost of the biofuel over the cost of petroleum diesel. In August 2012, HELCO signed a new 20-year contract with Aina Koa Pono-Ka’u LLC (AKP), subject to PUC approval, to supply 16 million gallons of biodiesel per year with initial consumption to begin within five years of PUC approval.

· In May 2012, the PUC approved a 3-year biodiesel supply contract with Renewable Energy Group through July 2015 for continued biodiesel supply to CT-1 of 3 million to 7 million gallons per year.

· In May 2012, HECO signed a contract, which was approved by the PUC, with the City and County of Honolulu to purchase an additional 27 MW of capacity and energy from an expanded waste-to-energy HPower facility.

· In May 2012, HELCO signed a power purchase agreement, subject to PUC approval, with Hu Honua Bioenergy for 21.5 MW of renewable, dispatchable firm capacity fueled by locally grown biomass from a facility on the island of Hawaii.

· In August 2012, the battery facility at a 30 MW Kahuku wind farm experienced a fire and HECO has not purchased wind energy from the wind farm since then.

· In August 2012, the PUC approved a waiver from the competitive bidding process to allow HECO to negotiate with the U.S. Department of the Army for construction of a 50 MW utility-owned and operated firm, renewable and dispatchable generation facility at Schofield Barracks on the island of Oahu.

· In September 2012, HECO began purchasing test wind energy from the 69 MW Kawailoa Wind, LLC facility. The wind farm was placed into full commercial operation in November 2012.

· In December 2012, the PUC approved a 3-year biodiesel supply contract with Pacific Biodiesel to supply 250,000 to 1 million gallons of biodiesel at the Honolulu International Airport Emergency Power Facility beginning in 2013.

· In December 2012, the 21 MW Auwahi Wind Energy LLC facility was placed into commercial operation, selling power to MECO under a 20-year contract.

· In December 2012, the 5 MW Kalaeloa Solar Two, LLC PV facility was placed into commercial operation, selling power to HECO under a 20-year contract.

· HECO, HELCO and MECO began accepting energy from feed-in tariff projects in 2011. As of December 31, 2012, there were 5,963 kW, 787 kW and 1,658 kW of installed feed-in tariff capacity from renewable energy technologies at HECO, HELCO and MECO, respectively.

· As of December 31, 2012, there were 83,610 kW, 20,275 kW and 23,554 kW of installed net energy metering capacity from renewable energy technologies (mainly PV) at HECO, HELCO and MECO, respectively. Net energy metering is proceeding at a record pace. The amount of net energy metering capacity installed in 2012 was more than twice the amount installed in 2011, which itself was at a record level.

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 March 2012, HECO filed its 2012 Adequacy of Supply (AOS) letter, which indicated that based on its May 2011 sales and peak forecast, HECO’s generation capacity for 2012 to 2016 is sufficient to meet reasonably expected demands for service and provide reasonable reserves for emergencies. The letter reported that, beginning in 2018, 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 and two generating units are retired at the end of 2017. These two generating units may be retired because of their age or more stringent environmental regulations. Also, two additional generating units may be retired in the 2020 timeframe. At the time of the filing, HECO estimated it would 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. Subsequently, HECO developed its May 2012 Sales and Peak Forecast, which was lower than its May 2011 sales and peak forecast. With this lower forecast, HECO expects the amount of new capacity needed to range from 150 MW to 200 MW and the timing to be dependent on the possible retirement of generating units.

HELCO. In January 2013, HELCO filed its 2013 AOS letter, which indicated that HELCO’s generation capacity through 2016 is sufficiently large to meet all reasonably expected demands for service and provide for reasonable reserves for emergencies. In March 2012, HELCO added 8 MW of renewable capacity from Puna Geothermal Venture. In May 2012, HELCO executed a contract with an independent power producer to supply additional firm renewable capacity to the HELCO grid. Should this additional firm renewable facility come on line within the next two 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 2013, HELCO filed with the PUC a Proposed Final Geothermal RFP seeking up to 50 MW of firm, dispatchable geothermal capacity.

MECO. In January 2013, MECO filed its 2013 AOS letter, which indicated that MECO’s generation capacity through 2015 is sufficient to meet the forecasted demands on the islands of Maui, Lanai, and Molokai, and also stated that MECO expects to have adequate firm capacity for the period through 2018 and anticipates needing additional firm capacity on Maui in the 2019 timeframe. MECO’s activities, such as its plans to proceed with a competitive bidding process to acquire new, renewable firm dispatchable capacity generation resources on Maui will be based on that 2019 estimated need date.

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 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.

For additional discussion of environmental legislation and regulations, see “Environmental regulation” in Note 3 of HEI’s “Notes to Consolidated Financial Statements.”

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	2012		2011
(dollars in millions)

Short-term borrowings	$ –	–%	$ –	–%
Long-term debt, net	1,148	43	1,058	43
Preferred stock	34	1	34	1
Common stock equity	1,472	56	1,403	56
	$2,654	100%	$2,495	100%

Information about HECO’s short-term borrowings (other than from HELCO and MECO) and line of credit facility were as follows:

	Year ended December 31, 2012
(in millions)		Average balance	End-of-period balance	December 31, 2012
Short-term borrowings1
Commercial paper		$ 41	$ –	$ –
Line of credit draws		–	–	–
Borrowings from HEI		–	–	–
Undrawn capacity under line of credit facility (expiring December 5, 2016)			175	175

1 The maximum amount of external short-term borrowings in 2012 was $124 million. At December 31, 2012, HECO had $18 million of short-term borrowings from HELCO and MECO had $9 million of short-term borrowings from HECO, which borrowings are eliminated in consolidation. At February 7, 2013, HECO had $50 million of outstanding commercial paper, its line of credit facility was undrawn, it had no borrowings from HEI and it had borrowings of $12 million from HELCO and a loan of $15 million to MECO.

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 and more recently the issuance of taxable unsecured senior notes, 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.

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, 2012, 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% (17.8% last twelve months as of March 31, 2012 – latest reported by Moody’s) and its cash flow coverage of interest fell below 3.5 times (4.8 times last twelve months as of March 31, 2012 – latest reported by Moody’s) for an extended period. On November 29, 2012, 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 risk and “strong” business risk profiles on HECO. S&P indicated that although decoupling can benefit HECO’s financial profile over time, the company will also need constructive outcomes in future rate case filings. Also, HECO needs resolution of the pending regulatory audits for previous capital spending for which the costs are currently deferred.

As of February 7, 2013, 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 ($11.4 million)	BBB-*	Baa1	*
Financial Guaranty Insurance Company ($0.3 billion)	BBB-*	Baa1	*
MBIA Insurance Corporation ($0.1 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.

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 by one of the following bond insurers: Ambac Assurance Corporation; Financial Guaranty Insurance Company, which was placed in a rehabilitation proceeding in the State of New York in June 2012 (in September 2012, a proposed Plan of Rehabilitation was filed); 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. 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 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 and December 2012, HECO sold $40 million and $44 million, respectively, of its common stock to HEI.

The PUC has approved the use of an expedited approval procedure for the approval of long-term debt financings or refinancings (including the issuance of taxable debt) by HECO, HELCO and MECO during the period 2013 through 2015, subject to certain conditions. New long-term debt authorizations of $150 million (HECO $100 million, HELCO $25 million and MECO $25 million) can be requested under the expedited approval procedure through 2015.

In January 2013, HECO, HELCO and MECO filed with the PUC a letter request for the expedited authorization to issue prior to January 1, 2014 up to $90 million, $56 million and $20 million, respectively, of unsecured obligations bearing taxable interest to refinance select series of outstanding revenue bonds.

In February 2013, HECO and MECO filed with the PUC a letter request for the expedited authorization to issue prior to January 1, 2014 up to $50 million and $20 million, respectively, of unsecured obligations bearing taxable interest. The proceeds are expected to be used to fund capital expenditures, including repaying short-term indebtedness incurred to fund capital expenditures.

On April 19, 2012, HECO, HELCO and MECO issued through a private placement taxable unsecured senior notes of various maturities (the HECO Notes, HELCO Notes and MECO Notes, and together, the April Notes) in the aggregate principal amounts of $327 million, $31 million and $59 million, respectively, with stated interest rates ranging from 3.79% to 5.39%. Proceeds of $267 million of the April Notes, together with additional funds, were used to redeem an aggregate principal amount of $271 million of bonds (with stated interest rates ranging from 5.45% to 6.20%). The $150 million of proceeds of the remaining HECO Notes, bearing interest at 5.39%, were used to finance or refinance capital expenditures.

On September 13, 2012, HECO issued another series of taxable unsecured senior notes through a private placement (the HECO September Notes) in the aggregate principal amount of $40 million with a stated interest rate of 4.53%. Proceeds of the HECO September Notes, together with additional funds, were used to redeem the $40 million aggregate principal amount 5.10% Series 2002A SPRBs. See Note 8 of HEI’s “Notes to Consolidated Financial Statements.”

Operating activities provided $177 million in net cash during 2012. Investing activities used net cash of $264 million, primarily for capital expenditures, net of contributions in aid of construction. Financing activities provided net cash of $55 million from net increase in long-term debt of $89 million and net proceeds from issuance of common stock of $44 million, partly offset by the payment of common and preferred stock dividends of $75 million.

For the five-year period 2013 through 2017, the utilities forecast $2.9 billion of net capital expenditures, approximately 48% of which is for transmission and distribution projects, 10% for generation projects and 7% for general plant and other projects, with the remaining 35% anticipated for major initiatives (including environmental compliance and infrastructure investments for fuel and to integrate renewables into the system), which could change over time based upon external factors such as the timing and scope of environmental regulations, unforeseen delays in permitting and the outcome of competitive bidding for new generation. 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 ($11.4 million in 2014) and to fund any unanticipated expenditures not included in the 2013 through 2017 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 $380 million needed for the net capital expenditures in 2013. For 2013, net capital expenditures include approximately $240 million for transmission and distribution projects, approximately $90 million for generation projects and approximately $50 million for general plant and other projects.

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 $53 million for 2012, $71 million for 2011 and $19 million for 2010 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 2012, 2011 and 2010. Contributions by the electric utilities to the retirement benefit plans for 2012, 2011 and 2010 totaled $63 million, $73 million and $31 million, respectively, and are expected to total $84 million in 2013. In addition, the electric utilities paid directly $1 million of benefits in 2012, $1 million of benefits in 2011 and $2 million of benefits in 2010 and expect to $1 million of benefits in 2013. 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, 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 and interim rate increases are subject to refund with interest if the interim increase is greater than the increase approved in the final D&O.

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 2013 will be generated from the burning of fossil fuel oil. Purchased KWHs provided approximately 40% of the total net energy generated and purchased in 2012, 2011 and 2010.

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 47 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 increased 4% in 2012, was essentially flat in 2011 and increased 6% in 2010, when compared to the prior year (4%, 0% and 12% respectively, excluding DSM program expenses). O&M expenses (excluding expenses covered by surcharges or by third parties) for 2013 are projected to be approximately 1% higher than 2012 as the electric utilities expect to manage expenses to near-2012 levels.

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. For example, 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 in 2007 and 2011, respectively. More recently, the utilities and the Consumer Advocate signed a settlement agreement, subject to approval by the PUC, to write off $40 million of costs in 2012 in lieu of conducting the regulatory audits of the CIP CT-1 and the CIS 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. The PUC has promoted a more competitive electric industry environment through its decisions concerning competitive bidding and distributed generation.

Competitive bidding. 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.

The Kalaeloa Solar Two photovoltaic energy PPA and the Kawailoa Wind windfarm PPA are two renewable projects that resulted from HECO’s Renewable Energy Request for Proposals (RFP) under the Competitive Bidding Framework.

The utilities received PUC approval for exemptions from the competitive framework to negotiate modifications to existing PPAs that generate electricity from renewable resources, including the City & County of Honolulu’s HPower facility expansion and the Puna Geothermal Venture geothermal facility expansion. Also, certain renewable energy projects were “grandfathered” from the competitive bidding process, including the Kahuku Wind Power, Auwahi Wind Energy LLC, and Kaheawa Wind Power II wind farms. The PUC can also grant waivers to renewable energy projects that are not exempt from the Competitive Bidding Framework such as for the Hu Honua biomass facility.

Distributed generation. 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). Hawaii law 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 such as the installation of additional emissions controls, retirements of older generating units and switches to lower emissions fuels. 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.

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. In addition, 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. See “Environmental regulation” in Note 3 of HEI’s “Notes to Consolidated Financial Statements.”

Technological developments. New technological developments (e.g., the commercial development of energy storage, fuel cells, 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, 2012, the consolidated regulatory liabilities and regulatory assets of the utilities amounted to $322 million and $865 million, respectively, compared to $315 million and $669 million as of December 31, 2011, 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, 2012 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, and RBA revenues or refunds for the difference between PUC-approved target revenues and recorded adjusted revenues, which delinks revenues from kilowatthour sales. As of December 31, 2012, revenues applicable to energy consumed, but not yet billed to customers, amounted to $134 million and the RBA revenues recognized in 2012 amounted to $56 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 the electric utilities also include PPACs 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 PPACs 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.”

Additional information concerning HECO is incorporated herein by reference to page 3 of HECO Exhibit 99.2.

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 2012 with assets of $5.0 billion and net income of $59 million, compared to assets of $4.9 billion as of December 31, 2011 and net income of $60 million in 2011.

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 such as mobile banking. 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 and/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.

ASB’s loan quality improved in 2012 as a result of stabilized or increasing property values, more financial flexibility of borrowers, and overall general economic improvement in the state of Hawaii. 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 2012 compared to 2011, 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 2012 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 2013 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.

· 2012 vs. 2011

(in millions)	2012		2011		Increase (decrease)	Primary reason(s) for significant change
Interest income	$190		$199		$(9)	The impact of higher average earning asset balances was more than offset by lower yields on earning assets. ASB’s average loan portfolio balance for 2012 was $116 million higher than 2011 as the average commercial markets, home equity lines of credit and commercial real estate loan balances increased by $77 million, $112 million and $51 million, respectively. ASB targeted these loan types because of their shorter duration and/or variable rates. Despite a $460 million increase in residential loan production, the average residential loan portfolio decreased by $122 million due to higher repayments and loan sales in connection with ASB’s long-term strategy to manage interest rate risk. The loan portfolio yield was impacted by the low interest rate environment as new loan production yields were lower than the average portfolio yield. The average investment and mortgage-related securities portfolio balance decreased by $14 million as ASB experienced higher prepayments on the portfolio, which were used to fund higher loan originations.

Noninterest income	76		65		11	Higher gain on sale of loans as more residential loans were sold in order to manage interest rate risk and increase in debit card fees due to an increase in transaction volume. The higher gain on sale revenue helped fund spending on ASB’s strategic priorities.
Revenues	266		264		2

Interest expense	11		14		(3)	Lower funding costs as a result of the low interest rate environment. Average deposit balances for 2012 increased by $89 million compared to 2011 due to an increase in core deposits of $170 million, partly offset by a decrease in term certificates of $81 million. The other borrowings average balance decreased by $24 million due to the payoff of a maturing FHLB advance in 2011 and lower retail repurchase agreements.

Provision for loan losses	13		15		(2)	The provision for loan losses benefited from lower net charge-offs and improved credit quality associated with the gradual improvement in Hawaii’s economy, partly offset by loan loss reserves established for the growth in the loan portfolio.

Noninterest expense	153		143		10	Higher transaction volumes and spending on ASB’s strategic projects and priorities, as well as increasing employee benefit expenses.


Expenses	177		172		5

Operating income	89		92		(3)	Lower net interest income and higher noninterest expenses, partially offset by higher noninterest income.


Net income	59		60		(1)	Lower operating income.
Return on average common equity 1	11.7	%	12.0	%	(0.3)%

· 2011 vs. 2010

(in millions)	2011		2010		Increase (decrease)	Primary reason(s) for significant change
Interest income	$199		$210		$(11)	Decrease largely due to lower yields on earning assets. 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.
Noninterest income	65		73		(8)	Lower fee income on deposits as a result of new overdraft fee legislation.
Revenues	264		283		(19)
Interest expense	14		20		(6)	Lower funding costs as a result of the low interest rate environment. 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.

Provision for loan losses	15		21		(6)	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% and 2.8% of total outstanding loans as of December 31, 2011 and 2010, respectively.

Noninterest expense	143		149		(6)	Lower data processing expense due to lower service bureau expenses with the system conversion in mid-2010.
Expenses	172		190		(18)

Operating income	92		93		(1)	Lower net interest income and noninterest income, partially offset by lower provision for loan losses and noninterest expenses.



Net income	60		58		2	Lower operating income, partly offset by lower taxes primarily due to additional low income housing credits and tax-free income from municipal bonds and bank-owned life insurance.


Return on average common equity 1	12.0	%	11.6	%	0.4%

1 Calculated using the average daily balances.

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 2012, 2011 and 2010.

	2012						2011
(dollars in thousands)	Average balance			Interest		Yield/ rate (%)	Average balance			Interest		Yield/ rate (%)
Assets:
Other investments 1	$	203,751		$	269	0.13	$	233,909		$	342	0.15
Available-for-sale investment and mortgage-related securities	623,438			14,368		2.30	637,123			14,763		2.32
Loans
Residential 1-4 family 2	1,894,603			99,056		5.23	2,016,224			109,908		5.45
Commercial real estate	402,410			18,387		4.57	351,832			17,911		5.09
Home equity line of credit	585,797			16,106		2.75	474,029			13,935		2.94
Residential land	34,744			2,097		6.04	53,904			2,979		5.53
Commercial loans	714,679			30,925		4.33	637,182			31,432		4.93
Consumer loans	101,933			9,486		9.31	85,356			8,320		9.75
Total loans 3	3,734,166			176,057		4.71	3,618,527			184,485		5.10
Total interest-earning assets 4	4,561,355			190,694		4.18	4,489,559			199,590		4.45
Allowance for loan losses	(39,323		)				(39,263		)
Non-interest-earning assets	431,680						423,183
Total Assets	$	4,953,712					$	4,873,479

Liabilities and Shareholder’s Equity:
Savings	$	1,727,754		1,128		0.07	$	1,672,033		1,756		0.11
Interest-bearing checking	612,629			111		0.02	593,891			184		0.03
Money market	202,539			319		0.16	250,682			650		0.26
Time certificates	517,752			4,865		0.94	598,360			6,393		1.07
Total interest-bearing deposits	3,060,674			6,423		0.21	3,114,966			8,983		0.29
Advances from Federal Home Loan Bank	50,014			2,176		4.35	64,466			2,553		3.96
Securities sold under agreements to repurchase	172,683			2,693		1.56	182,655			2,933		1.61
Total interest-bearing liabilities	3,283,371			11,292		0.34	3,362,087			14,469		0.43
Non-interest bearing liabilities:
Deposits	1,060,121						916,957
Other	108,161						95,363
Shareholder’s equity	502,059						499,072
Total Liabilities and Shareholder’s Equity	$	4,953,712					$	4,873,479
Net interest income				$	179,402					$	185,121
Net interest margin (%) 5						3.93						4.12

	2010
(dollars in thousands)	Average balance		Interest	Yield/ rate (%)
Assets:
Other investments 1	$ 334,270		$ 621	0.19
Available-for-sale investment and mortgage-related securities	566,126		14,468	2.56
Loans
Residential 1-4 family 2	2,197,582		124,101	5.65
Commercial real estate	324,324		16,642	5.13
Home equity line of credit	375,853		12,568	3.34
Residential land	82,895		4,671	5.64
Commercial loans	530,731		29,626	5.58
Consumer loans	80,409		7,584	9.43
Total loans 3	3,591,794		195,192	5.43
Total interest-earning assets 4	4,492,190		210,281	4.68
Allowance for loan losses	(39,135	)
Non-interest-earning assets	415,986
Total Assets	$4,869,041

Liabilities and Shareholder’s Equity:
Savings	$1,608,650		2,262	0.14
Interest-bearing checking	568,659		329	0.06
Money market	232,809		884	0.38
Time certificates	768,991		11,221	1.46
Total interest-bearing deposits	3,179,109		14,696	0.46
Advances from Federal Home Loan Bank	65,000		2,566	3.95
Securities sold under agreements to repurchase	201,149		3,087	1.53
Total interest-bearing liabilities	3,445,258		20,349	0.59
Non-interest bearing liabilities:
Deposits	824,039
Other	96,510
Shareholder’s equity	503,234
Total Liabilities and Shareholder’s Equity	$4,869,041
Net interest income			$189,932
Net interest margin (%) 5				4.23

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

2 Includes loans held for sale.

3 Includes loan fees of $4.9 million, $3.9 million and $6.3 million for 2012, 2011 and 2010, respectively, together with interest accrued prior to suspension of interest accrual on nonaccrual loans.

4 Interest income includes taxable equivalent basis adjustments, based upon a federal statutory tax rate of 35%, of $0.8 million $0.5 million and $0.1 million for 2012, 2011 and 2010, respectively.

5 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 was impacted by disruptions in the financial markets and these conditions may continue and 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 $3.6 billion at the end of 2011 to $3.7 billion at the end of 2012 was primarily due to growth in the commercial real estate and home equity line of credit loan portfolios, which ASB targeted because of their shorter duration and/or variable rates partly offset by lower residential loan balances.

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 2012, the allowance for loan losses increased by $4.1 million due to growth in the loan portfolios (2.6% growth or $96.3 million increase in outstanding balances) and higher impairment reserves for the commercial and commercial real estate loan portfolios. Although overall loan quality improved, a number of commercial borrowers experienced financial stress during the year.

Investment and mortgage-related securities. As of December 31, 2012, ASB’s investment portfolio consisted of 62% mortgage-related securities issued by Federal National Mortgage Association (FNMA), Federal Home Loan Mortgage Corporation (FHLMC) and Government National Mortgage Association (GNMA), 26% federal agency obligations and 12% municipal bonds. 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.

Principal and interest on mortgage-related securities issued by FNMA, FHLMC and GNMA are guaranteed by the issuer and, in the case of GNMA, backed by the full faith and credit of the United States.

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, 2012, 2011 and 2010, ASB did not have any private-issue mortgage-related securities.

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, 2012, ASB’s costing liabilities consisted of 96% deposits and 4% other borrowings. As of December 31, 2011, ASB’s costing liabilities consisted of 95% deposits and 5% 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, 2012 and 2011, 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 $11 million and $10 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 (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 applicable laws and regulations are being interpreted, and new and amended regulations may be adopted, by the FRB and the OCC. HEI will 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 established the Bureau. It has 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. On December 21, 2012, the Bureau issued the Remittance Rule (an amendment to Regulation E) which closes for comment on January 30, 2013. For international wires, the rule now provides flexibility regarding the disclosure of foreign taxes, as well as fees imposed by a designated recipient’s institution for receiving a remittance transfer in an account. Second, the rule limits a remittance transfer provider’s obligation to disclose foreign taxes to those imposed by a country’s central government. And third, the rule revises the error resolution provisions that apply when a remittance transfer is not delivered to a designated recipient because the sender provided incorrect or insufficient information, and, in particular, when a sender provides an incorrect account number and that incorrect account number results in the funds being deposited in the wrong account. On January 10, 2013, the Bureau issued the Ability-to-Repay rule which closes for comment on February 25, 2013. For mortgages, among other things, (i) potential borrowers have to supply financial information, and lenders must verify it, (ii) to qualify for a particular loan, a consumer has to have sufficient assets or income to pay back the loan, and (iii) lenders will have to determine the consumer’s ability to repay both the principal and the interest over the long term – not just during an introductory period when the rate may be lower.

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.

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 2012, ASB had earned an average of 52 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.

Proposed Capital Rules. The FRB, OCC and FDIC issued three notices of proposed rulemaking (NPR) that would revise and replace the current capital rules. The proposed rules are intended to help ensure banks maintain strong capital positions, which would enable them to continue lending to creditworthy households and businesses even after unforeseen losses and during severe economic downturns.

The first NPR, titled Regulatory Capital Rules: Regulatory Capital, Implementation of Basel III, Minimum Regulatory Capital Ratios, Capital Adequacy, and Transition Provisions (Basel III NPR), applies to all depository institutions, bank holding companies with total consolidated assets of $500 million or more, and savings and loan holding companies and revises the risk-based and leverage capital requirements consistent with agreements reached by the Basel Committee on Banking Supervision (Basel III). The Basel III NPR would increase the quantity and quality of capital required, revise the definition of capital to improve the ability of regulatory capital instruments to absorb losses, establish limitations on capital distributions and certain discretionary bonus payments if additional specified amounts of common equity tier 1 capital are not met, and introduce a supplementary leverage ratio for internationally active banking organizations. The Basel III NPR would also revise the prompt corrective action framework by incorporating new regulatory capital minimums and updating the definition of tangible common equity.

The second NPR, titled Regulatory Capital Rules: Standardized Approach for Risk-weighted Assets; Market Discipline and Disclosure Requirements (Standardized Approach NPR), proposes to revise and harmonize the rules for calculating risk-weighted assets to enhance risk sensitivity and address weaknesses identified over the past several years. The Standardized Approach NPR would incorporate aspects of the Basel II standardized framework such as methods for determining risk-weighted assets for residential mortgages, securitization exposures and counterparty credit risk. The Standardized Approach NPR would apply to the same set of institutions as the Basel III NPR, but also introduces disclosure requirements for U.S. banking organizations with $50 billion or more in assets.

The third NPR, Regulatory Capital Rules: Advanced Approaches Risk-based Capital Rule: Market Risk Capital Rule (Advanced Approaches NPR), would apply to banking organizations that are subject to the banking agencies’ advanced approaches rule, or to their market risk rule, and revises the advanced approaches risk-based capital rules to be consistent with Basel III and the Dodd-Frank Act. Generally, the advanced approaches rules would apply to institutions with $250 billion or more in consolidated assets or $10 billion or more in foreign exposure, and the market risk rule would apply to savings and loan holding companies with significant trading activity.

Proposed Capital Requirements

Proposal effective dates	1/1/13	1/1/14	1/1/15	1/1/16	1/1/17	1/1/18	1/1/19
Capital conservation buffer				0.625%	1.25%	1.875%	2.50%
Common equity ratio + conservation buffer	3.50%	4.00%	4.50%	5.125%	5.75%	6.375%	7.00%
Tier 1 capital ratio + conservation buffer	4.50%	5.50%	6.00%	6.625%	7.25%	7.875%	8.50%
Total capital ratio + conservation buffer	8.00%	8.00%	8.00%	8.625%	9.25%	9.875%	10.50%
Countercyclical capital buffer – not applicable to ASB				0.625%	1.25%	1.875%	2.50%

The proposed rules allow for a transition period to meet the proposed capital requirement levels. ASB is reviewing the proposed rules and the impact to its capital ratios. Based on a preliminary assessment,

management believes ASB and HEI can satisfy the proposed capital rules that would be applicable to them, if adopted.

FHLB of Seattle stock. As of December 31, 2012, ASB’s investment in stock of the FHLB of Seattle of $96.0 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 $49.6 million for the nine months ended September 30, 2012 compared to net income of $70.7 million for the nine months ended September 30, 2011. The FHLB of Seattle reported retained earnings of $207 million as of September 30, 2012 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 (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 2010, 2011 or 2012.

In September 2012, the Finance Agency classified the FHLB of Seattle as “adequately capitalized” and after receiving approval from the Finance Agency, began repurchasing excess stock. The FHLB of Seattle repurchased a total of $2 million of excess stock from ASB in September and December of 2012.

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	2012	% change	2011	% change
(dollars in millions)

Total assets	$5,042	3	$4,910	2
Available-for-sale investment and mortgage-related securities	671	8	624	(8)
Loans receivable held for investment, net	3,737	3	3,643	4
Deposit liabilities	4,230	4	4,070	2
Other bank borrowings	196	(16)	233	(2)

As of December 31, 2012, ASB was one of Hawaii’s largest financial institutions based on assets of $5.0 billion and deposits of $4.2 billion.

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, 2012 were $160 million higher than December 31, 2011. 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, 2012, 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, 2012, ASB’s unused FHLB borrowing capacity was approximately $0.9 billion. As of December 31, 2012, securities sold under agreements to repurchase totaled $146 million, representing 2.9% 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, 2012, ASB had commitments to borrowers for undisbursed loan funds, loan commitments and unused lines and letters of credit of $1.5 billion. There are no commitments to lend additional funds to borrowers whose loans are impaired. There are no commitments to lend additional funds to borrowers whose loan terms have been modified in trouble debt restructurings as of December 31, 2012. 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, 2012 and 2011, ASB had $64.9 million and $66.8 million of loans on nonaccrual status, respectively, or 1.7% and 1.8% of net loans outstanding, respectively. As of December 31, 2012 and 2011, ASB had $6.1 million and $7.3 million, respectively, of real estate acquired in settlement of loans.

In 2012, operating activities provided cash of $50 million. Net cash of $163 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 $77 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, 2012, 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, 2012, the fair value and carrying value of the investment and mortgage-related securities held by ASB were $0.7 billion.

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 have made it challenging to find investments with adequate risk-adjusted returns and had 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, 2012, 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, 2012 with a tangible capital ratio of 9.1% (1.5%), a core capital ratio of 9.1% (4.0%) and a total risk-based capital ratio of 12.8% (8.0%).

· ASB met the capital requirements to be generally considered “well-capitalized” (noted in parentheses) as of December 31, 2012 with a leverage ratio of 9.1% (5.0%), a Tier-1 risk-based capital ratio of 11.7% (6.0%) and a total risk-based capital ratio of 12.8% (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, 2012, 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, 2012, 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.

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, 2012, 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, 2012, ASB’s allowance for loan losses was $42.0 million and ASB had $64.9 million of loans on nonaccrual status, compared to $37.9 million and $66.8 million at December 31, 2011, respectively. In 2012, ASB recorded a provision for loan losses of $12.9 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, 2012, 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.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

HEI and HECO (in the case of HECO, only the information related to HECO and its subsidiaries):

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, 2012.

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 (IRR). 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).

Consistent with OCC guidelines, the market value or economic capitalization of ASB is measured as economic value of equity (EVE). EVE 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, 2012 and 2011 constitute “forward-looking statements” and were as follows:

December 31	2012				2011
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	1.6	%	(9.4	)%	0.5	%	(7.4)	%
+200	0.5		(4.9	)	(0.3	)	(3.8	)
+100	0.1		(1.9	)	(0.4	)	(1.5	)
Base	–		–		–		–
-100	(0.2	)	(1.7	)	(0.4	)	(3.5	)

Management believes that ASB’s interest rate risk position as of December 31, 2012 represents a reasonable level of risk. The NII profile under the rising interest rate scenarios is asset sensitive for all rate increases as of December 31, 2012 compared to December 31, 2011 due to changes in assumption about the repricing of certain commercial loans.

ASB’s base EVE was $767 million as of December 31, 2012 compared to $848 million as of December 31, 2011 due to changes in discounting spreads for certain retail loans and changes in mix for core deposits.

The change in EVE was more sensitive in the rising scenarios as of December 31, 2012 compared to December 31, 2011 due to the shift in the investment portfolio towards a longer duration mix, and changes in the mix of retail loans and core deposits.

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, 2012, 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).

Other risks relating to HECO

Additional information required by this Item 7A is set forth in HECO’s Quantitative and Qualitative Disclosures about Market Risk, incorporated herein by reference to pages 3 and 4 of HECO Exhibit 99.2.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

HEI:

Index to Consolidated Financial Statements	Page

Report of Independent Registered Public Accounting Firm	85
Consolidated Financial Statements	86

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, 2012 and 2011 and the related consolidated statements of income, comprehensive income, changes in shareholders’ equity and cash flows for each of the three years in the period ended December 31, 2012 present fairly, in all material respects, the financial position of Hawaiian Electric Industries, Inc. and its subsidiaries (the “Company”) at December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012 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, 2012, 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.

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 19, 2013

Consolidated Statements of Income

Hawaiian Electric Industries, Inc. and Subsidiaries

Years ended December 31		2012		2011		2010
(in thousands, except per share amounts)

Revenues
Electric utility	$	3,109,439	$	2,978,690	$	2,382,366
Bank		265,539		264,407		282,693
Other		17		(762)		(77)
Total revenues		3,374,995		3,242,335		2,664,982
Expenses
Electric utility		2,896,427		2,763,556		2,203,978
Bank		177,106		172,806		190,105
Other		17,266		16,277		14,688
Total expenses		3,090,799		2,952,639		2,408,771
Operating income (loss)
Electric utility		213,012		215,134		178,388
Bank		88,433		91,601		92,588
Other		(17,249)		(17,039)		(14,765)
Total operating income		284,196		289,696		256,211
Interest expense – other than on deposit liabilities and other bank borrowings		(78,151)		(82,106)		(81,538)
Allowance for borrowed funds used during construction		4,355		2,498		2,558
Allowance for equity funds used during construction		7,007		5,964		6,016
Income before income taxes		217,407		216,052		183,247
Income taxes		76,859		75,932		67,822
Net income		140,548		140,120		115,425
Preferred stock dividends of subsidiaries		1,890		1,890		1,890
Net income for common stock	$	138,658	$	138,230	$	113,535
Basic earnings per common share	$	1.43	$	1.45	$	1.22
Diluted earnings per common share	$	1.42	$	1.44	$	1.21
Dividends per common share	$	1.24	$	1.24	$	1.24
Weighted-average number of common shares outstanding		96,908		95,510		93,421
Dilutive effect of share-based compensation		430		310		272
Adjusted weighted-average shares		97,338		95,820		93,693

The accompanying notes are an integral part of these consolidated financial statements.

Consolidated Statements of Comprehensive Income

Hawaiian Electric Industries, Inc. and Subsidiaries

Years ended December 31		2012		2011		2010
(in thousands)


Net income for common stock	$	138,658	$	138,230	$	113,535
Other comprehensive income (loss), net of taxes:
Net unrealized gains (losses) on securities:
Net unrealized gains (losses) on securities arising during the period, net of (taxes) benefits of ($631), ($4,343) and $789 for 2012, 2011 and 2010, respectively		956		6,578		(1,196)
Less: reclassification adjustment for net realized gains included in net income, net of taxes of $53, $148 and nil for 2012, 2011 and 2010, respectively		(81)		(224)		–
Derivatives qualified as cash flow hedges:
Net unrealized holding losses arising during the period, net of tax benefits of nil, $4 and $745 for 2012, 2011 and 2010, respectively		–		(8)		(1,169)
Less: reclassification adjustment to net income, net of tax benefits of $150, $115 and nil for 2012, 2011 and 2010, respectively		236		181		–
Retirement benefit plans:
Prior service credit arising during the period, net of taxes of nil, $4,422 and $3,001 for 2012, 2011 and 2010, respectively		–		6,943		4,712
Net losses arising during the period, net of tax benefits of $63,303, $83,147 and $28,431 for 2012, 2011 and 2010, respectively		(99,159)		(130,191)		(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 $9,764, $5,976 and $2,566 for 2012, 2011 and 2010, respectively		15,291		9,364		4,030
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes of $48,299, $64,134 and $21,336 for 2012, 2011 and 2010, respectively		75,471		100,692		33,499
Other comprehensive loss, net of tax benefits		(7,286)		(6,665)		(4,750)
Comprehensive income attributable to Hawaiian Electric Industries, Inc.	$	131,372	$	131,565	$	108,785

The accompanying notes are an integral part of these consolidated financial statements.

Consolidated Balance Sheets

Hawaiian Electric Industries, Inc. and Subsidiaries

December 31			2012			2011
(dollars in thousands)

ASSETS
Cash and cash equivalents		$	219,662		$	270,265
Accounts receivable and unbilled revenues, net			362,823			344,322
Available-for-sale investment and mortgage-related securities			671,358			624,331
Investment in stock of Federal Home Loan Bank of Seattle			96,022			97,764
Loans receivable held for investment, net			3,737,233			3,642,818
Loans held for sale, at lower of cost or fair value			26,005			9,601
Property, plant and equipment, net
Land	$ 70,799			$ 66,152
Plant and equipment	5,492,963			5,177,453
Construction in progress	156,353			140,717
	5,720,115			5,384,322
Less – accumulated depreciation	(2,125,286)		3,594,829	(2,049,821)		3,334,501
Regulatory assets			864,596			669,389
Other			494,414			519,296
Goodwill			82,190			82,190
Total assets		$	10,149,132		$	9,594,477

LIABILITIES AND SHAREHOLDERS’ EQUITY
Liabilities
Accounts payable		$	212,379		$	216,176
Interest and dividends payable			26,258			25,041
Deposit liabilities			4,229,916			4,070,032
Short-term borrowings—other than bank			83,693			68,821
Other bank borrowings			195,926			233,229
Long-term debt, net—other than bank			1,422,872			1,340,070
Deferred income taxes			439,329			354,051
Regulatory liabilities			322,074			315,466
Contributions in aid of construction			405,520			356,203
Retirement benefits liability			656,394			530,407
Other			526,613			521,982
Total liabilities			8,520,974			8,031,478

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: 97,928,403 shares and 96,038,328 shares in 2012 and 2011, respectively			1,403,484			1,349,446
Retained earnings			216,804			198,397
Accumulated other comprehensive income (loss), net of taxes
Net unrealized gains on securities	$ 10,761			$ 9,886
Unrealized losses on derivatives	(760)			(996)
Retirement benefit plans	(36,424)		(26,423)	(28,027)		(19,137)
Total shareholders’ equity			1,593,865			1,528,706
Total liabilities and shareholders’ equity		$	10,149,132		$	9,594,477

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)	Shares		Amount		earnings	income (loss)		Total
Balance, December 31, 2009	92,521	$	1,265,157	$	180,970	$ (7,722)	$	1,438,405
Net income for common stock	–		–		113,535	–		113,535
Other comprehensive loss, net of tax benefits	–		–		–	(4,750)		(4,750)
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		178,667	(12,472)		1,480,394
Net income for common stock	–		–		138,230	–		138,230
Other comprehensive loss, net of tax benefits	–		–		–	(6,665)		(6,665)
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		198,397	(19,137)		1,528,706
Net income for common stock	–		–		138,658	–		138,658
Other comprehensive loss, net of tax benefits	–		–		–	(7,286)		(7,286)
Issuance of common stock:
Dividend reinvestment and stock purchase plan	1,560		41,295		–	–		41,295
Retirement savings and other plans	330		8,196		–	–		8,196
Expenses and other, net	–		4,547		–	–		4,547
Dividend equivalents paid on equity-classified awards	–		–		(101)	–		(101)
Common stock dividends ($1.24 per share)	–		–		(120,150)	–		(120,150)
Balance, December 31, 2012	97,928	$	1,403,484	$	216,804	$ (26,423)	$	1,593,865

As of December 31, 2012, Hawaiian Electric Industries, Inc. (HEI) had reserved a total of 18,803,821 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	2012	2011	2010
(in thousands)

Cash flows from operating activities
Net income	$ 140,548	$ 140,120	$ 115,425
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation of property, plant and equipment	150,389	148,152	154,523
Other amortization	7,958	19,318	4,605
Provision for loan losses	12,883	15,009	20,894
Impairment of utility assets	40,000	9,215	–
Loans receivable originated and purchased, held for sale	(519,622)	(267,656)	(360,527)
Proceeds from sale of loans receivable, held for sale	513,000	273,932	392,406
Change in deferred income taxes	90,848	79,444	97,791
Change in excess tax benefits from share-based payment arrangements	(61)	35	45
Allowance for equity funds used during construction	(7,007)	(5,964)	(6,016)
Change in cash overdraft	–	(2,688)	(141)
Changes in assets and liabilities
Increase in accounts receivable and unbilled revenues, net	(18,501)	(77,326)	(25,880)
Decrease (increase) in fuel oil stock	10,129	(18,843)	(74,044)
Increase in regulatory assets	(72,401)	(40,132)	(2,936)
Increase (decrease) in accounts, interest and dividends payable	(39,738)	(34,480)	22,410
Change in prepaid and accrued income taxes and utility revenue taxes	21,079	73,153	(5,252)
Contributions to defined benefit pension and other postretirement benefit plans	(77,703)	(74,961)	(31,792)
Change in other assets and liabilities	(17,259)	14,038	39,206
Net cash provided by operating activities	234,542	250,366	340,717

Cash flows from investing activities
Available-for-sale investment and mortgage-related securities purchased	(243,633)	(361,876)	(714,552)
Principal repayments on available-for-sale investment and mortgage-related securities	191,253	389,906	465,437
Proceeds from sale of available-for-sale investment and mortgage-related securities	3,548	32,799	–
Net decrease (increase) in loans held for investment	(112,730)	(181,080)	118,892
Proceeds from sale of real estate acquired in settlement of loans	11,336	8,020	5,967
Capital expenditures	(325,480)	(235,116)	(182,125)
Contributions in aid of construction	45,982	23,534	22,555
Other	2,677	(2,974)	5,092
Net cash used in investing activities	(427,047)	(326,787)	(278,734)

Cash flows from financing activities
Net increase (decrease) in deposit liabilities	159,884	94,660	(83,388)
Net increase (decrease) in short-term borrowings with original maturities of three months or less	14,872	43,898	(17,066)
Net increase (decrease) in retail repurchase agreements	(37,291)	10,910	(60,308)
Proceeds from other bank borrowings	5,000	–	–
Repayments of other bank borrowings	(5,000)	(15,000)	–
Proceeds from issuance of long-term debt	457,000	125,000	–
Repayment of long-term debt	(375,500)	(150,000)	–
Change in excess tax benefits from share-based payment arrangements	61	(35)	(45)
Net proceeds from issuance of common stock	23,613	15,979	22,706
Common stock dividends	(96,202)	(106,812)	(93,034)
Preferred stock dividends of subsidiaries	(1,890)	(1,890)	(1,890)
Other	(2,645)	(675)	(2,229)
Net cash provided by (used in) financing activities	141,902	16,035	(235,254)

Net decrease in cash and cash equivalents	(50,603)	(60,386)	(173,271)
Cash and cash equivalents, January 1	270,265	330,651	503,922
Cash and cash equivalents, December 31	$ 219,662	$ 270,265	$ 330,651

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.

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 must 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 also evaluated for OTTI. Also see Note 5 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 3.1% in 2012, 3.2% in 2011 and 3.5% in 2010.

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 $19 million, $14 million and $13 million in 2012, 2011 and 2010, respectively. Future minimum lease payments are $18 million, $17 million, $14 million, $11 million, $9 million and $29 million for 2013, 2014, 2015, 2016, 2017 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 contributions to the plans 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 also 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, which approximates the effective interest 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. Valuation allowances are established when necessary to reduce deferred income tax assets to the amount expected to be realized.

The Company recognizes investment tax credits as a reduction of income tax expense in the period the assets giving rise to such credits are placed in service, except for the electric utility subsidiaries’ investment tax credits, which are deferred and amortized over the estimated useful lives of the properties to which the credits relate, in accordance with Accounting Standards Codification (ASC) Topic 980, “Regulated Operations.”

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.

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:

	2012		2011		2010
	Basic	Diluted	Basic	Diluted	Basic		Diluted
Distributed earnings	$ 1.24	$ 1.24	$ 1.24	$ 1.24	$ 1.24		$ 1.24
Undistributed earnings (loss)	0.19	0.18	0.21	0.20	(0.02	)	(0.03	)
	$ 1.43	$ 1.42	$ 1.45	$ 1.44	$ 1.22		$ 1.21

As of December 31, 2012 and 2010, the antidilutive effect of stock appreciation rights (SARs) on 102,000 and 450,000 shares of common stock (for which the SARs’ exercise prices were greater than the closing market prices of HEI’s common stock), respectively, was not included in the computation of diluted EPS. As of December 31, 2011, there were no shares that were antidilutive.

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.

Offsetting assets and liabilities. In December 2011, the FASB issued Accounting Standards Update (ASU) No. 2011-11, “Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities,” which requires disclosures about financial instruments and derivative instruments that are either offset or subject to an enforceable master netting arrangement or similar agreement to enable financial statement users to understand the effect of those arrangements on the entity’s financial position. The Company believes that the adoption of ASU No 2011-11 will not have a material impact on its financial statement disclosures.

Reporting of Amounts Reclassified Out of AOCI. In February 2013, the FASB issued ASU No. 2013-02, “Comprehensive Income (Topic 220): Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income,” which requires companies to provide information about the amounts reclassified out of AOCI by component and to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of AOCI by the respective line items of net income, but only if the amount reclassified is required under U.S. GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under U.S. GAAP to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures required under U.S. GAAP that provide additional detail about those amounts. The Company will include the disclosures required by ASU No. 2013-02 its financial statement for the first quarter of 2013.

Reclassifications and revisions. Certain reclassifications have been made to prior years’ financial statements to conform to the 2012 presentation, which did not affect previously reported results of operations.

The Company has revised its electric utilities’ previously issued financial statements to correct an error that resulted in the understatement of franchise taxes, net of tax benefits, that should have been recorded in years

prior to 2010. The Company determined the cumulative impact for periods prior to 2010 to be a charge to its earnings of $3.2 million. These adjustments were not considered to be material individually or in the aggregate to previously issued financial statements. The table below illustrates the effects of this revision on the Company’s Consolidated Financial Statements for those line items affected (these revisions have no impact on the Company’s Consolidated Statements of Income and Cash Flows for the periods reported):

(dollars in thousands)	As previously filed	As revised	Difference
December 31, 2011
Consolidated Balance Sheet
Other assets	517,550	519,296	1,746
Total assets	9,592,731	9,594,477	1,746

Other liabilities	516,990	521,979	4,989
Total liabilities	8,026,489	8,031,478	4,989
Retained earnings	201,640	198,397	(3,243)
Total shareholders’ equity	1,531,949	1,528,706	(3,243)
Total liabilities and shareholders’ equity	9,592,731	9,594,477	1,746

Consolidated Statement of Changes in Shareholders’ Equity
Retained earnings	201,640	198,397	(3,243)
Total shareholders’ equity	1,531,949	1,528,706	(3,243)

December 31, 2010
Consolidated Statement of Changes in Shareholders’ Equity
Retained earnings	181,910	178,667	(3,243)
Total shareholders’ equity	1,483,637	1,480,394	(3,243)

December 31, 2009
Consolidated Statement of Changes in Shareholders’ Equity
Retained earnings	184,213	180,970	(3,243)
Total shareholders’ equity	1,441,648	1,438,405	(3,243)

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. As of December 31, 2012 and 2011, the allowance for customer accounts receivable, accrued unbilled revenues and other accounts receivable was $2 million.

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 55 years as an offset against depreciation expense.

Electric utility revenues. Electric utility revenues are based on rates authorized by the PUC. Prior to the implementation of decoupling, revenues related to the sale of energy were generally recorded when service was rendered or energy was delivered to customers and included revenues applicable to energy consumed in the accounting period but not yet billed to the 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 also include purchased power adjustment clauses (PPACs) under which the remaining purchase power expenses are recovered through surcharge mechanisms. The amounts collected through the ECACs and PPACs are required to be reconciled quarterly.

Upon the implementation of decoupling (HECO on March 1, 2011, HELCO on April 9, 2012 and MECO on May 4, 2012), the electric utilities: (1) recognize monthly revenue balancing account (RBA) revenues or refunds for the difference between PUC-approved target revenues and recorded adjusted revenues, which delinks revenues from kilowatthour sales, (2) recognize a revenue escalation component via a revenue

adjustment mechanism (RAM) for certain O&M expenses and rate base changes, and (3) recognize (when applicable) an earnings sharing mechanism, which would provide for a reduction of revenues between rate cases in the event the utility’s ratemaking ROACE exceeds the ROACE allowed in its most recent rate case.

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 in the period are based on the prior year’s billed revenues (in the case of public service company taxes and PUC fees) or on the current year’s cash collections from electric sales (in the case of franchise taxes). For 2012, 2011 and 2010, HECO and its subsidiaries included approximately $280 million, $264 million and $211 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 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 7.6% in 2012, 8.0% in 2011 and 8.1% in 2010, 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. Ratings are applied separately to the probability of default (borrower risk) and loss given default (transaction risk). 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 that are not considered collateral dependent, generally the discounted cash flow method is 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 (uncollectible) 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, interest only payments for an extended period of time, protracted terms such as amortization and maturity beyond the customary length of time found in the normal market place, 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 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, 2012 and 2011, ASB had $6.1 million and $7.3 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 31, 2012 and 2011, 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 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 (considered 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 considered the following events and circumstances in its analysis:

· Macroeconomic conditions – the national economy has stabilized and the Hawaii economy continues to improve. ASB’s business is primarily in the state of Hawaii which continues to show a stabilization of job growth and modest growth in the economy.

· Interest rate environment – the continued low interest rate environment will put pressure on ASB’s net interest margin. ASB has strategic plans to grow the loan portfolio and credit quality continues to improve.

· Financial performance – ASB’s profitability measures of net interest margin, return on assets, return on equity, efficiency ratio and net charge-offs compare favorably to industry peers.

· Regulation and legislation – the impact of lower noninterest income as a result of changes in fee legislation has been reflected in ASB’s financial results and the Durbin Amendment to the Dodd-Frank Act does not apply to ASB as the bank is under $10 billion of assets.

Based on its analysis, ASB 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, 2012, there has been no impairment of goodwill.

Amortized intangible assets.

December 31	2012				2011
	Gross carrying	Accumulated	Valuation	Net carrying	Gross carrying	Accumulated	Valuation	Net carrying
(in thousands)	amount	amortization	allowance	amount	amount	amortization	allowance	amount
Mortgage servicing assets	$25,835	(14,519)	(498)	$10,818	$21,171	(12,769)	(175)	$8,227

Changes in the valuation allowance for mortgage servicing assets were as follows:

(in thousands)	2012		2011		2010
Valuation allowance, January 1	$ 175		$128		$201
Provision (recovery)	504		121		(12	)
Other-than-temporary impairment	(181	)	(74	)	(61	)
Valuation allowance, December 31	$ 498		$175		$128

The estimated aggregate amortization expenses for mortgage servicing assets for 2013, 2014, 2015, 2016 and 2017 are $1.9 million, $1.5 million, $1.3 million, $1.1 million and $0.9 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 2012, 2011 and 2010, mortgage servicing assets acquired through the sale or securitization of loans held for sale were $4.8 million, $2.8 million and $3.3 million, respectively. Amortization expenses for ASB’s mortgage servicing assets amounted to $1.7 million, $1.1 million and $0.9 million for 2012, 2011 and 2010, respectively, and are recorded as a reduction in revenues on the consolidated statements of income.

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. Each segment 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, HELCO and MECO have been aggregated into the electric utility segment primarily because all three entities: (1) are involved in the business of supplying electric energy in the same geographical location (i.e., the State of Hawaii), (2) have similar production processes that include electric generators (e.g., conventional oil-fired steam units and combustion turbines), (3) serve similar customers within their franchise territories (e.g., residential, commercial and industrial customers), (4) use similar electric grids to distribute the energy to their customers, (5) are regulated by the PUC and undergo similar rate-making processes, and (6) have similar economic characteristics. 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.

100

Other

“Other” includes amounts for the holding companies (HEI and American Savings Holdings, Inc.), other subsidiaries not qualifying as reportable segments and intercompany eliminations.

Segment financial information was as follows:

(in thousands)	Electric utility	Bank	Other		Total

2012
Revenues from external customers	$3,109,353	$ 265,539	$ 103		$3,374,995
Intersegment revenues (eliminations)	86	–	(86	)	–
Revenues	3,109,439	265,539	17		3,374,995
Depreciation and amortization	151,496	5,334	1,517		158,347
Interest expense	62,055	11,292	16,096		89,443
Income (loss) before income taxes	162,319	89,021	(33,933	)	217,407
Income taxes (benefit)	61,048	30,384	(14,573	)	76,859
Net income (loss)	101,271	58,637	(19,360	)	140,548
Preferred stock dividends of subsidiaries	1,995	–	(105	)	1,890
Net income (loss) for common stock	99,276	58,637	(19,255	)	138,658
Capital expenditures	310,091	14,979	410		325,480
Assets (at December 31, 2012)	5,108,793	5,041,673	(1,334	)	10,149,132
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
Assets (at December 31, 2011)	4,674,007	4,909,974	10,496		9,594,477
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
Assets (at December 31, 2010)	4,287,745	4,796,759	2,905		9,087,409

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.

101

3 · Electric utility subsidiary

Selected financial information

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statements of Income Data

Years ended December 31	2012		2011		2010
(in thousands)
Revenues
Operating revenues	$3,101,998		$2,973,764		$2,367,441
Other – nonregulated	7,441		4,926		14,925
Total revenues	3,109,439		2,978,690		2,382,366
Expenses
Fuel oil	1,297,419		1,265,126		900,408
Purchased power	724,240		689,652		548,800
Other operation	272,117		257,065		251,027
Maintenance	122,312		121,219		127,487
Depreciation	144,498		142,975		149,708
Taxes, other than income taxes	292,841		276,504		222,117
Impairment of utility assets	40,000		9,215		–
Other – nonregulated	3,000		1,800		4,431
Total expenses	2,896,427		2,763,556		2,203,978
Operating income from regulated and nonregulated activities	213,012		215,134		178,388
Allowance for equity funds used during construction	7,007		5,964		6,016
Interest expense and other charges	(62,055	)	(60,031	)	(61,510)
Allowance for borrowed funds used during construction	4,355		2,498		2,558
Income before income taxes	162,319		163,565		125,452
Income taxes	61,048		61,584		46,868
Net income	101,271		101,981		78,584
Preferred stock dividends of subsidiaries	915		915		915
Net income attributable to HECO	100,356		101,066		77,669
Preferred stock dividends of HECO	1,080		1,080		1,080
Net income for common stock	$ 99,276		$ 99,986		$ 76,589

Consolidated Statements of Comprehensive Income

Years ended December 31	2012		2011		2010
(in thousands)

Net income for common stock	$ 99,276		$ 99,986		$ 76,589
Other comprehensive income (loss), net of taxes:
Retirement benefit plans:
Prior service credit arising during the period, net of taxes of nil, $4,408 and $3,001 for 2012, 2011 and 2010, respectively	–		6,921		4,712
Net losses arising during the period, net of tax benefits of $57,375, $74,346 and $27,408 for 2012, 2011 and 2010, respectively	(90,082	)	(116,726	)	(43,031)
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 $8,709, $5,332 and $2,387 for 2012, 2011 and 2010, respectively	13,673		8,372		3,747
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes of $48,069, $64,134 and $21,336 for 2012, 2011 and 2010, respectively	75,471		100,692		33,499
Other comprehensive loss, net of tax benefits	(938	)	(741	)	(1,073)
Comprehensive income attributable to Hawaiian Electric Company, Inc.	$ 98,338		$ 99,245		$ 75,516

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Consolidated Balance Sheet Data

December 31	2012		2011
(in thousands, except share data)
Assets
Utility plant, at cost
Property, plant and equipment	$ 5,415,968		$ 5,103,541
Less accumulated depreciation	(2,040,789	)	(1,966,894	)
Construction in progress	151,378		138,838
Net utility plant	3,526,557		3,275,485
Regulatory assets	864,596		669,389
Other	717,640		729,133
Total assets	$ 5,108,793		$ 4,674,007
Capitalization and liabilities
Common stock ($6 2/3 par value, authorized 50,000,000 shares, outstanding 14,665,264 shares and 14,233,723 shares in 2012 and 2011, respectively)	$ 97,788		$ 94,911
Premium on common stock	468,045		426,921
Retained earnings	907,273		881,041
Accumulated other comprehensive loss, net of tax benefits	(970	)	(32	)
Common stock equity	1,472,136		1,402,841
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	1,147,872		1,000,570
Total capitalization	2,654,301		2,437,704
Current portion of long-term debt	–		57,500
Taxes accrued	251,066		230,076
Deferred income taxes	417,611		337,863
Regulatory liabilities	322,074		315,466
Retirement benefits liability	620,591		495,134
Contributions in aid of construction	405,520		356,203
Other	437,630		444,061
Total capitalization and liabilities	$ 5,108,793		$ 4,674,007

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

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in parentheses are the original PUC authorized amortization or recovery periods and the remaining amortization or recovery periods as of December 31, 2012, if different.

Regulatory assets were as follows:

December 31	2012	2011
(in thousands)

Retirement benefit plans (balance primarily varies with plans’ funded statuses)	$660,835	$523,640
Income taxes, net (1 to 55 years)	84,931	83,386
Decoupling revenue balancing account (1 to 2 years)	66,076	20,780
Unamortized expense and premiums on retired debt and equity issuances (14 to 30 years; 2 to 20 years remaining)	17,130	12,267
Vacation earned, but not yet taken (1 year)	8,493	8,161
Postretirement benefits other than pensions (18 years; 1 year remaining)	249	1,861
Other (1 to 50 years; 1 to 47 years remaining)	26,882	19,294
	$864,596	$669,389

Regulatory liabilities were as follows:

December 31	2012	2011
(in thousands)

Cost of removal in excess of salvage value (1 to 60 years)	$305,978	$294,817
Retirement benefit plans (5 years beginning with respective utility’s next rate case; primarily 5 years remaining)	15,563	20,000
Other (5 years; 1 to 2 years remaining)	533	649
	$322,074	$315,466

The regulatory asset and liability relating to retirement benefit plans was recorded 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% ($349 million), 11% ($316 million) and 10% ($242 million) of their operating revenues from the sale of electricity to various federal government agencies in 2012, 2011 and 2010, 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, 2016. 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. West Coast and U.S. Midwest. Based on the average price per barrel as of December 31, 2012, the estimated cost of minimum purchases under the fuel supply contracts is $0.9 billion in 2013, $0.9 billion in 2014, $0.4 billion in 2015 and $0.4 billion in 2016. The actual cost of purchases in 2013 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, $1.3 billion and $1.0 billion of fuel under contractual agreements in 2012, 2011 and 2010, 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. A successor agreement between the parties for the supply of LSFO commences May 1, 2013 with an initial term ending December 31, 2016 and may automatically renew for annual terms thereafter unless earlier terminated by either party. The PUC issued an interim approval for the recovery of cost incurred under this contract on December 31, 2012.

HECO and Tesoro Hawaii Corp. (Tesoro) are parties to an amended LSFO supply contract (LSFO contract), which runs through April 30, 2013. A successor agreement between the parties for the supply of LSFO commences May 1, 2013 with an initial term ending December 31, 2014 and may automatically renew for

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annual terms thereafter unless earlier terminated by either party. The PUC issued an interim approval for the recovery of cost incurred under this contract on December 31, 2012. On January 8, 2013, Tesoro announced the April 2013 closure of its Kapolei refinery on Oahu. Tesoro stated that it will continue operations as a terminal for imported fuel while its Hawaii assets remain for sale. Tesoro has also stated it will honor all existing contracts.

HECO, MECO and HELCO are parties to amended contracts for the supply of industrial fuel oil and diesel fuels with Chevron and Tesoro, respectively, which end December 31, 2014. Both agreements may be automatically renewed for annual terms thereafter unless earlier terminated by either of the respective parties.

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 LSFO under a Facility Fuel Supply Contract (fuel contract) between them. The fuel contract between Kalaeloa and Tesoro term ends May 31, 2016 and may be extended for terms thereafter unless terminated by one of the parties.

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, 2012, HECO and its subsidiaries had six firm capacity PPAs for a total of 545 megawatts (MW) of firm capacity. Purchases from these six independent power producers (IPPs) and all other IPPs totaled $0.7 billion, $0.7 billion and $0.5 billion for 2012, 2011 and 2010, 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 as amended) 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 2013 through 2017 and a total of $0.7 billion in the period from 2018 through 2033.

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 PUC has approved purchased power adjustment clauses (PPACs) for the utilities. Purchased power capacity, operation and maintenance (O&M) and other non-energy costs previously recovered through base rates are now recovered in the PPACs, and subject to approval by the PUC, such costs resulting from new purchased power agreements can be added to the PPACs 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.

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, geothermal and others. This includes HECO’s plan to

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integrate wind power into the Oahu electrical grid that would be imported via a yet-to-be-built undersea transmission cable system from a large windfarm proposed to be built on the island of Lanai.

In December 2009, the PUC allowed HECO to defer the costs of studies for the 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. A decision from the PUC is pending.

In November 2011, HECO and MECO filed their application to seek PUC approval to defer for later recovery approximately $555,000 (split evenly between HECO and MECO) also through the REIP surcharge for additional studies to determine the value proposition of interconnecting the islands of Oahu and of Maui County (Maui, Lanai, and Molokai) and if doing so would be operationally beneficial and cost-effective. In August 2012, the PUC allowed HECO and MECO to defer the outside service costs for the additional studies for later review of prudence and reasonableness. The specific amount to be recovered, as well as the recovery mechanism and the terms of the recovery mechanism, will be determined at a later date.

A revised draft Request for Proposals (RFP) for 200 MW or more of renewable energy to be delivered to Oahu from any of the Hawaiian Islands has been posted on the HECO website prior to the issuance of a proposed final RFP. In February 2012, the PUC granted HECO’s request for deferred accounting treatment for the inter-island project support costs. The amount of the deferred costs was limited to $5.89 million.

In May 2012, the PUC instituted a proceeding for a competitive bidding process for up to 50 MW of firm renewable geothermal dispatchable energy (Geothermal RFP) on the island of Hawaii, and in July 2012, HELCO filed an application to defer 2012 costs related to the Geothermal RFP. HELCO filed the Proposed Final Geothermal RFP with the PUC in January 2013 and is seeking PUC approval to issue the Geothermal RFP.

Interim increases. As of December 31, 2012, HECO and its subsidiaries had recognized $7 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, 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 (CIS) project. The PUC subsequently eliminated the requirement for a regulatory audit for the EOTP Phase I in connection with an approved settlement of the project cost issues. As part of a settlement agreement with the Consumer Advocate, subject to PUC approval, the parties agreed that the regulatory audits for the CIP CT-1 and CIS projects would be eliminated (see “Subsequent event” below).

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 $163 million of project costs. In July 2011, the PUC allowed HECO to defer the portion of costs that are in excess of the prior PUC approved amounts and related depreciation for HECO’s CIP CT-1 project ($32 million) until completion of an independently conducted regulatory audit. The PUC also approved the accrual of a carrying charge on the cost of the project not yet included in rates and the related depreciation expense, from July 1, 2011 until the regulatory audit is 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 collected in electric rates. Management believes no adjustment to project costs is required as of December 31, 2012.

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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 in two phases (then estimated at $56 million - $42 million for Phase 1 and $14 million for Phase 2).

Phase 1 was placed in service in June 2010. The interim D&O issued in July 2011 in HECO’s 2011 test year rate case reflected approximately $16 million of Phase 1 costs and related depreciation expense in determining revenue requirements. In that D&O, the PUC ordered that a regulatory audit was to be conducted before the PUC determined the recoverability of the remaining Phase 1 costs.

In March 2012, the PUC approved a settlement agreement reached among HECO, the Consumer Advocate and the Department of Defense, under which, in lieu of a regulatory audit, HECO would write off $9.5 million of Phase 1 gross plant in service and associated adjustments. This resulted in an after-tax charge to net income in the fourth quarter of 2011 of approximately $6 million and the elimination of the requirement for a Phase 1 regulatory audit. The PUC also provided for an additional increase of approximately $5 million in HECO’s 2011 test year rate case for the additional revenue requirements reflecting all remaining Phase 1 costs not previously included in rates or agreed to be written off.

In October 2010, the PUC approved HECO’s proposed modification request for Phase 2 of the EOTP using smart grid technology. Phase 2 was placed in service in August 2012. As of December 31, 2012, HECO’s incurred costs for the Modified Phase 2 project amounted to $10 million (total cost of $15 million, less $5 million received in Smart Grid Investment Grant funding). Management believes that no adjustment to project costs of EOTP Modified Phase 2 is required as of December 31, 2012.

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’s new software system became operational in May 2012. In February 2012 and May 2012, the PUC granted HECO’s and MECO’s requests, respectively, to defer CIS project operation and maintenance expenses (limited to $2.3 million per year in 2011 and 2012 for HECO and limited to $0.6 million in 2012 for MECO) that are to be subject to a regulatory audit. The PUC also allowed them to accrue AFUDC on project costs (including deferred operation and maintenance expenses) until the completion of the regulatory audit and begin amortization of such costs when the amortization is included in rates. For accounting purposes, the utilities will recognize the equity portion of the carrying charge when it is collected in electric rates.

As of December 31, 2012, the utilities’ total deferred and capital costs for the CIS project were $20 million (after the write-off of $40 million of project costs—see “Subsequent event” below). Management believes no further adjustment to project costs is required as of December 31, 2012.

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 HECO’s power plants on the island of Oahu. If adopted as proposed, management believes the proposed regulations would require significant capital and annual O&M expenditures. On June 11, 2012, the EPA published additional information on the

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section 316(b) rule making that indicates that the EPA is considering establishing lower cost compliance alternatives in the final rule. The EPA has delayed issuance of the final section 316(b) rule until June 2013.

On February 16, 2012, the Federal Register published the EPA’s 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 power plants. MATS establishes the Maximum Achievable Control Technology standards for the control of hazardous air pollutants emissions from new and existing EGUs. Based on a review of the final rule and the benefits and costs of alternative compliance strategies, HECO has selected a MATS compliance strategy based on switching to lower emission fuels. The use of lower emission fuels will provide for MATS compliance at lower overall costs, avoid the reduction in operational flexibility imposed by emissions control equipment, achieve timely compliance with the MATS and provide flexibility for optimizing the combined compliance strategies for MATS and the tightening of the National Ambient Air Quality Standards.

On September 14, 2012, the EPA Administrator signed the final action for the Hawaii Regional Haze Federal Implementation Plan (FIP), which became effective on November 8, 2012. The plan establishes an annual limit for sulfur dioxide emissions from five HELCO steam generating units, with compliance required commencing December 31, 2018. No specific control technologies are required for any HECO or MECO generating units.

Depending upon the final outcome of the CWA 316(b) regulations, possible changes in CWA effluent standards, the specifics of the MATS compliance plan, and the implementation of more stringent National Ambient Air Quality Standards, 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. HECO and its subsidiaries believe the costs of responding to such 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.

Former Molokai Electric Company generation site. In 1989, MECO acquired by merger Molokai Electric Company. Molokai Electric Company had sold its former generation site (Site) in 1983, but continued to operate at the Site under a lease until 1985. The EPA has since performed Brownfield assessments of the Site that identified environmental impacts in the subsurface. Although MECO never operated at the Site and operations there had stopped four years before the merger, in discussions with the EPA and the Hawaii Department of Health (DOH), MECO agreed to undertake additional investigations at the Site and an adjacent parcel that Molokai Electric Company had used for equipment storage (the Adjacent Parcel) to determine the extent of impacts of subsurface contaminants. A 2011 assessment by a MECO contractor of the Adjacent Parcel identified environmental impacts, including elevated polychlorinated biphenyls (PCBs) in the subsurface soils. In cooperation with the DOH and EPA, MECO is further investigating the Site and the Adjacent Parcel to determine the extent of impacts of PCBs, fuel oils, and other subsurface contaminants. In March 2012, MECO accrued an additional $3.1 million (reserve balance of $3.6 million as of December 31, 2012) for the additional investigation and estimated cleanup costs at the Site and the Adjacent Parcel; however, final costs of remediation will depend on the results of continued investigation.

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 participated in a Task Force established under Act 234, which was 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

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those being implemented under the Energy Agreement. On October 19, 2012, the DOH posted the proposed regulations required by Act 234 for public hearing and comment. In general, the proposed regulations would require affected sources that have the potential to emit GHGs in excess of established thresholds to reduce GHG emissions by 25% below 2010 emission levels by 2020. The proposed regulations also assess affected sources an annual fee based on tons per year of GHG emissions, beginning with emissions in calendar year 2012. The proposed DOH GHG rule also tracks the federal “Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule” (GHG Tailoring Rule, see below) and would create new thresholds for GHG emissions from new and existing stationary source facilities. Both the federal and state regulations create certain exclusions for carbon dioxide (CO2) emissions from biomass-fired and other biogenic sources. The utilities are evaluating the impact of the proposed regulations; 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 have submitted the required reports for 2010 and 2011 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 GHG Tailoring Rule. Effective January 2, 2011, under the Prevention of Significant Deterioration program, permitting of new or modified stationary sources 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. On March 27, 2012, the Federal Register published the EPA’s proposed New Source Performance Standard regulating carbon dioxide emissions from affected new fossil fuel-fired generating units. As proposed, the rule does not apply to non-continental units (i.e., in Hawaii and U.S. Territories) and therefore does not apply to the utilities.

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 generating units, and testing biofuel blends in other HECO and MECO generating units. The utilities are also working with the State of Hawaii and other entities to pursue the use of liquefied natural gas as a cleaner and lower cost fuel to replace, at least in part, the petroleum oil that would otherwise be used. 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 their earnings. The cost of the AROs is recovered over the life of the asset through depreciation.

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AROs recognized by HECO and its subsidiaries relate to obligations to retire plant and equipment, including removal of asbestos and other hazardous materials.

Changes to the ARO liability included in “Other liabilities” on HECO’s balance sheet were as follows:

(in thousands)	2012		2011

Balance, January 1	$ 50,871		$ 48,630
Accretion expense	1,563		2,202
Liabilities incurred	–		256
Liabilities settled	(4,003	)	(835	)
Revisions in estimated cash flows	–		618
Balance, December 31	$ 48,431		$ 50,871

Collective bargaining agreements. As of December 31, 2012, approximately 52% 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 November 1, 2012, the utilities’ bargaining unit employees ratified a new collective bargaining agreement and a new benefit agreement that both expire on October 31, 2018. The collective bargaining agreement provides for general non-compounded wage increases of 3% for 2014, 2015, 2017 and 2018, and 3.25% for 2016. (A general 3% non-compounded wage increase has been provided to bargaining unit employees for 2013 under the collective bargaining agreement ratified in March 2011). The agreement also includes wage adjustments for certain trades and crafts positions and different wage rates for new bargaining unit office and clerical positions. The new benefit agreement provides for an escalating percentage of employee contributions without caps for medical premiums throughout the term of the agreement.

Subsequent event. On January 28, 2013, HECO, HELCO and MECO signed a settlement agreement with the Consumer Advocate (Agreement), subject to approval by the PUC, to write off $40 million of CIS project costs, in lieu of conducting the regulatory audits of the CIP CT-1 and the CIS projects. An after-tax charge to net income of $24 million ($18 million for HECO, $3 million for HELCO, and $3 million for MECO) was recorded in the fourth quarter of 2012 for the write-off of the project costs. In accordance with the Agreement, the remaining recoverable costs for CIP CT-1 and CIS of $52 million have been included in rate base as of December 31, 2012.

As part of the Agreement, the parties also agreed that HELCO would withdraw its 2013 test year rate case and will not file a rate case until its next turn in the 3-year cycle, which will be for a 2016 test year, but HELCO will make annual RBA and RAM rate adjustment filings to roll forward the base year information from its prior rate case. Additionally, HECO would delay the filing of its scheduled 2014 test year rate case, until no earlier than January 2, 2014. The parties also agree that starting in 2014, HECO will be allowed to record Revenue Adjustment Mechanism (RAM) revenues starting January 1 of each year through 2016. The cash collection of RAM revenues will remain unchanged, starting June 1 of each year through May 31 of the following year.

In deciding to enter into the Agreement, HECO, HELCO, and MECO took into account a number of considerations, including (1) the significant passage of time since the initial costs for the CIP CT-1 and CIS projects were incurred, (2) the uncertain timing and significant resources that would be required by the PUC, HECO and other parties to conduct a fair and meaningful regulatory audit of project costs for CIP CT-1 and CIS, (3) the additional carrying charges that would be accrued to the project cost for both CIP CT-1 and CIS, (4) resolving the regulatory audits, (5) the need to allow the PUC, the Consumer Advocate, HECO, HELCO and MECO to focus their resources on the numerous priorities they face in improving customer service and transforming the electric utility industry in Hawaii from one based on oil-fired generation to one based on energy efficiency and Hawaii’s indigenous renewable energy resources, and (6) the concern for the current high electric bills due to the high fuel costs.

Management cannot predict or provide any assurances concerning the approval or timing of approval of the Agreement by the PUC.

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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	2012	2011	2010
(in thousands)
Interest income
Interest and fees on loans	$176,057	$184,485	$195,192
Interest on investment and mortgage-related securities	13,822	14,568	14,946
Total interest income	189,879	199,053	210,138
Interest expense
Interest on deposit liabilities	6,423	8,983	14,696
Interest on other borrowings	4,869	5,486	5,653
Total interest expense	11,292	14,469	20,349
Net interest income	178,587	184,584	189,789
Provision for loan losses	12,883	15,009	20,894
Net interest income after provision for loan losses	165,704	169,575	168,895
Noninterest income
Fees from other financial services	31,361	28,881	27,280
Fee income on deposit liabilities	17,775	18,026	26,369
Fee income on other financial products	6,577	6,704	6,487
Gain on sale of loans	14,628	5,028	6,338
Net gains on sale of securities	134	371	–
Other income, net	5,185	6,344	6,081
Total noninterest income	75,660	65,354	72,555
Noninterest expense
Compensation and employee benefits	75,979	71,137	71,476
Occupancy	17,179	17,154	16,548
Data processing	10,098	8,155	13,213
Services	9,866	7,396	6,594
Equipment	7,105	6,903	6,620
Office supplies, printing and postage	3,870	3,934	3,928
Marketing	3,260	3,001	2,418
Communication	1,809	1,764	2,221
Other expense	23,177	23,949	25,920
Total noninterest expense	152,343	143,393	148,938
Income before income taxes	89,021	91,536	92,512
Income taxes	30,384	31,693	34,056
Net income	$58,637	$ 59,843	$ 58,456

Consolidated Statements of Comprehensive Income

Years ended December 31	2012		2011		2010
(in thousands)
Net income	$58,637		$ 59,843		$ 58,456
Other comprehensive income (loss), net of taxes:
Net unrealized gains (losses) on securities:
Net unrealized gains (losses) on securities arising during the period, net of (taxes) benefits of ($631), ($4,343) and $789, for 2012, 2011 and 2010, respectively	956		6,578		(1,196	)
Less: reclassification adjustment for net realized gains included in net income, net of taxes of $53, $148 and nil for 2012, 2011 and 2010, respectively	(81	)	(224	)	–
Retirement benefit plans:
Net gains (losses) arising during the period, net of (taxes) benefits of $5,240, $6,577 and ($3,007) for 2012, 2011 and 2010, respectively	(7,936	)	(9,960	)	4,554
Less: amortization of transition obligation, prior service credit and net losses recognized during the period in net periodic benefit cost, net of (taxes) benefits of $684, $346 and ($13) for 2012, 2011 and 2010, respectively	1,036		523		(20	)
Other comprehensive income (loss), net of taxes	(6,025	)	(3,083	)	3,338
Comprehensive income	$ 52,612		$ 56,760		$ 61,794

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Consolidated Balance Sheet Data

December 31	2012		2011
(in thousands)

Assets
Cash and cash equivalents	$ 184,430		$ 219,678
Available-for-sale investment and mortgage-related securities	671,358		624,331
Investment in stock of Federal Home Loan Bank of Seattle	96,022		97,764
Loans receivable held for investment	3,779,218		3,680,724
Allowance for loan losses	(41,985	)	(37,906	)
Loans receivable held for investment, net	3,737,233		3,642,818
Loans held for sale, at lower of cost or fair value	26,005		9,601
Other	244,435		233,592
Goodwill	82,190		82,190
Total assets	$5,041,673		$4,909,974
Liabilities and shareholder’s equity
Deposit liabilities–noninterest-bearing	$1,164,308		$ 993,828
Deposit liabilities–interest-bearing	3,065,608		3,076,204
Other borrowings	195,926		233,229
Other	117,752		118,078
Total liabilities	4,543,594		4,421,339
Commitments and contingencies (see “Litigation” below)
Common stock	333,712		331,880
Retained earnings	179,763		166,126
Accumulated other comprehensive loss, net of tax benefits	(15,396	)	(9,371	)
Total shareholder’s equity	498,079		488,635
Total liabilities and shareholder’s equity	$5,041,673		$4,909,974
Other assets
Bank-owned life insurance	$125,726		$121,470
Premises and equipment, net	62,458		52,940
Prepaid expenses	13,199		15,297
Accrued interest receivable	13,228		14,190
Mortgage-servicing rights	10,818		8,227
Real estate acquired in settlement of loans, net	6,050		7,260
Other	12,956		14,208
	$244,435		$233,592
Other liabilities
Accrued expenses	$17,103		$21,216
Federal and state income taxes payable	35,408		35,002
Cashier’s checks	23,478		22,802
Advance payments by borrowers	9,685		10,100
Other	32,078		28,958
	$117,752		$118,078

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.

As of December 31, 2012, ASB’s investment portfolio distribution was 62% mortgage-related securities issued by FNMA, FHLMC or GNMA, 26% federal agency obligations and 12% municipal bonds. These investment and mortgage-related securities are widely traded in the market and have observable transactions that allow them to be readily priced.

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 third party pricing service uses applications, models and pricing matrices that correlate security prices to benchmark securities which are adjusted for various inputs. Inputs include: benchmark yields, reported trades, broker/dealer quotes, issuer spreads, two-sided markets, benchmark security bids and offers, TBA prices, monthly payment information, and reference data including market

112

research. The pricing service may prioritize inputs differently on any given day for any security, and not all inputs are available for use in the evaluation process on any given day or for each security. The pricing vendor corroborates its finding on an on-going basis by monitoring market activity and events.

Third party pricing services provide security prices in good faith using rigorous methodologies; however, they do not warrant or guarantee the adequacy or accuracy of their information. Therefore, ASB utilizes a separate third party pricing vendor to corroborate security pricing of the first pricing vendor. If the pricing differential between the two pricing sources exceeds an established threshold, a pricing inquiry will be sent to both vendors or to an independent broker to determine a price that can be supported based on observable inputs found in the market. Such challenges to pricing are required infrequently and are generally resolved using additional security-specific information that was not available to a specific vendor.

December 31, 2012

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

$168,324

$ 3,167

$ –

$171,491

$ –

Mortgage-related securities- FNMA, FHLMC and GNMA

407,175

10,412

(204

)

417,383

32,269

(204

)

–

Municipal bonds

77,993

4,491

–

82,484

–

$653,492

$18,070

$(204

)

$671,358

$32,269

$(204

)

$ –

December 31, 2011

		Gross	Gross		Estimated	Gross unrealized losses
	Amortized	unrealized	unrealized		fair	Less than 12 months			12 months or longer
(dollars in thousands)	cost	gains	losses		value	Fair value	Amount		Fair value	Amount

Available-for-sale
Federal agency obligations	$218,342	$ 2,393	$ (8	)	$220,727	$ 19,992	$ (8	)	$ –	$ –
Mortgage-related securities-FNMA, FHLMC and GNMA	334,183	10,699	(17	)	344,865	11,994	(17	)	–	–
Municipal bonds	55,393	3,346	–		58,739	–	–		–	–
	$607,918	$16,438	$(25	)	$624,331	$31,986	$(25	)	$ –	$ –

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	$ 28,120	$ 28,283
Due after one year through five years	102,549	104,453
Due after five years through ten years	89,666	94,895
Due after ten years	25,982	26,344
	246,317	253,975
Mortgage-related securities-FNMA,FHLMC and GNMA	407,175	417,383
Total available-for-sale securities	$653,492	$671,358

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 2012, 2011 and 2010, proceeds from sales of available-for-sale mortgage-related securities were $3.5 million, $30.7 million and nil, resulting in gross realized gains of $0.1 million, $0.4 million and nil, respectively and there were no gross realized losses. In 2011, proceeds from the sale of municipal bonds were $2.1 million

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resulting in gross realized gains of $5,000 and no gross realized losses. There were no sales of municipal bonds in 2012 and 2010.

ASB pledged mortgage-related securities and federal agency obligations with a market value of approximately $98.0 million and $91.9 million as of December 31, 2012 and 2011, respectively, as collateral for public funds deposits, automated clearinghouse transactions with Bank of Hawaii, and deposits in ASB’s bankruptcy account with the Federal Reserve Bank of San Francisco. As of December 31, 2012 and 2011, mortgage-related securities and federal agency obligations with a carrying value of $189.3 million and $219.7 million, respectively, were pledged as collateral for securities sold under agreements to repurchase.

FHLB of Seattle stock. As of December 31, 2012 and 2011, 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, 2012, consistent with its accounting policy. ASB did not recognize an OTTI loss for 2012 based on its evaluation of the underlying investment, including:

· the net income and growth in retained earnings recorded by the FHLB of Seattle in the first nine months of 2012;

· compliance with all of its regulatory capital requirements and being classified “adequately capitalized” by the Federal Housing Finance Agency (Finance Agency);

· being allowed by the Finance Agency to repurchase excess stock;

· 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. ASB did not recognize OTTI for 2012, 2011 or 2010.

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Loans receivable.

December 31	2012	2011
(in thousands)
Real estate loans:
Residential 1-4 family	$1,866,450	$1,926,774
Commercial real estate	375,677	331,931
Home equity line of credit	630,175	535,481
Residential land	25,815	45,392
Commercial construction	43,988	41,950
Residential construction	6,171	3,327
Total real estate loans	2,948,276	2,884,855

Commercial loans	721,349	716,427
Consumer loans	121,231	93,253
Total loans	3,790,856	3,694,535
Deferred loan fees, net and unamortized discounts	(11,638)	(13,811)
Allowance for loan losses	(41,985)	(37,906)
Total loans, net	$3,737,233	$3,642,818

As of December 31, 2012 and 2011, ASB’s commitments to originate loans approximated $97.9 million and $95.4 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, 2012 and 2011, ASB had commitments to sell residential loans of $86.6 million and $44.9 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, net” with an offset on the ASB balance sheet in “Other” liabilities. As of December 31, 2012 and 2011, ASB had rate lock commitments on outstanding loans totaling notional amounts of $60.4 million and $35.8 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, 2012 and 2011, the notional amounts for forward sales contracts were $86.6 million and $44.9 million, respectively. Valuation models are applied using current market information to estimate fair value. There were no significant gains or losses on derivatives in 2012, 2011 and 2010.

As of December 31, 2012 and 2011, standby, commercial and banker’s acceptance letters of credit totaled $10.5 million and $10.8 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, 2012 and 2011, undrawn consumer lines of credit, including credit cards, totaled $1.0 billion and $0.9 billion, respectively, and undrawn commercial loans including lines of credit totaled $376.2 million and $289.3 million, respectively.

ASB services real estate loans for investors ($1.3 billion, $1.0 billion and $0.8 billion as of December 31, 2012, 2011 and 2010, respectively), which are not included in the accompanying consolidated balance sheet

115

data. 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, 2012 and 2011, ASB had pledged loans with an amortized cost of approximately $1.0 billion and $1.1 billion, respectively, as collateral to secure advances from the FHLB of Seattle.

As of December 31, 2012 and 2011, 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 $70.9 million and $62.1 million, respectively. The $8.8 million increase in such loans in 2012 was attributed to new commitments and loans of $10.0 million to new and existing directors and executive officers, offset by closed lines of credits and repayments of $1.2 million. As of December 31, 2012 and 2011, $65.9 million and $56.4 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.

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.

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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.

The allowance for loan losses was comprised of the following:

	Residential	Commercial real	Home equity line	Residen- tial	Commercial	Residential	Commer- cial	Consu- mer	Unallo-
(in thousands)	1-4 family	estate	of credit	land	construction	construction	loans	loans	cated	Total
December 31, 2012
Allowance for loan losses:
Beginning balance	$6,500	$1,688	$4,354	$3,795	$1,888	$4	$14,867	$3,806	$1,004	$ 37,906
Charge-offs	(3,183)	–	(716)	(2,808)	–	–	(3,606)	(2,517)	–	(12,830)
Recoveries	1,328	–	108	1,443	–	–	649	498	–	4,026
Provision	1,423	1,277	747	1,845	135	5	4,021	2,232	1,198	12,883
Ending balance	$6,068	$2,965	$4,493	$4,275	$2,023	$9	$15,931	$4,019	$2,202	$41,985
Ending balance: individually evaluated for impairment	$384	$535	$–	$3,221	$–	$–	$2,659	$–	$–	$6,799
Ending balance: collectively evaluated for impairment	$5,684	$2,430	$4,493	$1,054	$2,023	$9	$13,272	$4,019	$2,202	$35,186

Financing Receivables:
Ending balance	$1,866,450	$375,677	$630,175	$25,815	$43,988	$6,171	$721,349	$121,231	$–	$3,790,856
Ending balance: individually evaluated for impairment	$25,279	$6,751	$1,560	$18,563	$–	$–	$20,298	$22	$–	$72,473
Ending balance: collectively evaluated for impairment	$1,841,171	$368,926	$628,615	$7,252	$43,988	$6,171	$701,051	$121,209	$–	$3,718,383

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

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Changes in the allowance for loan losses were as follows:

(dollars in thousands)	2012	2011	2010

Allowance for loan losses, January 1	$37,906	$40,646	$41,679

Provision for loan losses	12,883	15,009	20,894

Charge-offs, net of recoveries
Real estate loans	3,828	10,733	14,276
Other loans	4,976	7,016	7,651
Net charge-offs	8,804	17,749	21,927
Allowance for loan losses, December 31	$41,985	$37,906	$40,646

Ratio of net charge-offs to average loans outstanding	0.24%	0.49%	0.61%

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 trends so that appropriate steps can be initiated to manage risk and avoid or minimize future losses. Loans subject to grading include commercial and industrial, commercial real estate and commercial construction loans.

A dual ten-point risk rating system is used to reflect the probability of default (borrower risk rating) and loss given default (transaction risk rating). The borrower risk rating addresses risk presented by the individual borrower and is 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, competitive issues, experience and quality of management, financial reporting quality and industry/economic factors. Separately, the transaction risk rating addresses risk in the transaction and is a function of the type of collateral control exercised over the collateral, loan structure, guarantees, and other structural support or enhancements to the loan.

The numerical representation of the risk 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	2012			2011
(in thousands)	Commercial real estate	Commercial construction	Commercial	Commercial real estate	Commercial construction	Commercial
Grade:
Pass	$314,182	$39,063	$638,854	$308,843	$41,950	$650,234
Special mention	25,437	4,925	24,511	8,594	–	14,660
Substandard	29,308	–	53,538	11,058	–	47,607
Doubtful	6,750	–	4,446	3,436	–	3,926
Loss	–	–	–	–	–	–
Total	$375,677	$43,988	$721,349	$331,931	$41,950	$716,427

The increase in commercial real estate and commercial loans graded special mention, substandard or doubtful was due to the downgrade of a small number of specific large commercial credits that are being closely monitored and managed. This risk migration reflects both adverse financial trends affecting those borrowers and improved risk rating accuracy of loans across all portfolios.

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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, 2012
Real estate loans:
Residential 1-4 family	$ 6,353	$1,741	$24,054	$32,148	$1,834,302	$1,866,450	$ –
Commercial real estate	85	–	6,750	6,835	368,842	375,677	–
Home equity line of credit	1,077	142	1,319	2,538	627,637	630,175	–
Residential land	2,851	75	7,788	10,714	15,101	25,815	–
Commercial construction	–	–	–	–	43,988	43,988	–
Residential construction	–	–	–	–	6,171	6,171	–
Commercial loans	3,052	2,814	1,098	6,964	714,385	721,349	131
Consumer loans	598	348	424	1,370	119,861	121,231	242
Total loans	$14,016	$5,120	$41,433	$60,569	$3,730,287	$3,790,856	$373

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

The credit risk profile based on nonaccrual loans and accruing loans 90 days or more past due was as follows:

December 31	2012		2011
	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	$26,721	$ –	$28,298	$ –
Commercial real estate	6,750	–	3,436	–
Home equity line of credit	2,349	–	2,258	–
Residential land	8,561	–	14,535	205
Commercial construction	–	–	–	–
Residential construction	–	–	–	–
Commercial loans	20,222	131	17,946	28
Consumer loans	284	242	281	308
Total	$64,887	$373	$66,754	$541

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The total carrying amount and the total unpaid principal balance of impaired loans was as follows:

December 31	2012					2011
(in thousands)	Recorded investment	Unpaid principal balance	Related Allow- ance	Average recorded investment	Interest income recognized	Recorded investment	Unpaid principal balance	Related allow- ance		Average recorded investment	Interest income recognized

With no related allowance recorded
Real estate loans:
Residential 1-4 family	$14,633	$20,247	$ –	$16,688	$ 294	$ 19,217	$ 26,614	$	–	$ 21,385	$	282
Commercial real estate	2,929	2,929	–	7,771	237	13,397	13,397	–		13,404	747
Home equity line of credit	581	1,374	–	632	1	711	1,612	–		954	6
Residential land	7,691	10,624	–	21,589	1,185	30,781	39,136	–		33,398	1,779
Commercial construction	–	–	–	–	–	–	–	–		–	–
Residential construction	–	–	–	–	–	–	–	–		–	–
Commercial loans	4,265	6,994	–	24,605	986	41,680	43,516	–		40,952	2,912
Consumer loans	21	21	–	23	–	25	25	–		16	–
	30,120	42,189	–	71,308	2,703	105,811	124,300	–		110,109	5,726

With an allowance recorded
Real estate loans:
Residential 1-4 family	4,803	4,803	384	4,204	250	3,525	3,525	203		3,527	201
Commercial real estate	3,821	3,840	535	1,295	–	–	–	–		–	–
Home equity line of credit	–	–	–	26	–	–	–	–		–	–
Residential land	9,984	10,364	3,221	7,428	575	7,792	7,852	2,525		8,158	603
Commercial construction	–	–	–	–	–	–	–	–		–	–
Residential construction	–	–	–	–	–	–	–	–		–	–
Commercial loans	16,033	16,912	2,659	8,429	23	6,561	6,561	976		8,131	737
Consumer loans	–	–	–	–	–	–	–	–		–	–
	34,641	35,919	6,799	21,382	848	17,878	17,938	3,704		19,816	1,541

Total
Real estate loans:
Residential 1-4 family	19,436	25,050	384	20,892	544	22,742	30,139	203		24,912	483
Commercial real estate	6,750	6,769	535	9,066	237	13,397	13,397	–		13,404	747
Home equity line of credit	581	1,374	–	658	1	711	1,612	–		954	6
Residential land	17,675	20,988	3,221	29,017	1,760	38,573	46,988	2,525		41,556	2,382
Commercial construction	–	–	–	–	–	–	–	–		–	–
Residential construction	–	–	–	–	–	–	–	–		–	–
Commercial loans	20,298	23,906	2,659	33,034	1,009	48,241	50,077	976		49,083	3,649
Consumer loans	21	21	–	23	–	25	25	–		16	–
	$64,761	$78,108	$6,799	$92,690	$3,551	$123,689	$142,238	$	3,704	$129,925	$	7,267

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 experiencing financial difficulty fails to make a required payment on a loan or is in imminent default, ASB takes a number of steps to improve the collectability of the loan and maximize the likelihood of full repayment. At times, ASB may modify or restructure a loan to help a distressed borrower improve its 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, extended amortization of principal, temporary deferral of principal payments, and temporary interest rate reductions. ASB rarely grants principal forgiveness in its TDR modifications. Residential loan modifications generally involve interest rate reduction, extending the amortization period, or capitalizing certain delinquent amounts owed not to exceed the original loan balance. Land loans at origination 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 up to five 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, extending the amortization period, and 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 effective original contractual rate, (2) fair value of collateral less cost to sell, or (3) observable market price. The financial impact of the calculated

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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 2012 and 2011 were as follows:

	2012			2011
	Number of	Outstanding recorded investment		Number of	Outstanding recorded investment
(dollars in thousands)	contracts	Pre-modification	Post-modification	contracts	Pre-modification	Post-modification

Troubled debt restructurings
Real estate loans:
Residential 1-4 family	35	$ 8,805	$ 8,232	42	$11,233	$ 9,853
Commercial real estate	–	–	–	–	–	–
Home equity line of credit	–	–	–	1	93	93
Residential land	26	6,149	5,484	46	9,965	9,946
Commercial loans	19	2,583	2,583	56	35,349	35,349
Consumer loans	–	–	–	1	25	25
	80	$17,537	$16,299	146	$56,665	$55,266

Loans modified in TDRs that experienced a payment default of 90 days or more in 2012 and 2011, and for which the payment default occurred within one year of the modification, were as follows:

	2012			2011
(dollars in thousands)	Number of contracts	Recorded investment		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	1	482		4	799
Consumer loans	–	–		–	–
	1	$	482	5	$	1,327

For 2012 the one commercial loan that subsequently defaulted was modified by temporarily lowering the monthly payments and deferring principal payments for a short period of time. For 2011 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	2012			2011
	Weighted-average			Weighted-average
(dollars in thousands)	stated rate		Amount	stated rate		Amount

Savings	0.06	%	$1,758,547	0.07	%	$1,684,875
Other checking
Interest-bearing	0.02		641,970	0.02		610,542
Noninterest-bearing	–		621,806	–		538,214
Commercial checking	–		542,502	–		455,614
Money market	0.13		191,398	0.21		236,641
Term certificates	0.86		473,693	0.98		544,146
	0.13	%	$4,229,916	0.18	%	$4,070,032

As of December 31, 2012 and 2011, certificate accounts of $100,000 or more totaled $106 million and $119 million, respectively.

The approximate amounts of term certificates outstanding as of December 31, 2012 with scheduled maturities for 2013 through 2017 were $284 million in 2013, $64 million in 2014, $70 million in 2015, $26 million in 2016, $20 million in 2017, and $10 million thereafter.

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Interest expense on deposit liabilities by type of deposit was as follows:

(in thousands)	2012	2011	2010

Term certificates	$4,865	$6,393	$11,221
Savings	1,128	1,756	2,262
Money market	319	650	884
Interest-bearing checking	111	184	329
	$6,423	$8,983	$14,696

Other borrowings.

Securities sold under agreements to repurchase.

December 31, 2012
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	$95,642	0.15	%	$127,093
1 to 29 days	–	–		–
30 to 90 days	–	–		–
Over 90 days	50,284	4.75		62,748
	$145,926	1.74	%	$189,841

At December 31, 2012, $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.

Information concerning securities sold under agreements to repurchase, which provided for the repurchase of identical securities, was as follows:

(dollars in millions)	2012		2011		2010

Amount outstanding as of December 31	$146		$183		$172
Average amount outstanding during the year	$173		$183		$201
Maximum amount outstanding as of any month-end	$189		$186		$238
Weighted-average interest rate as of December 31	1.74	%	1.56	%	1.71	%
Weighted-average interest rate during the year	1.56	%	1.61	%	1.53	%
Weighted-average remaining days to maturity as of December 31	489		490		628

Advances from Federal Home Loan Bank.

December 31, 2012	Weighted-average stated rate		Amount
(dollars in thousands)

Due in
2013	–	%	$ –
2014	–		–
2015	–		–
2016	–		–
2017	4.28		50,000
Thereafter	–		–
	4.28	%	$50,000

At December 31, 2012, $50 million of fixed rate FHLB advances with a rate of 4.28% is callable quarterly at par until maturity in 2017.

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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, 2012 and 2011.

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, 2012, as a result of capital contributions in prior years, HEI’s maximum obligation to contribute additional capital under the Capital Maintenance Agreement has been reduced to approximately $28.3 million. As of December 31, 2012, ASB was in compliance with the minimum capital requirements under OCC regulations.

In 2012, ASB paid cash dividends of $45 million to HEI, compared to cash dividends of $58 million and distributed noncash dividends of $5 million in 2011. 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. In November 2012, a federal judge granted preliminary approval to a proposed settlement between merchants and Visa over credit card fees. The federal judge will hold a hearing to give objectors a chance to weigh in before final approval is given. No date has been set for the hearing. As of December 31, 2012, ASB had accrued $1.1 million related to the agreement. Because the extent of ASB’s obligations under this agreement depends 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 years ended December 31, 2012 and 2011, ASB’s FDIC insurance assessments were $3.0 million and $3.6 million, respectively.

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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. The lawsuit is still in its preliminary stage, thus, the probable outcome and range of reasonably possible loss are not determinable at this time.

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 the obligations of HELCO and MECO under their respective debentures, are the sole assets of Trust III. Taken together, HECO’s obligations under the HECO debentures, the HECO indenture, the subsidiary guarantees, the trust agreement, the expense agreement and trust guarantee provide, in the aggregate, a full, irrevocable and unconditional guarantee of payments of amounts due on the Trust Preferred Securities. 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, 2012 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 2012 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, 2012, HECO and its subsidiaries had six PPAs for 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 firm capacity is purchased from AES Hawaii, Inc. (AES Hawaii), Kalaeloa, Hamakua Energy Partners, L.P. (HEP)

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and HPower. Purchases from all IPPs for 2012 totaled $724 million with purchases from AES Hawaii, Kalaeloa, HEP and HPower totaling $146 million, $310 million, $65 million and $65 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,” 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 2012, 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 later agreed to provide 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. 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. As of December 31, 2012, HECO’s accounts payable to Kalaeloa amounted to $23 million.

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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, 2012 and 2011, HEI had $84 million and $69 million of outstanding commercial paper, respectively, with a weighted-average interest rate of 0.9% and 0.8%, respectively, and HECO had no commercial paper outstanding.

As of December 31, 2012, HEI and HECO each maintained a syndicated credit facility of $125 million and $175 million, respectively. HEI borrowed under its facility in August 2012 and repaid such borrowings in the same month. HEI had no borrowings under its facility during 2011 and HECO had no borrowings under its facility during 2012 and 2011. None of the facilities are collateralized.

Credit agreements.

HEI. 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 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 18% as of December 31, 2012, as calculated under the agreement) and “Consolidated Net Worth” of at least $975 million (Net Worth of $1.7 billion as of December 31, 2012, as calculated under the agreement), or if HEI no longer owns HECO.

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.

HECO. 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”,

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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 contains customary conditions that must be met in order to draw on the credit facility, 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 43% for MECO as of December 31, 2012, as calculated under the agreement)). In addition to customary defaults, HECO’s failure to maintain its financial ratios, as defined in its credit agreement, or meet other requirements may result in an event of default. For example, under the credit agreement, it is an event of default if HECO fails to maintain a “Consolidated Capitalization Ratio” (equity) of at least 35% (ratio of 55% as of December 31, 2012, as calculated under the credit agreement), or if HECO is no longer owned by HEI.

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	2012			2011
(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	61,000			118,500
5.00-5.50%, due 2014-2032	63,400			203,400
5.65-5.75%, due 2018-2027	100,000			216,000
6.15-6.20%, due 2020-2029	–			55,000
4.60-4.65%, due 2026-2037	265,000			265,000
6.50%, due 2039	150,000			150,000
	639,400			1,007,900
Less unamortized discount	(74		)	(1,376		)
	639,326			1,006,524

HEI medium-term note 7.13%, due 2012	–			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			75,000
HEI senior note 5.67%, due 2021	50,000			50,000
HECO, HELCO and MECO senior notes 3.79%, due 2018	50,000			–
HECO and MECO senior notes 4.03%, due 2020	82,000			–
HECO, HELCO and MECO senior notes 4.55%, due 2023	100,000			–
HECO senior note 4.72%, due 2029	35,000			–
HECO senior note 4.53%, due 2032	40,000			–
HECO senior note 5.39%, due 2042	150,000			–
	$	1,422,872		$	1,340,070

As of December 31, 2012, the aggregate principal payments required on long-term debt for 2013 through 2017 are $50 million in 2013, $111 million in 2014, nil in 2015, $75 million in 2016 and nil in 2017.

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The HEI medium-term notes and Note Agreement for the HEI senior notes contain 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). The Note Agreement for the HEI senior notes also contains 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 18% as of December 31, 2012, as calculated under the agreement) or “Consolidated Net Worth” of at least $975 million (Net Worth of $1.7 billion as of December 31, 2012, 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).

The electric utilities’ senior notes contain customary representations and warranties, affirmative and negative covenants, and events of default (the occurrence of which may result in some or all of the notes of each and all of the utilities then outstanding becoming immediately due and payable) and provisions requiring the maintenance by HECO, and each of HELCO and MECO, of certain financial ratios generally consistent with those in HECO’s existing amended revolving noncollateralized credit agreement, which established a line of credit facility of $175 million.

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 pension plans and include, in the case of the HEI/HECO Pension Plan, benefits for utility union employees determined in accordance with the terms of the collective bargaining agreements between the utilities and the union. 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 under “Defined benefit pension and other postretirement benefit plans information” 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

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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 amendments, 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 HECO Benefits 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 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 each of 2011 and 2012) 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 to AOCI of $124 million pretax and $165 million pretax for 2012 and 2011, 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

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rates (as NPPC is recorded in excess of contributions). As of December 31, 2012, HECO’s pension asset had been reduced to $2 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 2012, 2011 and 2010 was $32 million, $34 million and $39 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 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 2012 and 2011 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, 2012 and 2011 were as follows:

	2012				2011
(in thousands)	Pension benefits		Other benefits		Pension benefits		Other benefits
Benefit obligation, January 1	$1,322,430		$190,549		$1,174,534		$180,332
Service cost	43,221		4,211		35,016		4,409
Interest cost	67,480		9,009		64,966		9,534
Amendments	–		–		–		(11,365	)
Actuarial losses (gains)	217,205		(1,991	)	104,970		16,518
Benefits paid and expenses	(60,032	)	(7,643	)	(57,056	)	(8,879	)
Benefit obligation, December 31	1,590,304		194,135		1,322,430		190,549
Fair value of plan assets, January 1	839,580		142,992		832,356		151,117
Actual return (loss) on plan assets	115,794		18,477		(9,713	)	(2,308	)
Employer contributions	74,923		2,780		72,931		2,030
Benefits paid and expenses	(58,983	)	(7,518	)	(55,994	)	(7,847	)
Fair value of plan assets, December 31	971,314		156,731		839,580		142,992
Accrued benefit liability, December 31	(618,990	)	(37,404	)	(482,850	)	(47,557	)
AOCI, January 1 (excluding impact of PUC D&Os)	533,537		28,684		366,552		9,036
Recognized during year – net recognized transition obligation	(1	)	–		(2	)	–
Recognized during year – prior service credit	325		1,793		389		1,494
Recognized during year – net actuarial losses	(25,675	)	(1,498	)	(16,987	)	(234	)
Occurring during year – prior service cost	–		–		–		(11,365	)
Occurring during year – net actuarial losses (gains)	172,595		(10,133	)	183,585		29,753
	680,781		18,846		533,537		28,684
Cumulative impact of PUC D&Os	(621,310	)	(18,123	)	(486,710	)	(29,183	)
AOCI, December 31	59,471		723		46,827		(499	)
Net actuarial loss	680,973		36,521		534,054		48,152
Prior service gain	(192	)	(17,675	)	(518	)	(19,468	)
Net transition obligation	–		–		1		–
	680,781		18,846		533,537		28,684
Cumulative impact of PUC D&Os	(621,310	)	(18,123	)	(486,710	)	(29,183	)
AOCL(AOCI), December 31	59,471		723		46,827		(499	)
Income taxes (benefits)	(23,489	)	(281	)	(18,495	)	194
AOCL(AOCI), net of taxes (benefits), December 31	$ 35,982		$ 442		$ 28,332		$ (305	)

The dates used to determine retirement benefit measurements for the defined benefit plans were December 31 of 2012, 2011 and 2010.

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, 2012 and 2011, had aggregate ABOs of $1,383 million and $1,182 million, respectively, and plan assets of $971 million and $840 million, respectively.

On July 6, 2012, President Obama signed the Moving Ahead for Progress in the 21st Century Act (MAP-21), which included provisions related to the funding and administration of pension plans. This law does not affect the Company’s accounting for pension benefits; therefore, the net periodic benefit costs disclosed for the plans were not affected. The Company elected to apply MAP-21 for 2012, which reduced the 2012 minimum funding requirement and lifted the restrictions on accelerated distribution options (which restrictions were in effect April 1, 2011 to September 30, 2012) for HEI and HECO and its subsidiaries. If the Adjusted Funding Target Attainment Percentage falls below 80% in the future, the restrictions on accelerated distribution options may apply again.

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. The HEI Retirement Plan fell below these thresholds in 2011 and the minimum required contribution for 2012 incorporated the more conservative assumptions required. Other factors could cause changes to the required contribution levels.

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The Company estimates that the cash funding for the qualified defined benefit pension plans in 2013 will be $85 million, 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 its pension and other postretirement benefit plans in 2013 is $86 million.

As of December 31, 2012, the benefits expected to be paid under all retirement benefit plans in 2013, 2014, 2015, 2016, 2017 and 2018 through 2022 amounted to $69 million, $72 million, $74 million, $77 million, $81 million and $460 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	2012		2011		Target		Range		2012		2011		Target		Range
Asset category
Equity securities	69	%	68	%	70	%	65-75	%	70	%	69	%	70	%	65-75	%
Fixed income	31		32		30		25-35	%	30		31		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	2012		2011		2010		2012		2011		2010

Benefit obligation Discount rate	4.13	%	5.19	%	5.68	%	4.07	%	4.90	%	5.60	%
Rate of compensation increase	3.5		3.5		3.5		NA		NA		NA
Net periodic benefit cost (years ended) Discount rate	5.19		5.68		6.50		4.90		5.60		6.50
Expected return on plan assets	7.75		8.00		8.25		7.75		8.00		8.25
Rate of compensation increase	3.5		3.5		3.5		NA		NA		NA

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, industry and corporate surveys and the past performance of the plans’ assets.

As of December 31, 2012, the assumed health care trend rates for 2013 and future years were as follows: medical, 8%, grading down to 5% for 2019 and thereafter; dental, 5%; and vision, 4%. 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%. Medicare Advantage

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reimbursements are expected to phase out by 2016; therefore, post age 65 medical trends are adjusted to reflect anticipated increases above the ordinary medical trend rates. For post age 65, the medical trend is 4% higher than pre-65 for 2012 through 2014 and 3% higher in 2015.

The components of NPBC were as follows:

	Pension benefits						Other benefits
(in thousands)	2012		2011		2010		2012		2011		2010

Service cost	$ 43,221		$ 35,016		$ 28,801		$ 4,211		$ 4,409		$ 4,739
Interest cost	67,480		64,966		64,527		9,009		9,534		10,378
Expected return on plan assets	(71,183	)	(68,901	)	(68,959	)	(10,336	)	(10,650	)	(11,101	)
Amortization of net transition obligation	1		2		2		–		–		–
Amortization of net prior service gain	(325	)	(389	)	(388	)	(1,793	)	(1,494	)	(396	)
Amortization of net actuarial loss (gain)	25,675		16,987		7,392		1,498		234		(14	)
Net periodic benefit cost	64,869		47,681		31,375		2,589		2,033		3,606
Impact of PUC D&Os	(15,754	)	(3,516	)	10,207		(2,227	)	2,674		5,400
Net periodic benefit cost (adjusted for impact of PUC D&Os)	$ 49,115		$ 44,165		$ 41,582		$ 362		$ 4,707		$ 9,006

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 2013 are $(0.1) million, $39.3 million and nil, 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 2013 are $(1.8) million, $2.1 million and nil, respectively.

The Company recorded pension expense of $35 million, $32 million and $32 million and OPEB expense of $1 million, $4 million and $7 million in 2012, 2011 and 2010, respectively, and charged the remaining amounts primarily to electric utility plant.

All pension plans and other benefits plans had ABO exceeding plan assets as of December 31, 2012 and 2011.

The health care cost trend rate assumptions can have a significant effect on the amounts reported for other benefits. As of December 31, 2012, 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 $5.7 million, and a one-percentage-point decrease would have reduced the total service and interest cost by $0.3 million and the APBO by $5.8 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 2012, 2011 and 2010, the Company’s expense for its defined contribution pension plans under the HEIRSP and the ASB 401(k) Plan was $4 million, $3 million and $4 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.

As of December 31, 2012, there were 3.8 million shares remaining available for future issuance under the EIP of which an estimated 2.0 million shares could be issued upon the vesting of outstanding restricted stock units and the achievement of performance goals under long-term incentive plans (based on the assumption that long-term incentive plan (LTIP) awards are achieved at maximum levels).

Under the 1987 Stock Option and Incentive Plan, as amended (SOIP), grants and awards of an estimated 0.2 million shares of common stock (based on various assumptions, including LTIP awards earned at maximum levels and the use of the December 31, 2012 market price of shares as the price on the exercise/payment dates) were outstanding as of December 31, 2012 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 shares compensation expense has been recognized in accordance with the fair-value-based measurement method of accounting. Dividends on restricted shares are paid quarterly in cash.

Restricted stock units awarded under the EIP in 2012 and 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 at the end of the restriction period when the associated restricted stock units vest.

Stock performance awards granted under the 2010-2012, 2011-2013 and 2012-2014 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 performance awards portion of the LTIP has been recognized in accordance with the fair-value-based measurement method of accounting for performance shares.

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The Company’s share-based compensation expense and related income tax benefit were as follows:

(in millions)	2012	2011	2010

Share-based compensation expense 1	$5.9	$3.8	$2.7
Income tax benefit	2.0	1.3	0.9

1 The Company has not capitalized any share-based compensation cost.

Nonqualified stock options. Information about HEI’s NQSOs was as follows:

	2012			2011			2010
	Shares		(1)	Shares		(1)	Shares		(1)

Outstanding, January 1	55,500		$20.92	215,500		$20.76	374,500		$19.73
Granted	–		–	–		–	–		–
Exercised	(41,500	)	21.06	(160,000	)	20.70	(157,000	)	18.32
Forfeited	–		–	–		–	–		–
Expired	–		–	–		–	(2,000	)	20.49
Outstanding, December 31	14,000		$20.49	55,500		$20.92	215,500		$20.76

Exercisable, December 31	14,000		$20.49	55,500		$20.92	215,500		$20.76

(1) Weighted-average exercise price

December 31, 2012		Outstanding & Exercisable (Vested)
Year of Grant	Exercise price	Number of options	Weighted-average remaining contractual life	Weighted-average exercise price

2003	20.49	14,000	0.3	$20.49

As of December 31, 2012, all NQSOs outstanding were exercisable and had an aggregate intrinsic value (including dividend equivalents) of $0.1 million.

NQSO activity and statistics were as follows:

(dollars in thousands)	2012	2011	2010

Cash received from exercise	$874	$3,312	$2,876
Intrinsic value of shares exercised 1	354	1,270	1,355
Tax benefit realized for the deduction of exercises	138	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:

	2012			2011			2010
	Shares		(1)	Shares		(1)	Shares		(1)

Outstanding, January 1	282,000		$26.14	450,000		$26.13	480,000		$26.13
Granted	–		–	–		–	–		–
Exercised	(114,000	)	26.17	(110,000	)	26.09	–		–
Forfeited	–		–	–		–	–		–
Expired	(4,000	)	26.18	(58,000	)	26.13	(30,000	)	26.18
Outstanding, December 31	164,000		$26.12	282,000		$26.14	450,000		$26.13

Exercisable, December 31	164,000		$26.12	282,000		$26.14	450,000		$26.13

(1) Weighted-average exercise price

December 31, 2012		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	62,000	1.3	$26.02
2005	26.18	102,000	2.3	26.18
	$26.02 –26.18	164,000	1.9	$26.12

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As of December 31, 2012, all SARs outstanding were exercisable and had no aggregate intrinsic value.

SARs activity and statistics were as follows:

(dollars in thousands, except prices)	2012	2011	2010

Intrinsic value of shares exercised 1	$197	$64	–
Tax benefit realized for the deduction of exercises	77	25	–

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.

Restricted shares and restricted stock awards. Information about HEI’s grants of restricted shares and restricted stock awards was as follows:

	2012			2011			2010
	Shares		(1)	Shares		(1)	Shares		(1)

Outstanding, January 1	46,807		$24.45	89,709		$24.64	129,000		$25.50
Granted	–		–	–		–	18,009	(2)	22.21
Vested	(37,802	)	24.99	(40,102	)	24.83	(43,565	)	26.29
Forfeited	–		–	(2,800	)	24.93	(13,735	)	24.35
Outstanding, December 31	9,005		$22.21	46,807		$24.45	89,709		$24.64

(1) Weighted-average grant-date fair value per share based on 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 2012, 2011 and 2010, total restricted stock vested had a grant-date fair value of $0.9 million, $1.0 million and $1.1 million, respectively, and the tax benefits realized for the tax deductions related to restricted stock awards were $0.2 million for 2012, $0.2 million for 2011, $0.3 million for 2010.

As of December 31, 2012, there was $0.1 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 1.9 years.

Restricted stock units. Information about HEI’s grants of restricted stock units was as follows:

	2012			2011			2010
	Shares		(1)	Shares		(1)	Shares		(1)

Outstanding, January 1	247,286		$21.80	146,500		$19.80	70,500		$16.99
Granted	98,446	(2)	25.99	101,786	(3)	24.68	77,500	(4)	22.30
Vested	(25,728	)	24.68	–		–	(250	)	16.99
Forfeited	(4,910	)	24.92	(1,000	)	22.60	(1,250	)	16.99
Outstanding, December 31	315,094		$22.82	247,286		$21.80	146,500		$19.80

(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 $2.6 million.

(3) Total weighted-average grant-date fair value of $2.5 million.

(4) Total weighted-average grant-date fair value of $1.7 million.

For 2012 and 2010, total restricted stock units that vested and related dividends had a grant-date fair value of $0.7 million and $6,000, respectively, and the related tax benefits were $0.2 million and $2,000, respectively.

As of December 31, 2012, there was $3.4 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 2.5 years.

LTIP payable in stock. The 2011-2013 LTIP and the 2012-2014 LTIP provide for performance awards under the EIP and the 2010-2012 LTIP provides for performance awards under the SOIP of shares of HEI common stock based on the satisfaction of performance goals considered to be a market condition and service conditions. 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 potential payout varies from 0% to 200% of the number of target shares depending on achievement of the goals. The LTIP performance goals for the 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 2010-2012

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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 and the 2012-2014 LTIP have performance goals related to levels of HEI consolidated net income, HECO consolidated net income, HECO consolidated ROACE, ASB net income and ASB return on assets – all based on the applicable three-year averages.

LTIP linked to TRS. Information about HEI’s LTIP grants linked to TRS was as follows:

	2012			2011			2010
	Shares		(1)	Shares		(1)	Shares		(1)

Outstanding, January 1	197,385		$25.94	126,782		$20.33	36,198		$14.85
Granted	81,223	(2)	30.71	75,015	(3)	35.46	97,191	(4)	22.45
Vested	(35,397	)	14.85	–		–	–		–
Forfeited	(3,955	)	30.82	(4,412	)	29.56	(6,607	)	21.53
Outstanding, December 31	239,256		$29.12	197,385		$25.94	126,782		$20.33

(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 $2.5 million (at target performance levels).

(3) Total weighted-average grant-date fair value of $2.7 million (at target performance levels).

(4) Total weighted-average grant-date fair value of $2.2 million (at target performance levels).

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 awards linked to TRS and the resulting fair value of LTIP awards granted:

	2012	2011	2010
Risk-free interest rate	0.33%	1.25%	1.30%
Expected life in years	3	3	3
Expected volatility	25.3%	27.8%	27.9%
Range of expected volatility for Peer Group	15.5% to 34.5%	21.2% to 82.6%	22.3% to 52.3%
Grant date fair value (per share)	$30.71	$35.46	$22.45

For 2012, total vested LTIP awards linked to TRS and related dividends had a fair value of $0.6 million and the related tax benefits were $0.2 million.

As of December 31, 2012, there was $2.5 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 year.

LTIP awards linked to other performance conditions. Information about HEI’s LTIP awards payable in shares linked to other performance conditions was as follows:

	2012			2011			2010
	Shares		(1)	Shares		(1)	Shares		(1)

Outstanding, January 1	182,498		$22.63	161,310		$18.66	24,131		$16.99
Granted	125,157		26.05	113,831	(2)	24.96	160,939	(3)	18.95
Vested	–		–	–		–	–		–
Cancelled	(50,786	)	18.95	(81,908	)	18.38	–		–
Forfeited	(9,694	)	24.44	(10,735	)	20.12	(23,760	)	18.90
Outstanding, December 31	247,175		$25.04	182,498		$22.63	161,310		$18.66

(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 $2.8 million (at target performance levels).

(3) Total weighted-average grant-date fair value of $3.0 million (at target performance levels).

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In 2012, LTIP grants (under the 2012-2014 LTIP) were made payable in 125,157 shares of HEI common stock (based on the grant date prices of $25.98, $26.75, $27.35, $27.22 and $26.03 and target performance levels relating to performance goals other than TRS), with a weighted-average grant date fair value of $3.3 million based on the weighted-average grant date fair value per share of $26.05.

As of December 31, 2012, there was $3.0 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 1.4 years.

11 · Income taxes

The components of income taxes attributable to net income for common stock were as follows:

Years ended December 31	2012		2011		2010
(in thousands)

Federal
Current	$ (15,411	)	$ (7,638	)	$(25,446	)
Deferred	82,138		73,494		85,268
Deferred tax credits, net	187		–		(901	)
	66,914		65,856		58,921
State
Current	(4,654	)	2,437		(7,392	)
Deferred	8,710		5,949		13,425
Deferred tax credits, net	5,889		1,690		2,868
	9,945		10,076		8,901
Total	$ 76,859		$ 75,932		$ 67,822

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	2012	2011	2010
(in thousands)

Amount at the federal statutory income tax rate	$76,092	$75,618	$64,136
Increase (decrease) resulting from:
State income taxes, net of federal income tax benefit	6,464	6,550	5,786
Other, net	(5,697)	(6,236)	(2,100)
Total	$76,859	$75,932	$67,822
Effective income tax rate	35.4%	35.1%	37.0%

The effective tax rate increased slightly from 2011 to 2012 due primarily to lower utility tax credit amortization and its lower relative impact on higher operating income in 2012, and tax-free bank-owned life insurance proceeds received in 2011. 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.

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The tax effects of book and tax basis differences that give rise to deferred tax assets and liabilities were as follows:

December 31	2012	2011
(in thousands)

Deferred tax assets
Allowance for loan losses	$ 17,254	$ 14,076
Retirement benefits	266	6,175
Other	34,354	33,217
Total deferred tax assets	51,874	53,468
Deferred tax liabilities
Property, plant and equipment related	316,900	255,488
Goodwill	23,781	22,028
Regulatory assets, excluding amounts attributable to property, plant and equipment	33,071	32,343
FHLB stock dividend	20,062	20,552
Change in accounting method related to repairs	69,514	48,566
Other	27,875	28,542
Total deferred tax liabilities	491,203	407,519
Net deferred income tax liability	$439,329	$354,051

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. As of December 31, 2012, the valuation allowance for deferred tax benefits is not significant. In 2012, 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 2012, 2011 and 2010, 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 $1.4 million, $1.2 million and $0.9 million, respectively. The credit adjustments to interest expense were primarily due to the resolution of tax issues with the IRS. As of December 31, 2012 and 2011, the total amount of accrued interest related to uncertain tax positions and recognized on the balance sheet in “Interest and dividends payable” was $0.3 million and $1.5 million, respectively.

As of December 31, 2012, the total amount of liability for uncertain tax positions was $0.8 million and, of this amount, $0.2 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 2013.

The changes in total unrecognized tax benefits were as follows:

(in millions)	2012		2011		2010
Unrecognized tax benefits, January 1	$ 5.7		$ 15.4		$ 26.5
Additions based on tax positions taken during the year	0.3		–		11.0
Reductions based on tax positions taken during the year	–		(0.6	)	–
Additions for tax positions of prior years	–		0.1		2.2
Reductions for tax positions of prior years	(4.1	)	(8.1	)	(18.2	)
Settlements	–		–		(6.1	)
Lapses of statute of limitations	(1.1	)	(1.1	)	–
Unrecognized tax benefits, December 31	$ 0.8		$ 5.7		$ 15.4

The 2012 reduction in unrecognized tax benefits was primarily due to the IRS’s acceptance of the deductibility of costs of repairs to utility generation property for tax years 2007-2009. The 2011 reduction in unrecognized tax benefits was primarily due to the IRS’s issuance of guidance (Revenue Procedure 2011-43,

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issued in August 2011) on the deductibility of costs of repairs to utility transmission and distribution (T&D) property, 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 elected the “safe harbor” method in its 2011 tax return, which resulted in the reduction of associated unrecognized tax benefits for 2011.

The IRS is currently auditing tax years 2010 to 2011. Tax years 2007 to 2011 remain subject to examination by the Department of Taxation of the State of Hawaii.

As of December 31, 2012, 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)	2012		2011		2010
Supplemental disclosures of cash flow information
Interest paid to non-affiliates	$ 84		$ 97		$ 95
Income taxes paid/(refunded)	(14	)	(22	)	6
Supplemental disclosures of noncash activities
Common stock dividends reinvested in HEI common stock 1	24		12		23
Increases in common stock related to director and officer compensatory plans	6		8		4
Electric utility property, plant and equipment
AFUDC-equity	7		6		6
Estimated fair value of noncash contributions in aid of construction	10		7		7
Unpaid invoices and other	37		45		21
Loans transferred from held for investment to held for sale	–		6		–
Real estate acquired in settlement of loans	11		12		7

1 The amounts shown represents common stock dividends reinvested in HEI common stock under the HEI DRIP in noncash transactions.

13 · Regulatory restrictions on net assets

As of December 31, 2012, HECO and its subsidiaries could not transfer approximately $637 million of net assets to HEI in the form of dividends, loans or advances without PUC approval.

ASB is required to notify the FRB and OCC prior to making any capital distribution (including dividends) to HEI. Generally, the FRB and OCC may disapprove or deny ASB’s request 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, 2012, ASB could transfer approximately $108 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.

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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. 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.

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:

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. To determine the fair value of investment securities held in ASB’s available-for-sale portfolio, independent third-party vendor or broker pricing is used on an unadjusted basis. Prices for investments and mortgage-related securities are based on observable inputs, including historical trading levels or sector yields, using market-based valuation techniques. The third party pricing service uses applications, models and pricing matrices that correlate security prices to benchmark securities which are adjusted for various inputs. Inputs include: benchmark yields, reported trades, broker/dealer quotes, issuer spreads, two-sided markets, benchmark security bids and offers, TBA prices, monthly payment information, and reference data including market research. The pricing service may prioritize inputs differently on any given day for any security, and not all inputs are available for use in the evaluation process on any given day or for each security. The pricing vendor corroborates its finding on an on-going basis by monitoring market activity and events.

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observable inputs found in the market. Such challenges to pricing are required infrequently and are generally resolved using additional security-specific information that was not available to a specific vendor.

Loans receivable. The estimated fair value of loans receivable is determined based on characteristics such as loan category, repricing features and remaining maturity, and includes prepayment estimates.

For residential real estate loans, fair values were estimated by discounting estimated cash flows using discount rates based on current industry pricing for loans with similar contractual characteristics and remaining maturity.

For other types of loans, fair values were 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 the Company’s current assessments of loan collectability. Also see “Fair value measurements on a nonrecurring basis” below.

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. Fair value was estimated by discounting the future cash flows using the current rates available for borrowings with similar credit terms and remaining maturities.

Long-term debt. Fair value was obtained from third-party financial services providers based on the current rates offered for debt of the same or similar remaining maturities.

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.

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The estimated fair values of certain of the Company’s financial instruments were as follows:

			Estimated fair value
(in thousands)	Carrying or notional amount		Level 1		Level 2		Level 3		Total

December 31, 2012
Financial assets
Money market funds	$	10	$	–	$	10	$	–	$	10
Available-for-sale investment and mortgage-related securities	671,358		–		671,358		–		671,358
Investment in stock of Federal Home Loan Bank of Seattle	96,022		–		96,022		–		96,022
Loans receivable, net	3,763,238		–		–		3,957,752		3,957,752
Financial liabilities
Deposit liabilities	4,229,916		–		4,235,527		–		4,235,527
Short-term borrowings—other than bank	83,693		–		83,693		–		83,693
Other bank borrowings	195,926		–		212,163		–		212,163
Long-term debt, net—other than bank	1,422,872		–		1,481,004		–		1,481,004

December 31, 2011
Financial assets
Money market funds	$	10	$	–	$	10	$	–	$	10
Available-for-sale investment and mortgage-related securities	624,331		–		624,331		–		624,331
Investment in stock of Federal Home Loan Bank of Seattle	97,764		–		97,764		–		97,764
Loans receivable, net	3,652,419		–		–		3,886,253		3,886,253
Financial liabilities
Deposit liabilities	4,070,032		–		4,075,6561		–		4,075,656		1
Short-term borrowings—other than bank	68,821		–		68,821		–		68,821
Other bank borrowings	233,229		–		250,486		–		250,486
Long-term debt, net—other than bank	1,340,070		–		1,400,241		–		1,400,241

1 Revised (increased by $83.9 million) to correct an error in the estimated fair value disclosure at December 31, 2011.

As of December 31, 2012 and 2011, loan commitments and unused lines and letters of credit issued by ASB had notional amounts of $1.5 billion and $1.3 billion, respectively, and their estimated fair value on such dates were $1.2 million and $0.3 million, respectively. As of December 31, 2012 and 2011, loans serviced by ASB for others had notional amounts of $1.3 billion and $993.3 million and the estimated fair value of the servicing rights for such loans was $11.9 million and $9.8 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. 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.

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Assets and liabilities measured at fair value on a recurring basis were as follows:

	Fair value measurements using
	Quoted prices in	Significant other	Significant
	active markets for identical	observable inputs	unobservable inputs
(in thousands)	assets (Level 1)	(Level 2)	(Level 3)

December 31, 2012
Money market funds (“other” segment)	$ –	$ 10	$ –
Available-for-sale securities (bank segment)
Mortgage-related securities-FNMA, FHLMC and GNMA	$ –	$417,383	$ –
Federal agency obligations	–	171,491	–
Municipal bonds	–	82,484	–
	$ –	$671,358	$ –
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	$ –

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 based on the current appraised value of the collateral securing the loans 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 2012 and 2011, 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).

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, 2012	$ 21	$ –	$ –	$ 21
December 31, 2011	34	–	–	34

For 2012 and 2011, there were no adjustments to fair value for ASB’s loans held for sale.

Residential loans. The fair value of ASB’s residential loans that were written down due to impairment was determined based on third party appraisals, which include the appraisers’ assumptions and judgment, and therefore, is classified as a Level 3 measurement.

Home equity lines of credit. The fair value of ASB’s home equity lines of credit that were written down due to impairment was determined based on third party appraisals, which include the appraisers’ assumptions and judgment, and therefore, is classified as a Level 3 measurement.

Commercial loans. The fair value of ASB’s commercial loans that were written down due to impairment was determined based on third party appraisals, which include the appraisers’ assumptions and judgment, the value placed on the assets of the business and cash flows generated by the business entity, and therefore, is classified as a Level 3 measurement.

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Real estate acquired in settlement of loans. The fair value of ASB’s real estate acquired in settlement of loans that were written down due to impairment was determined based on third party appraisals, which include the appraisers’ assumptions and judgment, and therefore, is classified as a Level 3 measurement.

For loans and real estate acquired in settlement of loans classified as Level 3 as of December 31, 2012, the significant unobservable inputs used in the fair value measurement were as follows:

($ in thousands)	Fair value at December 31, 2012	Valuation technique	Significant unobservable input	Significant unobservable input value
Residential loans	$16,401	Fair value of property or collateral	Appraised value	13 - 96%
Home equity lines of credit	581	Fair value of property or collateral	Appraised value	22 - 80%

Commercial loan	14	Fair value of property or collateral	U.S. government agency guarantee	85%
Commercial loan	118	Fair value of property or collateral	Appraised value	73%
Commercial loan	225	Fair value of property or collateral	Insurance proceeds	60%
Commercial loans	1,203	Fair value of property or collateral	Fair value of business assets	9 - 94%
Commercial loan	1,961	Discounted cash flow	Present value of expected future cash flows based on anticipated debt restructuring	Paydown of loan – 61%
			Discount rate	4.5%
Total commercial loans	3,521
Real estate acquired in settlement of loans	2,529	Fair value of property or collateral	Appraised value	58 – 99%

Significant increases (decreases) in any of those inputs in isolation would result in significantly higher (lower) fair value measurement.

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Retirement benefit plans

Assets held in various trusts for the retirement benefit plans (Plans) are measured at fair value on a recurring basis and were as follows:

	Pension benefits				Other benefits
		Fair value measurements using				Fair value measurements using
		Quoted prices in active markets for identical assets	Significant other observable inputs	Significant unobserv- able inputs		Quoted prices in active markets for identical assets	Significant other observable inputs	Significant unobserv- able inputs
(in millions)	December 31	(Level 1)	(Level 2)	(Level 3)	December 31	(Level 1)	(Level 2)	(Level 3)
2012
Equity securities	$513	$513	$ –	$ –	$ 83	$ 83	$ –	$ –
Equity index funds	95	95	–	–	15	15	–	–
Fixed income securities	338	125	213	–	47	41	6	–
Pooled and mutual funds and other	78	1	76	1	13	–	13	–
Total	1,024	$734	$289	$ 1	158	$139	$19	$ –
Receivables and payables, net	(53)				(1)

Fair value of plan assets	$971				$157

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 and other	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

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 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, 2012 and 2011.

Equity securities, equity index funds, U.S. Treasury fixed income securities and public mutual funds (Level 1). Equity securities, equity index funds, U.S. Treasury fixed income securities and public mutual funds are valued at the closing price reported on the active market on which the individual securities or funds are traded.

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

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and are valued at the net asset value per share. Certain other investments are valued based on discounted cash flow analyses, using observable inputs.

Other (Level 3). Venture capital interest is valued at historical cost, modified by revaluation of financial assets and financial liabilities at fair value through profit or loss.

For 2012 and 2011, the changes in Level 3 assets were as follows:

	2012		2011
(in thousands)	Pension benefits	Other benefits	Pension benefits	Other benefits
Balance, January 1	$217	$ 7	$141	$ 5
Realized and unrealized gains (losses)	(24)	(1)	92	3
Purchases and settlements, net	388	12	(16)	(1)
Balance, December 31	$581	$18	$217	$ 7

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

2012
Revenues	$814,860	$854,268	$867,720	$838,147	$3,374,995
Operating income	75,816	79,406	91,702	37,272	284,196
Net income for common stock 1	38,316	38,800	47,706	13,836	138,658
Basic earnings per common share 2	0.40	0.40	0.49	0.14	1.43
Diluted earnings per common share 3	0.40	0.40	0.49	0.14	1.42
Dividends per common share	0.31	0.31	0.31	0.31	1.24
Market price per common share 4
High	26.79	28.87	29.24	26.75	29.24
Low	24.86	24.65	26.26	23.65	23.65

2011
Revenues	$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 5	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

1 In the fourth quarter of 2012, as part of a settlement agreement with the Consumer Advocate, the electric utilities recorded a writedown of $24 million (net of taxes) of CIS project costs in lieu of conducting regulatory audits of the CIP CT-1 and CIS projects.

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 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) relating to a transmission project.

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HECO:

The information required by this Item 8 for HECO is incorporated herein by reference to pages of HECO Exhibit 99.2 as noted in Item 15(a)(1).

ITEM 9. CHANGES 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, 2012. Based on their evaluations, as of December 31, 2012, 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, 2012 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, 2012.

The effectiveness of the Company’s internal control over financial reporting as of December 31, 2012 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears on page 85.

Changes in Internal Control over Financial Reporting

There have been no changes in internal control over financial reporting during the quarter ended December 31, 2012 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, 2012. Based on their evaluations, as of December 31, 2012, 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, 2012 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, 2012.

Changes in Internal Control over Financial Reporting

There have been no changes in internal control over financial reporting during the quarter ended December 31, 2012 that have materially affected, or are reasonably likely to materially affect, HECO’s internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

On February 14, 2013, David M. Kostecki provided HEI notification of his voluntary resignation as Vice President-Finance, Controller and Chief Accounting Officer, effective on or about March 8, 2013. Mr. Kostecki has recently received an offer to lead another business operation and is resigning in order to pursue this opportunity. Mr. Kostecki’s resignation was not the result of any disagreement with the Company on any matter relating to the Company’s operations, policies or practices.

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 4 of this report.

The remaining information required by this Item 10 for HEI is incorporated herein by reference to the following sections in the HEI 2013 Proxy Statement:

· “Nominees for Class II directors whose terms expire at the 2016 Annual Meeting”

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

· “Continuing Class I directors whose terms expire at the 2015 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)

149

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 2013 Proxy Statement.

HECO:

The information required by this Item 10 for HECO is incorporated herein by reference to pages 1 to 8 of HECO Exhibit 99.3.

ITEM 11. EXECUTIVE COMPENSATION

HEI:

The information required by this Item 11 for HEI is incorporated herein by reference to the information relating to executive and director compensation in the HEI 2013 Proxy Statement.

HECO:

The information required by this Item 11 for HECO is incorporated herein by reference to:

· Pages 8 to 34 of HECO Exhibit 99.3;

· The discussion of “What is HECO’s 2011-2013 long-term incentive plan?” at pages 166-167 of HECO’s Annual Report on Form 10-K for the year ended December 31, 2011; and

· Information concerning compensation paid to directors of HECO who are also directors of HEI under the section of the HEI 2013 Proxy Statement entitled, “Director Compensation.”

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 2013 Proxy Statement.

HECO:

The information required by this Item 11 for HECO is incorporated herein by reference to page 8 of HECO Exhibit 99.3.

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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 by this Item 12 for HEI 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 2013 Proxy Statement.

Equity compensation plan information

Information as of December 31, 2012 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	1,351,869	$25.00	2,041,754
Equity compensation plans not approved by shareholders	–	–	–
Total	1,351,869	$25.00	2,041,754

(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, 2012, including:

SOIP	EIP	TOTAL
15,197	–	15,197	Nonqualified stock options plus accrued dividend equivalents
100	–	100	Stock appreciation rights plus accrued dividend equivalent rights
68,812	284,788	353,600	Restricted stock units plus estimated compounded dividend equivalents (if applicable) *
103,182	–	103,182	Shares issued in February 2013 under the 2010-2012 LTIP plus compounded dividend equivalents
–	879,790	879,790	Shares issuable at maximum payouts under the 2011-2013 and 2012-2014 LTIPs, including estimated compounded dividend equivalents
187,291	1,164,578	1,351,869

* Under the EIP, RSUs will be counted against the shares authorized for issuance as four shares for every share issued. Accordingly, the 284,788 RSU shares in the table are counted as 1,139,152 shares in determining the 2,041,754 shares available for future issuance under the EIP.

(2) The weighted average exercise price in this column relates to the outstanding 14,000 nonqualified stock options and 62,000 stock appreciation rights which were granted in 2004. Excluded from the weighted average exercise price calculation are 102,000 stock appreciation rights whose exercise price was greater than the share price on December 31, 2012 and 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, 2012 for future awards, including 1,806,110 shares available for future awards under the EIP and 235,644 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:

The information required by this Item 12 for HECO is incorporated herein by reference to pages 34 to 35 of HECO Exhibit 99.3.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

HEI:

The information required by this Item 13 for HEI is incorporated herein by reference to the sections relating to related person transactions and director independence in the HEI 2013 Proxy Statement.

HECO:

The information required by this Item 13 for HECO is incorporated herein by reference to pages 36 to 37 of HECO Exhibit 99.3.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

HEI:

The information required by this Item 14 for HEI is incorporated herein by reference to the relevant information in the Audit Committee Report in the HEI 2013 Proxy Statement (but no other part of the “Audit Committee Report” is incorporated herein by reference).

HECO:

The information required by this Item 14 for HECO is incorporated herein by reference to page 38 of HECO Exhibit 99.3.

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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 the pages of HECO Exhibit 99.2 indicated below:

		Page/s in HECO Exhibit 99.2

Report of Independent Registered Public Accounting Firm		5
Consolidated Statements of Income, Years ended December 31, 2012, 2011 and 2010		6
Consolidated Statements of Comprehensive income, Years ended December 31, 2012, 2011 and 2010		7
Consolidated Balance Sheets, December 31, 2012 and 2011		8
Consolidated Statements of Capitalization, December 31, 2012 and 2011		9-10
Consolidated Statements of Changes in Common Stock Equity, Years ended December 31, 2012, 2011 and 2010		11
Consolidated Statements of Cash Flows, Years ended December 31, 2012, 2011 and 2010		12
Notes to Consolidated Financial Statements		13-47

(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

Report of Independent Registered Public Accounting Firm		154	155
Schedule I	Condensed Financial Information of Registrant, Hawaiian Electric Industries, Inc. (Parent Company) as of December 31, 2012 and 2011 and Years ended December 31, 2012, 2011 and 2010	156-158	NA
Schedule II	Valuation and Qualifying Accounts, Years ended December 31, 2012, 2011 and 2010	159	159
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.

153

[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 19, 2013 appearing in this Annual Report on Form 10-K, also included an audit of the financial statement schedules listed in Item 15(a)(2) of this Form 10-K. In our opinion, these financial statement schedules 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 19, 2013

154

[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 19, 2013 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 for the three years ended December 31, 2012 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, 2012 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 19, 2013

155

Hawaiian Electric Industries, Inc.

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT

HAWAIIAN ELECTRIC INDUSTRIES, INC. (PARENT COMPANY)

CONDENSED BALANCE SHEETS

December 31	2012				2011
(dollars in thousands)
Assets
Cash and cash equivalents	$	18,021			$	1,765
Accounts receivable	1,836				1,361
Property, plant and equipment, net	5,814				6,076
Deferred income tax assets	8,517				14,208
Other assets	8,390				7,661
Investments in subsidiaries, at equity	1,978,283				1,898,911
	$	2,020,861			$	1,929,982
Liabilities and shareholders’ equity
Liabilities
Accounts payable	$	24,086			$	3,602
Interest payable	4,781				5,270
Notes payable to subsidiaries	7,722				7,019
Commercial paper	83,694				68,821
Long-term debt, net	275,000				282,000
Retirement benefits liability	28,004				26,201
Other	3,709				8,363
	426,996				401,276
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: 97,928,403 shares and 96,038,328 shares	1,403,484				1,349,446
Retained earnings	216,804				198,397
Accumulated other comprehensive loss	(26,423			)	(19,137			)
	1,593,865				1,528,706
	$	2,020,861			$	1,929,982
Note to Balance Sheets
Long-term debt consisted of :
HEI medium-term note 7.13%, paid in 2012	$		–		$		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				75,000
HEI senior note 5.67%, due 2021	50,000				50,000
	$		275,000		$		282,000

The aggregate payments of principal required subsequent to December 31, 2012 on long-term debt are $50 million in 2013, $100 million in 2014, nil in 2015, $75 million in 2016 and nil in 2017.

As of December 31, 2012, 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.

156

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	2012		2011		2010
(in thousands)

Revenues	$	221	$	253	$	204

Equity in net income of subsidiaries	157,883		158,722		134,470

Expenses:

Operating, administrative and general	16,191		15,401		13,336

Depreciation of property, plant and equipment	672		227		320

Taxes, other than income taxes	421		409		314

	17,284		16,037		13,970

Interest expense	16,695		22,013		19,961

Income before income tax benefits	124,125		120,925		100,743

Income tax benefits	14,533		17,305		12,792

Net income	$	138,658	$	138,230	$	113,535

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.

HAWAIIAN ELECTRIC INDUSTRIES, INC. (PARENT COMPANY)

STATEMENTS OF COMPREHENSIVE INCOME

STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

Incorporated by reference are HEI and Subsidiaries’ Statements of Consolidated Comprehensive Income and Consolidated Statements of Changes in Shareholders’ Equity in Part II, Item 8.

157

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)	2012			2011			2010
Cash flows from operating activities
Net income	$	138,658		$	138,230		$	113,535
Adjustments to reconcile net income to net cash provided by operating activities
Equity in net income	(157,883		)	(158,722		)	(134,470		)
Common stock dividends/distributions received from subsidiaries	118,044			128,558			110,769
Depreciation of property, plant and equipment	672			227			320
Other amortization	845			981			625
Changes in deferred income taxes	150			276			(1,432		)
Changes in excess tax benefits from share-based payment arrangements	(61		)	35			45
Changes in assets and liabilities
Decrease (increase) in accounts receivable	(475		)	412			(148		)
Increase in accounts and interest payable	19,995			1,324			936
Changes in prepaid and accrued income taxes	(4,861		)	3,550			(1,897		)
Contribution to defined benefit pension and other postretirement benefit plans	(1,628		)	(1,785		)	(724		)
Changes in other assets and liabilities	13,662			5,183			4,381
Net cash provided by operating activities	127,118			118,269			91,940
Cash flows from investing activities
Capital expenditures	(410		)	(110		)	(84		)
Investments in subsidiaries	(44,000		)	(40,000		)	(4,364		)
Other	–			(4,206		)	–
Net cash used in investing activities	(44,410		)	(44,316		)	(4,448		)
Cash flows from financing activities
Net decrease in notes payable to subsidiaries with original maturities of three months or less	(1,797		)	(1,757		)	(1,428		)
Net increase (decrease) in short-term borrowings with original maturities of three months or less	14,873			43,897			(17,066		)
Proceeds from issuance of long-term debt	–			125,000			–
Repayment of long-term debt	(7,000		)	(150,000		)	–
Changes in excess tax benefits from share-based payment arrangements	61			(35		)	(45		)
Net proceeds from issuance of common stock	23,613			15,979			22,706
Common stock dividends	(96,202		)	(106,812		)	(93,034		)
Net cash used in financing activities	(66,452		)	(73,728		)	(88,867		)
Net increase (decrease) in cash and equivalents	16,256			225			(1,375		)
Cash and cash equivalents, January 1	1,765			1,540			2,915
Cash and cash equivalents, December 31	$	18,021		$	1,765		$	1,540

Supplemental disclosures of noncash activities:

In 2012, 2011 and 2010, $1.8 million, $1.3 million and $1.1 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 $24 million, $12 million and $23 million in 2012, 2011 and 2010, respectively. HEI satisfied the requirements of the HEI DRIP, Hawaiian Electric Industries Retirement Savings Plan (HEIRSP) and ASB 401(k) Plan (from August 18, 2011 through January 8, 2012) by acquiring for cash its common shares through open market purchases rather than by issuing additional shares.

Note:

HEI’s “Notes to Consolidated Financial Statements” in Part II, Item 8 should be read in conjunction with the above HEI (Parent Company) financial statements.

158

Hawaiian Electric Industries, Inc.

and Hawaiian Electric Company, Inc.

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS

Years ended December 31, 2012, 2011 and 2010

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
2012
Allowance for uncollectible accounts – electric utility	$2,221	$3,230		$1,180	(a)	$4,483	(b)	$2,148
Allowance for uncollectible interest – bank	$4,825	–		–		$1,659		$3,166
Allowance for losses for loans receivable – bank	$37,906	$12,883		$4,026	(a)	$12,830	(b)	$41,985
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

(a) Primarily bad debts recovered.

(b) Bad debts charged off.

159

(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 Officer and Treasurer of HEI		Senior Vice President and Chief Financial Officer of HECO
			Senior Vice President and Chief Financial Officer of HECO
	(Principal Financial Officer of HEI)		(Principal Financial Officer of HECO)

Date:	February 19, 2013	Date:	February 19, 2013

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 19, 2013. 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)

160

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/ Cathlynn L. Yoshida		Controller of HECO
Cathlynn L. Yoshida		(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/ Micah A. Kane		Director of HECO
Micah A. Kane



/s/ Bert A. Kobayashi, Jr.		Director of HECO
Bert A. Kobayashi, Jr.



/s/ A. Maurice Myers		Director of HEI
A. Maurice Myers

161

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

162

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. HEI:		Description
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. 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(b)		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(c)		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		Hawaiian Electric Industries Retirement Savings Plan, restatement effective January 1, 2013.

4.6		Master Trust Agreement dated as of September 4, 2012 between HEI and ASB and Fidelity Management Trust Company, as Trustee (Exhibit 4 to HEI’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2012, File No. 1-8503).

*4.6(a)		Letter Amendment effective November 28, 2012 to Master Trust Agreement dated as of September 4, 2012 between HEI and ASB and Fidelity Management Trust Company.

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. 333-180413).

*4.8		American Savings Bank 401(k) Plan, restatement effective January 1, 2013.

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).

Exhibit no.			Description
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 10.19 are also management contracts or compensatory plans or arrangements with HECO participants.

*10.4			HEI Executive Incentive Compensation Plan amended as of February 4, 2013.

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, amended as of February 4, 2013, pursuant to 2010 Equity and Incentive Plan.

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 as of February 4, 2013.

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).

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 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).

*10.10(c)			Amendment No. 1 dated December 13, 2010 to January 1, 2009 Restatement of HEI Excess Pay Plan.

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).

Exhibit no.		Description
10.13		HEI 2011 Nonemployee Director Stock Plan (Appendix 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		Form of Indemnity Agreement (HEI, HECO and ASB with their respective directors and HEI with certain of its senior officers) (Exhibit 10.1 to HEI’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2012, File No. 1-8503).

10.20		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).

10.21		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).

10.21(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).

10.22		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).

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.

*12.1		Computation of Ratio of Earnings to Fixed Charges.

*21.1		Subsidiaries of HEI.

*23.1		Consent of Independent Registered Public Accounting Firm (PricewaterhouseCoopers 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).

Exhibit no.		Description

*32.1		HEI Certification Pursuant to 18 U.S.C. Section 1350.

*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).

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).

Exhibit no.		Description
4.13		Note Purchase Agreement among HECO and the Purchasers that are parties thereto, dated April 19, 2012 (Exhibit 4(a) to HECO’s Current Report on Form 8-K dated April 19, 2012, File No. 1-4955).

4.14		Note Purchase and Guaranty Agreement among HECO, MECO and the Purchasers that are parties thereto, dated April 19, 2012 (Exhibit 4(b) to HECO’s Current Report on Form 8-K dated April 19, 2012, File No. 1-4955).

4.15		Note Purchase and Guaranty Agreement among HECO, HELCO and the Purchasers that are parties thereto, dated April 19, 2012 (Exhibit 4(c) to HECO’s Current Report on Form 8-K dated April 19, 2012, File No. 1-4955).

4.16		Note Purchase Agreement among HECO and the Purchasers that are parties thereto, dated September 13, 2012 (Exhibit 4 to HECO’s Current Report on Form 8-K dated September 13, 2012, 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).

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).

Exhibit no.		Description

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 (Exhibit 10.4(f) to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 2011, File No. 1-4955).

10.4(g)		Power Purchase Agreement between Puna Geothermal Venture and HELCO dated February 7, 2011 (Exhibit 10.4(g) to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 2011, File No. 1-4955).

10.5(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).

10.5(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).

10.5(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).

10.5(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).

10.5(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).

10.5(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).

Exhibit no.		Description

10.6(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).

10.6(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).

10.6(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).

10.7		Low Sulfur Fuel Oil Supply Contract by and between Chevron and HECO dated as of August 24, 2012 (confidential treatment has been requested for portions of this exhibit) (Exhibit 10.2 to HECO’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2012, 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).

10.11		Low Sulfur Fuel Oil Supply Contract by and between Tesoro and HECO dated as of August 28, 2012 (confidential treatment has been requested for portions of this exhibit, which has been redacted accordingly) (Exhibit 10.3 to HECO’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2012, File No. 1-4955).

10.12(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).

10.12(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(c)		Second 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 January 31, 2012 (confidential treatment has been requested for portions of this exhibit, which has been redacted accordingly) (Exhibit 10.4 to HECO’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2012, File No. 1-4955).

Exhibit no.		Description

10.13(a)		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(b)		Consent to Change of Ownership/Control of Carrier by and between K-Sea Operating Partnership, L.P., and HELCO, dated July 1, 2011.

10.14(a)		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(b)		Consent to Change of Ownership/Control of Carrier by and between K-Sea Operating Partnership, L.P., and MECO, dated July 1, 2011.

10.15		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).

10.16		Stipulated Settlement Agreement between the Hawaiian Electric Companies and the Division of Consumer Advocacy regarding Certain Regulatory Matters (Exhibit 10 to HECO’s Current Report on Form 8-K, dated January 28, 2013, File No. 1-4955).

10.17		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).

10.18		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).

*12.2		Computation of Ratio of Earnings to Fixed Charges.

*21.2		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).

*32.2		HECO Certification Pursuant to 18 U.S.C. Section 1350.

*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 2012 Financial Statements (with Report of Independent Registered Public Accounting Firm thereon).

*99.3		HECO’s Directors, Executive Officers and Corporate Governance; HECO’s Executive Compensation; HECO’s Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters; HECO’s Certain Relationships and Related Transactions, and Director Independence; and HECO’s Principal Accounting Fees and Services.