UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

x  QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2013

OR

o  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)  OF THE SECURITIES EXCHANGE ACT OF 1934

Exact Name of Registrant as	Commission	I.R.S. Employer
Specified in Its Charter	File Number	Identification No.
HAWAIIAN ELECTRIC INDUSTRIES, INC.	1-8503	99-0208097
and Principal Subsidiary
HAWAIIAN ELECTRIC COMPANY, INC.	1-4955	99-0040500

State of Hawaii

(State or other jurisdiction of incorporation or organization)

Hawaiian Electric Industries, Inc. – 1001 Bishop Street, Suite 2900, Honolulu, Hawaii  96813

Hawaiian Electric Company, Inc. – 900 Richards Street, Honolulu, Hawaii  96813

(Address of principal executive offices and zip code)

Hawaiian Electric Industries, Inc. – (808) 543-5662

Hawaiian Electric Company, Inc. – (808) 543-7771

(Registrant’s telephone number, including area code)

Not applicable

(Former name, former address and former fiscal year, if changed since last report)

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 o Hawaiian Electric Company, Inc.  Yes x     No o

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 o Hawaiian Electric Company, Inc.  Yes x     No o

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 o    No x Hawaiian Electric Company, Inc.  Yes o     No x

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 o Non-accelerated filer o (Do not check if a smaller reporting company) Smaller reporting company o Hawaiian Electric Company, Inc. Large accelerated filer o Accelerated filer o Non-accelerated filer x (Do not check if a smaller reporting company) Smaller reporting company o

APPLICABLE ONLY TO CORPORATE ISSUERS:

Indicate the number of shares outstanding of each of the issuers’ classes of common stock, as of the latest practicable date.

Class of Common Stock	Outstanding April 29, 2013
Hawaiian Electric Industries, Inc. (Without Par Value)	98,541,357 Shares
Hawaiian Electric Company, Inc. ($6-2/3 Par Value)	14,665,264 Shares (not publicly traded)

Hawaiian Electric Industries, Inc. and Subsidiaries

Hawaiian Electric Company, Inc. and Subsidiaries

Form 10-Q—Quarter ended March 31, 2013

INDEX

Page No.
ii	Glossary of Terms
iv	Forward-Looking Statements
	PART I. FINANCIAL INFORMATION
1	Item 1.	Financial Statements
		Hawaiian Electric Industries, Inc. and Subsidiaries
1		Consolidated Statements of Income - three months ended March 31, 2013 and 2012
2		Consolidated Statements of Comprehensive Income - three months ended March 31, 2013 and 2012
3		Consolidated Balance Sheets - March 31, 2013 and December 31, 2012
4		Consolidated Statements of Changes in Shareholders’ Equity - three months ended March 31, 2013 and 2012
5		Consolidated Statements of Cash Flows - three months ended March 31, 2013 and 2012
6		Notes to Consolidated Financial Statements
		Hawaiian Electric Company, Inc. and Subsidiaries
27		Consolidated Statements of Income - three months ended March 31, 2013 and 2012
27		Consolidated Statements of Comprehensive Income - three months ended March 31, 2013 and 2012
28		Consolidated Balance Sheets - March 31, 2013 and December 31, 2012
29		Consolidated Statements of Changes in Common Stock Equity - three months ended March 31, 2013 and 2012
30		Consolidated Statements of Cash Flows - three months ended March 31, 2013 and 2012
31		Notes to Consolidated Financial Statements
49	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
49		HEI Consolidated
53		Electric Utilities
61		Bank
68	Item 3.	Quantitative and Qualitative Disclosures About Market Risk
69	Item 4.	Controls and Procedures
	PART II. OTHER INFORMATION
70	Item 1.	Legal Proceedings
70	Item 1A.	Risk Factors
80	Item 5.	Other Information
84	Item 6.	Exhibits
85	Signatures

i

Hawaiian Electric Industries, Inc. and Subsidiaries

Hawaiian Electric Company, Inc. and Subsidiaries

Form 10-Q—Quarter ended March 31, 2013

GLOSSARY OF TERMS

Terms	Definitions
AFTAP	Adjusted Funding Target Attainment Percentage
AFUDC	Allowance for funds used during construction
AOCI	Accumulated other comprehensive income
ARO	Asset retirement obligation
ASB	American Savings Bank, F.S.B., a wholly-owned subsidiary of American Savings Holdings, Inc.
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.
CIP CT-1	Campbell Industrial Park 110 MW combustion turbine No. 1
Company	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.).
Consumer Advocate	Division of Consumer Advocacy, Department of Commerce and Consumer Affairs of the State of Hawaii
DBEDT	State of Hawaii Department of Business, Economic Development and Tourism
D&O	Decision and order
Dodd-Frank Act	Dodd-Frank Wall Street Reform and Consumer Protection Act
DOH	Department of Health of the State of Hawaii
DRIP	HEI Dividend Reinvestment and Stock Purchase Plan
DSM	Demand-side management
ECAC	Energy cost adjustment clauses
EIP	2010 Equity and Incentive Plan
EGU	Electrical generating unit
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
EPA	Environmental Protection Agency -- federal
EPS	Earnings per share
EVE	Economic value of equity
Exchange Act	Securities Exchange Act of 1934
FDIC	Federal Deposit Insurance Corporation
federal	U.S. Government
FHLB	Federal Home Loan Bank
FHLMC	Federal Home Loan Mortgage Corporation
FNMA	Federal National Mortgage Association
FRB	Federal Reserve Board

ii

GLOSSARY OF TERMS, continued

Terms	Definitions
GAAP	U.S. generally accepted accounting principles
GHG	Greenhouse gas
GNMA	Government National Mortgage Association
HCEI	Hawaii Clean Energy Initiative
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.
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.)
HEIRSP	Hawaiian Electric Industries Retirement Savings Plan
HELCO	Hawaii Electric Light Company, Inc., an electric utility subsidiary of Hawaiian Electric Company, Inc.
HPOWER	City and County of Honolulu with respect to a power purchase agreement for a refuse-fired plant
IPP	Independent power producer
Kalaeloa	Kalaeloa Partners, L.P.
KW	Kilowatt
KWH	Kilowatthour
LTIP	Long-term incentive plan
MAP-21	Moving Ahead for Progress in the 21st Century Act
MECO	Maui Electric Company, Limited, an electric utility subsidiary of Hawaiian Electric Company, Inc.
MW	Megawatt/s (as applicable)
NII	Net interest income
NQSO	Nonqualified stock option
O&M	Other operation and maintenance
OCC	Office of the Comptroller of the Currency
OPEB	Postretirement benefits other than pensions
PPA	Power purchase agreement
PPAC	Purchased power adjustment clause
PUC	Public Utilities Commission of the State of Hawaii
RAM	Revenue adjustment mechanism
RBA	Revenue balancing account
RFP	Request for proposal
REIP	Renewable Energy Infrastructure Program
RHI	Renewable Hawaii, Inc., a wholly owned subsidiary of Hawaiian Electric Company, Inc.
ROACE	Return on average common equity
RORB	Return on average rate base
RPS	Renewable portfolio standard
SAR	Stock appreciation right
SEC	Securities and Exchange Commission
See	Means the referenced material is incorporated by reference
SOIP	1987 Stock Option and Incentive Plan, as amended
TDR	Troubled debt restructuring
UBC	Uluwehiokama Biofuels Corp., a non-regulated subsidiary of Hawaiian Electric Company, Inc.
VIE	Variable interest entity

iii

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 (including the effects of sequestration), 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 climate change, 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), 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;

iv

·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 existing, new and 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 and/or liabilities), 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, 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);

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

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

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

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

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

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

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

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

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

·other risks or uncertainties described elsewhere in this report and in other reports (e.g., “Item 1A. Risk Factors” in the Company’s Annual Report on Form 10-K) previously and subsequently filed by HEI and/or HECO with the Securities and Exchange Commission (SEC).

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

v

PART I - FINANCIAL INFORMATION

Item 1.  Financial Statements

Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Statements of Income (unaudited)

Three months ended March 31	2013			2012
(in thousands, except per share amounts)
Revenues
Electric utility	$	719,273		$	749,610
Bank	64,756			65,252
Other	35			(2		)
Total revenues	784,064			814,860
Expenses
Electric utility	666,320			692,356
Bank	43,005			42,340
Other	4,082			4,348
Total expenses	713,407			739,044
Operating income (loss)
Electric utility	52,953			57,254
Bank	21,751			22,912
Other	(4,047		)	(4,350		)
Total operating income	70,657			75,816
Interest expense—other than on deposit liabilities and other bank borrowings	(19,788		)	(18,539		)
Allowance for borrowed funds used during construction	730			870
Allowance for equity funds used during construction	1,215			1,940
Income before income taxes	52,814			60,087
Income taxes	18,662			21,298
Net income	34,152			38,789
Preferred stock dividends of subsidiaries	473			473
Net income for common stock	$	33,679		$	38,316
Basic earnings per common share	$	0.34		$	0.40
Diluted earnings per common share	$	0.34		$	0.40
Dividends per common share	$	0.31		$	0.31
Weighted-average number of common shares outstanding	98,135			96,167
Net effect of potentially dilutive shares	405			394
Adjusted weighted-average shares	98,540			96,561

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

1

Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Statements of Comprehensive Income (unaudited)

Three months ended March 31	2013			2012
(in thousands)
Net income for common stock	$	33,679		$	38,316
Other comprehensive income (loss), net of taxes:
Net unrealized losses on securities:
Net unrealized losses on securities arising during the period, net of tax benefits, of $547 and $149 for the three months ended March 31, 2013 and 2012, respectively	(828		)	(226		)
Derivatives qualified as cash flow hedges:
Less: reclassification adjustment to net income, net of tax benefits of $37 for the three months ended March 31, 2013 and 2012	59			59
Retirement benefit plans:
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 $3,846 and $2,473 for the three months ended March 31, 2013 and 2012, respectively	6,021			3,873
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes of $3,384 and $2,162 for the three months ended March 31, 2013 and 2012, respectively	(5,313		)	(3,395		)
Other comprehensive income (loss), net of taxes	(61		)	311
Comprehensive income attributable to Hawaiian Electric Industries, Inc.	$	33,618		$	38,627

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

2

Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Balance Sheets (unaudited)

(dollars in thousands)				March 31, 2013						December 31, 2012
Assets
Cash and cash equivalents				$	262,708					$	219,662
Accounts receivable and unbilled revenues, net				348,487						362,823
Available-for-sale investment and mortgage-related securities				659,400						671,358
Investment in stock of Federal Home Loan Bank of Seattle				95,152						96,022
Loans receivable held for investment, net				3,803,002						3,737,233
Loans held for sale, at lower of cost or fair value				5,351						26,005
Property, plant and equipment, net of accumulated depreciation of $2,142,040 in 2013 and $2,125,286 in 2012				3,640,308						3,594,829
Regulatory assets				874,151						864,596
Other				527,820						494,414
Goodwill				82,190						82,190
Total assets				$	10,298,569					$	10,149,132
Liabilities and shareholders’ equity
Liabilities
Accounts payable				$	253,096					$	212,379
Interest and dividends payable				26,358						26,258
Deposit liabilities				4,312,620						4,229,916
Short-term borrowings—other than bank				133,937						83,693
Other bank borrowings				193,233						195,926
Long-term debt, net—other than bank				1,422,875						1,422,872
Deferred income taxes				459,249						439,329
Regulatory liabilities				325,527						322,074
Contributions in aid of construction				415,795						405,520
Retirement benefits liability				643,104						656,394
Other				471,217						526,613
Total liabilities				8,657,011						8,520,974
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: 98,471,405 shares in 2013 and 97,928,403 shares in 2012				1,413,700						1,403,484
Retained earnings				220,049						216,804
Accumulated other comprehensive income (loss), net of taxes
Net unrealized gains on securities	$	9,933					$	10,761
Unrealized losses on derivatives	(701		)				(760		)
Retirement benefit plans	(35,716		)	(26,484		)	(36,424		)	(26,423		)
Total shareholders’ equity				1,607,265						1,593,865
Total liabilities and shareholders’ equity				$	10,298,569					$	10,149,132

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

3

Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Statements of Changes in Shareholders’ Equity (unaudited)

	Common stock			Retained			Accumulated other comprehensive
(in thousands, except per share amounts)	Shares	Amount		Earnings			loss			Total
Balance, December 31, 2012	97,928	$	1,403,484	$	216,804		$	(26,423	)	$	1,593,865
Net income for common stock	—	—		33,679			—			33,679
Other comprehensive loss, net of tax benefits	—	—		—			(61		)	(61		)
Issuance of common stock, net	543	10,216		—			—			10,216
Common stock dividends ($0.31 per share)	—	—		(30,434		)	—			(30,434		)
Balance, March 31, 2013	98,471	$	1,413,700	$	220,049		$	(26,484	)	$	1,607,265
Balance, December 31, 2011	96,038	$	1,349,446	$	198,397		$	(19,137	)	$	1,528,706
Net income for common stock	—	—		38,316			—			38,316
Other comprehensive income, net of taxes	—	—		—			311			311
Issuance of common stock, net	503	13,434		—			—			13,434
Dividend equivalents paid on equity-classified awards	—	—		(95		)	—			(95		)
Common stock dividends ($0.31 per share)	—	—		(29,817		)	—			(29,817		)
Balance, March 31, 2012	96,541	$	1,362,880	$	206,801		$	(18,826	)	$	1,550,855

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

4

Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Statements of Cash Flows (unaudited)

Three months ended March 31	2013			2012
(in thousands)
Cash flows from operating activities
Net income	$	34,152		$	38,789
Adjustments to reconcile net income to net cash provided by (used in) operating activities
Depreciation of property, plant and equipment	39,726			37,911
Other amortization	935			1,419
Provision for loan losses	1,858			3,546
Loans receivable originated and purchased, held for sale	(79,224		)	(89,087		)
Proceeds from sale of loans receivable, held for sale	102,254			85,252
Change in deferred income taxes	19,967			21,260
Change in excess tax benefits from share-based payment arrangements	(414		)	(44		)
Allowance for equity funds used during construction	(1,215		)	(1,940		)
Changes in assets and liabilities
Decrease in accounts receivable and unbilled revenues, net	14,335			37,562
Increase in fuel oil stock	(29,272		)	(14,458		)
Increase in regulatory assets	(17,746		)	(13,948		)
Increase (decrease) in accounts, interest and dividends payable	38,148			(36,991		)
Change in prepaid and accrued income taxes and utility revenue taxes	(50,933		)	(41,126		)
Contributions to defined benefit pension and other postretirement benefit plans	(21,476		)	(26,815		)
Change in other assets and liabilities	(2,776		)	(17,046		)
Net cash provided by (used in) operating activities	48,319			(15,716		)
Cash flows from investing activities
Available-for-sale investment and mortgage-related securities purchased	(26,705		)	(53,931		)
Principal repayments on available-for-sale investment and mortgage-related securities	36,504			46,355
Net increase in loans held for investment	(66,934		)	(34,212		)
Proceeds from sale of real estate acquired in settlement of loans	3,046			3,371
Capital expenditures	(71,041		)	(65,300		)
Contributions in aid of construction	11,710			22,855
Other	869			—
Net cash used in investing activities	(112,551		)	(80,862		)
Cash flows from financing activities
Net increase in deposit liabilities	82,704			55,172
Net increase in short-term borrowings with original maturities of three months or less	50,244			87,467
Net decrease in retail repurchase agreements	(2,680		)	(379		)
Proceeds from issuance of long-term debt	50,000			—
Repayment of long-term debt	(50,000		)	(57,500		)
Change in excess tax benefits from share-based payment arrangements	414			44
Net proceeds from issuance of common stock	4,703			5,940
Common stock dividends	(24,394		)	(23,855		)
Preferred stock dividends of subsidiaries	(473		)	(473		)
Other	(3,240		)	(3,757		)
Net cash provided by financing activities	107,278			62,659
Net increase (decrease) in cash and cash equivalents	43,046			(33,919		)
Cash and cash equivalents, beginning of period	219,662			270,265
Cash and cash equivalents, end of period	$	262,708		$	236,346

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

5

Hawaiian Electric Industries, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1 · Basis of presentation

The accompanying unaudited consolidated financial statements have been prepared in conformity with U.S. generally accepted accounting principles (GAAP) for interim financial information, the instructions to SEC Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. In preparing the financial statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the balance sheet and the reported amounts of revenues and expenses for the period. Actual results could differ significantly from those estimates. The accompanying unaudited consolidated financial statements and the following notes should be read in conjunction with the audited consolidated financial statements and the notes thereto in HEI’s Form 10-K for the year ended December 31, 2012.

In the opinion of HEI’s management, the accompanying unaudited consolidated financial statements contain all material adjustments required by GAAP to fairly state the Company’s financial position as of March 31, 2013 and December 31, 2012 and the results of its operations and cash flows for the three months ended March 31, 2013 and 2012. All such adjustments are of a normal recurring nature, unless otherwise disclosed in this Form 10-Q or other referenced material. Results of operations for interim periods are not necessarily indicative of results for the full year. When required, certain reclassifications are made to the prior period’s consolidated financial statements to conform to the current presentation.

6

2 · Segment financial information

(in thousands)	Electric utility		Bank		Other			Total
Three months ended March 31, 2013
Revenues from external customers	$	719,267	$	64,756	$	41		$	784,064
Intersegment revenues (eliminations)	6		—		(6		)	—
Revenues	719,273		64,756		35			784,064
Income (loss) before income taxes	39,322		21,752		(8,260		)	52,814
Income taxes (benefit)	14,394		7,597		(3,329		)	18,662
Net income (loss)	24,928		14,155		(4,931		)	34,152
Preferred stock dividends of subsidiaries	499		—		(26		)	473
Net income (loss) for common stock	24,429		14,155		(4,905		)	33,679
Assets (at March 31, 2013)	5,174,235		5,116,385		7,949			10,298,569
Three months ended March 31, 2012
Revenues from external customers	$	749,574	$	65,252	$	34		$	814,860
Intersegment revenues (eliminations)	36		—		(36		)	—
Revenues	749,610		65,252		(2		)	814,860
Income (loss) before income taxes	45,207		23,464		(8,584		)	60,087
Income taxes (benefit)	17,408		7,587		(3,697		)	21,298
Net income (loss)	27,799		15,877		(4,887		)	38,789
Preferred stock dividends of subsidiaries	499		—		(26		)	473
Net income (loss) for common stock	27,300		15,877		(4,861		)	38,316
Assets (at December 31, 2012)	5,108,793		5,041,673		(1,334		)	10,149,132

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.

3 · Electric utility subsidiary

For consolidated HECO financial information, including its commitments and contingencies, see HECO’s consolidated financial statements beginning on page 27 through Note 10 on page 40.

7

4 · Bank subsidiary

Selected financial information

American Savings Bank, F.S.B.

Statements of Income Data

Three months ended March 31	2013		2012
(in thousands)
Interest income
Interest and fees on loans	$	42,603	$	44,888
Interest on investment and mortgage-related securities	3,464		3,805
Total interest income	46,067		48,693
Interest expense
Interest on deposit liabilities	1,312		1,779
Interest on other borrowings	1,164		1,261
Total interest expense	2,476		3,040
Net interest income	43,591		45,653
Provision for loan losses	1,858		3,546
Net interest income after provision for loan losses	41,733		42,107
Noninterest income
Fees from other financial services	7,643		7,337
Fee income on deposit liabilities	4,314		4,278
Fee income on other financial products	1,794		1,549
Gain on sale of loans	3,346		2,035
Other income, net	1,592		1,360
Total noninterest income	18,689		16,559
Noninterest expense
Compensation and employee benefits	20,088		18,646
Occupancy	4,123		4,225
Data processing	2,987		2,111
Services	2,103		1,783
Equipment	1,774		1,730
Other expense	7,595		6,707
Total noninterest expense	38,670		35,202
Income before income taxes	21,752		23,464
Income taxes	7,597		7,587
Net income	$	14,155	$	15,877

American Savings Bank, F.S.B.

Statements of Comprehensive Income Data

Three months ended March 31	2013			2012
(in thousands)
Net income	$	14,155		$	15,877
Other comprehensive income (loss), net of taxes:
Net unrealized losses on securities:
Net unrealized losses on securities arising during the period, net of tax benefits, of $547and $149 for the three months ended March 31, 2013 and 2012, respectively	(828		)	(226		)
Retirement benefit plans:
Less: amortization of prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits of $1,424 and $164 for the three months ended March 31, 2013 and 2012, respectively	2,157			248
Other comprehensive income, net of taxes	1,329			22
Comprehensive income	$	15,484		$	15,899

8

American Savings Bank, F.S.B.

Balance Sheets Data

(in thousands)				March 31, 2013						December 31, 2012
Assets
Cash and cash equivalents				$	224,870					$	184,430
Available-for-sale investment and mortgage-related securities				659,400						671,358
Investment in stock of Federal Home Loan Bank of Seattle				95,152						96,022
Loans receivable held for investment				3,845,732						3,779,218
Allowance for loan losses				(42,730		)				(41,985		)
Loans receivable held for investment, net				3,803,002						3,737,233
Loans held for sale, at lower of cost or fair value				5,351						26,005
Other				246,420						244,435
Goodwill				82,190						82,190
Total assets				$	5,116,385					$	5,041,673
Liabilities and shareholder’s equity
Deposit liabilities—noninterest-bearing				$	1,223,921					$	1,164,308
Deposit liabilities—interest-bearing				3,088,699						3,065,608
Other borrowings				193,233						195,926
Other				106,337						117,752
Total liabilities				4,612,190						4,543,594
Commitments and contingencies (see “Litigation” below)
Common stock				334,344						333,712
Retained earnings				183,918						179,763
Accumulated other comprehensive income (loss), net of taxes
Net unrealized gains on securities	$	9,933					$	10,761
Retirement benefit plans	(24,000		)	(14,067		)	(26,157		)	(15,396		)
Total shareholder’s equity				504,195						498,079
Total liabilities and shareholder’s equity				$	5,116,385					$	5,041,673
Other assets
Bank-owned life insurance				$	126,798					$	125,726
Premises and equipment, net				64,217						62,458
Prepaid expenses				13,189						13,199
Accrued interest receivable				13,773						13,228
Mortgage-servicing rights				11,400						10,818
Real estate acquired in settlement of loans, net				3,785						6,050
Other				13,258						12,956
				$	246,420					$	244,435
Other liabilities
Accrued expenses				$	13,723					$	17,103
Federal and state income taxes payable				42,205						35,408
Cashier’s checks				21,810						23,478
Advance payments by borrowers				6,443						9,685
Other				22,156						32,078
				$	106,337					$	117,752

Bank-owned life insurance is life insurance purchased by ASB on the lives of certain key employees, with ASB as the beneficiary. The insurance is used to fund employee benefits through tax-free income from increases in the cash value of the policies and insurance proceeds paid to ASB upon an insured’s death.

9

Other borrowings consisted of securities sold under agreements to repurchase and advances from the Federal Home Loan Bank (FHLB) of Seattle of $143 million and $50 million, respectively, as of March 31, 2013 and $146 million and $50 million, respectively, as of December 31, 2012.

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 balance sheet. All such agreements are subject to master netting arrangements, which provide for conditional right of set-off in case of default by either party; however, ASB presents securities sold under agreements to repurchase on a gross basis in the balance sheet. The following tables present information about the securities sold under agreements to repurchase, including the related collateral received from or pledged to counterparties:

(in millions)	Gross amount of recognized liabilities		Gross amount offset in the Balance Sheet		Net amount of liabilities presented in the Balance Sheet
Repurchase agreements
March 31, 2013	$	143	$	—	$	143
December 31, 2012	146		—		146

	Gross amount not offset in the Balance Sheet
(in millions)	Net amount of liabilities presented in the Balance Sheet		Financial instruments		Cash collateral pledged		Net amount
March 31, 2013
Financial institution	$	50	$	50	$	—	$	—
Commercial account holders	93		93		—		—
Total	$	143	$	143	$	—	$	—
December 31, 2012
Financial institution	$	50	$	50	$	—	$	—
Commercial account holders	96		96		—		—
Total	$	146	$	146	$	—	$	—

Investment and mortgage-related securities portfolio.

Available-for-sale securities.  The book value (amortized cost), gross unrealized gains and losses, estimated fair value and gross unrealized losses (fair value and amount by duration of time in which positions have been held in a continuous loss position) for securities held in ASB’s “available-for-sale” portfolio by major security type were as follows:

			Gross		Gross			Estimated		Gross unrealized losses
	Amortized		unrealized		unrealized			fair		Less than 12 months					12 months or longer
(in thousands)	cost		gains		losses			value		Fair value		Amount			Fair value		Amount
March 31, 2013
Federal agency obligations	$	165,402	$	2,606	$	(48	)	$	167,960	$	12,025	$	(48	)	$	—	$	—
Mortgage-related securities- FNMA, FHLMC and GNMA	399,784		10,061		(506		)	409,339		66,595		(506		)	—		—
Municipal bonds	77,723		4,378		—			82,101		—		—			—		—
	$	642,909	$	17,045	$	(554	)	$	659,400	$	78,620	$	(554	)	$	—	$	—
December 31, 2012
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	)	$	—	$	—

The unrealized losses on ASB’s investments in mortgage-related securities and obligations issued by federal agencies were caused by interest rate movements. The contractual terms of these investments do not permit the issuer to settle the securities at a price less than the amortized cost basis of the investments. Because ASB does

10

not intend to sell the securities and has determined it is more likely than not that it will not be required to sell the investments before recovery of their amortized costs basis, which may be at maturity, ASB did not consider these investments to be other-than-temporarily impaired at March 31, 2013.

The fair values of ASB’s investment securities could decline if interest rates rise or spreads widen.

The following table details the contractual maturities of available-for-sale securities. 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 have the right to prepay obligations with or without prepayment penalties.

March 31, 2013	Amortized cost		Fair value
(in thousands)
Due in one year or less	$	68,120	$	68,635
Due after one year through five years	63,839		65,258
Due after five years through ten years	78,211		82,977
Due after ten years	32,955		33,191
	243,125		250,061
Mortgage-related securities-FNMA,FHLMC and GNMA	399,784		409,339
Total available-for-sale securities	$	642,909	$	659,400

Allowance for loan losses.  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.

The allowance for loan losses (balances and changes) and financing receivables were as follows:

				Commercial		Home
	Residential			real		equity line			Residential			Commercial			Residential		Commercial			Consumer
(in thousands)	1-4 family			estate		of credit			land			construction			construction		loans			loans			Unallocated		Total
Three months ended March 31, 2013
Allowance for loan losses:
Beginning balance	$	6,068		$	2,965	$	4,493		$	4,275		$	2,023		$	9	$	15,931		$	4,019		$	2,202	$	41,985
Charge-offs	(210		)	—		(670		)	(227		)	—			—		(426		)	(645		)	—		(2,178		)
Recoveries	192			—		194			137			—			—		392			150			—		1,065
Provision	(39		)	3,691		540			(1,442		)	(151		)	3		(934		)	131			59		1,858
Ending balance	$	6,011		$	6,656	$	4,557		$	2,743		$	1,872		$	12	$	14,963		$	3,655		$	2,261	$	42,730
Ending balance: individually evaluated for impairment	$	454		$	3,169	$	—		$	1,943		$	—		$	—	$	2,285		$	—		$	—	$	7,851
Ending balance: collectively evaluated for impairment	$	5,557		$	3,487	$	4,557		$	800		$	1,872		$	12	$	12,678		$	3,655		$	2,261	$	34,879
Financing Receivables:
Ending balance	$	1,915,207		$	391,679	$	648,904		$	23,894		$	40,698		$	8,275	$	699,918		$	127,260		$	—	$	3,855,835
Ending balance: individually evaluated for impairment	$	25,320		$	10,662	$	1,259		$	17,618		$	—		$	—	$	19,302		$	21		$	—	$	74,182
Ending balance: collectively evaluated for impairment	$	1,889,887		$	381,017	$	647,645		$	6,276		$	40,698		$	8,275	$	680,616		$	127,239		$	—	$	3,781,653
Year ended 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

11

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

2- Minimal risk

3- Modest risk

4- Better than average risk

5- Average risk

6- Acceptable risk

7- Special mention

8- Substandard

9- Doubtful

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:

	March 31, 2013						December 31, 2012
(in thousands)	Commercial real estate		Commercial construction		Commercial		Commercial real estate		Commercial construction		Commercial
Grade:
Pass	$	310,265	$	35,623	$	620,811	$	314,182	$	39,063	$	638,854
Special mention	36,381		—		13,601		25,437		4,925		24,511
Substandard	41,222		5,075		61,133		29,308		—		53,538
Doubtful	3,811		—		4,373		6,750		—		4,446
Loss	—		—		—		—		—		—
Total	$	391,679	$	40,698	$	699,918	$	375,677	$	43,988	$	721,349

12

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
March 31, 2013
Real estate loans:
Residential 1-4 family	$	5,435	$	1,277	$	23,292	$	30,004	$	1,885,203	$	1,915,207	$	—
Commercial real estate	743		—		3,811		4,554		387,125		391,679		—
Home equity line of credit	649		371		1,323		2,343		646,561		648,904		—
Residential land	599		1,138		9,748		11,485		12,409		23,894		1,268
Commercial construction	—		—		—		—		40,698		40,698		—
Residential construction	—		—		—		—		8,275		8,275		—
Commercial loans	3,513		400		6,370		10,283		689,635		699,918		88
Consumer loans	567		250		402		1,219		126,041		127,260		272
Total loans	$	11,506	$	3,436	$	44,946	$	59,888	$	3,795,947	$	3,855,835	$	1,628
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

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

	March 31, 2013				December 31, 2012
(in thousands)	Nonaccrual loans		Accruing loans 90 days or more past due		Nonaccrual loans		Accruing loans 90 days or more past due
Real estate loans:
Residential 1-4 family	$	25,578	$	—	$	26,721	$	—
Commercial real estate	10,663		—		6,750		—
Home equity line of credit	2,352		—		2,349		—
Residential land	9,249		1,268		8,561		—
Commercial construction	—		—		—		—
Residential construction	—		—		—		—
Commercial loans	19,305		88		20,222		131
Consumer loans	281		272		284		242
Total	$	67,428	$	1,628	$	64,887	$	373

13

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

	March 31, 2013										December 31, 2012
(in thousands)	Recorded investment		Unpaid principal balance		Related Allowance		Average recorded investment		Interest income recognized*		Recorded investment		Unpaid principal balance		Related allowance		Average recorded investment		Interest income recognized*
With no related allowance recorded
Real estate loans:
Residential 1-4 family	$	14,815	$	20,228	$	—	$	14,756	$	134	$	14,633	$	20,247	$	—	$	16,688	$	294
Commercial real estate	—		—		—		3,207		—		2,929		2,929		—		7,771		237
Home equity line of credit	732		1,444		—		655		—		581		1,374		—		632		1
Residential land	9,141		11,535		—		7,833		97		7,691		10,624		—		21,589		1,185
Commercial construction	—		—		—		—		—		—		—		—		—		—
Residential construction	—		—		—		—		—		—		—		—		—		—
Commercial loans	4,573		8,175		—		4,220		—		4,265		6,994		—		24,605		986
Consumer loans	21		21		—		21		—		21		21		—		23		—
	29,282		41,403		—		30,692		231		30,120		42,189		—		71,308		2,703
With an allowance recorded
Real estate loans:
Residential 1-4 family	5,442		5,442		454		5,008		101		4,803		4,803		384		4,204		250
Commercial real estate	10,662		10,739		3,169		6,100		—		3,821		3,840		535		1,295		—
Home equity line of credit	—		—		—		—		—		—		—		—		26		—
Residential land	7,013		7,140		1,943		8,886		113		9,984		10,364		3,221		7,428		575
Commercial construction	—		—		—		—		—		—		—		—		—		—
Residential construction	—		—		—		—		—		—		—		—		—		—
Commercial loans	14,729		15,775		2,285		15,221		5		16,033		16,912		2,659		8,429		23
Consumer loans	—		—		—		—		—		—		—		—		—		—
	37,846		39,096		7,851		35,215		219		34,641		35,919		6,799		21,382		848
Total
Real estate loans:
Residential 1-4 family	20,257		25,670		454		19,764		235		19,436		25,050		384		20,892		544
Commercial real estate	10,662		10,739		3,169		9,307		—		6,750		6,769		535		9,066		237
Home equity line of credit	732		1,444		—		655		—		581		1,374		—		658		1
Residential land	16,154		18,675		1,943		16,719		210		17,675		20,988		3,221		29,017		1,760
Commercial construction	—		—		—		—		—		—		—		—		—		—
Residential construction	—		—		—		—		—		—		—		—		—		—
Commercial loans	19,302		23,950		2,285		19,441		5		20,298		23,906		2,659		33,034		1,009
Consumer loans	21		21		—		21		—		21		21		—		23		—
	$	67,128	$	80,499	$	7,851	$	65,907	$	450	$	64,761	$	78,108	$	6,799	$	92,690	$	3,551

*Since loan was classified as impaired.

Troubled debt restructurings.  A loan modification is deemed to be a troubled debt restructuring (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 fulfill 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

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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 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 were as follows for the indicated periods:

	Three months ended March 31, 2013					Three months ended March 31, 2012
	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	4	$	1,122	$	1,063	7	$	1,413	$	1,410
Commercial real estate	—	—		—		—	—		—
Home equity line of credit	4	462		215		—	—		—
Residential land	3	924		868		7	1,734		1,441
Commercial loans	—	—		—		6	160		160
Consumer loans	—	—		—		—	—		—
	11	$	2,508	$	2,146	20	$	3,307	$	3,011

Loans modified in TDRs that experienced a payment default of 90 days or more in 2013 and 2012, and for which the payment default occurred within one year of the modification, were as follows:

	Three months ended March 31, 2013			Three months ended March 31, 2012
(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	—	—		—	—
Commercial loans	—	—		4	879
Consumer loans	—	—		—	—
	—	$	—	4	$	879

For 2012, the four commercial loans that subsequently defaulted were modified by extending the maturity date and deferring principal payments for a short period of time. There are no commitments to lend additional funds to borrowers whose loan terms have been impaired or modified in TDRs as of March 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 · Retirement benefits

Defined benefit pension and other postretirement benefit plans information. For the first three months of 2013, the Company contributed $21 million (primarily by the utilities) to its pension and other postretirement benefit plans, compared to $27 million (primarily by the utilities) in the first three months of 2012. The Company’s current estimate of contributions to its pension and other postretirement benefit plans in 2013 is $86 million ($84 million by the utilities, $2 million by HEI and nil by ASB), compared to $78 million ($63 million by the utilities, $2 million by HEI

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and $13 million by ASB) in 2012. In addition, the Company expects to pay directly $2 million ($1 million each by the utilities and HEI) of benefits in 2013, compared to $1 million paid in 2012.

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 improved the plans’ Adjusted Funding Target Attainment Percentage (AFTAP) for funding and benefit distribution purposes and thereby 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. The effects of MAP-21 are expected to cause the minimum required funding under ERISA to be less than the net periodic cost for 2013 and 2014; therefore, the Company expects to contribute the net periodic cost for these years. If the AFTAP 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.

The components of net periodic benefit cost for consolidated HEI were as follows:

	Pension benefits						Other benefits
Three months ended March 31	2013			2012			2013			2012
(in thousands)
Service cost	$	14,089		$	10,191		$	1,049		$	1,096
Interest cost	16,106			16,771			1,931			2,281
Expected return on plan assets	(18,085		)	(17,856		)	(2,562		)	(2,621		)
Amortization of prior service gain	(24		)	(81		)	(448		)	(448		)
Amortization of net actuarial loss	9,819			6,423			521			453
Net periodic benefit cost	21,905			15,448			491			761
Impact of PUC D&Os	(7,436		)	(3,857		)	(397		)	(680		)
Net periodic benefit cost (adjusted for impact of PUC D&Os)	$	14,469		$	11,591		$	94		$	81

Consolidated HEI recorded retirement benefits expense of $11 million and $8 million in the first quarters of 2013 and 2012, respectively, and charged the remaining amounts primarily to electric utility plant.

The utilities have implemented pension and OPEB tracking mechanisms under which all of their retirement benefit expenses (except for executive life and nonqualified pension plan expenses) determined in accordance with GAAP are recovered over time. Under the tracking mechanisms, these retirement benefit costs that are over/under amounts allowed in rates are charged/credited to a regulatory asset/liability. The regulatory asset/liability for each utility will be amortized over 5 years beginning with the respective utility’s next rate case.

Defined contribution plans information.  For the first quarters of 2013 and 2012, the Company’s expense for its defined contribution pension plans under the Hawaiian Electric Industries Retirement Savings Plan (HEIRSP) and the ASB 401(k) Plan was $1.0 million and $0.9 million, respectively, and cash contributions were $2.4 million and $2.2 million, respectively.

6 · 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 March 31, 2013, there were 3.6 million shares remaining available for future issuance under the EIP of which an estimated 2.7 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 25,000 shares of common stock (based on the March 31, 2013 market price of shares as the price on the exercise

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dates) were outstanding as of March 31, 2013 to selected employees in the form of nonqualified stock options (NQSOs), stock appreciation rights (SARs) 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.

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

Three months ended March 31	2013		2012
(in millions)
Share-based compensation expense (1)	$	1.9	$	1.8
Income tax benefit	0.7		0.6

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

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

March 31, 2013			Outstanding & Exercisable (Vested)
Year of grant	Range of exercise prices		Number of options	Weighted-average remaining contractual life	Weighted-average exercise price
2003	$	20.49	12,000	0.1	$	20.49

As of December 31, 2012, NQSOs outstanding totaled 14,000 (representing the same number of underlying shares), with a weighted-average exercise price of $20.49. As of March 31, 2013, 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:

Three months ended March 31	2013		2012
(dollars in thousands, except prices)
Shares exercised	2,000		12,000
Weighted-average exercise price	$	20.49	$	21.68
Cash received from exercise	$	41	$	260
Intrinsic value of shares exercised (1)	$	15	$	91
Tax benefit realized for the deduction of exercises	$	6	$	36

(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 was as follows:

March 31, 2013			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	1.1	$	26.02
2005	26.18		102,000	2.0	26.18
	$	26.02 –26.18	164,000	1.7	$	26.12

As of December 31, 2012, the shares underlying SARs outstanding totaled 164,000, with a weighted-average exercise price of $26.12. As of March 31, 2013, all SARs outstanding were exercisable and had an aggregate intrinsic value (including dividend equivalent rights) of $0.3 million.

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

	2013			2012
Three months ended March 31	Shares	(1)		Shares		(1)
Outstanding, beginning of period	9,005	$	22.21	46,807		$	24.45
Granted	—	—		—		—
Vested	—	—		(8,700	)	27.17
Forfeited	—	—		—		—
Outstanding, end of period	9,005	$	22.21	38,107		$	23.83

(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.

As of March 31, 2013, there was $0.2 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 1.7 years.

For the first quarter of 2012, total restricted stock vested had a grant-date fair value of $0.2 million and the tax benefits realized for tax deductions related to restricted stock awards were $0.1 million.

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

	2013				2012
Three months ended March 31	Shares		(1)		Shares		(1)
Outstanding, beginning of period	315,094		$	22.82	247,286		$	21.80
Granted	107,231	(2)	26.89		92,512	(3)	25.98
Vested	(113,212	)	20.30		(21,247	)	24.95
Forfeited	(7,968	)	25.26		—		—
Outstanding, end of period	301,145		$	25.15	318,551		$	22.80

(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 $2.9 million.

(3)Total weighted-average grant-date fair value of $2.4 million.

As of March 31, 2013, there was $5.4 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 3 years.

For the first quarters of 2013 and 2012, total restricted stock units that vested and related dividends had a grant-date fair value of $3.5 million and $0.6 million, respectively, and the related tax benefits were $1.1 million and $0.2 million, respectively.

LTIP payable in stock. The 2011-2013 LTIP, 2012-2014 LTIP and the 2013-2015 LTIP provide for performance awards under the EIP of shares of HEI common stock based on the satisfaction of performance goals 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 2011-2013 LTIP, the 2012-2014 LTIP and the 2013-2015 LTIP have performance goals related to levels of HEI consolidated net income, HEI consolidated return on common equity (ROACE), HECO consolidated net income, HECO consolidated ROACE, ASB net income and ASB return on assets — all based on the applicable three-year averages.

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

	2013				2012
Three months ended March 31	Shares		(1)		Shares		(1)
Outstanding, beginning of period	239,256		$	29.12	197,385		$	25.94
Granted	89,533		32.69		77,482	(2)	30.71
Vested	(87,753	)	22.45		(35,397	)	14.85
Forfeited	(5,972	)	32.96		—		—
Outstanding, end of period	235,064		$	32.87	239,470		$	29.12

(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 $2.4 million.

On February 4, 2013, LTIP grants (under the 2013-2015 LTIP) were made payable in 89,533 shares of HEI common stock (based on the grant date price of $26.89 and target TRS performance levels) with a weighted-average grant date fair value of $2.9 million based on the weighted-average grant date fair value per share of $32.69.

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:

	2013			2012
Risk-free interest rate	0.38		%	0.33		%
Expected life in years	3			3
Expected volatility	19.4		%	25.3		%
Range of expected volatility for Peer Group	12.4% to 25.3		%	15.5% to 34.5		%
Grant date fair value (per share)	$	32.69		$	30.71

For the three months ended March 31, 2013 and 2012, total vested LTIP awards linked to TRS and related dividends had a fair value of $2.2 million and $0.6 million, respectively, and the related tax benefits were $0.9 million and $0.2 million, respectively.

As of March 31, 2013, there was $4.1 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 1.8 years.

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

	2013				2012
Three months ended March 31	Shares		(1)		Shares		(1)
Outstanding, beginning of period	247,175		$	25.04	182,498		$	22.63
Granted	118,895		26.89		115,104	(2)	25.98
Vested	(18,275	)	18.95		—		—
Forfeited	(5,971	)	25.94		—		—
Outstanding, end of period	341,824		$	26.00	297,602		$	23.92

(1)Weighted-average grant-date fair value per share based on the average price of HEI common stock on the date of grant.

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

On February 4, 2013, LTIP grants (under the 2013-2015 LTIP) were made payable in 118,895 shares of HEI common stock (based on the grant date price of $26.89 and target performance levels relating to performance goals other than TRS), with a weighted-average grant date fair value of $3.2 million based on the weighted-average grant date fair value per share of $26.89.

For the three months ended March 31, 2013, total vested LTIP awards linked to other performance conditions and related dividends had a fair value of $0.6 million and the related tax benefits were $0.2 million.

As of March 31, 2013, there was $5.4 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 1.8 years.

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7 · Earnings per share and shareholders’ equity

Earnings per share.  Under the two-class method of computing earnings per share (EPS), EPS was comprised as follows for both participating securities and unrestricted common stock:

	2013		2012
Three months ended March 31	Basic and diluted		Basic and diluted
Distributed earnings	$	0.31	$	0.31
Undistributed earnings (loss)	0.03		0.09
	$	0.34	$	0.40

As of March 31, 2013, there were no shares that were antidilutive. As of March 31, 2012 the antidilutive effects of SARs of 210,000 shares of HEI common stock, for which the exercise prices were greater than the closing market price of HEI’s common stock were not included in the computation of diluted EPS.

Shareholders’ equity.

Equity forward transaction.On March 19, 2013, HEI entered into an equity forward transaction in connection with a public offering of 6.1 million shares of HEI common stock. On March 20, 2013, the underwriters exercised their over-allotment option in full and HEI entered into an equity forward transaction in connection with 0.9 million shares of HEI common stock. The use of an equity forward transaction substantially eliminates future equity market price risk by fixing a common equity offering sales price under the then existing market conditions, while mitigating immediate share dilution resulting from the offering by postponing the actual issuance of common stock until funds are needed in accordance with the Company’s capital investment plans.

Pursuant to the terms of these transactions, a forward counterparty borrowed 7 million shares of HEI’s common stock from third parties and sold them to a group of underwriters for $26.75 per share, less an underwriting discount equal to $1.00312 per share. Under the terms of the equity forward transactions, to the extent that the transactions are physically settled, HEI would be required to issue and deliver shares of HEI common stock to the forward counterparty at the then applicable forward sale price. The forward sale price was initially determined to be $25.74688 per share at the time the equity forward transactions were entered into, and the amount of cash to be received by HEI upon physical settlement of the equity forward is subject to certain adjustments in accordance with the terms of the equity forward transactions. The equity forward transactions must be settled fully by March 25, 2015. Except in specified circumstances or events that would require physical settlement, HEI is able to elect to settle the equity forward transactions by means of physical, cash or net share settlement, in whole or in part, at any time on or prior to March 25, 2015.

The equity forward transactions had no initial fair value since they were entered into at the then market price of the common stock. HEI will not receive any proceeds from the sale of common stock until the equity forward transactions are settled, and at that time HEI will record the proceeds, if any, in equity. HEI concluded that the equity forward transactions were equity instruments based on the accounting guidance in ASC 480 and ASC 815 and that they qualified for an exception from derivative accounting under ASC 815 because the forward sale transactions were indexed to its own stock. HEI anticipates settling the equity forward transactions through physical settlement before March 25, 2015.

At March 31, 2013, the equity forward transactions could have been settled with physical delivery of the shares to the forward counterparty in exchange for cash of $180 million. At March 31, 2013, the equity forward transactions could also have been cash settled, with delivery of cash of approximately $12 million (which amount includes $7 million of underwriting discount) to the forward counterparty, or net share settled with delivery of approximately 440,000 shares of common stock to the forward counterparty.

Prior to their settlement, the equity forward transactions will be reflected in HEI’s diluted earnings per share calculations using the treasury stock method. Under this method, the number of shares of HEI’s common stock used in calculating diluted earnings per share for a reporting period would be increased by the number of shares, if any, that would be issued upon physical settlement of the equity forward transactions less the number of shares that could be purchased by HEI in the market (based on the average market price during that reporting period)

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using the proceeds receivable upon settlement of the equity forward transactions (based on the adjusted forward sale price at the end of that reporting period). The excess number of shares is weighted for the portion of the reporting period in which the equity forward transactions are outstanding.

Accordingly, before physical or net share settlement of the equity forward transactions, and subject to the occurrence of certain events, HEI anticipates that the forward sale agreement and additional forward sale agreement will have a dilutive effect on HEI’s earnings per share only during periods when the applicable average market price per share of HEI’s common stock is above the per share adjusted forward sale price, as described above. However, if HEI decides to physically or net share settle the forward sale agreement and additional forward sale agreement, any delivery by HEI of shares upon settlement could result in dilution to HEI’s earnings per share.

For the three months ended March 31, 2013, the equity forward transactions did not have a material dilutive effect on HEI’s earnings per share.

Accumulated other comprehensive income.Reclassifications out of accumulated other comprehensive income (AOCI) were as follows:

	Three months ended March 31
	2013			2012
(in thousands)	Amount reclassified from AOCI						Affected line item in the Statement of Income
Unrealized gains and losses on securities	$	—		$	—		Revenues-bank (net gains on sales of securities)
Derivatives qualified as cash flow hedges
Interest rate contracts (settled in 2011)	59			59			Interest expense
Retirement benefit plan items
Amortization of transition obligation, prior service credit and net losses recognized during the period in net periodic benefit cost	6,021			3,873			(See Note 5 for additional details)
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets	(5,313		)	(3,395		)	(See Note 5 for additional details)
Total reclassifications	$	767		$	537

8 · Commitments and contingencies

See Note 4, “Bank subsidiary,” above and Note 5, “Commitments and contingencies,” of HECO’s “Notes to Consolidated Financial Statements,” below.

9 · 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:

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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 is 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 (to be announced) 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.

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.

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 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.

22

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 and from discounting the future cash flows using 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.

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

	Carrying or notional		Estimated fair value
(in thousands)	amount		Level 1		Level 2		Level 3		Total
March 31, 2013
Financial assets
Money market funds	$	10	$	—	$	10	$	—	$	10
Available-for-sale investment and mortgage-related securities	659,400		—		659,400		—		659,400
Investment in stock of Federal Home Loan Bank of Seattle	95,152		—		95,152		—		95,152
Loans receivable, net	3,808,353		—		—		3,974,112		3,974,112
Financial liabilities
Deposit liabilities	4,312,620		—		4,317,805		—		4,317,805
Short-term borrowings—other than bank	133,937		—		133,937		—		133,937
Other bank borrowings	193,233		—		208,410		—		208,410
Long-term debt, net—other than bank	1,422,875		—		1,529,541		—		1,529,541
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

As of March 31, 2013 and December 31, 2012, loan commitments and unused lines and letters of credit issued by ASB had notional amounts of $1.6 billion and $1.5 billion, respectively, and their estimated fair value on such dates were $1.3 million and $1.2 million, respectively. As of March 31, 2013 and December 31, 2012, loans serviced by ASB for others had notional amounts of $1.3 billion and the estimated fair value of the servicing rights for such loans was $13.6 million and $11.9 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

23

nonperformance risk that market participants would use in pricing the asset based on market data obtained from independent sources. Available-for-sale securities were comprised of federal agency obligations and mortgage-backed securities and municipal bonds.

Assets 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)
March 31, 2013
Money market funds (“other” segment)	$	—	$	10	$	—
Available-for-sale securities (bank segment)
Mortgage-related securities-FNMA, FHLMC and GNMA	$	—	$	409,339	$	—
Federal agency obligations	—		167,960		—
Municipal bonds	—		82,101		—
	$	—	$	659,400	$	—
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	$	—

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. During the first quarter of 2013, it was not required that a measurement of the fair value of goodwill be calculated and goodwill was not measured at fair value.

Assets measured at fair value on a nonrecurring basis were as follows:

			Fair value measurements
(in millions)	Balance		Level 1		Level 2		Level 3
Loans
March 31, 2013	$	21	$	—	$	—	$	21
December 31, 2012	21		—		—		21
Real estate acquired in settlement of loans
March 31, 2013	1		—		—		1
December 31, 2012	3		—		—		3

For the first quarters of 2013 and 2012, 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

24

placed on the assets of the business and cash flows generated by the business entity, and therefore, is classified as a Level 3 measurement.

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 March 31, 2013, the significant unobservable inputs used in the fair value measurement were as follows:

($ in thousands)	Fair value at March 31, 2013		Valuation technique	Significant unobservable input	Significant unobservable input value
Residential loans	$	17,331	Fair value of property or collateral	Appraised value	13 - 96%
Home equity lines of credit	732		Fair value of property or collateral	Appraised value	25 - 85%
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	222		Fair value of property or collateral	Insurance proceeds	60%
Commercial loans	1,127		Fair value of property or collateral	Fair value of business assets	9 - 93%
Commercial loan	1,775		Discounted cash flow	Present value of expected future cash flows based on anticipated debt restructuring	Paydown of loan – 59%
				Discount rate	4.5%
Total commercial loans	3,256
Real estate acquired in settlement of loans	1,235		Fair value of property or collateral	Appraised value	81 – 99%

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

10 · Cash flows

Three months ended March 31	2013			2012
(in millions)
Supplemental disclosures of cash flow information
Interest paid to non-affiliates	$	21		$	22
Income taxes paid/(refunded)	(3		)	—
Supplemental disclosures of noncash activities
Common stock dividends reinvested in HEI common stock (1)	6			6
Increases in common stock related to director and officer compensatory plans	—			2
Additions to electric utility property, plant and equipment - Unpaid invoices and other	3			3
Real estate acquired in settlement of loans	1			2

(1)The amounts shown represent common stock dividends reinvested in HEI common stock under the HEI Dividend Reinvestment and Stock Purchase Plan (DRIP) in noncash transactions.

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11 · Recent accounting pronouncements

Obligations resulting from joint and several liability.  In February 2013, the FASB issued Accounting Standards Update (ASU) No. 2013-04, “Liabilities (Topic 405): Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation Is Fixed at the Reporting Date,” which provides guidance for the recognition, measurement and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date. The guidance requires entities to measure these obligations as the sum of the amount the entity has agreed with co-obligors to pay and any additional amount it expects to pay on behalf of its co-obligors. The guidance also requires an entity to disclose the nature and amount of the obligation as well as other information. This guidance is effective for all fiscal years, and interim periods within those years, beginning after December 31, 2013.

The Company will retrospectively adopt ASU No. 2013-04 in the first quarter of 2014 and does not expect it to have a material impact on the Company’s results of operations, financial condition or liquidity.

12 · Credit agreement and long-term debt

Credit agreement. HEI maintains an amended revolving noncollateralized credit agreement, which established a line of credit facility of $125 million, with a letter of credit sub-facility, expiring on December 5, 2016, with a syndicate of eight financial institutions. The credit 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.

Changes in long-term debt.

March 6, 2013 notes.  On March 6, 2013, HEI entered into a First Supplement (the First Supplement) to the Master Note Purchase Agreement dated March 24, 2011 (the Note Agreement). Under the First Supplement, HEI issued $50 million of its unsecured, 3.99% Series 2013A Senior Notes, due March 6, 2023, via a private placement with The Prudential Insurance Company of America, Prudential Arizona Reinsurance Captive Company and The Lincoln National Life Insurance Company.

The Note Agreement, as modified by the First Supplement (which includes representations that supersede and supplement the representations in the Note Agreement), contains 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 then outstanding becoming immediately due and payable) and provisions requiring the maintenance by HEI of certain financial ratios generally consistent with those in HEI’s existing amended revolving noncollateralized credit agreement described above and in HEI’s Form 10-K for the year ended December 31, 2012. For example, under the Note Agreement, it is an event of default if HEI fails to maintain an unconsolidated “Capitalization Ratio” (funded debt) of 50% or less or “Consolidated Net Worth” of at least $975 million.

The net proceeds from the issuance of the Notes were used by HEI to refinance $50 million of its unsecured, 5.25% Medium-Term Notes, Series D, which matured on March 7, 2013.

26

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statements of Income (unaudited)

Three months ended March 31	2013			2012
(in thousands)
Operating revenues	$	716,197		$	747,938
Operating expenses
Fuel oil	305,100			327,839
Purchased power	153,364			164,789
Other operation	71,423			61,849
Maintenance	29,702			30,038
Depreciation	38,280			36,482
Taxes, other than income taxes	67,687			70,995
Income taxes	14,095			17,365
Total operating expenses	679,651			709,357
Operating income	36,546			38,581
Other income
Allowance for equity funds used during construction	1,215			1,940
Other, net	2,312			1,309
Income tax expense	(299		)	(44		)
Total other income	3,228			3,205
Interest and other charges
Interest on long-term debt	14,614			14,383
Amortization of net bond premium and expense	647			745
Other interest charges (credits)	315			(271		)
Allowance for borrowed funds used during construction	(730		)	(870		)
Total interest and other charges	14,846			13,987
Net income	24,928			27,799
Preferred stock dividends of subsidiaries	229			229
Net income attributable to HECO	24,699			27,570
Preferred stock dividends of HECO	270			270
Net income for common stock	$	24,429		$	27,300

HEI owns all of the common stock of HECO. Therefore, per share data with respect to shares of common stock of HECO are not meaningful.

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

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statements of Comprehensive Income (unaudited)

Three months ended March 31	2013			2012
(in thousands)
Net income for common stock	$	24,429		$	27,300
Other comprehensive income, net of taxes:
Retirement benefit plans:
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 $3,395 and $2,212 for the three months ended March 31, 2013 and 2012, respectively	5,331			3,472
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes of $3,384 and $2,162 for the three months ended March 31, 2013 and 2012, respectively	(5,313		)	(3,395		)
Other comprehensive income, net of taxes	18			77
Comprehensive income attributable to Hawaiian Electric Company, Inc.	$	24,447		$	27,377

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

27

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Balance Sheets (unaudited)

(dollars in thousands, except par value)	March 31, 2013			December 31, 2012
Assets
Utility plant, at cost
Land	$	51,598		$	51,568
Plant and equipment	5,427,933			5,364,400
Less accumulated depreciation	(2,062,810		)	(2,040,789		)
Construction in progress	153,669			151,378
Net utility plant	3,570,390			3,526,557
Current assets
Cash and cash equivalents	36,940			17,159
Customer accounts receivable, net	194,457			210,779
Accrued unbilled revenues, net	135,615			134,298
Other accounts receivable, net	5,795			28,176
Fuel oil stock, at average cost	190,691			161,419
Materials and supplies, at average cost	54,430			51,085
Prepayments and other	32,255			32,865
Regulatory assets	61,804			51,267
Total current assets	711,987			687,048
Other long-term assets
Regulatory assets	812,347			813,329
Unamortized debt expense	10,245			10,554
Other	69,266			71,305
Total other long-term assets	891,858			895,188
Total assets	$	5,174,235		$	5,108,793
Capitalization and liabilities
Capitalization
Common stock ($6 2/3 par value, authorized 50,000,000 shares; outstanding 14,665,264 shares)	$	97,788		$	97,788
Premium on capital stock	468,045			468,045
Retained earnings	911,632			907,273
Accumulated other comprehensive loss, net of income taxes-retirement benefit plans	(952		)	(970		)
Common stock equity	1,476,513			1,472,136
Cumulative preferred stock — not subject to mandatory redemption	34,293			34,293
Long-term debt, net	1,147,875			1,147,872
Total capitalization	2,658,681			2,654,301
Commitments and contingencies (Note 5)
Current liabilities
Short-term borrowings from nonaffiliates	43,052			—
Accounts payable	228,426			186,824
Interest and preferred dividends payable	21,693			21,092
Taxes accrued	199,350			251,066
Other	67,930			62,879
Total current liabilities	560,451			521,861
Deferred credits and other liabilities
Deferred income taxes	435,598			417,611
Regulatory liabilities	325,527			322,074
Unamortized tax credits	67,939			66,584
Retirement benefits liability	611,678			620,205
Other	98,566			100,637
Total deferred credits and other liabilities	1,539,308			1,527,111
Contributions in aid of construction	415,795			405,520
Total capitalization and liabilities	$	5,174,235		$	5,108,793

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

28

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statements of Changes in Common Stock Equity (unaudited)

	Common stock			Premium on capital		Retained			Accumulated other comprehensive
(in thousands)	Shares	Amount		stock		earnings			income (loss)			Total
Balance, December 31, 2012	14,665	$	97,788	$	468,045	$	907,273		$	(970	)	$	1,472,136
Net income for common stock	—	—		—		24,429			—			24,429
Other comprehensive income, net of taxes	—	—		—		—			18			18
Common stock dividends	—	—		—		(20,070		)	—			(20,070		)
Balance, March 31, 2013	14,665	$	97,788	$	468,045	$	911,632		$	(952	)	$	1,476,513
Balance, December 31, 2011	14,234	$	94,911	$	426,921	$	881,041		$	(32	)	$	1,402,841
Net income for common stock	—	—		—		27,300			—			27,300
Other comprehensive income, net of taxes	—	—		—		—			77			77
Common stock dividends	—	—		—		(18,261		)	—			(18,261		)
Balance, March 31, 2012	14,234	$	94,911	$	426,921	$	890,080		$	45		$	1,411,957

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

29

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statements of Cash Flows (unaudited)

Three months ended March 31	2013			2012
(in thousands)
Cash flows from operating activities
Net income	$	24,928		$	27,799
Adjustments to reconcile net income to net cash provided by (used in) operating activities
Depreciation of property, plant and equipment	38,280			36,482
Other amortization	957			1,561
Change in deferred income taxes	17,975			20,061
Change in tax credits, net	1,382			1,356
Allowance for equity funds used during construction	(1,215		)	(1,940		)
Changes in assets and liabilities
Decrease in accounts receivable	38,703			25,001
Decrease (increase) in accrued unbilled revenues	(1,317		)	11,184
Increase in fuel oil stock	(29,272		)	(14,458		)
Increase in materials and supplies	(3,345		)	(3,561		)
Increase in regulatory assets	(17,746		)	(13,948		)
Increase (decrease) in accounts payable	38,934			(33,174		)
Change in prepaid and accrued income taxes and utility revenue taxes	(53,666		)	(44,561		)
Contributions to defined benefit pension and other postretirement benefit plans	(21,010		)	(26,183		)
Change in other assets and liabilities	19,913			3,444
Net cash provided by (used in) operating activities	53,501			(10,937		)
Cash flows from investing activities
Capital expenditures	(67,915		)	(63,436		)
Contributions in aid of construction	11,710			22,855
Net cash used in investing activities	(56,205		)	(40,581		)
Cash flows from financing activities
Common stock dividends	(20,070		)	(18,261		)
Preferred stock dividends of HECO and subsidiaries	(499		)	(499		)
Repayment of long-term debt	—			(57,500		)
Net increase in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less	43,052			84,942
Other	2			(120		)
Net cash provided by financing activities	22,485			8,562
Net increase (decrease) in cash and cash equivalents	19,781			(42,956		)
Cash and cash equivalents, beginning of period	17,159			48,806
Cash and cash equivalents, end of period	$	36,940		$	5,850

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

30

Hawaiian Electric Company, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1 · Basis of presentation

The accompanying unaudited consolidated financial statements have been prepared in conformity with GAAP for interim financial information, the instructions to SEC Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. In preparing the financial statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the balance sheet and the reported amounts of revenues and expenses for the period. Actual results could differ significantly from those estimates. The accompanying unaudited consolidated financial statements and the following notes should be read in conjunction with the audited consolidated financial statements and the notes thereto incorporated by reference in HECO’s Form 10-K for the year ended December 31, 2012.

In the opinion of HECO’s management, the accompanying unaudited consolidated financial statements contain all material adjustments required by GAAP to fairly state the financial position of HECO and its subsidiaries as of March 31, 2013 and December 31, 2012, the results of their operations and their cash flows for the three months ended March 31, 2013 and 2012. All such adjustments are of a normal recurring nature unless otherwise disclosed in this Form 10-Q or other referenced material. Results of operations for interim periods are not necessarily indicative of results for the full year. When required, certain reclassifications are made to the prior period’s consolidated financial statements to conform to the current presentation.

2 · 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 Hawaii Electric Light Company, Inc. (HELCO) and Maui Electric Company, Limited (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 sheets as of March 31, 2013 and December 31, 2012 each 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 statements for the three months ended March 31, 2013 and 2012 each consisted of $0.8 million of interest income received from the 2004 Debentures, $0.8 million of distributions to holders of the Trust Preferred Securities, and $25,000 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

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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 March 31, 2013, HECO and its subsidiaries had six PPAs for firm capacity and other PPAs with smaller independent power producers (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 Partners, L.P. (Kalaeloa), Hamakua Energy Partners, L.P. (HEP) and HPOWER. Purchases from all IPPs for the quarter ended March 31, 2013 totaled $153 million, with purchases from AES Hawaii, Kalaeloa, HEP and HPOWER totaling $23 million, $65 million, $12 million, and $15 million, respectively. Purchases from all IPPs for the quarter ended March 31, 2012 totaled $165 million, with purchases from AES Hawaii, Kalaeloa, HEP and HPOWER totaling $35 million, $69 million, $14 million, and $16 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. A windfarm and Kalaeloa provided sufficient information, as required under their PPAs or amendments, such that HECO could determine that consolidation was not required. Management has concluded that the consolidation of some IPPs is not required as HECO and its subsidiaries do not have variable interests in the IPPs because the PPAs do not require them to absorb any variability of the IPPs.

An enterprise with an interest in a VIE or potential VIE created before December 31, 2003, and not thereafter materially modified, is not required to apply accounting standards for VIEs to that entity if the enterprise is unable to obtain the necessary information after making an exhaustive effort. HECO and its subsidiaries have made and continue to make exhaustive efforts to get the necessary information from two firm capacity producers and other small IPPs who entered into their PPAs prior to December 31, 2003 and have not provided such information, but have been unsuccessful to date as it was not a contractual requirement to provide such information prior to 2004. 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. 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 the potential recognition of 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

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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 March 31, 2013, HECO’s accounts payable to Kalaeloa amounted to $24 million.

3 · Revenue taxes

HECO and its subsidiaries’ operating revenues include amounts for various Hawaii state revenue taxes. Revenue taxes are generally recorded as an expense in the period 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 the three months ended March 31, 2013 and 2012, HECO and its subsidiaries included approximately $64 million and $67 million, respectively, of revenue taxes in “operating revenues” and in “taxes, other than income taxes” expense.

4 · Retirement benefits

Defined benefit pension and other postretirement benefit plans information. For the first quarter of 2013, HECO and its subsidiaries contributed $21 million to their pension and other postretirement benefit plans, compared to $26 million in the first quarter of 2012. HECO and its subsidiaries’ current estimate of contributions to their pension and other postretirement benefit plans in 2013 is $84 million, compared to contributions of $63 million in 2012. In addition, HECO and its subsidiaries expect to pay directly $1.0 million of benefits in 2013, compared to $0.5 million paid in 2012.

On July 6, 2012, President Obama signed the MAP-21, which included provisions related to the funding and administration of pension plans. This law does not affect the utilities’ accounting for pension benefits; therefore, the net periodic benefit costs disclosed for the plans were not affected. The utilities elected to apply MAP-21 for 2012, which improved the plan’s AFTAP for funding and benefit distribution purposes and thereby 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 HECO and its subsidiaries. The effects of MAP-21 are expected to cause the minimum required funding under ERISA to be less than the net periodic cost for 2013 and 2014; therefore, the utilities expect to contribute the net periodic cost for these years as they did for 2012. If the AFTAP 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.

The components of net periodic benefit cost were as follows:

	Pension benefits						Other benefits
Three months ended March 31	2013			2012			2013			2012
(in thousands)
Service cost	$	13,603		$	9,802		$	1,014		$	1,048
Interest cost	14,676			15,261			1,861			2,205
Expected return on plan assets	(16,090		)	(16,060		)	(2,520		)	(2,579		)
Amortization of net transition obligation	—			—			—			(2		)
Amortization of net prior service gain	(116		)	(172		)	(451		)	(451		)
Amortization of net actuarial loss	8,790			5,869			504			440
Net periodic benefit cost	20,863			14,700			408			661
Impact of PUC D&Os	(7,436		)	(3,857		)	(397		)	(680		)
Net periodic benefit cost (adjusted for impact of PUC D&Os)	$	13,427		$	10,843		$	11		$	(19	)

HECO and its subsidiaries recorded retirement benefits expense of $10 million and $8 million for the first quarters of 2013 and 2012, respectively. The electric utilities charged a portion of the net periodic benefit cost to electric utility plant.

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The utilities have implemented pension and OPEB tracking mechanisms under which all of their retirement benefit expenses (except for executive life and nonqualified pension plan expenses) determined in accordance with GAAP are recovered over time. Under the tracking mechanisms, these retirement benefit costs that are over/under amounts allowed in rates are charged/credited to a regulatory asset/liability. The regulatory asset/liability for each utility will be amortized over 5 years beginning with the respective utility’s next rate case.

Accumulated other comprehensive income.Reclassifications out of AOCI were as follows:

	Three months ended March 31
	2013			2012
(in thousands)	Amount reclassified from AOCI
Retirement benefit plan items
Amortization of transition obligation, prior service credit and net losses recognized during the period in net periodic benefit cost	$	5,331		$	3,472		(See above)
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets	(5,313		)	(3,395		)	(See above)
Total reclassifications	$	18		$	77

Defined contribution plan information.  For the first quarters of 2013 and 2012, the utilities’ expense for its defined contribution pension plan was $0.2 million and de minimis, respectively.

5 · Commitments and contingencies

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 evaluate opportunities 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 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. In April 2013, the PUC approved the recovery of $3.9 million in costs for stage 1 studies for the large wind project over a three-year period, with carrying costs to be accrued over the recovery period at the rate of 1.75% per annum, through the Renewable Energy Infrastructure Program (REIP) Surcharge.

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

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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. In February 2013, HELCO issued the Final Geothermal RFP. Bids were received in April 2013 and are being evaluated.

Interim increases.  As of March 31, 2013, HECO and its subsidiaries had recognized $3 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.

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. However, in March 2012, the PUC eliminated the requirement for a regulatory audit for the EOTP Phase I in connection with an approved settlement of the project cost issues and, in March 2013, the PUC eliminated the requirement for the CIP CT-1 and CIS projects as described below.

On January 28, 2013, HECO and its subsidiaries and the Consumer Advocate, signed a settlement agreement (2013 Agreement), subject to PUC approval, to write-off $40 million of costs in lieu of conducting the regulatory audits of the CIP CT-1 project and the CIS project. Based on the 2013 Agreement, as of December 31, 2012, the utilities recorded an after-tax charge to net income of approximately $24 million—$17.1 million for HECO, $3.4 million for HELCO, and $3.2 million for MECO. The remaining recoverable costs of $52 million were included in rate base as of December 31, 2012.

As part of the 2013 Agreement, HELCO would withdraw its 2013 test year rate case, and delay filing a new rate case until a 2016 test year. Additionally, HECO would delay the filing of its scheduled 2014 test year rate case to no earlier than January 2, 2014. For both utilities, the existing terms of the last rate case decisions would continue. HECO would also be allowed to record Revenue Adjustment Mechanism (RAM) revenues starting on January 1 of 2014, 2015 and 2016. The cash collection of RAM revenues would remain unchanged, starting June 1 of each year through May 31 of the following year.

On March 19, 2013, the PUC issued a decision and order (2013 D&O) approving the 2013 Agreement, with the following clarifications, none of which changed the financial impact recorded as of December 31, 2012: (1) the PUC reiterated its authority to examine and ascertain what post go-live CIS costs would be subject to regulatory review in future rate cases; (2) the PUC discouraged requesting single issue cost deferral accounting and/or cost recovery mechanisms during the period of rate case deferral by HECO and HELCO; (3) the PUC approved the agreed-upon recovery of CIP CT-1 and CIS project costs through the RAM, as set forth in the 2013 Agreement, however not setting a precedent for future projects; and (4) the PUC reaffirmed its right to rule on the substance of the MECO 2012 test year rate case in its ongoing rate case proceeding.

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 allowance for funds used during construction (AFUDC). In July 2011, the PUC allowed HECO to defer $32 million of costs that were in excess of the prior PUC approved amounts and related depreciation for HECO’s CIP CT-1 project until completion of the contemplated regulatory audit, which was subsequently cancelled pursuant to the 2013 D&O. 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 and allowed the remaining project costs that were not deferred to be included in electric rates.

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For accounting purposes, HECO will recognize the equity portion of the carrying charge when it is collected in electric rates (expected to begin on June 1, 2013). Effective May 31, 2013, the accrual of a carrying charge will end. The CIP CT-1 deferred costs and depreciation are expected to be recovered in electric rates beginning on June 1, 2013. Management believes no adjustment to project costs is required as of March 31, 2013.

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) until completion of the contemplated regulatory audit, which was subsequently cancelled pursuant to the 2013 D&O. The PUC also allowed them to accrue AFUDC on project costs (including deferred operation and maintenance expenses). For accounting purposes, the utilities will recognize the equity portion of the carrying charge when it is collected in electric rates (expected to begin on June 1, 2013). Effective May 31, 2013, the accrual of AFUDC will end. As of March 31, 2013, the utilities’ total deferred and capital costs for the CIS project were $20 million (after the write-off of $40 million of project costs pursuant to the 2013 Agreement and 2013 D&O described above). The CIS project costs of $20 million are expected to be recovered in electric rates beginning on June 1, 2013. Management believes no further adjustment to project costs is required as of March 31, 2013.

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 other operation and maintenance (O&M) expenditures. On June 11, 2012, the EPA published additional information on the 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 February 6, 2013, the EPA issued a guidance document titled “Next Steps for Area Designations and Implementation of the Sulfur Dioxide National Ambient Air Quality Standard,” which outlines a process that will provide the states additional flexibility and time for their development of one-hour SO2 NAAQS implementation plans. HECO will work with the Hawaii Department of Health (DOH) and the EPA in the rulemaking process for these implementation plans to insure development of cost-effective strategies for NAAQS compliance.

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Depending upon the final outcome of the CWA 316(b) regulations and proposed changes to 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 or deactivate 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 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 March 31, 2013) 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 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 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. HECO submitted comments on the proposed regulations in January 2013. HECO continues to monitor this rulemaking proceeding and will participate in the further development of the regulations.

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, 2011 and 2012 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.

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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. 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)	2013			2012
Balance, January 1	$	48,431		$	50,871
Accretion expense	124			451
Liabilities incurred	—			—
Liabilities settled	(642		)	(210		)
Revisions in estimated cash flows	—			—
Balance, March 31	$	47,913		$	51,112

Collective bargaining agreements.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

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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. As of April 1, 2013, 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.

6 · Cash flows

Three months ended March 31	2013			2012
(in millions)
Supplemental disclosures of cash flow information
Interest paid	$	14		$	15
Income taxes refunded	(26		)	(1		)
Supplemental disclosures of noncash activities
Additions to electric utility property, plant and equipment - Unpaid invoices and other	3			3

7 · 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 electric utilities use their 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 electric utilities were to sell their entire holdings of a particular financial instrument at one time. Because no active trading market exists for a portion of the electric utilities’ 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 is 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 electric utilities 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.  The carrying amount approximated fair value because of the short maturity of these instruments.

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.

39

The estimated fair values of certain of the electric utilities’ financial instruments were as follows:

	March 31, 2013				December 31, 2012
(in thousands)	Carrying amount		Estimated fair value (Level 2)		Carrying amount		Estimated fair value (Level 2)
Financial liabilities
Short-term borrowings - nonaffiliates	$	43,052	$	43,052	$	—	$	—
Long-term debt, net, including amounts due within one year	1,147,875		1,230,067		1,147,872		1,181,631

Fair value measurements on a nonrecurring basis.  From time to time, the utilities may be required to measure certain liabilities at fair value on a nonrecurring basis in accordance with GAAP. The fair value of the utilities 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 “Asset retirement obligations” in Note 5.

8 · Recent accounting pronouncements

Obligations resulting from joint and several liability.  In February 2013, the FASB issued Accounting Standards Update (ASU) No. 2013-04, “Liabilities (Topic 405): Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation Is Fixed at the Reporting Date,” which provides guidance for the recognition, measurement and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date. The guidance requires entities to measure these obligations as the sum of the amount the entity has agreed with co-obligors to pay and any additional amount it expects to pay on behalf of its co-obligors. The guidance also requires an entity to disclose the nature and amount of the obligation as well as other information. This guidance is effective for all fiscal years, and interim periods within those years, beginning after December 31, 2013.

HECO and its subsidiaries will retrospectively adopt ASU No. 2013-04 in the first quarter of 2014 and does not expect it to have a material impact on HECO and its subsidiaries’ results of operations, financial condition or liquidity.

9 · Credit agreement

HECO maintains an amended revolving noncollateralized credit agreement, which established a line of credit facility of $175 million, with a letter of credit sub-facility, expiring on December 5, 2016, with a syndicate of eight financial institutions. 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.

10 ·Reconciliation of electric utility operating income per HEI and HECO consolidated statements of income

Three months ended March 31	2013			2012
(in thousands)
Operating income from regulated and nonregulated activities before income taxes (per HEI consolidated statements of income)	$	52,953		$	57,254
Deduct:
Income taxes on regulated activities	(14,095		)	(17,365		)
Revenues from nonregulated activities	(3,076		)	(1,672		)
Add:
Expenses from nonregulated activities	764			364
Operating income from regulated activities after income taxes (per HECO consolidated statements of income)	$	36,546		$	38,581

40

11 ·Consolidating financial information

HECO is not required to provide separate financial statements or other disclosures concerning HELCO and MECO to holders of the 2004 Debentures issued by HELCO and MECO to Trust III since all of their voting capital stock is owned, and their obligations with respect to these securities have been fully and unconditionally guaranteed, on a subordinated basis, by HECO. Consolidating information is provided below for these and other HECO subsidiaries for the periods ended and as of the dates indicated.

HECO also unconditionally guarantees HELCO’s and MECO’s obligations (a) to the State of Hawaii for the repayment of principal and interest on Special Purpose Revenue Bonds issued for the benefit of HELCO and MECO, (b)under their respective private placement note agreements and the HELCO notes and MECO notes issued thereunder and (c) relating to the trust preferred securities of Trust III (see Note 2 above). HECO is also obligated, after the satisfaction of its obligations on its own preferred stock, to make dividend, redemption and liquidation payments on HELCO’s and MECO’s preferred stock if the respective subsidiary is unable to make such payments.

41

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Income (Loss) (unaudited)

Three months ended March 31, 2013

(in thousands)	HECO			HELCO		MECO		Other subsidiaries	Consolidating adjustments		HECO Consolidated
Operating revenues	$	505,829		106,016		104,352		—	—		$	716,197
Operating expenses
Fuel oil	221,967			32,936		50,197		—	—		305,100
Purchased power	111,155			30,122		12,087		—	—		153,364
Other operation	50,111			11,064		10,248		—	—		71,423
Maintenance	21,652			3,806		4,244		—	—		29,702
Depreciation	24,707			8,547		5,026		—	—		38,280
Taxes, other than income taxes	48,085			9,686		9,916		—	—		67,687
Income taxes	7,311			2,714		4,070		—	—		14,095
Total operating expenses	484,988			98,875		95,788		—	—		679,651
Operating income	20,841			7,141		8,564		—	—		36,546
Other income (loss)
Allowance for equity funds used during construction	983			138		94		—	—		1,215
Equity in earnings of subsidiaries	10,985			—		—		—	(10,985	)	—
Other, net	2,021			142		177		—	(28	)	2,312
Income tax benefits	(230		)	(23	)	(46	)	—	—		(299		)
Total other income (loss)	13,759			257		225		—	(11,013	)	3,228
Interest and other charges
Interest on long-term debt	9,902			2,750		1,962		—	—		14,614
Amortization of net bond premium and expense	410			117		120		—	—		647
Other interest charges	157			69		117		—	(28	)	315
Allowance for borrowed funds used during construction	(568		)	(92	)	(70	)	—	—		(730		)
Total interest and other charges	9,901			2,844		2,129		—	(28	)	14,846
Net income	24,699			4,554		6,660		—	(10,985	)	24,928
Preferred stock dividend of subsidiaries	—			134		95		—	—		229
Net income attributable to HECO	24,699			4,420		6,565		—	(10,985	)	24,699
Preferred stock dividends of HECO	270			—		—		—	—		270
Net income for common stock	$	24,429		4,420		6,565		—	(10,985	)	$	24,429

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Comprehensive Income (Loss) (unaudited)

Three months ended March 31, 2013

(in thousands)	HECO			HELCO		MECO		Other subsidiaries	Consolidating adjustments		HECO Consolidated
Net income for common stock	$	24,429		4,420		6,565		—	(10,985	)	$	24,429
Other comprehensive income (loss), net of taxes:
Retirement benefit plans:
Less: amortization of transition obligation, prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits	5,331			759		657		—	(1,416	)	5,331
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes	(5,313		)	(761	)	(656	)	—	1,417		(5,313		)
Other comprehensive income (loss), net of taxes	18			(2	)	1		—	1		18
Comprehensive income attributable to common shareholder	$	24,447		4,418		6,566		—	(10,984	)	$	24,447

42

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Income (Loss) (unaudited)

Three months ended March 31, 2012

(in thousands)	HECO			HELCO		MECO		Other subsidiaries		Consolidating adjustments		HECO Consolidated
Operating revenues	$	530,613		112,327		104,998		—		—		$	747,938
Operating expenses
Fuel oil	235,026			32,410		60,403		—		—		327,839
Purchased power	124,780			33,908		6,101		—		—		164,789
Other operation	39,948			9,015		12,886		—		—		61,849
Maintenance	20,836			4,249		4,953		—		—		30,038
Depreciation	22,571			8,436		5,475		—		—		36,482
Taxes, other than income taxes	50,553			10,463		9,979		—		—		70,995
Income taxes	11,963			4,223		1,179		—		—		17,365
Total operating expenses	505,677			102,704		100,976		—		—		709,357
Operating income	24,936			9,623		4,022		—		—		38,581
Other income (loss)
Allowance for equity funds used during construction	1,581			125		234		—		—		1,940
Equity in earnings of subsidiaries	8,490			—		—		—		(8,490	)	—
Other, net	1,094			116		110		(1	)	(10	)	1,309
Income tax benefits	(30		)	(15	)	1		—		—		(44		)
Total other income (loss)	11,135			226		345		(1	)	(8,500	)	3,205
Interest and other charges
Interest on long-term debt	9,130			2,985		2,268		—		—		14,383
Amortization of net bond premium and expense	483			137		125		—		—		745
Other interest charges	(387		)	33		93		—		(10	)	(271		)
Allowance for borrowed funds used during construction	(725		)	(51	)	(94	)	—		—		(870		)
Total interest and other charges	8,501			3,104		2,392		—		(10	)	13,987
Net income (loss)	27,570			6,745		1,975		(1	)	(8,490	)	27,799
Preferred stock dividend of subsidiaries	—			134		95		—		—		229
Net income (loss) attributable to HECO	27,570			6,611		1,880		(1	)	(8,490	)	27,570
Preferred stock dividends of HECO	270			—		—		—		—		270
Net income (loss) for common stock	$	27,300		6,611		1,880		(1	)	(8,490	)	$	27,300

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Comprehensive Income (Loss) (unaudited)

Three months ended March 31, 2012

(in thousands)	HECO			HELCO		MECO		Other subsidiaries		Consolidating adjustments		HECO Consolidated
Net income (loss) for common stock	$	27,300		6,611		1,880		(1	)	(8,490	)	$	27,300
Other comprehensive income (loss), net of taxes:
Retirement benefit plans:
Less: amortization of transition obligation, prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits	3,472			532		473		—		(1,005	)	3,472
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes	(3,395		)	(526	)	(467	)	—		993		(3,395		)
Other comprehensive income (loss), net of taxes	77			6		6		—		(12	)	77
Comprehensive income (loss) attributable to common shareholder	$	27,377		6,617		1,886		(1	)	(8,502	)	$	27,377

43

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Balance Sheet (unaudited)

March 31, 2013

(in thousands)	HECO			HELCO		MECO		Other subsidiaries	Consolidating adjustments		HECO Consolidated
Assets
Utility plant, at cost
Land	$	43,400		5,182		3,016		—	—		$	51,598
Plant and equipment	3,377,351			1,089,414		961,168		—	—		5,427,933
Less accumulated depreciation	(1,198,256		)	(439,184	)	(425,370	)	—	—		(2,062,810		)
Construction in progress	123,898			17,623		12,148		—	—		153,669
Net utility plant	2,346,393			673,035		550,962		—	—		3,570,390
Investment in wholly owned subsidiaries, at equity	501,871			—		—		—	(501,871	)	—
Current assets
Cash and cash equivalents	32,661			2,770		1,405		104	—		36,940
Advances to affiliates	13,000			16,650		—		—	(29,650	)	—
Customer accounts receivable, net	139,540			30,046		24,871		—	—		194,457
Accrued unbilled revenues, net	102,307			16,484		16,824		—	—		135,615
Other accounts receivable, net	13,437			861		1,341		—	(9,844	)	5,795
Fuel oil stock, at average cost	153,331			13,429		23,931		—	—		190,691
Materials and supplies, at average cost	33,632			5,950		14,848		—	—		54,430
Prepayments and other	26,668			3,133		2,663		—	(209	)	32,255
Regulatory assets	50,315			5,412		6,077		—	—		61,804
Total current assets	564,891			94,735		91,960		104	(39,703	)	711,987
Other long-term assets
Regulatory assets	601,447			109,547		101,353		—	—		812,347
Unamortized debt expense	6,844			2,004		1,397		—	—		10,245
Other	45,348			9,057		14,861		—	—		69,266
Total other long-term assets	653,639			120,608		117,611		—	—		891,858
Total assets	$	4,066,794		888,378		760,533		104	(541,574	)	$	5,174,235
Capitalization and liabilities
Capitalization
Common stock equity	$	1,476,513		269,716		232,051		104	(501,871	)	$	1,476,513
Cumulative preferred stock—not subject to mandatory redemption	22,293			7,000		5,000		—	—		34,293
Long-term debt, net	780,547			201,328		166,000		—	—		1,147,875
Total capitalization	2,279,353			478,044		403,051		104	(501,871	)	2,658,681
Current liabilities
Current portion of long-term debt	43,052			—		—		—	—		43,052
Short-term borrowings-affiliate	16,650			—		13,000		—	(29,650	)	—
Accounts payable	181,266			26,534		20,626		—	—		228,426
Interest and preferred dividends payable	14,643			3,789		3,274		—	(13	)	21,693
Taxes accrued	138,681			30,586		30,292		—	(209	)	199,350
Other	49,186			11,989		16,586		—	(9,831	)	67,930
Total current liabilities	443,478			72,898		83,778		—	(39,703	)	560,451
Deferred credits and other liabilities
Deferred income taxes	316,153			71,233		48,212		—	—		435,598
Regulatory liabilities	220,715			68,878		35,934		—	—		325,527
Unamortized tax credits	41,111			13,428		13,400		—	—		67,939
Retirement benefits liability	453,573			79,421		78,684		—	—		611,678
Other	67,362			16,937		14,267		—	—		98,566
Total deferred credits and other liabilities	1,098,914			249,897		190,497		—	—		1,539,308
Contributions in aid of construction	245,049			87,539		83,207		—	—		415,795
Total capitalization and liabilities	$	4,066,794		888,378		760,533		104	(541,574	)	$	5,174,235

44

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Balance Sheet (unaudited)

December 31, 2012

(in thousands)	HECO			HELCO		MECO		Other subsidiaries	Consolidating adjustments		HECO Consolidated
Assets
Utility plant, at cost
Land	$	43,370		5,182		3,016		—	—		$	51,568
Plant and equipment	3,325,862			1,086,048		952,490		—	—		5,364,400
Less accumulated depreciation	(1,185,899		)	(433,531	)	(421,359	)	—	—		(2,040,789		)
Construction in progress	130,143			12,126		9,109		—	—		151,378
Net utility plant	2,313,476			669,825		543,256		—	—		3,526,557
Investment in wholly owned subsidiaries, at equity	497,939			—		—		—	(497,939	)	—
Current assets
Cash and cash equivalents	8,265			5,441		3,349		104	—		17,159
Advances to affiliates	9,400			18,050		—		—	(27,450	)	—
Customer accounts receivable, net	154,316			29,772		26,691		—	—		210,779
Accrued unbilled revenues, net	100,600			14,393		19,305		—	—		134,298
Other accounts receivable, net	33,313			1,122		3,016		—	(9,275	)	28,176
Fuel oil stock, at average cost	123,176			15,485		22,758		—	—		161,419
Materials and supplies, at average cost	31,779			5,336		13,970		—	—		51,085
Prepayments and other	21,708			5,146		6,011		—	—		32,865
Regulatory assets	42,675			4,056		4,536		—	—		51,267
Total current assets	525,232			98,801		99,636		104	(36,725	)	687,048
Other long-term assets
Regulatory assets	601,451			109,815		102,063		—	—		813,329
Unamortized debt expense	7,042			2,066		1,446		—	—		10,554
Other	46,586			9,871		14,848		—	—		71,305
Total other long-term assets	655,079			121,752		118,357		—	—		895,188
Total assets	$	3,991,726		890,378		761,249		104	(534,664	)	$	5,108,793
Capitalization and liabilities
Capitalization
Common stock equity	$	1,472,136		268,908		228,927		104	(497,939	)	$	1,472,136
Cumulative preferred stock—not subject to mandatory redemption	22,293			7,000		5,000		—	—		34,293
Long-term debt, net	780,546			201,326		166,000		—	—		1,147,872
Total capitalization	2,274,975			477,234		399,927		104	(497,939	)	2,654,301
Current liabilities
Current portion of long-term debt	—			—		—		—	—		—
Short-term borrowings-affiliate	18,050			—		9,400		—	(27,450	)	—
Accounts payable	134,651			27,457		24,716		—	—		186,824
Interest and preferred dividends payable	14,479			4,027		2,593		—	(7	)	21,092
Taxes accrued	174,477			38,778		37,811		—	—		251,066
Other	47,203			10,310		14,634		—	(9,268	)	62,879
Total current liabilities	388,860			80,572		89,154		—	(36,725	)	521,861
Deferred credits and other liabilities
Deferred income taxes	302,569			68,479		46,563		—	—		417,611
Regulatory liabilities	218,437			67,359		36,278		—	—		322,074
Unamortized tax credits	39,827			13,450		13,307		—	—		66,584
Retirement benefits liability	459,765			80,686		79,754		—	—		620,205
Other	68,783			17,799		14,055		—	—		100,637
Total deferred credits and other liabilities	1,089,381			247,773		189,957		—	—		1,527,111
Contributions in aid of construction	238,510			84,799		82,211		—	—		405,520
Total capitalization and liabilities	$	3,991,726		890,378		761,249		104	(534,664	)	$	5,108,793

45

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Changes in Common Stock Equity (unaudited)

Three months ended March 31, 2013

(in thousands)	HECO			HELCO		MECO		Other subsidiaries	Consolidating adjustments		HECO Consolidated
Balance, December 31, 2012	$	1,472,136		268,908		228,927		104	(497,939	)	$	1,472,136
Net income for common stock	24,429			4,420		6,565		—	(10,985	)	24,429
Other comprehensive income, net of taxes	18			(2	)	1		—	1		18
Common stock dividends	(20,070		)	(3,610	)	(3,442	)	—	7,052		(20,070		)
Balance, March 31, 2013	$	1,476,513		269,716		232,051		104	(501,871	)	$	1,476,513

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Changes in Common Stock Equity (unaudited)

Three months ended March 31, 2012

(in thousands)	HECO			HELCO		MECO		Other subsidiaries		Consolidating adjustments		HECO Consolidated
Balance, December 31, 2011	$	1,402,841		280,468		235,568		107		(516,143	)	$	1,402,841
Net income (loss) for common stock	27,300			6,611		1,880		(1	)	(8,490	)	27,300
Other comprehensive income, net of taxes	77			6		6		—		(12	)	77
Common stock dividends	(18,261		)	(3,284	)	(2,187	)	—		5,471		(18,261		)
Balance, March 31, 2012	$	1,411,957		283,801		235,267		106		(519,174	)	$	1,411,957

46

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Cash Flows (unaudited)

Three months ended March 31, 2013

(in thousands)	HECO			HELCO		MECO		Other subsidiaries	Consolidating adjustments		HECO Consolidated
Cash flows from operating activities:
Net income	$	24,699		4,554		6,660		—	(10,985	)	$	24,928
Adjustments to reconcile net income to net cash provided by operating activities:
Equity in earnings of subsidiaries	(11,010		)	—		—		—	10,985		(25		)
Common stock dividends received from subsidiaries	7,052			—		—		—	(7,052	)	—
Depreciation of property, plant and equipment	24,707			8,547		5,026		—	—		38,280
Other amortization	(8		)	358		607		—	—		957
Change in deferred income taxes	13,572			2,755		1,648		—	—		17,975
Change in tax credits, net	1,299			(17	)	100		—	—		1,382
Allowance for equity funds used during construction	(983		)	(138	)	(94	)	—	—		(1,215		)
Changes in assets and liabilities:
Decrease (increase) in accounts receivable	34,652			(13	)	3,495		—	569		38,703
Decrease (increase) in accrued unbilled revenues	(1,707		)	(2,091	)	2,481		—	—		(1,317		)
Decrease (increase) in fuel oil stock	(30,155		)	2,056		(1,173	)	—	—		(29,272		)
Increase in materials and supplies	(1,853		)	(614	)	(878	)	—	—		(3,345		)
Increase in regulatory assets	(13,071		)	(2,464	)	(2,211	)	—	—		(17,746		)
Increase (decrease) in accounts payable	44,887			(903	)	(5,050	)	—	—		38,934
Change in prepaid and accrued income and utility revenue taxes	(41,093		)	(8,078	)	(4,495	)	—	—		(53,666		)
Contributions to defined benefit pension and other postretirement benefit plans	(15,530		)	(2,763	)	(2,717	)	—	—		(21,010		)
Change in other assets and liabilities	11,117			5,170		4,220		—	(569	)	19,938
Net cash provided by operating activities	46,575			6,359		7,619		—	(7,052	)	53,501
Cash flows from investing activities:
Capital expenditures	(47,709		)	(10,118	)	(10,088	)	—	—		(67,915		)
Contributions in aid of construction	7,816			3,432		462		—	—		11,710
Advances from (to) affiliates	(3,600		)	1,400		—		—	2,200		—
Net cash used in investing activities	(43,493		)	(5,286	)	(9,626	)	—	2,200		(56,205		)
Cash flows from financing activities:
Common stock dividends	(20,070		)	(3,610	)	(3,442	)	—	7,052		(20,070		)
Preferred stock dividends of HECO and subsidiaries	(270		)	(134	)	(95	)	—	—		(499		)
Net increase in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less	41,652			—		3,600		—	(2,200	)	43,052
Other	2			—		—		—	—		2
Net cash provided by (used in) financing activities	21,314			(3,744	)	63		—	4,852		22,485
Net increase (decrease) in cash and cash equivalents	24,396			(2,671	)	(1,944	)	—	—		19,781
Cash and cash equivalents, beginning of period	8,265			5,441		3,349		104	—		17,159
Cash and cash equivalents, end of period	$	32,661		2,770		1,405		104	—		$	36,940

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Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Cash Flows (unaudited)

Three months ended March 31, 2012

(in thousands)	HECO			HELCO		MECO		Other subsidiaries		Consolidating adjustments		HECO Consolidated
Cash flows from operating activities:
Net income (loss)	$	27,570		6,745		1,975		(1	)	(8,490	)	$	27,799
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Equity in earnings of subsidiaries	(8,515		)	—		—		—		8,490		(25		)
Common stock dividends received from subsidiaries	5,471			—		—		—		(5,471	)	—
Depreciation of property, plant and equipment	22,571			8,436		5,475		—		—		36,482
Other amortization	485			622		454		—		—		1,561
Change in deferred income taxes	13,721			2,563		3,777		—		—		20,061
Change in tax credits, net	1,320			36		—		—		—		1,356
Allowance for equity funds used during construction	(1,581		)	(125	)	(234	)	—		—		(1,940		)
Changes in assets and liabilities:
Decrease (increase) in accounts receivable	19,978			343		2,431		—		2,249		25,001
Decrease (increase) in accrued unbilled revenues	11,188			57		(61	)	—		—		11,184
Decrease (increase) in fuel oil stock	(11,819		)	(2,058	)	(581	)	—		—		(14,458		)
Increase in materials and supplies	(2,320		)	(1,128	)	(113	)	—		—		(3,561		)
Increase in regulatory assets	(11,612		)	(1,039	)	(1,297	)	—		—		(13,948		)
Increase (decrease) in accounts payable	(27,400		)	(2,941	)	(2,833	)	—		—		(33,174		)
Change in prepaid and accrued income and utility revenue taxes	(29,011		)	(5,741	)	(9,809	)	—		—		(44,561		)
Contributions to defined benefit pension and other postretirement benefit plans	(19,428		)	(3,279	)	(3,476	)	—		—		(26,183		)
Change in other assets and liabilities	(2,190		)	2,320		5,589		(1	)	(2,249	)	3,469
Net cash provided by (used in) operating activities	(11,572		)	4,811		1,297		(2	)	(5,471	)	(10,937		)
Cash flows from investing activities:
Capital expenditures	(51,026		)	(6,727	)	(5,683	)	—		—		(63,436		)
Contributions in aid of construction	20,748			1,579		528		—		—		22,855
Advances from (to) affiliates	—			10,250		14,500		—		(24,750	)	—
Net cash used in investing activities	(30,278		)	5,102		9,345		—		(24,750	)	(40,581		)
Cash flows from financing activities:
Common stock dividends	(18,261		)	(3,284	)	(2,187	)	—		5,471		(18,261		)
Preferred stock dividends of HECO and subsidiaries	(270		)	(134	)	(95	)	—		—		(499		)
Repayment of long-term debt	(42,580		)	(7,200	)	(7,720	)	—		—		(57,500		)
Net increase in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less	60,192			—		—		—		24,750		84,942
Other	(70		)	(2	)	(48	)	—		—		(120		)
Net cash provided by (used in) financing activities	(989		)	(10,620	)	(10,050	)	—		30,221		8,562
Net increase (decrease) in cash and cash equivalents	(42,839		)	(707	)	592		(2	)	—		(42,956		)
Cash and cash equivalents, beginning of period	44,819			3,383		496		108		—		48,806
Cash and cash equivalents, end of period	$	1,980		2,676		1,088		106		—		$	5,850

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Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion updates “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in HEI’s and HECO’s Form 10-K for 2012 and should be read in conjunction with the 2012 annual consolidated financial statements of HEI and HECO and notes thereto included and incorporated by reference, respectively, in HEI’s and HECO’s Form 10-K for 2012, as well as the quarterly (as of and for the three months ended March 31, 2013) financial statements and notes thereto included in this Form 10-Q.

HEI Consolidated

RESULTS OF OPERATIONS

(in thousands, except per	Three months ended March 31				%		Primary reason(s) for
share amounts)	2013		2012		change		significant change*
Revenues	$	784,064	$	814,860	(4	)	Decrease for the electric utility and bank segments
Operating income	70,657		75,816		(7	)	Decrease for the electric utility and bank segments, partly offset by a reduced operating loss for the “other” segment
Net income for common stock	33,679		38,316		(12	)	Lower operating income, higher “interest expense—other than on deposit liabilities and other bank borrowings” and lower AFUDC, partly offset by lower income taxes
Basic earnings per common share	$	0.34	$	0.40	(15	)	Lower net income and higher weighted average shares outstanding
Weighted-average number of common shares outstanding	98,135		96,167		2		Issuances of shares under the HEI Dividend Reinvestment and Stock Purchase Plan and other plans

*Also, see segment discussions which follow.

Notes:  The Company’s effective tax rates (combined federal and state) for the first quarters of 2013 and 2012 were 35%.

HEI’s consolidated ROACE was 8.5% for the twelve months ended March 31, 2013 and 9.7% for the twelve months ended March 31, 2012.

Dividends.  The payout ratios for the first quarter of 2013 and full year 2012 were 90% and 87%, respectively. HEI currently expects to maintain the dividend at its present level; however, the HEI Board of Directors evaluates the dividend quarterly and considers many factors in the evaluation, 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.

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 and continued to grow into 2013, although at a slower pace. State visitor arrivals grew by 7.1% in the first three months of 2013 over 2012. State visitor expenditures also continued to grow, increasing by 7.6% in the first three months of 2013 over 2012. Hotel occupancies and room rates also continued to rise. The outlook for the visitor industry remains positive, albeit with a potential for more moderate growth, with the Hawaii Tourism Authority expecting a 10.0% increase in scheduled nonstop seats to Hawaii for April — June 2013 over the same period in 2012.

Hawaii’s unemployment rate was 5.1% in March 2013, lower than the state’s 6.2% rate in March 2012 and the March 2013 national unemployment rate of 7.6%.

Hawaii real estate activity as indicated by the home resale market has been mixed in the first quarter of 2013. The median sales price for single family residential homes on Oahu decreased by 2.7%, but closed sales increased

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6.9% in the first three months of 2013 as compared to the same period in 2012. Oahu condominiums showed strong momentum with median prices rising 9.7% and closed sales (including 174 presale units for the new Holomua project) increasing 37.1% for first quarter of 2013 as compared to the same period in 2012.

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 through 2012 and into 2013.

The Federal Open Market Committee (FOMC) maintained a highly accommodative stance of monetary policy in their continuing efforts to stimulate the U.S. economy. At its meeting on March 19-20, 2013, the FOMC held the federal funds rate target at 0% to 0.25% and expected to maintain the record low rates for at least as long as the unemployment rate is above 6.5% and the inflation outlook remained under control. The FOMC stated it will continue purchases of Treasury and agency mortgage-backed securities and employ other policy tools as appropriate to support progress toward the FOMC’s statutory mandate of maximum employment and price stability.

Overall, Hawaii’s economy is expected to see strengthening growth in 2013 and 2014 with local economic growth supported by continued expansion of the visitor industry and finally signs of recovery in the construction industry.  U.S. budget cuts, continued uncertainty in global economies, heightened tensions with North Korea and avian influenza pose possible risks to local economic growth. Despite economic improvement, the electric utilities’ kilowatt-hour sales declined in 2012. Based on expectations of additional customer renewable self-generation and energy-efficiency installations, the electric utilities’ 2013 and 2014 kilowatt-hour sales are expected to further decline below 2012 levels.

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 $120 million, primarily attributable to the utilities.

The Internal Revenue Service (IRS) issued regulations that provide a general framework for determining whether expenditures are deductible as repairs, effective January 1, 2014. The IRS plans to issue final regulations related to repairs deductions in 2013. In the interim, the IRS has directed its examination teams to discontinue the current examination of these repairs issues and withdraw any proposed adjustments previously made in the examination of tax years prior to 2012. Once final regulations are issued, the Company will review the regulations and will analyze any subsequently issued transitional rules and guidance for their impacts and for the opportunities they present for the current and future years.

The IRS recently released a revenue procedure relating to deductions for repairs of generation property, which provides some guidance (that is elective) for taxpayers that own steam or electric generation property. This guidance defines the relevant components of generation property to be used in determining whether such component expenditures should be deducted as repairs or capitalized and depreciated by taxpayers. The revenue procedure also provides an extrapolation methodology that could be used by taxpayers in determining deductions for prior years’ repairs without going back to the specific documentation of those years. The guidance does not provide specific methods for determining the repairs amount. The utilities have begun to evaluate the costs and benefits of adopting this guidance, in order to determine whether and when the election should be made.

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.

Retirement benefits.  For the first quarter of 2013, the Company’s defined benefit pension and other postretirement benefit plans’ assets generated a gain, after investment management fees, of 6.5%. The market value of these assets

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as of March 31, 2013 was $1.2 billion (including $1.1 billion for the utilities) compared to $1.1 billion at December 31, 2012 (including $1.0 billion for the utilities).

The Company estimates that the cash funding for its defined benefit pension and other postretirement benefit plans in 2013 will be $86 million ($84 million by the utilities, $2 million by HEI and nil by ASB), which is expected to fully satisfy the minimum required contribution, including requirements of the utilities’ pension and other postretirement benefits tracking mechanisms and the plans’ funding policies.

Commitments and contingencies.See Note 4, “Bank subsidiary,” of HEI’s “Notes to Consolidated Financial Statements” and Note 5, “Commitments and contingencies,” of HECO’s “Notes to Consolidated Financial Statements.”

Recent accounting pronouncements.See Note 11, “Recent accounting pronouncements,” of HEI’s “Notes to Consolidated Financial Statements.”

“Other” segment.

	Three months ended March 31						%
(in thousands)	2013			2012			change	Primary reason(s) for significant change
Revenues	$	35		$	(2	)	NM
Operating loss	(4,047		)	(4,350		)	NM	Lower administrative and general expenses
Net loss	(4,905		)	(4,861		)	NM	Lower operating loss more than offset by slightly higher interest expense and lower income tax benefits

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., a company holding passive, venture capital investments; and The Old Oahu Tug Service, Inc., a maritime freight transportation company that ceased operations in 1999; as well as eliminations of intercompany transactions.

FINANCIAL CONDITION

Liquidity and capital resources.  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 for the foreseeable future.

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

(dollars in millions)	March 31, 2013				December 31, 2012
Short-term borrowings—other than bank	$	134	4	%	$	84	3	%
Long-term debt, net—other than bank	1,423		45		1,423		45
Preferred stock of subsidiaries	34		1		34		1
Common stock equity	1,607		50		1,594		51
	$	3,198	100	%	$	3,135	100	%

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

	Three months ended March 31, 2013		Balance
(in millions)	Average balance		March 31, 2013		December 31, 2012
Short-term borrowings(1)
Commercial paper	$	84	$	91	$	84
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.” The maximum amount of HEI’s external short-term

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borrowings during the first quarter of 2013 was $96 million. At April 29, 2013, HEI had $89 million in outstanding commercial paper and its line of credit facility was undrawn.

HEI has a line of credit facility of $125 million (see Note 12 of HEI’s “Notes to Consolidated Financial Statements”). There are customary conditions which must be met in order to draw on it, including compliance with its covenants (such as covenants preventing HEI’s 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 the credit agreement, or meet other requirements may result in an event of default. For example, under the agreement, it is an event of default if HEI fails to maintain a nonconsolidated “Capitalization Ratio” (funded debt) of 50% or less (ratio of 19% as of March 31, 2013, as calculated under the agreement) and “Consolidated Net Worth” of at least $975 million (Net Worth of $1.7 billion as of March 31, 2013, as calculated under the agreement), or if HEI no longer owns HECO. The commitment fee and interest charges on drawn amounts under the credit agreement are subject to adjustment in the event of a change in HEI’s long-term credit ratings.

The Company raised $11 million through the issuance of approximately 0.4 million shares of common stock under the DRIP, the HEIRSP, ASB 401(k) Plan and other plans during the first quarter of 2013.

In March 2013, HEI entered into equity forward transactions in which a forward counterparty borrowed 7 million shares of HEI’s common stock from third parties and such borrowed shares were sold pursuant to an HEI registered public offering. At March 31, 2013, the equity forward transactions could have been settled with physical delivery by HEI of 7 million newly-issued shares to the forward counterparty in exchange for cash of $180 million. HEI will not receive any proceeds from the sale of common stock until the equity forward transactions are settled. HEI anticipates physical settlement of the equity forward transactions before March 25, 2015.

On March 6, 2013, HEI issued $50 million of 3.99% Senior Notes due March 6, 2023 via a private placement.  HEI used the net proceeds from the issuance of the Senior Notes to refinance $50 million of its 5.25% medium-term notes that matured on March 7, 2013. The 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) and provisions requiring the maintenance by HEI of certain financial ratios generally consistent with those in HEI’s revolving noncollateralized credit agreement. For example, see discussion of “Capitalization Ratio” and “Consolidated Net Worth” above.

For the first quarter of 2013, net cash provided by operating activities of consolidated HEI was $48 million. Net cash used by investing activities for the same period was $113 million, due to HECO’s consolidated capital expenditures, a net increase in ASB’s loans held for investment and purchases of investment and mortgage-related securities, partly offset by repayments of investment and mortgage-related securities and HECO’s contributions in aid of construction. Net cash provided by financing activities during this period was $107 million as a result of several factors, including net increases in deposit liabilities and short-term borrowings and proceeds from the issuance of common stock under HEI plans, partly offset by the payment of common 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 the first quarter of 2013, HECO and ASB (via ASHI) paid cash dividends to HEI of $20 million and $10 million, respectively.

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 the Company’s control and could cause future results of operations to differ materially from historical results. For information about certain of these factors, see pages 48 to 49, 64 to 67, and 78 to 80 of HEI’s MD&A included in Part II, Item 7 of HEI’s 2012 Form 10-K.

Additional factors that may affect future results and financial condition are described on pages iv and v under “Forward-Looking Statements.”

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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.

In accordance with SEC Release No. 33-8040, “Cautionary Advice Regarding Disclosure About Critical Accounting Policies,” management has identified the accounting policies it believes to be the most critical to the Company’s financial statements—that is, management believes that these policies 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.

For information about these material estimates and critical accounting policies, see pages 49 to 50, 67 to 68, and 80 to 81 of HEI’s MD&A included in Part II, Item 7 of HEI’s 2012 Form 10-K.

Following are discussions of the results of operations, liquidity and capital resources of the electric utility and bank segments.

Electric utility

RESULTS OF OPERATIONS

Utility strategic progress.  In 2012 and the first quarter of 2013, the utilities continued to make significant progress in implementing their renewable 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 renewable energy and reliability on a more timely basis.

The utilities are committed to achieving or exceeding the State’s Renewable Portfolio Standard goal of 40% renewable energy by 2030 (see “Renewable energy strategy” below). In addition, while it will not take precedence over the utilities’ work to increase their use of renewable energy, the utilities are also working with the State of Hawaii and other entities to examine the possibility of using liquefied natural gas as a cleaner and lower cost fuel to replace, at least in part, the petroleum oil that would otherwise be used for the remaining generation.

Regulatory.  In January 2013, the utilities and Consumer Advocate signed a settlement agreement (2013 Agreement), which the PUC approved with clarifications in March 2013 (2013 D&O). See “Major projects” in Note 5 to HECO’s “Notes to Consolidated Financial Statements” and the discussion under “Most recent rate proceedings” below.

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 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.

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 near-term 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-

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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 (as of March 31, 2013) returns were as follows:

%	Return on rate base (RORB)*						ROACE**						Rate-making ROACE***
Twelve months ended March 31, 2013	HECO		HELCO		MECO		HECO		HELCO		MECO		HECO		HELCO		MECO
Utility returns	7.78		6.44		7.06		6.97		5.07		7.41		9.53		6.83		8.65
PUC-allowed returns	8.11		8.31		7.91		10.00		10.00		10.00		10.00		10.00		10.00
Difference	(0.33	)	(1.87	)	(0.85	)	(3.03	)	(4.93	)	(2.59	)	(0.47	)	(3.17	)	(1.35	)

*	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.
***	ROACE adjusted to remove items not included by the PUC in establishing rates, such as the write-off of $40 million of CIS project costs, executive bonuses and advertising.

The approval of decoupling by the PUC will help the utilities to gradually improve their ROACEs, which in turn will facilitate the utilities’ ability to effectively raise capital for needed infrastructure investments. However, the utilities continue to expect an ongoing structural gap between their PUC-allowed ROACEs and the ROACEs they actually achieve due to the following:

1) the timing of general rate case decisions,

2) the effective date of the RAMs,

3) the 5-year historical average for baseline plant additions, and

4) the PUC’s consistent exclusion of certain expenses from rates.

The structural gap in 2014 to 2016 is expected to be 80 to 110 basis points, an improvement of 40 basis points from management’s prior expectations. The improvement is due to the change in the timing of the recognition of the RAM revenues in 2014 to 2016 as defined in the settlement agreement approved by the PUC on March 19, 2013. For 2013, the structural gap remains unchanged at 120 to 150 basis points. Between rate cases, items not covered by the annual RAMs could also have a negative impact on the actual ROACEs achieved by the utilities (primarily investments in software projects, changes in fuel inventory and O&M in excess of indexed escalations). The specific magnitude of the impact will depend on various factors, including the size of software projects, changes in fuel prices and management’s ability to manage costs within the current mechanisms.

Management expects the earned ROACE to gradually improve from 2014 to 2016.

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 $40 million of CIS project costs pursuant to the 2013 Agreement, 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.

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Annual decoupling filings.  On March 28, 2013, HECO, HELCO and MECO submitted their annual decoupling filings for tariffed rates for each respective utility that will be effective from June 1, 2013 through May 31, 2014 unless the filing is modified or suspended by the PUC. Incremental annual changes included in the tariffed rates include: (1) the incremental RAM adjusted revenues (the components of which are shown below), (2) the accrued earnings sharing credits to be refunded, and (3) the amount of the accrued RBA balance as of December 31, 2012 (and associated revenue taxes) to be collected:

(in millions)	HECO			HELCO		MECO
Annual incremental RAM adjusted revenues
O&M	$	3.9		$	0.9	$	1.0
Invested capital	27.7			1.2		3.2
Total annual incremental RAM adjusted revenues	$	31.6		$	2.1	$	4.2
Accrued earnings sharing credits to be refunded	$	(2.1	)	$	—	$	—
Accrued RBA balance (and associated revenue taxes) to be collected	$	55.4		$	4.9	$	5.8

Under the 2011 decoupling tariff order, HECO, HELCO and MECO will accrue and collect 7/12ths of the annual incremental RAM adjusted revenues in one year and the remaining 5/12ths in the following year, provided the RAM rate adjustment remains in effect. The RAM rate adjustment terminates on the effective date of the D&O in a general rate case. However, based on the 2013 Agreement and 2013 D&O, HECO will be allowed to record incremental RAM revenues starting on January 1 of 2014, 2015 and 2016. See “Major projects” in Note 5 of HECO’s “Notes to Consolidated Financial Statements.”

See “Economic conditions” in the “HEI Consolidated” section above.

Results.

Three months ended March 31				Increase
2013		2012		(decrease)			(in millions)
$	719	$	750	$	(31	)	Revenues. Decrease largely due to:
				$	(37	)	Lower fuel prices and purchased power, partly offset by:
				3			Interim rate increase granted to MECO in its 2012 test year rate case
				1			Interim and final rate increases granted to HECO in its 2011 test year rate case
305		328		(23		)	Fuel oil expense. Decrease largely due to lower fuel prices and lower KWHs generated
153		165		(12		)	Purchased power expense. Decrease due to lower KWH purchased and lower purchase capacity/non-fuel charges
101		92		9			Other operation and maintenance expenses. Increase largely due to:
				5			Higher customer service expenses
				2			Reversal of 2011 expenses for the 200 MW RFP and CIS deferral costs in 2012
				2			Higher employee benefit costs
				(3		)	Partly offset by a 2012 increase in general liability reserve for an environmental matter
107		108		(1		)	Other expenses. Decrease largely due to lower taxes other than income taxes due to lower operating revenues, partially offset by higher depreciation due to an increase in plant additions
53		57		(4		)	Operating income. Decrease from prior year largely due to higher O&M and depreciation expenses, partly offset by interim and final rate increases
24		27		(3		)	Net income for common stock. Decrease largely due to lower operating income
2,123		2,251		(128		)	Kilowatthour sales (millions)
66.0		67.2		(1.2		)	Wet-bulb temperature (Oahu average; degrees Fahrenheit)
789		861		(72		)	Cooling degree days (Oahu)
$	130.83	$	134.37	$	(3.54	)	Average fuel oil cost per barrel
449,512		447,407		2,105			Customer accounts (end of period)

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Note:  The electric utilities had effective tax rates for the first quarters of 2013 and 2012 of 37% and 39%, respectively. The 2% decrease in the effective tax rate from the first quarter of 2012 was due to the receipt of nontaxable executive life insurance proceeds and the recognition of research and development credits which became available in 2013 under the American Taxpayer Relief Act of 2012.

HECO’s consolidated ROACE was 6.7% for the twelve months ended March 31, 2013 and 7.9% for the twelve months ended March 31, 2012.

Other operation and maintenance expenses (excluding expenses covered by surcharges or by third parties) for 2013 are projected to be flat to 1% higher than 2012, as the electric utilities expect to manage expenses to near-2012 levels.

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/ implemented)	Amount		% over rates in effect	ROACE (%)	RORB (%)	Rate base		Common equity %	Stipulated agreement reached with Consumer Advocate	ROACE 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 (5)
Request	8/16/12	$	19.8	4.2	10.25	8.30	$	455	57.05		Yes
Closed	3/27/13
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.

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(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 5 of HECO’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 depreciation rates and methodology as proposed by HECO in a separate depreciation proceeding. 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 was 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. As a result of the 2013 Agreement and 2013 D&O (described below), the rate case was withdrawn and the docket has been closed.

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

HECO 2011 test year rate case.  In the HECO 2011 test year rate case, the PUC had 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) that were 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.

On January 28, 2013, HECO, HELCO, MECO and the Consumer Advocate entered into the 2013 Agreement to, among other things, write-off $40 million of CIS Project costs in lieu of conducting the regulatory audits of the CIP CT-1 and the CIS projects, with the remaining recoverable costs of $52 million to be included in rate base as of December 31, 2012. The parties agreed that HELCO would withdraw its 2013 test year rate case and not file a rate case until its next turn in the rate case cycle, for a 2016 test year, and HECO would delay the filing of its scheduled 2014 test year rate case to no earlier than January 2, 2014. The parties also agreed that starting in 2014, HECO will be allowed to record RAM revenues starting on January 1 of 2014, 2015 and 2016. On March 19, 2013, the PUC issued its 2013 D&O approving the 2013 Agreement, with clarifications. See “Major projects” in Note 5 of HECO’s Consolidated Financial Statements for additional information on the 2013 Agreement and the 2013 D&O and other effects.

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.

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Renewableenergy strategy.  The utilities’ policy is to support efforts to increase renewable energy in Hawaii. The utilities believe their actions will help stabilize customer bills as they become less dependent on costly and price-volatile fossil fuel. The utilities’ renewable 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. For 2012, HECO achieved an RPS without DSM energy savings of 13.9%, 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’ renewable energy strategy include the following (also see the projects discussed under “Renewable Energy Projects” in Note 5 of HECO’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. 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 or deactivation of generating units. The scope of both RFPs will be further defined in the the utilities’ IRP, targeted to be filed with the PUC in June 2013. The respective schedules for the HECO and MECO RFPs will be assessed thereafter.

·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 to begin within five years of PUC approval. 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 Aina Koa Pono-Ka’u LLC (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 AKP, subject to PUC approval, to supply 16 million gallons of biodiesel per year with initial consumption to begin as early as 2015.

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

·In May 2012, MECO began purchasing wind energy from the 21 MW Kaheawa Wind Power II, LLC facility, which went into commercial operation in July 2012.

·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 expected to be placed in service in the second quarter of 2013.

·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. 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 and expected to be placed in service in 2017.

·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.

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·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.

·In February 2013, HELCO issued the Final Geothermal RFP for up to 50 MW of dispatchable firm power on the island of Hawaii. Bids were received in April 2013 and are being evaluated.

·HECO, HELCO and MECO began accepting energy from feed-in tariff projects in 2011. As of March 31, 2013, there were 9 MW, 1 MW and 1 MW of installed feed-in tariff capacity from renewable energy technologies at HECO, HELCO and MECO, respectively.

·As of March 31, 2013, there were 105 MW, 24 MW and 27 MW 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 the first quarter of 2013 was more than twice the amount installed in the same quarter of 2012.

·In February 2013, HECO issued an “Invitation for Low Cost Renewable Energy Projects on Oahu Through Request for Waiver from Competitive Bidding.” The invitation for waiver projects seeks to lower the cost of electricity for customers in the near term with qualified renewable energy projects on Oahu that can be quickly placed into service at a low cost per kilowatt-hour. HECO will consider requesting a waiver from the PUC Competitive Bidding Framework for projects that meet these goals. Proposals were received in March 2013 and are being evaluated.

Commitments and contingencies.  See Note 5 of HECO’s “Notes to Consolidated Financial Statements.”

Recent accounting pronouncements.See Note 8, “Recent accounting pronouncements,” of HECO’s “Notes to Consolidated Financial Statements.”

FINANCIAL CONDITION

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:

(dollars in millions)	March 31, 2013				December 31, 2012
Short-term borrowings	$	43	2	%	$	—	—	%
Long-term debt, net	1,148		42		1,148		43
Preferred stock	34		1		34		1
Common stock equity	1,477		55		1,472		56
	$	2,702	100	%	$	2,654	100	%

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

	Average balance		Balance
(in millions)	Three months ended March 31, 2013		March 31, 2013		December 31, 2012
Short-term borrowings(1)
Commercial paper	$	36	$	43	$	—
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 HECO’s external short-term borrowings during the first quarter of 2013 was $71 million. At March 31, 2013, HECO had $17 million of short-term borrowings from HELCO, and MECO had $13 million of short-term borrowings from HECO. At April 29, 2013, HECO had $40 million of outstanding commercial paper, no draws under its line of credit facility, no borrowings from HEI and $14 million of short-term borrowings from HELCO. Also, at April 29, 2013, MECO had $19 million of short-term borrowings from HECO. Intercompany borrowings are eliminated in consolidation.

HECO has a line of credit facility of $175 million (see Note 9 of HECO’s “Notes to Consolidated Financial Statements”). There are customary conditions that must be met in order to draw on it, including compliance with several covenants (such as covenants preventing its subsidiaries from entering into agreements that restrict the ability

59

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 March 31, 2013, 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 March 31, 2013, as calculated under the credit agreement), or if HECO is no longer owned by HEI.

Revenue bonds have been issued by the Department of Budget and Finance of the State of Hawaii (DBF) to finance (and refinance) 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; MBIA Insurance Corporation (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 Standard & Poor’s (S&P’s) and Moody’s Investor Service’s ratings of each of these insurers, which at the time the insured obligations were issued were higher than the ratings of the utilities, are currently either lower than the ratings of the utilities or have been withdrawn.

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.

Operating activities provided $54 million in net cash during the first quarter of 2013. Investing activities for the same period used net cash of $56 million for capital expenditures, net of contributions in aid of construction. Financing activities for the same period provided net cash of $22 million, primarily due to the increase in short-term borrowings, partly offset by payment of $21 million of common and preferred dividends.

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Bank

RESULTS OF OPERATIONS

	Three months ended March 31				Increase
(in millions)	2013		2012		(decrease)			Primary reason(s) for significant change
Interest income	$	46	$	49	$	(3	)	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 the first quarter of 2013 was $108 million higher than for the first quarter of 2012 as the average home equity lines of credit, commercial real estate and consumer loan balances increased by $89 million, $36 million and $28 million, respectively. ASB targeted these loan types because of their shorter duration and/or variable rates. The average residential loan portfolio decreased by $27 million due to higher repayments and loan sales during 2012. 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 increased by $54 million as ASB used its excess liquidity to purchase securities.
Noninterest income	19		16		3			Higher gain on sale of loans as more residential loans were sold in order to manage interest rate risk.
Revenues	65		65		—
Interest expense	2		3		(1		)	Lower funding costs as a result of the low interest rate environment. Average deposit balances for the first quarter of 2013 increased by $137 million compared to first quarter of 2012 due to an increase in core deposits of $209 million, partly offset by a decrease in term certificates of $72 million. The other borrowings average balance decreased by $40 million due to lower retail repurchase agreements.
Provision for loan losses	2		4		(2		)	The provision for loan losses benefited from lower net charge-offs and improved credit quality associated with the continued improvement in Hawaii’s economy. However, the provision was impacted by a single commercial real estate loan that was put on nonaccrual status.
Noninterest expense	39		35		4			Higher compensation and benefits expenses due to targeted staffing increases to support increased business volumes, IT and risk management capabilities.
Expenses	43		42		1
Operating income	22		23		(1		)	Lower net interest income and higher noninterest expenses, partially offset by higher noninterest income.
Net income	14		16		(2		)	Lower operating income.

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Details of ASB’s other noninterest income and other noninterest expense were as follows:

Three months ended March 31	2013		2012
(in thousands)
Bank-owned life insurance	$	967	$	979
Other	625		381
Total other income, net	$	1,592	$	1,360
FDIC insurance premium	$	840	$	853
Marketing	538		550
Office supplies, printing and postage	873		990
Communication	471		436
Reversal of interest expense-tax	—		(552		)
Other	4,873		4,430
Total other expense	$	7,595	$	6,707

See Note 4 of HEI’s “Notes to Consolidated Financial Statements” and “Economic conditions” in the “HEI Consolidated” section above.

Despite the revenue pressures across the banking industry, management expects ASB’s low-cost funding base and lower-risk profile to continue to deliver strong performance compared to industry peers.

For the quarter ended March 31, 2013, ASB reported a 1.12% annualized return on assets, net interest margin of 3.78% and a 61% efficiency ratio. For the year ended December 31, 2012, ASB reported a 1.18% return on assets, net interest margin of 3.93% and a 59% efficiency ratio.

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Average balance sheet and net interest margin.The following tables set forth average balances, together with interest earned and accrued, and resulting yields and costs:

Three months ended March 31	2013						2012
(dollars in thousands)	Average balance			Interest		Yield/ rate (%)	Average balance			Interest		Yield/ rate (%)
Assets:
Other investments (1)	$	198,202		$	64	0.13	$	251,615		$	97	0.15
Available-for-sale investment and mortgage-related securities	648,693			3,619		2.23	595,072			3,879		2.61
Loans(2)
Residential 1-4 family	1,882,185			23,356		4.96	1,909,675			25,610		5.36
Commercial real estate	421,492			4,633		4.42	385,916			4,586		4.76
Home equity line of credit	640,151			4,462		2.83	550,790			3,770		2.75
Residential land	25,009			256		4.09	41,868			555		5.30
Commercial loans	711,707			7,469		4.24	712,599			7,959		4.49
Consumer loans	123,648			2,427		7.94	95,220			2,408		10.17
Total loans (3)	3,804,192			42,603		4.50	3,696,068			44,888		4.87
Total interest-earning assets (4)	4,651,087			46,286		4.00	4,542,755			48,864		4.31
Allowance for loan losses	(42,608		)				(38,187		)
Non-interest-earning assets	434,117						432,600
Total assets	$	5,042,596					$	4,937,168
Liabilities and shareholder’s equity:
Savings	$	1,775,477		254		0.06	$	1,698,849		310		0.07
Interest-bearing checking	640,190			24		0.02	605,526			30		0.02
Money market	195,563			63		0.13	249,685			121		0.19
Time certificates	469,798			971		0.84	541,330			1,318		0.98
Total interest-bearing deposits	3,081,028			1,312		0.17	3,095,390			1,779		0.23
Advances from Federal Home Loan Bank	50,000			535		4.28	50,000			541		4.28
Securities sold under agreements to repurchase	147,296			629		1.71	187,326			720		1.52
Total interest-bearing liabilities	3,278,324			2,476		0.30	3,332,716			3,040		0.36
Non-interest bearing liabilities:
Deposits	1,151,572						1,000,099
Other	110,850						110,913
Total liabilities	4,540,746						4,443,728
Shareholder’s equity	501,850						493,440
Total liabilities and shareholder’s equity	$	5,042,596					$	4,937,168
Net interest income				$	43,810					$	45,824
Net interest margin (%) (5)						3.78						4.04

(1)Includes federal funds sold, interest bearing deposits and stock in the FHLB of Seattle.

(2)Includes loans held for sale.

(3)Includes loan fees of $1.5 million and $1.1 million for the three months ended March 31, 2013 and 2012, respectively, together with interest accrued prior to suspension of interest accrual on nonaccrual loans, includes nonaccrual loans.

(4)Interest income includes taxable equivalent basis adjustments, based upon a federal statutory tax rate of 35%, of $0.2 million and $0.2 million for the three months ended March 31, 2013 and 2012, respectively.

(5)Defined as net interest income as a percentage of average earning assets.

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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 interest rate environment has been impacted by disruptions in the financial markets and these conditions have continued to 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. The composition of ASB’s loan portfolio was as follows:

	March 31, 2013				December 31, 2012
(dollars in thousands)	Balance			% of total	Balance			% of total
Real estate loans:
Residential 1-4 family	$	1,915,207		49.7	$	1,866,450		49.2
Commercial real estate	391,679			10.2	375,677			9.9
Home equity line of credit	648,904			16.8	630,175			16.6
Residential land	23,894			0.6	25,815			0.7
Commercial construction	40,698			1.1	43,988			1.2
Residential construction	8,275			0.2	6,171			0.2
Total real estate loans, net	3,028,657			78.6	2,948,276			77.8
Commercial loans	699,918			18.1	721,349			19.0
Consumer loans	127,260			3.3	121,231			3.2
	3,855,835			100.0	3,790,856			100.0
Less: Deferred fees and discounts	(10,103		)		(11,638		)
Allowance for loan losses	(42,730		)		(41,985		)
Total loans, net	$	3,803,002			$	3,737,233

The increase in the total loan portfolio during the first quarter of 2013 was primarily due to an increase in originated ASB’s residential 1-4 family, home equity lines of credit and commercial real estate loan portfolios and is in line with ASB’s target of mid-single digit growth for the year.

Loan portfolio risk elements.See Note 4 of HEI’s “Notes to Consolidated Financial Statements.”

Investment and mortgage-related securities. ASB’s investment portfolio was comprised as follows:

	March 31, 2013				December 31,2012
(dollars in thousands)	Balance		% of total		Balance		% of total
Federal agency obligations	$	167,960	26	%	$	171,491	26	%
Mortgage-related securities — FNMA, FHLMC and GNMA	409,339		62		417,383		62
Municipal bonds	82,101		12		82,484		12
	$	659,400	100	%	$	671,358	100	%

Principal and interest on mortgage-related securities issued by Federal National Mortgage Association (FNMA), Federal Home Loan Mortgage Corporation (FHLMC) and Government National Mortgage Association (GNMA) are guaranteed by the issuer and, in the case of GNMA, backed by the full faith and credit of the U.S.

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. Advances from the FHLB of Seattle have remained at $50 million from December 31, 2012 to March 31, 2013. As of March 31, 2013 and December 31, 2012, ASB’s costing liabilities consisted of 96% deposits and 4% other borrowings. The weighted average cost of deposits for the first quarter of 2013 was 0.12%, compared to 0.17% for the first quarter of 2012.

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

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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 March 31, 2013 and December 31, 2012, ASB had unrealized gains, net of taxes, on available-for-sale investments and mortgage-related securities (including securities pledged for repurchase agreements) in AOCI of $10 million and $11 million, respectively. See “Item 3. Quantitative and qualitative disclosures about market risk.”

During the first quarter of 2013, ASB recorded a provision for loan losses of $1.9 million primarily due to charge-offs during the quarter for 1-4 family, residential land, commercial and consumer loans. During the first quarter of 2012, ASB recorded a provision for loan losses of $3.5 million primarily due to charge-offs during the quarter for 1-4 family, residential land, commercial and consumer loans. Continued financial stress on ASB’s customers may result in higher levels of delinquencies and losses.

	Three months ended March 31						Year ended December 31
(in thousands)	2013			2012			2012
Allowance for loan losses, January 1	$	41,985		$	37,906		$	37,906
Provision for loan losses	1,858			3,546			12,883
Less: net charge-offs	1,113			2,618			8,804
Allowance for loan losses, end of period	$	42,730		$	38,834		$	41,985
Ratio of allowance for loan losses, end of period, to end of period loans outstanding	1.11		%	1.05		%	1.11		%
Ratio of net charge-offs during the period to average loans outstanding (annualized)	0.12		%	0.28		%	0.24		%

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.”

Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act).  Regulation of the financial services industry, including regulation of HEI, ASHI 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, ASHI and ASB, under the Dodd-Frank Act, on July 21, 2011, all of the functions of the Office of Thrift Supervision transferred to the OCC, the FDIC, the Federal Reserve Board (FRB) and the Consumer Financial Protection Bureau (Bureau). Supervision and regulation of HEI and ASHI, as a thrift holding companies, 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, OCC and the Bureau. 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 closed 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

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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 closed for comment on February 25, 2013. For mortgages, under the proposed Ability-to-Repay rule, among other things, (i) potential borrowers will have to supply financial information, and lenders must verify it, (ii) to qualify for a particular loan, a consumer will have 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. 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. For the first quarter of 2013, ASB had earned an average of 49 cents per transaction. However, market pressures could cause all banks to observe the 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

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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.

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

FINANCIAL CONDITION

Liquidity and capital resources.

(dollars in millions)	March 31, 2013		December 31, 2012		% change
Total assets	$	5,116	$	5,042	1
Available-for-sale investment and mortgage-related securities	659		671		(2	)
Loans receivable held for investment, net	3,803		3,737		2
Deposit liabilities	4,313		4,230		2
Other bank borrowings	193		196		(1	)

As of March 31, 2013, ASB was one of Hawaii’s largest financial institutions based on assets of $5.1 billion and deposits of $4.3 billion.

As of March 31, 2013, ASB’s unused FHLB borrowing capacity was approximately $1.0 billion. As of March 31, 2013, ASB had commitments to borrowers for loan commitments and unused lines and letters of credit of $1.6 billion. Management believes ASB’s current sources of funds will enable it to meet these obligations while maintaining liquidity at satisfactory levels.

For the first quarter of 2013, net cash provided by ASB’s operating activities was $30 million. Net cash used during the same period by ASB’s investing activities was $56 million, primarily due to purchases of investment and mortgage-related securities of $27 million, a net increase in loans receivable of $67 million and additions to premises and equipment of $3 million, partly offset by repayments of investment and mortgage-related securities of $37 million and proceeds from the sale of real estate acquired in settlement of loans of $3 million. Net cash provided in financing activities during this period was $67 million, primarily due to net increases in deposit liabilities of $83 million, partly offset by a net decrease in retail repurchase agreements of $3 million, the payment of $10 million in common stock dividends to HEI (through ASHI) and a net decrease in mortgage escrow deposits of $3 million.

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 March 31, 2013, ASB was well-capitalized (minimum ratio requirements noted in parentheses) 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%). FRB approval is required before ASB can pay a dividend or otherwise make a capital distribution to HEI (through ASHI).

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

The Company considers interest-rate risk (a non-trading market risk) to be a very significant market risk for ASB as it could potentially have a significant effect on the Company’s results of operations, financial condition and liquidity. For additional quantitative and qualitative information about the Company’s market risks, see pages 82 to 84, HEI’s Quantitative and Qualitative Disclosures About Market Risk, in Part II, Item 7A of HEI’s 2012 Form 10-K and HECO’s Quantitative and Qualitative Disclosures About Market Risk, which is incorporated into Part II, Item 7A of HECO’s 2012 Form 10-K by reference to Exhibit 99.2.

ASB’s interest-rate risk sensitivity measures as of March 31, 2013 and December 31, 2012 constitute “forward-looking statements” and were as follows:

	Change in NII (gradual change in interest rates)				Change in EVE (instantaneous change in interest rates)
Change in interest rates (basis points)	March 31, 2013		December 31, 2012		March 31, 2013		December 31, 2012
+300	3.1	%	1.6	%	(4.7	)%	(9.4	)%
+200	1.5		0.5		(1.9	)	(4.9	)
+100	0.6		0.1		(0.5	)	(1.9	)
-100	(0.2	)	(0.2	)	(3.8	)	(1.7	)

Management believes that ASB’s interest rate risk position as of March 31, 2013 represents a reasonable level of risk. Net interest income (NII) sensitivity as of March 31, 2013 was more asset sensitive for increases in rates compared to December 31, 2012 due to changes in the mix of earning assets as more short-term interest earning assets were held as of March 31, 2013 compared to December 31, 2012 and changes in assumptions about the rate sensitivity of certain core deposits.

ASB’s base economic value of equity (EVE) increased to $833 million as of March 31, 2013 compared to $767 million as of December 31, 2012 due to changes in the assumptions about the behavior of core deposits.

The change in EVE was less sensitive to rising rate scenarios as of March 31, 2013 compared to December 31, 2012 due to growth and changes in the composition of the residential portfolio and changes in the assumptions about the behavior of 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, pre-tax 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.

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Item 4. Controls and Procedures

HEI:

Changes in Internal Control over Financial Reporting

During the first quarter of 2013, there were no changes in internal control over financial reporting identified in connection with management’s evaluation of the effectiveness of the Company’s internal control over financial reporting as of March 31, 2013 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

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 March 31, 2013. Based on their evaluations, as of March 31, 2013, 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) 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.

HECO:

Changes in Internal Control over Financial Reporting

During the first quarter of 2013, there were no changes in internal control over financial reporting identified in connection with management’s evaluation of the effectiveness of HECO and its subsidiaries’ internal control over financial reporting as of March 31, 2013 that has materially affected, or is reasonably likely to materially affect, HECO and its subsidiaries’ internal control over financial reporting.

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 March 31, 2013. Based on their evaluations, as of March 31, 2013, 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) 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.

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PART II - OTHER INFORMATION

Item 1. Legal Proceedings

The descriptions of legal proceedings (including judicial proceedings and proceedings before the PUC and environmental and other administrative agencies) in HEI’s Form 10-K (see “Part I. Item 3. Legal Proceedings” and proceedings referred to therein) and this 10-Q (see “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” Note 4 of HEI’s “Notes to Consolidated Financial Statements” and HECO’s “Notes to Consolidated Financial Statements”) are incorporated by reference in this Item 1. With regard to any pending legal proceeding, alternative dispute resolution, such as mediation or settlement, may be pursued where appropriate, with such efforts typically maintained in confidence unless and until a resolution is achieved. Certain HEI subsidiaries (including HECO and its subsidiaries and ASB) may also be involved in ordinary routine PUC proceedings, environmental proceedings and litigation incidental to their respective businesses.

Item 1A. Risk Factors

The following are updated risk factors for HEI, the electric utilities and ASB:

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 March 31, 2013) 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 of non-objection or prior approval from the OCC and FRB 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

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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 March 31, 2013, 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.

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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

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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, state and local environmental laws and regulations relating to air quality, water quality, hazardous substances, waste management, natural resources and health and safety, which regulate, among other matters, the operation of existing facilities, the construction and operation of new facilities and the proper cleanup and disposal of hazardous and toxic wastes and substances. HEI or its subsidiaries are currently involved in investigatory or remedial actions at current, former or third-party sites and there is no assurance that the Company will not incur material costs relating to these sites. In addition, compliance with these legal requirements requires HEI’s utility subsidiaries to commit significant resources and funds toward, among other things, 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 or the cessation of operations.

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

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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 $874 million as of March 31, 2013) 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 $326 million as of March 31, 2013) 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. 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. For example, HECO’s East Oahu Transmission Project

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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 to write off $40 million of costs in lieu of conducting PUC-ordered regulatory audits of the CIP CT-1 and the CIS projects.

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 electric utilities may be adversely affected by new legislation.  Congress, the Hawaii legislature and governmental agencies periodically consider legislation and other initiatives that could have uncertain or negative effects on the electric utilities and their customers. Congress, the Hawaii legislature and governmental agencies have adopted, or are considering adopting, a number of measures that will significantly affect the electric utilities, as described below.

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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 megawatthour (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 adopted by the PUC. 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 is 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 climate change have led to action by the state of Hawaii and the EPA 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. Environmental Protection Agency, 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 and report 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 and requires certain facilities to obtain PSD and Title V operating permits. 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 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

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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 48% of ASB’s loan portfolio as of March 31, 2013 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 degree to which compression of ASB’s margin will continue when interest rates rise is uncertain.

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 higher 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;

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·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 prompt corrective action regulations or capital distribution regulations if ASB’s capital position deteriorates. In order to maintain its status as a qualified thrift lender (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 HEI and 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

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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 or other conditions may result in loan losses and adversely affect the Company’s profitability.  As of March 31, 2013 approximately 79% 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, or any environmental clean-up obligation, 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.

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Item 5. Other Information

A.Ratio of earnings to fixed charges.

	Three months ended March 31		Years ended December 31
	2013	2012	2012	2011	2010	2009	2008
HEI and Subsidiaries
Excluding interest on ASB deposits	3.22	3.63	3.28	3.22	2.89	2.29	2.06
Including interest on ASB deposits	3.11	3.44	3.14	3.03	2.64	1.95	1.71
HECO and Subsidiaries	3.32	3.77	3.37	3.52	2.88	2.99	3.48

See HEI Exhibit 12.1 and HECO Exhibit 12.2.

B.Description of HEI’s Common Stock and Preferred Stock.

Under our Amended and Restated Articles of Incorporation (Articles), we are authorized to issue 200,000,000 shares of common stock without par value (common stock) and 10,000,000 shares of preferred stock without par value (preferred stock). As of March 19, 2013, 98,467,907 shares of common stock were issued and outstanding and no shares of preferred stock were designated, issued or outstanding.

The following is a description of the general terms and provisions of our capital stock and does not purport to be complete and is subject to and qualified in its entirety by reference to the Articles and the Bylaws.

Common stock

General. The outstanding shares of common stock, other than shares of restricted stock previously issued under HEI’s Stock Option and Incentive Plan of 1987 (as amended and restated) or issued from time to time under HEI’s 2010 Equity and Incentive Plan (as amended and restated) until such restrictions are satisfied, are fully paid and nonassessable. Additional shares of common stock, when issued pursuant to proper authorization, will be fully paid and nonassessable when the consideration for which HEI’s Board of Directors authorizes their issuance has been received by HEI. The holders of common stock have no preemptive rights and there are no applicable conversion, redemption or sinking fund provisions.

Common stock is transferable at the Shareholder Services Office of the Company, American Savings Bank Tower, 8th Floor, 1001 Bishop Street, Honolulu, Hawaii 96813, and at the office of Continental Stock Transfer & Trust Company, Co-Transfer Agent and Registrar, 17 Battery Place, New York, New York 10004. Shares of common stock may either be certificated or uncertificated.

Dividend Rights and Limitations. Stock and cash dividends may be issued and paid to the holders of common stock as and when declared by our Board of Directors, provided that, after giving effect to the payment of cash dividends, HEI is able to pay its debts as they become due in the usual course of its business and HEI’s total assets are not less than the sum of its total liabilities plus the maximum amount that then would be payable in any liquidation in respect of all outstanding shares having preferential rights in liquidation. All shares of common stock are entitled to participate equally with respect to dividends.

HEI is a legal entity separate and distinct from its various subsidiaries. As a holding company with no significant operations of its own, the principal sources of its funds are dividends or other distributions from its operating subsidiaries, borrowings and sales of equity. The ability of certain of HEI’s direct and indirect subsidiaries to pay dividends or make other distributions to HEI, or to make loans or extend credit to or purchase assets from HEI, is subject to contractual, statutory and regulatory restrictions, including without limitation the provisions of an agreement with the PUC (pertaining to HEI’s electric utility subsidiaries) and the minimum capital requirements imposed by law on ASB, as well as restrictions and limitations set forth in debt instruments, preferred stock resolutions and guarantees. HEI does not expect that the regulatory and contractual restrictions applicable to HEI or its direct or indirect subsidiaries will significantly affect HEI’s ability to pay dividends on its common stock. See “Business—HEI Consolidated—Regulation—Restrictions on dividends and other distributions” in HEI’s Annual Report on Form 10-K

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for the year ended December 31, 2012 for a more complete description of the ability of certain of HEI’s subsidiaries to pay dividends or make other distributions to HEI.

Liquidation Rights. In the event of any liquidation, dissolution, receivership, bankruptcy, disincorporation or winding-up of the affairs of HEI, voluntarily or involuntarily, holders of common stock are entitled to any assets of HEI available for distribution to HEI’s stockholders after the payment in full of any amounts owing to its creditors and any preferential amounts to which holders of any preferred stock may be entitled. All shares of common stock will rank equally in the event of liquidation.

Voting Rights. Holders of common stock are entitled to one vote per share, subject to such limitation or loss of right as may be provided in resolutions which may be adopted by the Board of Directors of HEI from time to time creating series of preferred stock or otherwise. The annual meeting of shareholders is held on the date and at the time designated by the Board of Directors, or, if it does not act, by the Chairman of the Board of Directors, or, in the Chairman’s absence or disability, by the President. A shareholder may bring business before the annual meeting only if the shareholder complies with the advance notice and other requirements specified in the Bylaws. A special meeting of shareholders can be called by the Board of Directors, the Chairman of the Board of Directors, the President or upon written demand of shareholders entitled under Hawaii law to make such a demand in the manner prescribed by Hawaii law and in accordance with the advance notice provisions in the Bylaws. At annual and special meetings of stockholders, the presence in person or by proxy of holders of a majority of the outstanding shares of common stock constitutes a quorum, the election of directors requires a plurality of votes cast at a meeting at which a quorum is present and any other action may be approved at a meeting where a quorum is present and due notification of the proposed action has been given if the votes cast in favor of the action exceed the votes cast opposing the action, except (a) as otherwise required by law, (b) as provided in the Articles, (c) as provided in the Bylaws (including with respect to the amendment of certain provisions of the Bylaws) and/or (d) as may be provided in resolutions that may be adopted from time to time creating series of preferred stock or otherwise.

Under the current Bylaws, the Board of Directors is to consist of not less than five nor more than eighteen members, with the Board of Directors having the authority to fix the exact number of directors so long as the number is not less than five nor more than eighteen. Nominations for election to the Board of Directors may be made only by or at the direction of the Board of Directors (or a duly authorized committee of the Board of Directors) or by a shareholder who meets the requirements specified in the Bylaws and complies with the advance notice provisions set forth in the Bylaws. So long as there are at least nine directors, one-third (as nearly as possible) of the total number of directors is elected at each annual meeting of stockholders and, under Hawaii law, no holder of common stock is entitled to cumulate votes in an election of directors so long as HEI shall have a class of equity securities registered pursuant to the Exchange Act that is listed on a national securities exchange or traded over-the-counter on the National Market System of the National Association of Securities Dealers, Inc. Automated Quotation System. Under the Bylaws, directors may be removed from office at a special meeting of shareholders properly called for that purpose.

Subject to compliance with any applicable advance notice provisions, the Bylaws may be amended by the affirmative vote of a majority of the entire Board of Directors, or at the annual meeting of shareholders or a special meeting of shareholders called for that purpose by the affirmative vote of a majority of shares represented and entitled to vote at such meeting, except that any provision of the Bylaws for which a greater vote is required by the Articles, the Bylaws or by law may itself be amended only by such greater vote. In addition, an amendment to the provisions in the Bylaws relating to (1) matters which may be properly brought before an annual meeting, (2) who may call a special meeting and matters which may be brought before a special meeting, (3) cumulative voting, (4) the number, the manner of fixing the number and the staggered terms of members of the Board of Directors, (5) removal of directors and (6) restricting the amendment of certain provisions of the Bylaws must in each case be approved either (a) by the affirmative vote of 80% of the shares entitled to vote generally with respect to the election of directors voting together as a single class or (b) by the affirmative vote of a majority of the entire Board of Directors plus a concurring vote of a majority of the “continuing directors” (as that term is defined in the Bylaws) voting separately and as a subclass of directors.

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The provisions of HEI’s Bylaws referred to in the foregoing two paragraphs, and the statutory provisions referred to below, may have the effect of delaying, deferring or preventing a change in control of HEI.

Preferred stock

Preferred stock may be authorized by the Board of Directors for issuance in one or more series, without action by stockholders and with such preferences, voting powers, restrictions and qualifications as may be fixed by resolution of the Board of Directors authorizing the issuance of those shares. Under current Hawaii law, all shares of a series of preferred stock must have preferences, limitations and relative rights identical with those of other shares of the same series and, except to the extent otherwise provided in the description of the series, with those of other series in the same class. Under the current Articles, there is no restriction on the repurchase or redemption of shares of preferred stock at a time when there is an arrearage in the payment of dividends or sinking fund installments.

If and when authorized by the Board of Directors, preferred stock may be preferred as to dividends or in liquidation, or both, over the common stock. For example, the terms of the preferred stock, if and when authorized, could prohibit dividends on shares of common stock until all dividends and any mandatory redemptions have been paid with respect to shares of preferred stock. In addition, the Board of Directors may, without stockholder approval, issue preferred stock with voting and conversion rights which could adversely affect the voting power or economic rights of the holders of common stock. Issuance of preferred stock by HEI could thus have the effect of delaying, deferring or preventing a change of control of HEI.

Restriction on purchases of shares and consequences of substantial holdings under certain Hawaii and federal laws

Provisions of Hawaii and federal law, some of which are described below, place restrictions on the acquisition of beneficial ownership of 5% or more of the voting power of HEI. The following does not purport to be a complete enumeration of all of these provisions, nor does it purport to be a complete description of the statutory provisions that are enumerated. Persons contemplating the acquisition of 5% or more of the issued and outstanding shares of HEI’s common stock should consult with their legal and financial advisors concerning statutory and other restrictions on such acquisitions.

The Hawaii Control Share Acquisition Act places restrictions on the acquisition of ranges of voting power (starting at 10% and at 10% intervals up to a majority) for the election of directors of HEI unless the acquiring person obtains approval of the acquisition, in the manner specified in the Hawaii Control Share Acquisition Act, by the affirmative vote of the holders of a majority of the voting power of all shares entitled to vote, exclusive of the shares beneficially owned by the acquiring person, and consummates the proposed control share acquisition within 180 days after shareholder approval. If such approval is not obtained, the statute provides that the shares acquired may not be voted for a period of one year from the date of acquisition, the shares will be nontransferable on HEI’s books for one year after acquisition and HEI, during the one-year period, has the right to call the shares for redemption either at the prices at which the shares were acquired or at book value per share as of the last day of the fiscal quarter ended prior to the date of the call for redemption.

Under provisions of the Hawaii Business Corporation Act, subject to certain exceptions, HEI may not be a party to a merger or consolidation unless the merger or consolidation is approved by the holders of at least 75% of all of the issued and outstanding voting stock of HEI.

Under provisions of Hawaii law regulating public utilities, not more than 25% of the issued and outstanding voting stock of certain public utility corporations, including HECO and its wholly-owned electric utility subsidiaries, may be held, directly or indirectly, by any single foreign corporation or any single nonresident alien, or held by any person, without the prior approval of the PUC. The acquisition of more than 25% of the issued and outstanding voting stock of HEI in one or more transactions might be deemed to result in the holding of more than 25% of the voting stock of its electric utility subsidiaries. In addition, HEI is subject to an agreement entered into with the PUC when HECO became a wholly-owned subsidiary of HEI. This agreement provides that the acquisition of HEI by a third party, whether by purchase, merger, consolidation or otherwise, requires the prior written approval of the PUC.

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Federal law restricts acquisitions of a federal savings bank and any entity considered to be its holding company by establishing thresholds of “control” the acquisition of which requires prior regulatory approval and by limiting the types of persons and entities eligible to acquire such control. The primary federal banking regulator of ASB historically was the Office of Thrift Supervision (OTS), but the OTS was abolished on July 21, 2011 and its supervisory and regulatory functions have been transferred to the OCC. As a result of HEI’s indirect ownership of ASB, both HEI and ASHI, the direct parent corporation of ASB, are also subject to a certain degree of regulation as “unitary savings and loan holding companies” (i.e., companies which control one savings association). The supervision and regulation of HEI and ASHI have been moved to the FRB effective July 21, 2011. Since 1999, companies that engage in activities not permitted to financial services companies under federal law are not permitted to acquire control, directly or indirectly, of a savings institution. Nonfinancial companies that owned savings institutions prior to May 4, 1999, such as HEI and ASHI, however, are considered “grandfathered” so that HEI and its subsidiaries are able to continue to engage in their current activities and retain ownership of ASB. The effect of this prohibition therefore is that any acquisition of HEI by a third party is likely to require HEI to divest ASB or its assets and liabilities. The divestiture would be required to occur within a two year period following the FRB’s approval of the acquisition of HEI. Federal law also limits the entities eligible to acquire ASB or its assets and liabilities generally to those that engage in activities permissible to bank and financial holding companies under the Bank Holding Company Act.

The thresholds of “control” which will trigger the need for notice to the FRB and, in certain instances, prior FRB approval are set forth in federal statutes and FRB regulations. Generally, no existing savings and loan holding company may acquire direct or indirect ownership or control of more than 5% of the outstanding voting stock of a federal savings bank or its holding company without the prior written approval of the FRB. In addition, no other company or person may acquire control of a federal savings bank or savings and loan holding company, unless the FRB provides prior written approval. “Control” in this context means (i) the acquisition of, control of, or holding proxies representing, more than 25% of the voting shares of HEI or (ii) the power to control in any manner the election of a majority of the directors of HEI or (iii) the power, directly or indirectly, to exercise a controlling influence over the management or policies of HEI. A person that contributes more than 25% of the capital of HEI would also be deemed to control HEI. Moreover, under FRB regulations, one would be presumed to have acquired control if one acquires 10% or more of the voting shares of HEI or, in some circumstances, more than 5% of such voting shares. Any company subject to a preliminary determination of control by the FRB because it triggered a control presumption or was deemed to have the power to exercise a controlling influence over HEI may contest the determination and request a hearing, may file an application to retain the control relationship or may propose a plan to the FRB for prompt termination of the control relationship. The FRB may also deem acquisitions of less than 25% of the voting shares of HEI to be passive and noncontrolling, on the condition that the investor enter into certain passivity commitments with the FRB.

Dividend reinvestment and stock purchase plan

Any individual of legal age or entity is eligible to participate in the HEI Dividend Reinvestment and Stock Purchase Plan by making an initial cash investment in common stock, subject to applicable laws and regulations and the requirements of the plan. Holders of common stock, and holders of preferred stock of HEI’s electric utility subsidiaries, may automatically reinvest some or all of their dividends to purchase additional shares of common stock at market prices (as defined in the plan). Participants in the plan may also purchase additional shares of common stock at market prices (as defined in the plan) by making cash contributions to the plan. HEI reserves the right to suspend, modify or terminate the plan at any time. Shares of common stock issued under the plan may either be newly issued shares or shares purchased by the plan on the open market. Participants do not pay brokerage commissions or service charges in connection with purchases of newly issued shares, but do pay their pro rata share of brokerage commissions if the plan purchases shares for participants on the open market.

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Item 6. Exhibits

HEI Exhibit 12.1	Hawaiian Electric Industries, Inc. and Subsidiaries Computation of ratio of earnings to fixed charges, three months ended March 31, 2013 and 2012 and years ended December 31, 2012, 2011, 2010, 2009 and 2008
HEI Exhibit 31.1	Certification Pursuant to Rule 13a-14 promulgated under the Securities Exchange Act of 1934 of Constance H. Lau (HEI Chief Executive Officer)
HEI Exhibit 31.2	Certification Pursuant to Rule 13a-14 promulgated under the Securities Exchange Act of 1934 of James A. Ajello (HEI Chief Financial Officer)
HEI Exhibit 32.1	HEI Certification Pursuant to 18 U.S.C. Section 1350
HEI Exhibit 101.INS	XBRL Instance Document
HEI Exhibit 101.SCH	XBRL Taxonomy Extension Schema Document
HEI Exhibit 101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
HEI Exhibit 101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
HEI Exhibit 101.LAB	XBRL Taxonomy Extension Label Linkbase Document
HEI Exhibit 101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document
HECO Exhibit 12.2	Hawaiian Electric Company, Inc. and Subsidiaries Computation of ratio of earnings to fixed charges, three months ended March 31, 2013 and 2012 and years ended December 31, 2012, 2011, 2010, 2009 and 2008
HECO Exhibit 31.3	Certification Pursuant to Rule 13a-14 promulgated under the Securities Exchange Act of 1934 of Richard M. Rosenblum (HECO Chief Executive Officer)
HECO Exhibit 31.4	Certification Pursuant to Rule 13a-14 promulgated under the Securities Exchange Act of 1934 of Tayne S. Y. Sekimura (HECO Chief Financial Officer)
HECO Exhibit 32.2	HECO Certification Pursuant to 18 U.S.C. Section 1350

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SIGNATURES

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

HAWAIIAN ELECTRIC INDUSTRIES, INC.		HAWAIIAN ELECTRIC COMPANY, INC.
(Registrant)		(Registrant)
By	/s/ Constance H. Lau	By	/s/ Richard M. Rosenblum
	Constance H. Lau		Richard M. Rosenblum
	President and Chief Executive Officer		President and Chief Executive Officer
	(Principal Executive Officer of HEI)		(Principal Executive Officer of HECO)
By	/s/ James A. Ajello	By	/s/ Tayne S. Y. Sekimura
	James A. Ajello		Tayne S. Y. Sekimura
	Executive Vice President,		Senior Vice President
	Chief Financial Officer and Treasurer		and Chief Financial Officer
	(Principal Financial Officer of HEI)		(Principal Financial Officer of HECO)
By	/s/ Jennifer B. Loo	By	/s/ Cathlynn L. Yoshida
	Jennifer B. Loo		Cathlynn L. Yoshida
	Interim Chief Accounting Officer		Controller
	and Assistant Controller		(Principal Accounting Officer of HECO)
	(Principal Accounting Officer of HEI)
Date:  May 8, 2013		Date:  May 8, 2013

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