Hawaiian Electric Company, Inc. PFD SER D 5% (HAWEM) 10-Q 2012 Q1 Quarterly report

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, 2012

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)

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

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

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

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

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

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

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, 2012
Hawaiian Electric Industries, Inc. (Without Par Value)	96,602,192 Shares
Hawaiian Electric Company, Inc. ($6-2/3 Par Value)	14,233,723 Shares (not publicly traded)

Indicate by check mark whether Registrant Hawaiian Electric Industries, Inc. is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer  x	Accelerated filer  o
Non-accelerated filer  o	Smaller reporting company  o
(Do not check if a smaller reporting company)

Indicate by check mark whether Registrant Hawaiian Electric Company, Inc. is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer  o	Accelerated filer  o
Non-accelerated filer  x	Smaller reporting company  o
(Do not check if a smaller reporting company)

Hawaiian Electric Industries, Inc. and Subsidiaries

Hawaiian Electric Company, Inc. and Subsidiaries

Form 10-Q—Quarter ended March 31, 2012

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, 2012 and 2011
2		Statements of Consolidated Comprehensive Income - three months ended March 31, 2012 and 2011
3		Consolidated Balance Sheets - March 31, 2012 and December 31, 2011
4		Consolidated Statements of Changes in Shareholders’ Equity - three months ended March 31, 2012 and 2011
5		Consolidated Statements of Cash Flows - three months ended March 31, 2012 and 2011
6		Notes to Consolidated Financial Statements
		Hawaiian Electric Company, Inc. and Subsidiaries
24		Consolidated Statements of Income - three months ended March 31, 2012 and 2011
24		Statements of Consolidated Comprehensive Income - three months ended March 31, 2012 and 2011
25		Consolidated Balance Sheets - March 31, 2012 and December 31, 2011
26		Consolidated Statements of Changes in Common Stock Equity - three months ended March 31, 2012 and 2011
27		Consolidated Statements of Cash Flows - three months ended March 31, 2012 and 2011
28		Notes to Consolidated Financial Statements
46	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
46		HEI Consolidated
50		Electric Utilities
59		Bank
64	Item 3.	Quantitative and Qualitative Disclosures About Market Risk
65	Item 4.	Controls and Procedures
	PART II. OTHER INFORMATION
66	Item 1.	Legal Proceedings
66	Item 1A.	Risk Factors
66	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds
66	Item 5.	Other Information
67	Item 6.	Exhibits
68	Signatures

i

Hawaiian Electric Industries, Inc. and Subsidiaries

Hawaiian Electric Company, Inc. and Subsidiaries

Form 10-Q—Quarter ended March 31, 2012

GLOSSARY OF TERMS

Terms	Definitions
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
DG	Distributed generation
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
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
FSS	Forward Starting Swaps

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.
KWH	Kilowatthour
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
OCC	Office of the Comptroller of the Currency
O&M	Other operation and maintenance
OPEB	Postretirement benefits other than pensions
OTS	Office of Thrift Supervision, Department of Treasury
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, the implications and potential impacts of U.S. and foreign capital and credit market conditions and federal and state responses to those conditions, and the potential impacts of global developments (including unrest, conflict and the overthrow of governmental regimes in North Africa and the Middle East, terrorist acts, the war on terrorism, continuing U.S. presence in Afghanistan and potential conflict or crisis with North Korea or Iran);

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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	2012			2011
(in thousands, except per share amounts)
Revenues
Electric utility	$	749,610		$	645,335
Bank	65,252			65,313
Other	(2		)	(15		)
Total revenues	814,860			710,633
Expenses
Electric utility	692,356			600,127
Bank	42,340			43,559
Other	4,348			3,572
Total expenses	739,044			647,258
Operating income (loss)
Electric utility	57,254			45,208
Bank	22,912			21,754
Other	(4,350		)	(3,587		)
Total operating income	75,816			63,375
Interest expense—other than on deposit liabilities and other bank borrowings	(18,539		)	(20,140		)
Allowance for borrowed funds used during construction	870			520
Allowance for equity funds used during construction	1,940			1,244
Income before income taxes	60,087			44,999
Income taxes	21,298			16,064
Net income	38,789			28,935
Preferred stock dividends of subsidiaries	473			473
Net income for common stock	$	38,316		$	28,462
Basic earnings per common share	$	0.40		$	0.30
Diluted earnings per common share	$	0.40		$	0.30
Dividends per common share	$	0.31		$	0.31
Weighted-average number of common shares outstanding	96,167			94,817
Dilutive effect of share-based compensation	394			365
Adjusted weighted-average shares	96,561			95,182

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

1

Hawaiian Electric Industries, Inc. and Subsidiaries

Statements of Consolidated Comprehensive Income (unaudited)

Three months ended March 31
(in thousands)			2012					2011
Net income for common stock			$	38,316				$	28,462
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 $149 and $414 for the three months ended March 31, 2012 and 2011, respectively			(226		)			(626		)
Derivatives qualified as cash flow hedges:
Net unrealized holding losses arising during the period, net of tax benefits of $6 for the three months ended March 31, 2011	—					(9	)
Less: reclassification adjustment to net income, net of tax benefits of $37 and $3 for the three months ended March 31, 2012 and 2011, respectively	59		59			5		(4		)
Retirement benefit plans:
Less: amortization of net loss, prior service gain and transition obligation included in net periodic benefit cost, net of tax benefits of $2,473 and $631 for the three months ended March 31, 2012 and 2011, respectively	3,873					1,039
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes of $2,162 and $1,431 for the three months ended March 31, 2012 and 2011, respectively	(3,395	)	478			(2,247	)	(1,208		)
Other comprehensive income (loss), net of taxes			311					(1,838		)
Comprehensive income attributable to common shareholders			$	38,627				$	26,624

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, 2012			December 31, 2011
Assets
Cash and cash equivalents	$	236,346		$	270,265
Accounts receivable and unbilled revenues, net	306,760			344,322
Available-for-sale investment and mortgage-related securities	631,063			624,331
Investment in stock of Federal Home Loan Bank of Seattle	97,764			97,764
Loans receivable held for investment, net	3,672,401			3,642,818
Loans held for sale, at lower of cost or fair value	14,657			9,601
Property, plant and equipment, net of accumulated depreciation of $2,061,649 in 2012 and $2,049,821 in 2011	3,375,654			3,334,501
Regulatory assets	677,674			669,389
Other	538,443			517,550
Goodwill	82,190			82,190
Total assets	$	9,632,952		$	9,592,731
Liabilities and shareholders’ equity
Liabilities
Accounts payable	$	183,733		$	216,176
Interest and dividends payable	23,778			25,041
Deposit liabilities	4,125,204			4,070,032
Short-term borrowings—other than bank	156,288			68,821
Other bank borrowings	232,843			233,229
Long-term debt, net—other than bank	1,282,602			1,340,070
Deferred income taxes	375,510			354,051
Regulatory liabilities	316,560			315,466
Contributions in aid of construction	378,039			356,203
Retirement benefits liability	513,187			530,410
Other	456,817			516,990
Total liabilities	8,044,561			8,026,489
Preferred stock of subsidiaries - not subject to mandatory redemption	34,293			34,293
Commitments and contingencies (Notes 3 and 4)
Shareholders’ equity
Preferred stock, no par value, authorized 10,000,000 shares; issued: none	—			—
Common stock, no par value, authorized 200,000,000 shares; issued and outstanding: 96,541,143 shares in 2012 and 96,038,328 shares in 2011	1,362,880			1,349,446
Retained earnings	210,044			201,640
Accumulated other comprehensive loss, net of tax benefits	(18,826		)	(19,137		)
Total shareholders’ equity	1,554,098			1,531,949
Total liabilities and shareholders’ equity	$	9,632,952		$	9,592,731

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			Income (loss)			Total
Balance, December 31, 2011	96,038	$	1,349,446	$	201,640		$	(19,137	)	$	1,531,949
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	$	210,044		$	(18,826	)	$	1,554,098
Balance, December 31, 2010	94,691	$	1,314,199	$	181,910		$	(12,472	)	$	1,483,637
Net income for common stock	—	—		28,462			—			28,462
Other comprehensive loss, net of tax benefits	—	—		—			(1,838		)	(1,838		)
Issuance of common stock, net	598	15,702		—			—			15,702
Common stock dividends ($0.31 per share)	—	—		(29,412		)	—			(29,412		)
Balance, March 31, 2011	95,289	$	1,329,901	$	180,960		$	(14,310	)	$	1,496,551

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 (in thousands)	2012			2011
Cash flows from operating activities
Net income	$	38,789		$	28,935
Adjustments to reconcile net income to net cash used in operating activities
Depreciation of property, plant and equipment	37,911			37,708
Other amortization	1,419			2,354
Provision for loan losses	3,546			4,550
Loans receivable originated and purchased, held for sale	(89,087		)	(35,015		)
Proceeds from sale of loans receivable, held for sale	85,252			43,048
Change in deferred income taxes	21,260			16,687
Change in excess tax benefits from share-based payment arrangements	(44		)	(22		)
Allowance for equity funds used during construction	(1,940		)	(1,244		)
Change in cash overdraft	—			(2,688		)
Changes in assets and liabilities
Decrease (increase) in accounts receivable and unbilled revenues, net	37,562			(19,880		)
Increase in fuel oil stock	(14,458		)	(3,513		)
Decrease in accounts, interest and dividends payable	(36,991		)	(41,136		)
Change in prepaid and accrued income taxes and utility revenue taxes	(41,126		)	(1,594		)
Contributions to defined benefit pension and other postretirement benefit plans	(26,815		)	(31,200		)
Change in other assets and liabilities	(30,994		)	(10,224		)
Net cash used in operating activities	(15,716		)	(13,234		)
Cash flows from investing activities
Available-for-sale investment and mortgage-related securities purchased	(53,931		)	(109,307		)
Principal repayments on available-for-sale investment and mortgage-related securities	46,355			114,529
Net increase in loans held for investment	(34,212		)	(70,269		)
Proceeds from sale of real estate acquired in settlement of loans	3,371			1,253
Capital expenditures	(65,300		)	(38,491		)
Contributions in aid of construction	22,855			5,749
Other	—			145
Net cash used in investing activities	(80,862		)	(96,391		)
Cash flows from financing activities
Net increase in deposit liabilities	55,172			59,883
Net increase (decrease) in short-term borrowings with original maturities of three months or less	87,467			(24,923		)
Net increase (decrease) in retail repurchase agreements	(379		)	7,368
Proceeds from issuance of long-term debt	—			125,000
Repayment of long-term debt	(57,500		)	(50,000		)
Change in excess tax benefits from share-based payment arrangements	44			22
Net proceeds from issuance of common stock	5,940			5,674
Common stock dividends	(23,855		)	(23,593		)
Preferred stock dividends of subsidiaries	(473		)	(473		)
Other	(3,757		)	(3,730		)
Net cash provided by financing activities	62,659			95,228
Net decrease in cash and cash equivalents	(33,919		)	(14,397		)
Cash and cash equivalents, beginning of period	270,265			330,651
Cash and cash equivalents, end of period	$	236,346		$	316,254

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 included in HEI’s Form 10-K for the year ended December 31, 2011.

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, 2012 and December 31, 2011 and the results of its operations and cash flows for the three months ended March 31, 2012 and 2011. 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, 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
Tangible assets (at March 31, 2012)	4,656,064		4,880,927		13,771			9,550,762
Three months ended March 31, 2011
Revenues from external customers	$	645,299	$	65,313	$	21		$	710,633
Intersegment revenues (eliminations)	36		—		(36		)	—
Revenues	645,335		65,313		(15		)	710,633
Income (loss) before income taxes	31,267		21,727		(7,995		)	44,999
Income taxes (benefit)	11,579		7,876		(3,391		)	16,064
Net income (loss)	19,688		13,851		(4,604		)	28,935
Preferred stock dividends of subsidiaries	499		—		(26		)	473
Net income (loss) for common stock	19,189		13,851		(4,578		)	28,462
Tangible assets (at December 31, 2011)	4,671,942		4,827,784		10,815			9,510,541

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.

7

3 · Electric utility subsidiary

For consolidated HECO financial information, including its commitments and contingencies, see HECO’s consolidated financial statements beginning on page 24 through Note 10 on pages 37 and 38.

4 · Bank subsidiary

Selected financial information

American Savings Bank, F.S.B.

Statements of Income Data

Three months ended March 31
(in thousands)	2012			2011
Interest income
Interest and fees on loans	$	44,888		$	46,097
Interest on investment and mortgage-related securities	3,805			3,769
Total interest income	48,693			49,866
Interest expense
Interest on deposit liabilities	1,779			2,593
Interest on other borrowings	1,261			1,367
Total interest expense	3,040			3,960
Net interest income	45,653			45,906
Provision for loan losses	3,546			4,550
Net interest income after provision for loan losses	42,107			41,356
Noninterest income
Fees from other financial services	7,337			6,946
Fee income on deposit liabilities	4,278			4,449
Fee income on other financial products	1,549			1,673
Other income	3,395			2,379
Total noninterest income	16,559			15,447
Noninterest expense
Compensation and employee benefits	18,646			17,505
Occupancy	4,225			4,240
Data processing	2,111			1,970
Services	1,783			1,771
Equipment	1,730			1,657
Other expense	6,707			7,933
Total noninterest expense	35,202			35,076
Income before income taxes	23,464			21,727
Income taxes	7,587			7,876
Net income	$	15,877		$	13,851
American Savings Bank, F.S.B.
Statements of Comprehensive Income Data
Three months ended March 31
(in thousands)	2012			2011
Net income	$	15,877		$	13,851
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 $149 and $414 for the three months ended March 31, 2012 and 2011, respectively	(226		)	(626		)
Retirement benefit plans:
Less: amortization of net loss, prior service gain and transition obligation included in net periodic benefit cost, net of taxes (tax benefits) of $(164) and $1,082 for the three months ended March 31, 2012 and 2011, respectively	248			(1,639		)
Other comprehensive income (loss), net of taxes	22			(2,265		)
Comprehensive net income	$	15,899		$	11,586

8

American Savings Bank, F.S.B.

Balance Sheets Data

(in thousands)	March 31, 2012			December 31, 2011
Assets
Cash and cash equivalents	$	229,635		$	219,678
Available-for-sale investment and mortgage-related securities	631,063			624,331
Investment in stock of Federal Home Loan Bank of Seattle	97,764			97,764
Loans receivable held for investment, net	3,672,401			3,642,818
Loans held for sale, at lower of cost or fair value	14,657			9,601
Other	235,407			233,592
Goodwill	82,190			82,190
Total assets	$	4,963,117		$	4,909,974
Liabilities and shareholder’s equity
Deposit liabilities—noninterest-bearing	$	1,054,512		$	993,828
Deposit liabilities—interest-bearing	3,070,692			3,076,204
Other borrowings	232,843			233,229
Other	110,117			118,078
Total liabilities	4,468,164			4,421,339
Commitments and contingencies (see “Litigation” below)
Common stock	332,299			331,880
Retained earnings	172,003			166,126
Accumulated other comprehensive loss, net of tax benefits	(9,349		)	(9,371		)
Total shareholder’s equity	494,953			488,635
Total liabilities and shareholder’s equity	$	4,963,117		$	4,909,974
Other assets
Bank-owned life insurance	$	122,631		$	121,470
Premises and equipment, net	53,217			52,940
Prepaid expenses	15,957			15,297
Accrued interest receivable	14,186			14,190
Mortgage-servicing rights	8,582			8,227
Real estate acquired in settlement of loans, net	6,091			7,260
Other	14,743			14,208
	$	235,407		$	233,592
Other liabilities
Accrued expenses	$	12,124		$	21,216
Federal and state income taxes payable	42,598			35,002
Cashier’s checks	22,410			22,802
Advance payments by borrowers	6,464			10,100
Other	26,521			28,958
	$	110,117		$	118,078

Other borrowings consisted of securities sold under agreements to repurchase and advances from the Federal Home Loan Bank (FHLB) of Seattle of $183 million and $50 million, respectively, as of March 31, 2012 and December 31, 2011.

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.

As of March 31, 2012, ASB had total commitments to borrowers for loan commitments and unused lines and letters of credit of $1.4 billion, including $3 million to lend additional funds to borrowers whose loan terms have been modified in troubled debt restructurings (TDRs).

9

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
(dollars in thousands)	cost		gains		losses			value		Fair value		Amount			Fair value		Amount
March 31, 2012
Federal agency obligations	$	208,267	$	2,344	$	(71	)	$	210,540	$	19,870	$	(71	)	$	—	$	—
Mortgage-related securities- FNMA, FHLMC and GNMA	347,824		10,823		(61		)	358,586		10,012		(61		)	—		—
Municipal bonds	58,935		3,034		(32		)	61,937		3,638		(32		)	—		—
	$	615,026	$	16,201	$	(164	)	$	631,063	$	33,520	$	(164	)	$	—	$	—
December 31, 2011
Federal agency obligations	$	218,342	$	2,393	$	(8	)	$	220,727	$	19,992	$	(8	)	$	—	$	—
Mortgage-related securities- FNMA, FHLMC and GNMA	334,183		10,699		(17		)	344,865		11,994		(17		)	—		—
Municipal bonds	55,393		3,346		—			58,739		—		—			—		—
	$	607,918	$	16,438	$	(25	)	$	624,331	$	31,986	$	(25	)	$	—	$	—

The unrealized losses on ASB’s investments in 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 bases of the investments. Because ASB does 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 bases, which may be at maturity, ASB did not consider these investments to be other-than-temporarily impaired at March 31, 2012.

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 may have the right to call or prepay obligations with or without call or prepayment penalties.

March 31, 2012
(in thousands)	Amortized cost		Fair value
Due in one year or less	$	—	$	—
Due after one year through five years	189,439		191,371
Due after five years through ten years	66,828		69,705
Due after ten years	10,935		11,401
	267,202		272,477
Mortgage-related securities-FNMA,FHLMC and GNMA	347,824		358,586
Total available-for-sale securities	$	615,026	$	631,063

10

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 was comprised of the following:

	Residential			Commercial real		Home equity line			Residential			Commercial		Residential			Commercial			Consumer
(in thousands)	1-4 family			estate		of credit			land			construction		construction			loans			loans			Unallocated		Total
March 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	(600		)	—		—			(856		)	—		—			(1,359		)	(676		)	—		(3,491		)
Recoveries	489			—		8			74			—		—			196			106			—		873
Provision	330			79		397			493			265		1			871			514			596		3,546
Ending balance	$	6,719		$	1,767	$	4,759		$	3,506		$	2,153	$	5		$	14,575		$	3,750		$	1,600	$	38,834
Ending balance: individually evaluated for impairment	$	218		$	—	$	—		$	2,322		$	—	$	—		$	551		$	—		$	—	$	3,091
Ending balance: collectively evaluated for impairment	$	6,501		$	1,767	$	4,759		$	1,184		$	2,153	$	5		$	14,024		$	3,750		$	1,600	$	35,743
Financing Receivables:
Ending balance	$	1,895,442		$	351,716	$	562,386		$	39,025		$	47,850	$	3,082		$	727,292		$	97,262		$	—	$	3,724,055
Ending balance: individually evaluated for impairment	$	26,988		$	13,336	$	1,371		$	34,361		$	—	$	—		$	46,363		$	23		$	—	$	122,442
Ending balance: collectively evaluated for impairment	$	1,868,454		$	338,380	$	561,015		$	4,664		$	47,850	$	3,082		$	680,929		$	97,239		$	—	$	3,601,613
December 31, 2011
Allowance for loan losses:
Beginning balance	$	6,497		$	1,474	$	4,269		$	6,411		$	1,714	$	7		$	16,015		$	3,325		$	934	$	40,646
Charge-offs	(5,528		)	—		(1,439		)	(4,071		)	—		—			(5,335		)	(3,117		)	—		(19,490		)
Recoveries	110			—		25			170			—		—			869			567			—		1,741
Provision	5,421			214		1,499			1,285			174		(3		)	3,318			3,031			70		15,009
Ending balance	$	6,500		$	1,688	$	4,354		$	3,795		$	1,888	$	4		$	14,867		$	3,806		$	1,004	$	37,906
Ending balance: individually evaluated for impairment	$	203		$	—	$	—		$	2,525		$	—	$	—		$	976		$	—		$	—	$	3,704
Ending balance: collectively evaluated for impairment	$	6,297		$	1,688	$	4,354		$	1,270		$	1,888	$	4		$	13,891		$	3,806		$	1,004	$	34,202
Financing Receivables:
Ending balance	$	1,926,774		$	331,931	$	535,481		$	45,392		$	41,950	$	3,327		$	716,427		$	93,253		$	—	$	3,694,535
Ending balance: individually evaluated for impairment	$	26,012		$	13,397	$	1,450		$	39,364		$	—	$	—		$	48,241		$	24		$	—	$	128,488
Ending balance: collectively evaluated for impairment	$	1,900,762		$	318,534	$	534,031		$	6,028		$	41,950	$	3,327		$	668,186		$	93,229		$	—	$	3,566,047

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 ten-point risk rating system is used to determine loan grade and is based on borrower loan risk. The risk rating is a numerical representation of risk based on the overall assessment of the borrower’s financial and operating strength including earnings, operating cash flow, debt service capacity, asset and liability structure, competitive issues, experience and quality of management, financial reporting quality and industry/economic factors.

The loan grade categories are:

1- Substantially risk free	6- Acceptable risk
2- Minimal risk	7- Special mention
3- Modest risk	8- Substandard
4- Better than average risk	9- Doubtful
5- Average risk	10- Loss

11

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, 2012						December 31, 2011
(in thousands)	Commercial real estate		Commercial construction		Commercial		Commercial real estate		Commercial construction		Commercial
Grade:
Pass	$	325,360	$	47,850	$	657,235	$	308,843	$	41,950	$	650,234
Special mention	11,931		—		19,703		8,594		—		14,660
Substandard	10,989		—		43,733		11,058		—		47,607
Doubtful	3,436		—		6,621		3,436		—		3,926
Loss	—		—		—		—		—		—
Total	$	351,716	$	47,850	$	727,292	$	331,931	$	41,950	$	716,427

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, 2012
Real estate loans:
Residential 1-4 family	$	8,111	$	6,236	$	29,575	$	43,922	$	1,851,520	$	1,895,442	$	—
Commercial real estate	3,955		—		3,436		7,391		344,325		351,716		—
Home equity line of credit	1,007		545		1,816		3,368		559,018		562,386		—
Residential land	261		24		10,777		11,062		27,963		39,025		—
Commercial construction	—		—		—		—		47,850		47,850		—
Residential construction	—		—		—		—		3,082		3,082		—
Commercial loans	1,410		4,815		4,476		10,701		716,591		727,292		52
Consumer loans	642		298		456		1,396		95,866		97,262		310
Total loans	$	15,386	$	11,918	$	50,536	$	77,840	$	3,646,215	$	3,724,055	$	362
December 31, 2011
Real estate loans:
Residential 1-4 family	$	10,391	$	4,583	$	28,113	$	43,087	$	1,883,687	$	1,926,774	$	—
Commercial real estate	—		—		—		—		331,931		331,931		—
Home equity line of credit	1,671		494		1,421		3,586		531,895		535,481		—
Residential land	2,352		575		13,037		15,964		29,428		45,392		205
Commercial construction	—		—		—		—		41,950		41,950		—
Residential construction	—		—		—		—		3,327		3,327		—
Commercial loans	226		733		1,340		2,299		714,128		716,427		28
Consumer loans	553		344		486		1,383		91,870		93,253		308
Total loans	$	15,193	$	6,729	$	44,397	$	66,319	$	3,628,216	$	3,694,535	$	541

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

	March 31, 2012				December 31, 2011
(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	$	30,901	$	—	$	28,298	$	—
Commercial real estate	3,436		—		3,436		—
Home equity line of credit	2,799		—		2,258		—
Residential land	11,672		—		14,535		205
Commercial construction	—		—		—		—
Residential construction	—		—		—		—
Commercial loans	19,734		52		17,946		28
Consumer loans	272		310		281		308
Total	$	68,814	$	362	$	66,754	$	541

12

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

	March 31, 2012										December 31, 2011
(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	$	17,505	$	24,271	$	—	$	18,496	$	89	$	19,217	$	26,614	$	—	$	21,385	$	282
Commercial real estate	13,336		13,336		—		13,357		145		13,397		13,397		—		13,404		747
Home equity line of credit	659		1,557		—		659		1		711		1,612		—		954		6
Residential land	26,960		34,979		—		27,900		405		30,781		39,136		—		33,398		1,779
Commercial construction	—		—		—		—		—		—		—		—		—		—
Residential construction	—		—		—		—		—		—		—		—		—		—
Commercial loans	44,646		47,199		—		42,160		496		41,680		43,516		—		40,952		2,912
Consumer loans	24		24		—		24		—		25		25		—		16		—
	103,130		121,366		—		102,596		1,136		105,811		124,300		—		110,109		5,726
With an allowance recorded
Real estate loans:
Residential 1-4 family	3,860		3,860		218		3,633		75		3,525		3,525		203		3,527		201
Commercial real estate	—		—		—		—		—		—		—		—		—		—
Home equity line of credit	—		—		—		—		—		—		—		—		—		—
Residential land	7,210		7,270		2,322		7,583		185		7,792		7,852		2,525		8,158		603
Commercial construction	—		—		—		—		—		—		—		—		—		—
Residential construction	—		—		—		—		—		—		—		—		—		—
Commercial loans	1,717		1,717		551		4,663		9		6,561		6,561		976		8,131		737
Consumer loans	—		—		—		—		—		—		—		—		—		—
	12,787		12,847		3,091		15,879		269		17,878		17,938		3,704		19,816		1,541
Total
Real estate loans:
Residential 1-4 family	21,365		28,131		218		22,129		164		22,742		30,139		203		24,912		483
Commercial real estate	13,336		13,336		—		13,357		145		13,397		13,397		—		13,404		747
Home equity line of credit	659		1,557		—		659		1		711		1,612		—		954		6
Residential land	34,170		42,249		2,322		35,483		590		38,573		46,988		2,525		41,556		2,382
Commercial construction	—		—		—		—		—		—		—		—		—		—
Residential construction	—		—		—		—		—		—		—		—		—		—
Commercial loans	46,363		48,916		551		46,823		505		48,241		50,077		976		49,083		3,649
Consumer loans	24		24		—		24		—		25		25		—		16		—
	$	115,917	$	134,213	$	3,091	$	118,475	$	1,405	$	123,689	$	142,238	$	3,704	$	129,925	$	7,267

*    Since loan was classified as impaired.

Troubled debt restructurings.  A loan modification is deemed to be a TDR when ASB grants a concession it would not otherwise consider were it not for the borrower’s financial difficulty.  When a borrower fails to make a required payment on a loan or is in imminent default, ASB takes a number of steps to induce the borrower to cure the delinquency and restore the loan to current status or to avoid payment default. At times, ASB may restructure a loan to help a distressed borrower improve their financial position to eventually be able to fully repay the loan, provided the borrower has demonstrated both the willingness and the ability to handle the modified terms. TDR loans are considered an alternative to foreclosure or liquidation with the goal of minimizing losses to ASB and maximizing recovery.

ASB may consider various types of concessions in granting a TDR including maturity date extensions, temporary deferral of principal payments, temporary interest rate reductions, and covenant amendments or waivers. ASB does not grant principal forgiveness in its TDR modifications. Residential loan modifications generally involve the deferral of principal payments for a period of time not exceeding one year or a temporary reduction of principal and/or interest rate for a period of time generally not exceeding two years. Land loans are typically structured as a three-year term, interest-only monthly payment with a balloon payment due at maturity. Land loan TDR modifications typically involve extending the maturity date another one to three years and converting the payments from interest-only to principal and interest monthly, at the same or higher interest rate. Commercial loan modifications generally involve extensions of maturity dates, amendment or waiver of financial covenants, and to a

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lesser extent temporary deferral of principal payments. ASB does not reduce the interest rate on commercial loan TDR modifications. Occasionally, additional collateral and/or guaranties are obtained.

All TDR loans are classified impaired and are segregated and reviewed separately when assessing the adequacy of the allowance for loan losses based on the appropriate method of measuring impairment:  (1) present value of expected future cash flows discounted at the loan’s original effective interest at time of impairment, (2) fair value of collateral less costs to sell, or (3) observable market price. The financial impact of the calculated impairment amount is an increase to the allowance associated with the modified loan. When available information confirms that specific loans or portions thereof are uncollectible (confirmed losses), these amounts are charged off against the allowance for loan losses.

Loan modifications that occurred were as follows:

	Three months ended March 31, 2012					Three months ended March 31, 2011
(dollars in thousands)	Number of contracts	Pre-modification outstanding recorded investment		Post-modification outstanding recorded investment		Number  of contracts	Pre-modification outstanding recorded investment		Post-modification outstanding recorded investment
Troubled debt restructurings
Real estate loans:
Residential 1-4 family	7	$	1,413	$	1,410	9	$	2,358	$	2,235
Commercial real estate	—	—		—		—	—		—
Home equity line of credit	—	—		—		—	—		—
Residential land	7	1,734		1,441		18	2,912		2,920
Commercial loans	6	160		160		20	10,100		10,100
Consumer loans	—	—		—		—	—		—
Total	20	$	3,307	$	3,011	47	$	15,370	$	15,255

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

	Three months ended March 31, 2012			Three months ended March 31, 2011
(dollars in thousands)	Number of contracts	Recorded  investment		Number of  contracts	Recorded  investment
Troubled debt restructurings that subsequently defaulted
Real estate loans:
Residential 1-4 family	—	$	—	—	$	—
Commercial real estate	—	—		—	—
Home equity line of credit	—	—		—	—
Residential land	—	—		1	396
Commercial loans	4	879		6	697
Consumer loans	—	—		—	—
Total	4	$	879	7	$	1,093

The four commercial loans that subsequently defaulted were modified by extending the maturity date and deferring principal payments for a short period of time.

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.

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5 · Retirement benefits

Defined benefit pension and other postretirement benefit plans information.  For the first quarter of 2012, the Company contributed $27 million ($26 million by the utilities and $1 million by HEI) to its retirement benefit plans, compared to $31 million (primarily by the utilities) in the first quarter of 2011. The Company’s current estimate of contributions to its retirement benefit plans in 2012 is $107 million ($105 million by the utilities and $2 million by HEI), compared to $75 million ($73 million by the utilities and $2 million by HEI) in 2011. In addition, the Company expects to pay directly $2 million ($1 million each by the utilities and HEI) of benefits in 2012, comparable to 2011.

The Pension Protection Act provides that if a pension plan’s funded status falls below certain levels, more conservative assumptions must be used to value obligations under the pension plan and restrictions on participant benefit accruals may be placed on the plan. The HEI Retirement Plan has fallen below these thresholds and the minimum required contribution estimated for 2012 incorporates the more conservative assumptions required. Other factors could cause changes to the required contribution levels.

Effective April 1, 2011, accelerated distribution options (the $50,000 single sum distribution option and a Social Security level income option) under the HEI Retirement Plan became subject to partial restrictions because the funded status of the HEI Retirement Plan was deemed to be less than 80%. Generally, while the partial restrictions are in effect, a retiring participant may only elect an accelerated distribution option for 50% of the participant’s total benefit. The partial restrictions are expected to continue through 2012.

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

Three months ended March 31	Pension benefits						Other benefits
(in thousands)	2012			2011			2012			2011
Service cost	$	10,191		$	8,917		$	1,096		$	1,267
Interest cost	16,771			16,309			2,281			2,461
Expected return on plan assets	(17,856		)	(17,101		)	(2,621		)	(2,648		)
Amortization of net transition obligation	—			1			—			—
Amortization of prior service gain	(81		)	(97		)	(448		)	(224		)
Amortization of net actuarial loss	6,423			4,405			453			15
Net periodic benefit cost	15,448			12,434			761			871
Impact of PUC D&Os	(3,857		)	(1,544		)	(680		)	1,018
Net periodic benefit cost (adjusted for impact of PUC D&Os)	$	11,591		$	10,890		$	81		$	1,889

Consolidated HEI recorded retirement benefits expense of $8 million and $10 million in the first quarters of 2012 and 2011, respectively, and charged the remaining amounts primarily to electric utility plant.

The utilities have implemented pension and OPEB tracking mechanisms under which all retirement benefit expenses (except for executive life and nonqualified pension plan expenses) determined in accordance with GAAP are recovered over time.

Defined contribution plans information.  For the first quarters of 2012 and 2011, the Company’s expense for its defined contribution pension plans under the HEIRSP and the ASB 401(k) Plan was $0.9 million and $0.9 million, respectively, and cash contributions were $2.2 million and $2.4 million, respectively.

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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, 2012, there were 3.8 million shares remaining available for future issuance under the EIP of which an estimated 1.8 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 LTIP awards are achieved at maximum levels).

Under the 1987 Stock Option and Incentive Plan, as amended (SOIP), grants and awards of an estimated 0.6 million shares of common stock (based on various assumptions, including LTIP awards earned at maximum levels and the use of the March 31, 2012 market price of shares as the price on the exercise/payment dates) were outstanding as of March 31, 2012 to selected employees in the form of nonqualified stock options (NQSOs), stock appreciation rights (SARs), restricted stock units, LTIP performance and other shares and dividend equivalents. As of May 11, 2010 (when the EIP became effective), no new awards may be granted under the SOIP. After the shares of common stock for the outstanding SOIP grants and awards are issued or such grants and awards expire, the remaining shares registered under the SOIP will be deregistered and delisted.

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

Three months ended March 31 (in millions)	2012		2011
Share-based compensation expense (1)	$	1.8	$	1.2
Income tax benefit	0.6		0.4

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

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

March 31, 2012			Outstanding & Exercisable (Vested)
Year of grant	Range of exercise prices		Number of options	Weighted-average remaining contractual life	Weighted-average exercise price
2002	$	21.68	8,000	0.1	$	21.68
2003	20.49		35,500	0.7	20.49
	$	20.49 – 21.68	43,500	0.6	$	20.71

As of December 31, 2011, NQSOs outstanding totaled 55,500 (representing the same number of underlying shares), with a weighted-average exercise price of $20.92. As of March 31, 2012, all NQSOs outstanding were exercisable and had an aggregate intrinsic value (including dividend equivalents) of $0.3 million.

NQSO activity and statistics were as follows:

Three months ended March 31
(dollars in thousands, except prices)	2012		2011
Shares exercised	12,000		32,500
Weighted-average exercise price	$	21.68	$	20.27
Cash received from exercise	$	260	$	659
Intrinsic value of shares exercised (1)	$	91	$	258
Tax benefit realized for the deduction of exercises	$	36	$	101

(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.

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Stock appreciation rights.Information about HEI’s SARs was as follows:

March 31, 2012			Outstanding & Exercisable (Vested)
Year of grant	Range of exercise prices		Number of shares underlying SARs	Weighted-average remaining contractual life	Weighted-average exercise price
2004	$	26.02	72,000	2.1	$	26.02
2005	26.18		210,000	2.4	26.18
	$	26.02 –26.18	282,000	2.3	$	26.14

As of December 31, 2011, the shares underlying SARs outstanding totaled 282,000, with a weighted-average exercise price of $26.14. As of March 31, 2012, all SARs outstanding were exercisable and had no intrinsic value.

SARs activity and statistics were as follows:

Three months ended March 31
(dollars in thousands, except prices)	2012	2011
Shares expired	—	36,000
Weighted-average price of shares expired	—	$	26.10
Shares exercised	—	—

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

	2012				2011
Three months ended March 31	Shares		(1)		Shares		(1)
Outstanding, beginning of period	46,807		$	24.45	89,709		$	24.64
Granted	—		—		—		—
Vested	(8,700	)	27.17		—		—
Forfeited	—		—		(1,000	)	25.36
Outstanding, end of period	38,107		$	23.83	88,709		$	24.63

(1)Weighted-average grant-date fair value per share. The grant date fair value of a restricted stock award share was the closing or average price of HEI common stock on the date of grant.

As of March 31, 2012, 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 2.6 years.

For the three months ended March 31, 2012, total restricted stock that vested had a fair value of $0.2 million and the related tax benefits were $0.1 million.

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

	2012				2011
Three months ended March 31	Shares		(1)		Shares		(1)
Outstanding, beginning of period	247,286		$	21.80	146,500		$	19.80
Granted	92,512	(2)	25.98		85,017	(3)	24.95
Vested	(21,247	)	24.95		—		—
Forfeited	—		—		(1,000	)	22.60
Outstanding, end of period	318,551		$	22.80	230,517		$	21.69

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

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

(3)Total weighted-average grant-date fair value of $2.1 million.

As of March 31, 2012, there was $4.8 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 3.1 years.

For the three months ended March 31, 2012, total restricted stock units that vested and related dividends had a fair value of $0.6 million and the related tax benefits were $0.2 million.

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LTIP payable in stock.  The 2011-2013 LTIP and the 2012-2014 LTIP provide for performance awards under the EIP and the 2010-2012 LTIP provides for performance awards under the SOIP of shares of HEI common stock based on the satisfaction of performance goals and service conditions over a three-year performance period. The number of shares of HEI common stock that may be awarded is fixed on the date the grants are made subject to the achievement of specified performance levels. The payout varies from 0% to 200% of the number of target shares depending on achievement of the goals. The LTIP performance goals for both LTIP periods include awards with a market goal based on total return to shareholders (TRS) of HEI stock as a percentile to the Edison Electric Institute Index over the applicable three-year period. In addition, the 2010-2012 LTIP has performance goals related to levels of HEI consolidated net income, HECO consolidated ROACE, ASB net income and ASB return on assets — all based on two-year averages (2011-2012), and the 2011-2013 LTIP and the 2012-2014 LTIP have performance goals related to levels of HEI 3-year average consolidated net income, HECO consolidated ROACE, HECO 3-year average consolidated net income, ASB return on assets and ASB 3-year average net income.

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

	2012				2011
Three months ended March 31	Shares		(1)		Shares		(1)
Outstanding, beginning of period	197,385		$	25.94	126,782		$	20.33
Granted	77,482		30.71		74,540	(2)	35.46
Vested	(35,397	)	14.85		—		—
Forfeited	—		—		(587	)	22.45
Outstanding, end of period	239,470		$	29.12	200,735		$	25.94

(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 $2.6 million.

On February 3, 2012, LTIP grants (under the 2012-2014 LTIP) were made payable in 77,482 shares of HEI common stock (based on the grant date price of $25.98 and target TRS performance levels) with a weighted-average grant date fair value of $2.4 million based on the weighted-average grant date fair value per share of $30.71.

The following table summarizes the assumptions used to determine the fair value of the LTIP awards linked to TRS and the resulting fair value of LTIP awards granted:

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

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

As of March 31, 2012, there was $4 million of total unrecognized compensation cost related to the nonvested performance awards payable in shares linked to TRS. The cost is expected to be recognized over a weighted-average period of 1.7 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:

	2012			2011
Three months ended March 31	Shares	(1)		Shares		(1)
Outstanding, beginning of period	182,498	$	22.63	161,310		$	18.66
Granted	115,104	25.98		113,119	(2)	24.95
Vested	—	—		—		—
Forfeited	—	—		(879	)	18.95
Outstanding, end of period	297,602	$	23.92	273,550		$	21.26

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

(2)Total weighted-average grant-date fair value of $2.8 million.

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On February 3, 2012, LTIP grants (under the 2012-2014 LTIP) were made payable in 115,104 shares of HEI common stock (based on the grant date price of $25.98 and target performance levels relating to performance goals other than TRS), with a weighted-average grant date fair value of $3 million based on the weighted-average grant date fair value per share of $25.98.

As of March 31, 2012, there was $4.7 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 1.9 years.

7 · Interest rate swap agreements

In June 2010, HEI entered into multiple Forward Starting Swaps (FSS) with notional amounts totaling $125 million to hedge against interest rate fluctuations on medium-term notes expected to be issued by HEI in 2011, thereby enabling HEI to better forecast its future interest expense. The FSS entitled HEI to receive/(pay) the present value of the positive/(negative) difference between three-month LIBOR and a fixed rate at termination applied to the notional amount over a five-year period. The outstanding FSS were designated and accounted for as cash flow hedges. Changes in fair value were recognized (1) in other comprehensive income to the extent that they were considered effective, and (2) in “Interest expense—other than on deposit liabilities and other bank borrowings” for any portion considered ineffective.

In the first six months of 2011, HEI settled the FSS for payments totaling $5.2 million, of which $3.3 million was the ineffective portion ($0.8 million, ($0.4) million and $2.9 million recognized in 2010 and in the first and second quarters of 2011, respectively) and $1.9 million is being amortized to interest expense over five years beginning March 24, 2011 (the date that HEI issued $125 million of Senior Notes via a private placement).

8 · Earnings per share

Under the two-class method of computing earnings per share (EPS), EPS was comprised as follows for both unvested restricted stock awards and unrestricted common stock:

	2012		2011
Three months ended March 31	Basic and diluted		Basic and diluted
Distributed earnings	$	0.31	$	0.31
Undistributed earnings (loss)	0.09		(0.01		)
	$	0.40	$	0.30

As of March 31, 2012 and 2011, the antidilutive effects of SARs of 210,000 shares and 414,000 shares of HEI common stock, respectively, 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.

9 · Commitments and contingencies

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

10 · 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

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instruments, fair value estimates cannot be determined with precision. Changes in the underlying assumptions used, including discount rates and estimates of future cash flows, could significantly affect the estimates.  Fair value estimates are provided for certain financial instruments without attempting to estimate the value of anticipated future business and the value of assets and liabilities that are not considered financial instruments. In addition, the tax ramifications related to the realization of the unrealized gains and losses could have a significant effect on fair value estimates, but have not been considered in making such estimates.

The Company groups its financial assets measured at fair value in three levels outlined as follows:

Level 1:Inputs to the valuation methodology are quoted prices, unadjusted, for identical assets or liabilities in active markets. A quoted price in an active market provides the most reliable evidence of fair value and shall be used to measure fair value whenever available.

Level 2:Inputs to the valuation methodology include quoted prices for similar assets or liabilities in active markets; inputs to the valuation methodology include quoted prices for identical or similar assets or liabilities in markets that are not active; or inputs to the valuation methodology that are derived principally from or can be corroborated by observable market data by correlation or other means.

Level 3:Inputs to the valuation methodology are unobservable and significant to the fair value measurement. Level 3 assets and liabilities include financial instruments whose value is determined using discounted cash flow methodologies, as well as instruments for which the determination of fair value requires significant management judgment or estimation.

The Company used the following methods and assumptions to estimate the fair value of each applicable class of financial instruments for which it is practicable to estimate that value:

Cash and cash equivalents and short term borrowings—other than bank.  The carrying amount approximated fair value because of the short maturity of these instruments.

Investment and mortgage-related securities.  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. This method falls under Level 2 of ASB’s fair value measurement hierarchy.  Under this methodology, valuation is based upon quoted prices for similar assets in active markets; quoted prices for identical or similar assets in markets that are not active; or use of valuation methodologies that use inputs that are derived principally from or can be corroborated by observable market data by correlation or other means.

On a quarterly basis, fair value pricing levels obtained from ASB’s third-party vendor are reviewed by comparing its prices to a separate third party pricing service or to non-binding third-party broker quotes. ASB’s third-party vendor pricing is validated in the majority of cases for the determination of fair value. However, in cases where there are less active and orderly markets or less transparent information from ASB’s third-party vendor, fair value may be estimated by use of prices from the separate third party pricing service or from non-binding third-party broker quotes.

Loans receivable.  For residential real estate loans, fair value was calculated by discounting estimated cash flows using discount rates based on current industry pricing for loans with similar contractual characteristics.

For other types of loans, fair value was estimated by discounting contractual cash flows using discount rates that reflect current industry pricing for loans with similar characteristics and remaining maturity.  Where industry pricing is not available, discount rates are based on ASB’s current pricing for loans with similar characteristics and remaining maturity.

The fair value of all loans was adjusted to reflect current assessments of loan collectability. 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.

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

Off-balance sheet financial instruments.  The fair value of loans serviced for others was calculated by discounting expected net income streams using discount rates that reflect industry pricing for similar assets. Expected net income streams were estimated based on industry assumptions regarding prepayment speeds and income and expenses associated with servicing residential mortgage loans for others. The fair value of commitments to originate loans was estimated based on the change in current primary market prices of new commitments. Since lines of credit can expire without being drawn and customers are under no obligation to utilize the lines, no fair value was assigned to unused lines of credit. The fair value of letters of credit was estimated based on the fees currently charged to enter into similar agreements, taking into account the remaining terms of the agreements. The fair value of HECO-obligated preferred securities of trust subsidiaries was based on quoted market prices.

The estimated fair values of certain of the Company’s financial instruments (with the level of the fair value hierarchy in which the fair value measurements are categorized noted in parentheses) were as follows:

	March 31, 2012				December 31, 2011
(in thousands)	Carrying or notional amount		Estimated fair value		Carrying or notional amount		Estimated fair value
Financial assets
Cash and cash equivalents, excluding money market funds (Level 2)	$	236,336	$	236,336	$	270,255	$	270,255
Money market funds (Level 2)	10		10		10		10
Available-for-sale investment and mortgage-related securities (Level 2)	631,063		631,063		624,331		624,331
Investment in stock of Federal Home Loan Bank of Seattle (Level 2)	97,764		97,764		97,764		97,764
Loans receivable, net (Level 3)	3,687,058		3,896,679		3,652,419		3,886,253
Financial liabilities
Deposit liabilities (Level 2)	4,125,204		4,130,996		4,070,032		4,075,656		(1)
Short-term borrowings—other than bank (Level 2)	156,288		156,288		68,821		68,821
Other bank borrowings (Level 2)	232,843		249,259		233,229		250,486
Long-term debt, net—other than bank (Level 2)	1,282,602		1,338,777		1,340,070		1,400,241
Off-balance sheet items
HECO-obligated preferred securities of trust subsidiary (Level 2)	50,000		50,000		50,000		50,000

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

As of March 31, 2012 and December 31, 2011, loan commitments and unused lines and letters of credit issued by ASB had notional amounts of $1.4 billion and $1.3 billion, respectively, and their estimated fair value on such dates were $0.6 million and $0.3 million, respectively. As of March 31, 2012 and December 31, 2011, loans serviced by ASB for others had notional amounts of $1.0 billion and $993 million, respectively, and the estimated fair value of the servicing rights for such loans was $10.0 million and $9.8 million, respectively.

Fair value measurements on a recurring basis.  While securities held in ASB’s investment portfolio trade in active markets, they do not trade on listed exchanges nor do the specific holdings trade in quoted markets by dealers or brokers. All holdings are valued using market-based approaches that are based on exit prices that are taken from identical or similar market transactions, even in situations where trading volume may be low when compared with prior periods as has been the case during the recent market disruption. Inputs to these valuation techniques reflect the assumptions that consider credit and nonperformance risk that market participants would use in pricing the asset based on market data obtained from independent sources. Available-for-sale securities were comprised of federal agency obligations and mortgage-backed securities and municipal bonds.

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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, 2012
Money market funds (“other” segment)	$	—	$	10	$	—
Available-for-sale securities (bank segment)
Mortgage-related securities-FNMA, FHLMC and GNMA	$	—	$	358,586	$	—
Federal agency obligations	—		210,540		—
Municipal bonds	—		61,937		—
	$	—	$	631,063	$	—
December 31, 2011
Money market funds (“other” segment)	$	—	$	10	$	—
Available-for-sale securities (bank segment)
Mortgage-related securities-FNMA, FHLMC and GNMA	$	—	$	344,865	$	—
Federal agency obligations	—		220,727		—
Municipal bonds	—		58,739		—
	$	—	$	624,331	$	—

Fair value measurements on a nonrecurring basis.From time to time, the Company may be required to measure certain assets at fair value on a nonrecurring basis in accordance with GAAP. These adjustments to fair value usually result from the writedowns of individual assets. ASB does not record loans at fair value on a recurring basis. However, from time to time, ASB records nonrecurring fair value adjustments based on the current appraised value of the collateral securing the loans or unobservable market assumptions. Unobservable assumptions reflect ASB’s own estimate of the fair value of collateral used in valuing the loan. ASB may also be required to measure goodwill at fair value on a nonrecurring basis. During the first quarter of 2012, it was not required that a measurement of the fair value of goodwill be calculated and goodwill was not measured at fair value.

From time to time, the Company may be required to measure certain liabilities at fair value on a nonrecurring basis in accordance with GAAP. The fair value of HECO’s asset retirement obligations (Level 3) was determined by discounting the expected future cash flows using market-observable risk-free rates as adjusted by HECO’s credit spread (also see Note 3).

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

			Fair value measurements using
			Quoted prices in active		Significant other		Significant
			markets for identical		observable inputs		unobservable inputs
(in millions)	Balance		assets (Level 1)		(Level 2)		(Level 3)
Loans
March 31, 2012	$	33	$	—	$	—	$	33
December 31, 2011	34		—		—		34

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

Residential loans.  The fair value of ASB’s residential loans that were written down due to impairment was determined based on third party appraisals for similar residential property sales in an active market, 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 for similar residential property sales in an active market, and therefore, is classified as a Level 3 measurement.

Commercial loans.  The fair value of ASB’s commercial loans secured by real estate that was written down due to impairment was determined based on third party appraisals for the specific properties, the value placed on the assets of the business and cash flows generated by the business entity, and therefore, is classified as a Level 3 measurement.

22

For loans classified as Level 3 as of March 31, 2012, the significant unobservable inputs used in the fair value measurement were as follows:

($ in thousands)	Fair value at March 31, 2012		Valuation technique	Significant unobservable input	Significant unobservable input value
Residential loans	$	27,060	Third party appraisal	Property sales	65%
Home equity lines of credit	659		Third party appraisal	Property sales	42%
Commercial loan	1,506		Third party appraisal	Present value of expected cash flows of the property rental	61%
Commercial loans	97		Third party appraisal	Fair value of business assets	15%
Commercial loan	2,600		Present value of cash flows	Present value of expected future cash flows based on anticipated debt restructuring Discount rate	Paydown of loan — 66% 4.5%
Commercial loan	1,599		Third party appraisal	Insurance proceeds	100%

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

11 · Cash flows

Three months ended March 31 (in millions)	2012		2011
Supplemental disclosures of cash flow information
Interest paid to non-affiliates	$	22	$	23
Income tax paid/(refunded)	—		(30		)
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		4
Real estate acquired in settlement of loans	2		3

(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.

12 · 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.

23

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statements of Income (unaudited)

Three months ended March 31 (in thousands)	2012			2011
Operating revenues	$	747,938		$	644,301
Operating expenses
Fuel oil	327,839			260,860
Purchased power	164,789			147,958
Other operation	61,849			65,531
Maintenance	30,038			29,196
Depreciation	36,482			36,432
Taxes, other than income taxes	70,995			59,995
Income taxes	17,365			11,610
Total operating expenses	709,357			611,582
Operating income	38,581			32,719
Other income
Allowance for equity funds used during construction	1,940			1,244
Other, net	1,265			910
Total other income	3,205			2,154
Interest and other charges
Interest on long-term debt	14,383			14,383
Amortization of net bond premium and expense	745			783
Other interest charges (credits)	(271		)	539
Allowance for borrowed funds used during construction	(870		)	(520		)
Total interest and other charges	13,987			15,185
Net income	27,799			19,688
Preferred stock dividends of subsidiaries	229			229
Net income attributable to HECO	27,570			19,459
Preferred stock dividends of HECO	270			270
Net income for common stock	$	27,300		$	19,189

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

Statements of Consolidated Comprehensive Income (unaudited)

Three months ended March 31 (in thousands)			2012				2011
Net income for common stock			$	27,300			$	19,189
Other comprehensive income, net of taxes:
Retirement benefit plans:
Less: amortization of net loss, prior service gain and transition obligation included in net periodic benefit cost, net of tax benefits of $2,212 and $1,448 for the three months ended March 31, 2012 and 2011, respectively	3,472				2,274
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes of $2,162 and $1,431 for the three months ended March 31, 2012 and 2011, respectively	(3,395	)	77		(2,247	)	27
Other comprehensive income, net of taxes			77				27
Comprehensive income attributable to common shareholder			$	27,377			$	19,216

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

24

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Balance Sheets (unaudited)

(dollars in thousands, except par value)	March 31, 2012			December 31, 2011
Assets
Utility plant, at cost
Land	$	51,504		$	51,514
Plant and equipment	5,095,080			5,052,027
Less accumulated depreciation	(1,980,964		)	(1,966,894		)
Construction in progress	150,667			138,838
Net utility plant	3,316,287			3,275,485
Current assets
Cash and cash equivalents	5,850			48,806
Customer accounts receivable, net	158,879			183,328
Accrued unbilled revenues, net	126,642			137,826
Other accounts receivable, net	8,071			8,623
Fuel oil stock, at average cost	186,006			171,548
Materials and supplies, at average cost	46,749			43,188
Prepayments and other	31,210			34,602
Regulatory assets	26,364			20,283
Total current assets	589,771			648,204
Other long-term assets
Regulatory assets	651,310			649,106
Unamortized debt expense	12,477			12,786
Other	86,219			86,361
Total other long-term assets	750,006			748,253
Total assets	$	4,656,064		$	4,671,942
Capitalization and liabilities
Capitalization
Common stock ($6 2/3 par value, authorized 50,000,000 shares; outstanding 14,233,723 shares)	$	94,911		$	94,911
Premium on capital stock	426,921			426,921
Retained earnings	893,323			884,284
Accumulated other comprehensive income (loss), net of income taxes	45			(32		)
Common stock equity	1,415,200			1,406,084
Cumulative preferred stock — not subject to mandatory redemption	34,293			34,293
Commitments and contingencies (Note 5)
Long-term debt, net	1,000,602			1,000,570
Total capitalization	2,450,095			2,440,947
Current liabilities
Short-term borrowings — nonaffiliates	84,942			—
Current portion of long-term debt	—			57,500
Accounts payable	158,691			188,580
Interest and preferred dividends payable	18,835			19,483
Taxes accrued	183,273			224,768
Other	58,947			69,353
Total current liabilities	504,688			559,684
Deferred credits and other liabilities
Deferred income taxes	357,974			337,863
Regulatory liabilities	316,560			315,466
Unamortized tax credits	61,941			60,614
Retirement benefits liability	478,517			495,121
Other	108,250			106,044
Total deferred credits and other liabilities	1,323,242			1,315,108
Contributions in aid of construction	378,039			356,203
Total capitalization and liabilities	$	4,656,064		$	4,671,942

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

25

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, 2011	14,234	$	94,911	$	426,921	$	884,284		$	(32	)	$	1,406,084
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	$	893,323		$	45		$	1,415,200
Balance, December 31, 2010	13,831	$	92,224	$	389,609	$	854,856		$	709		$	1,337,398
Net income for common stock	—	—		—		19,189			—			19,189
Other comprehensive income, net of taxes	—	—		—		—			27			27
Common stock dividends	—	—		—		(17,640		)	—			(17,640		)
Balance, March 31, 2011	13,831	$	92,224	$	389,609	$	856,405		$	736		$	1,338,974

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

26

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statements of Cash Flows (unaudited)

Three months ended March 31
(in thousands)	2012			2011
Cash flows from operating activities
Net income	$	27,799		$	19,688
Adjustments to reconcile net income to net cash used in operating activities
Depreciation of property, plant and equipment	36,482			36,432
Other amortization	1,561			2,288
Change in deferred income taxes	20,061			13,521
Change in tax credits, net	1,356			755
Allowance for equity funds used during construction	(1,940		)	(1,244		)
Change in cash overdraft	—			(2,688		)
Changes in assets and liabilities
Decrease (increase) in accounts receivable	25,001			(11,271		)
Decrease (increase) in accrued unbilled revenues	11,184			(9,402		)
Increase in fuel oil stock	(14,458		)	(3,513		)
Increase in materials and supplies	(3,561		)	(1,065		)
Increase in regulatory assets	(13,948		)	(7,872		)
Decrease in accounts payable	(33,174		)	(42,123		)
Change in prepaid and accrued income taxes and utility revenue taxes	(44,561		)	240
Contributions to defined benefit pension and other postretirement benefit plans	(26,183		)	(30,693		)
Change in other assets and liabilities	3,444			9,315
Net cash used in operating activities	(10,937		)	(27,632		)
Cash flows from investing activities
Capital expenditures	(63,436		)	(37,556		)
Contributions in aid of construction	22,855			5,749
Net cash used in investing activities	(40,581		)	(31,807		)
Cash flows from financing activities
Common stock dividends	(18,261		)	(17,640		)
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	84,942			—
Other	(120		)	(4		)
Net cash provided by (used in) financing activities	8,562			(18,143		)
Net decrease in cash and cash equivalents	(42,956		)	(77,582		)
Cash and cash equivalents, beginning of period	48,806			122,936
Cash and cash equivalents, end of period	$	5,850		$	45,354

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

27

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, 2011.

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, 2012 and December 31, 2011 and the results of their operations and their cash flows for the three months ended March 31, 2012 and 2011. 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. 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, 2012 and December 31, 2011 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, 2012 and 2011 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 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.

28

Power purchase agreements.  As of March 31, 2012, HECO and its subsidiaries had six PPAs totaling 548 megawatts (MW) of 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 548 MW of firm capacity is purchased pursuant to PPAs entered into before December 31, 2003, with 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, 2012 totaled $165 million, with purchases from AES Hawaii, Kalaeloa, HEP and HPOWER totaling $35 million, $69 million, $14 million and $16 million, respectively. Purchases from all IPPs for the quarter ended March 31, 2011 totaled $148 million, with purchases from AES Hawaii, Kalaeloa, HEP and HPOWER totaling $35 million, $62 million, $14 million and $13 million, respectively.

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

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 are based on the prior year’s revenues. For the three months ended March 31, 2012 and 2011, HECO and its subsidiaries included approximately $67 million and $57 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 2012, HECO and its subsidiaries contributed $26 million to their retirement benefit plans, compared to $31 million in the first quarter of 2011. HECO and its subsidiaries’ current estimate of contributions to their retirement benefit plans in 2012 is $105 million, compared to contributions of $73 million in 2011. In addition, HECO and its subsidiaries expect to pay directly $0.8 million of benefits in 2012, compared to $1.3 million paid in 2011.

The Pension Protection Act provides that if a pension plan’s funded status falls below certain levels, more conservative assumptions must be used to value obligations under the pension plan and restrictions on participant benefit accruals may be placed on the plan. The HEI Retirement Plan has fallen below these thresholds and the minimum required contribution estimated for 2012 incorporates the more conservative assumptions required. Other factors could cause changes to the required contribution levels.

Effective April 1, 2011, accelerated distribution options (the $50,000 single sum distribution option and a Social Security level income option) under the HEI Retirement Plan became subject to partial restrictions because the

29

funded status of the HEI Retirement Plan was deemed to be less than 80%. Generally, while the partial restrictions are in effect, a retiring participant may only elect an accelerated distribution option for 50% of the participant’s total benefit. The partial restrictions are expected to continue through 2012.

The components of net periodic benefit cost were as follows:

Three months ended March 31	Pension benefits						Other benefits
(in thousands)	2012			2011			2012			2011
Service cost	$	9,802		$	8,565		$	1,048		$	1,223
Interest cost	15,261			14,849			2,205			2,384
Expected return on plan assets	(16,060		)	(15,284		)	(2,579		)	(2,608		)
Amortization of net transition obligation	—			—			(2		)	(2		)
Amortization of net prior service gain	(172		)	(187		)	(451		)	(227		)
Amortization of net actuarial loss	5,869			4,120			440			18
Net periodic benefit cost	14,700			12,063			661			788
Impact of PUC D&Os	(3,857		)	(1,544		)	(680		)	1,018
Net periodic benefit cost (adjusted for impact of PUC D&Os)	$	10,843		$	10,519		$	(19	)	$	1,806

HECO and its subsidiaries recorded retirement benefits expense of $8 million and $9 million for the first quarters of 2012 and 2011, respectively. The electric utilities charged a portion of the net periodic benefit cost to electric utility plant.

The utilities have implemented pension and OPEB tracking mechanisms under which all retirement benefit expenses (except for executive life and nonqualified pension plan expenses) determined in accordance with GAAP are recovered over time.

Defined contribution plan information.  For the first three months of 2012 and 2011, the utilities’ expense for its defined contribution pension plan was de minimis.

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 negotiate with developers of proposed projects to integrate power into its grid from a variety of renewable energy sources, including solar, biomass, wind, ocean thermal energy conversion, wave and others. This includes HECO’s plan to integrate wind power into the Oahu electrical grid that would be imported via a yet-to-be-built undersea transmission cable system from a windfarm proposed to be built on the island of Lanai. In December 2009, the PUC allowed HECO to defer the costs of studies for this large wind project for later review of prudence and reasonableness, and HECO is now seeking PUC approval to recover the deferred costs totaling $3.9 million for the Stage 1 studies through the REIP surcharge.  Additionally, in July 2011, the PUC directed HECO to file a draft Request for Proposal (RFP) for 200 MW or more of renewable energy to be delivered to Oahu from any of the Hawaiian islands. In October 2011, HECO filed the draft RFP with the PUC. In November 2011, HECO and MECO filed their application to seek PUC approval to defer for later recovery approximately $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.

30

Interim increases.  As of March 31, 2012, HECO and its subsidiaries had recognized $49 million of revenues with respect to interim orders related to general rate increase requests. Revenue amounts recorded pursuant to interim orders are subject to refund, with interest, if they exceed amounts allowed in a final order.

Major projects.  Many public utility projects require PUC approval and various permits from other governmental agencies. Difficulties in obtaining, or the inability to obtain, the necessary approvals or permits can result in significantly increased project costs or even cancellation of projects. Further, completion of projects is subject to various risks, such as problems or disputes with vendors. In the event a project does not proceed, or if it becomes probable the PUC will disallow cost recovery for all or part of a project, project costs may need to be written off in amounts that could result in significant reductions in HECO’s consolidated net income. Significant projects whose costs (or costs in excess of estimates) have not yet been allowed in rate base by a final PUC order include those described below.

In May 2011, based upon recommendations by the Consumer Advocate in HECO’s 2009 test year rate case, the PUC ordered independently conducted regulatory audits on the reasonableness of costs incurred for HECO’s East Oahu Transmission Project (EOTP), Campbell Industrial Park (CIP) combustion turbine No. 1 (CT-1) project, and Customer Information System (CIS) project. In the interim decision and order (D&O) in the 2011 test year rate case, issued in July 2011, the PUC approved the portion of the settlement agreement in that proceeding allowing HECO to defer the portion of costs that are in excess of the prior PUC approved amounts and related depreciation for HECO’s EOTP Phase 1 ($43 million) and the CIP CT-1 project ($32 million) until completion of independently conducted regulatory audits. In the interim D&O in HECO’s 2011 test year rate case, the PUC approved the accrual of a carrying charge on the cost of such projects not yet included in rates and the related depreciation expense, from July 1, 2011 until the regulatory audits are completed and allowed the remaining project costs that were not deferred to be included in electric rates. For accounting purposes, HECO will recognize the equity portion of the carrying charge when it is allowed in electric rates. The PUC did not approve the agreement to defer expenses (subject to a limit to which the parties had agreed) associated with the yet-to-be completed CIS project. Subsequently in February 2012, the PUC granted HECO’s request to defer CIS project operation and maintenance expenses (limited to $2,258,000 per year in 2011 and 2012 under a settlement agreement) that are to be subject to a regulatory audit of project costs, and allowed HECO to accrue an allowance for funds used during construction on these deferred costs until the completion of the regulatory audit. Pursuant to the PUC’s order in HECO’s 2009 test year rate case, HECO and the Consumer Advocate submitted proposals for the scope, timing, management and structure for the regulatory audits for the PUC’s review and consideration. The PUC subsequently eliminated the requirement for a regulatory audit for the EOTP Phase I (see “East Oahu Transmission Project” below) and has not yet issued a schedule or requirements for the regulatory audits of the CIP CT-1 and CIS projects.

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). HECO’s current rates reflect recovery of project costs of $163 million. See “Major projects” above regarding the regulatory audit process that must be completed in connection with determining recovery of the remaining costs for this project. Management believes no adjustment to project costs is required as of March 31, 2012.

East Oahu Transmission Project.  HECO had planned a project to construct a partially underground transmission line to a major substation. However, in 2002, an application for a permit, which would have allowed construction in a route through conservation district lands, was denied. In 2007, the PUC approved HECO’s request to expend funds for a revised EOTP using different routes requiring the construction of subtransmission lines in two phases (then estimated at $56 million - $42 million for Phase 1 and $14 million for Phase 2), but did not address the issue as to whether the pre-2003 planning and permitting costs, and related AFUDC, should be included in the project costs.

Phase 1 was placed in service on June 29, 2010. As of March 31, 2012, HECO’s incurred costs for Phase 1 of this project was $59 million (as a result of higher costs and the project delays), including (i) $12 million of pre-2003 planning and permitting costs, (ii) $24 million of planning, permitting and construction costs incurred after the denial

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of the permit and (iii) $23 million for AFUDC. The interim D&Os issued in HECO’s 2011 test year rate case reflects approximately $16 million of EOTP Phase 1 costs and related depreciation expense in determining revenue requirements. As described above under “Major projects,” the PUC ordered in HECO’s 2011 test year case that a regulatory audit was to be conducted before the PUC determined the recoverability of the remaining costs for EOTP Phase 1.

On February 3, 2012, HECO, the Consumer Advocate and the Department of Defense (parties in the HECO 2011 test year rate case proceeding) signed a settlement agreement, subject to PUC approval, regarding the EOTP Phase 1 project costs.  The parties agreed that, in lieu of a regulatory audit, HECO would write-off $9.5 million of gross plant in-service costs associated with EOTP Phase 1, and associated adjustments in the accumulated depreciation, deferred depreciation expense, accumulated deferred income taxes, unamortized state investment tax credits and carrying charges. In deciding to enter into the agreement, HECO took into account a number of considerations, including (1) the significant passage of time since the initial costs for the EOTP Phase 1 project were incurred, (2) the significant resources that would be required by the PUC, HECO and the other parties to conduct a fair and meaningful regulatory audit of project costs, and (3) additional carrying charges that would be accrued to the project cost during a lengthy audit process. The settlement agreement does not address the costs that are being deferred in connection with the CIP CT-1 project or the CIS project.

The settlement agreement resulted in an after-tax charge to net income in the fourth quarter of 2011 of approximately $6 million. The parties agreed to stipulate, subject to PUC approval, to an additional annual interim increase of $5 million to be effective March 1, 2012, based on additional revenue requirements reflecting all remaining EOTP costs not previously included in rates or agreed to be written off (an increase of approximately $31 million to rate base) and offset by other minor adjustments to the interim increase that became effective on July 26, 2011. The agreement allows HECO to continue to defer depreciation expense and accrue carrying charges related to the costs not yet included in rates. For accounting purposes, HECO will recognize the equity portion of the carrying charge when it is allowed in electric rates.

On March 29, 2012, the PUC approved the settlement agreement, and ordered that the interim increase for HECO’s 2011 test year rate case be adjusted by $5 million. The PUC also eliminated the requirement for a regulatory audit for the EOTP Phase 1. HECO submitted a revised tariff to reflect an increase in the interim increase effective April 2, 2012.

In April 2010, HECO proposed a modification of Phase 2 of the EOTP that uses smart grid technology and is estimated to cost $10 million (total cost of $15 million, less $5 million of funding through the Smart Grid Investment Grant Program of the American Recovery and Reinvestment Act of 2009). In October 2010, the PUC approved HECO’s modification request for Phase 2, which is projected for completion by the third quarter of 2012. As of March 31, 2012, HECO’s incurred costs for the Modified Phase 2 project amounted to $9 million (total cost of $13 million, less $4 million received in Smart Grid Investment funding).

Management believes that no adjustment to project costs of EOTP Phase 1 or Modified Phase 2 is required as of March 31, 2012.

Customer Information System Project.  In 2005, the PUC approved the utilities’ request to (i) expend the then-estimated $20 million (including $18 million for capital and deferred costs) for a new CIS project, provided that no part of the project costs may be included in rate base until the project is in service and is “used and useful for public utility purposes,” and (ii) defer certain computer software development costs, accumulate AFUDC during the deferral period, amortize the deferred costs over a specified period and include the unamortized deferred costs in rate base, subject to specified conditions.

The CIS project is proceeding with the implementation of a new software system. As of March 31, 2012, HECO’s total deferred and capital cost estimate for the CIS project was $60 million (of which $52 million was recorded). The PUC has ordered that this project undergo a regulatory audit, which likely will not be planned until the CIS project is complete and operational. Management believes no adjustment to the CIS project costs is required as of March 31, 2012.

Environmental regulation.  HECO and its subsidiaries are subject to environmental laws and regulations that regulate the operation of existing facilities, the construction and operation of new facilities and the proper cleanup

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and disposal of hazardous waste and toxic substances. In recent years, legislative, regulatory and governmental activities related to the environment, including proposals and rulemaking under the Clean Air Act (CAA) and Clean Water Act (CWA), have increased significantly and management anticipates that such activity will continue.

On April 20, 2011, the Federal Register published the federal Environmental Protection Agency’s (EPA’s) proposed regulations required by section 316(b) of the CWA designed to protect aquatic organisms from adverse impacts associated with existing power plant cooling water intake structures. The proposed regulations would apply to the cooling water systems for the steam generating units at the utilities’ Honolulu, Kahe and Waiau power plants on the island of Oahu. Although the proposed regulations provide some flexibility, management believes they do not adequately focus on site-specific conditions and cost-benefit factors and, if adopted as proposed, would require significant capital and annual O&M expenditures. As proposed, the regulations would require facilities to come into compliance within 8 years of the effective date of the final rule, which the EPA expects to issue in 2012.

On 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 Honolulu, Kahe and Waiau power plants. MATS establishes the Maximum Achievable Control Technology standards for the control of hazardous air pollutants emissions from new and existing EGUs. HECO is currently reviewing the final rule and developing a compliance plan and schedule. Depending on the specifics of the compliance plan, MATS may require significant capital and annual expenditures for the installation and operation of emission control equipment on HECO’s EGUs. The CAA requires that facilities come into compliance with the MATS limits within 3 years of the final rule, although facilities may be granted two 1-year extensions to install emission control technology. In view of the isolated nature of HECO’s electrical system and the potential requirement to install control equipment on all HECO EGUs while maintaining system reliability, the MATS compliance schedule poses a significant challenge to HECO.

Depending upon the final outcome of the CWA 316(b) regulations, possible changes in CWA effluent standards, the specifics of the MATS compliance plan, the tightening of the National Ambient Air Quality Standards, and the Regional Haze rule under the CAA, HECO and its subsidiaries may be required to incur material capital expenditures and other compliance costs, but such amounts are not determinable at this time. Additionally, the combined effects of these regulatory initiatives may result in a decision to retire certain generating units earlier than anticipated.

HECO, HELCO and MECO, like other utilities, periodically experience petroleum or other chemical releases into the environment associated with current operations and report and take action on these releases when and as required by applicable law and regulations. 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, which had been experiencing severe financial hardships and was facing bankruptcy. Molokai Electric Company sold its former generation site (Site) in 1983, but continued to operate at the Site under a lease until 1985. The EPA has since performed Brownfield assessments of the Site that identified environmental impacts in the subsurface. Although MECO never operated at the Site and operations there had stopped four years before the merger, in discussions with the EPA and the Hawaii Department of Health (DOH), MECO agreed to undertake additional investigations at the Site and an adjacent parcel that Molokai Electric Company had used for equipment storage, including transformers, (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 will further investigate 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, 2012) for the additional investigation and estimated cleanup costs, however, final costs of remediation will depend on the results of continued investigation.

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Global climate change and greenhouse gas emissions reduction.  National and international concern about climate change and the contribution of GHG emissions (including carbon dioxide emissions from the combustion of fossil fuels) to global warming have led to action by the State and to federal legislative and regulatory proposals to reduce GHG emissions.

In July 2007, Act 234, which requires a statewide reduction of GHG emissions by January 1, 2020 to levels at or below the statewide GHG emission levels in 1990, became law in Hawaii. The electric utilities are participating in a Task Force established under Act 234, which is charged with developing a work plan and regulatory approach to reduce GHG emissions, as well as in initiatives aimed at reducing their GHG emissions, such as those being implemented under the Energy Agreement. The DOH is currently preparing the proposed regulations required by Act 234, but has not yet released them. Because the regulations implementing Act 234 have not yet been promulgated, management cannot predict the impact of Act 234 on the electric utilities, but compliance costs could be significant.

Several approaches (e.g., “cap and trade”) to GHG emission reduction have been either introduced or discussed in the U.S. Congress; however, no federal legislation has yet been enacted.

On September 22, 2009, the EPA issued its Final Mandatory Reporting of Greenhouse Gases Rule, which requires that sources emitting GHGs above certain threshold levels monitor and report GHG emissions. The utilities have submitted the required reports for 2010 and 2011 to the EPA. In December 2009, the EPA made the finding that motor vehicle GHG emissions endanger public health or welfare. Since then, the EPA has also issued rules that begin to address GHG emissions from stationary sources, like the utilities’ generating units.

In June 2010, the EPA issued its “Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule” (GHG Tailoring Rule) that created new thresholds for GHG emissions from new and existing stationary source facilities. Effective January 2, 2011, under the Prevention of Significant Deterioration program, permitting of new or modified stationary sources (such as utility electrical generating units) that have the potential to emit GHGs in greater quantities than the thresholds in the GHG Tailoring Rule will entail GHG emissions evaluation, analysis and, potentially, control requirements. In January 2011, the EPA announced that it plans to defer, for three years, GHG permitting requirements for carbon dioxide (CO2) emissions from biomass-fired and other biogenic sources. The utilities are evaluating the impact of this deferral on their generation units that are or will be fired on biofuels. 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 electrical 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 generation units, and testing biofuel blends in other HECO and MECO generating units. Management is unable to evaluate the ultimate impact on the utilities’ operations of eventual comprehensive GHG regulation. However, management believes that the various initiatives it is undertaking will provide a sound basis for managing the electric utilities’ carbon footprint and meeting GHG reduction goals that will ultimately emerge.

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

Asset retirement obligations.  Asset retirement obligations (AROs) represent legal obligations associated with the retirement of certain tangible long-lived assets, are measured as the present value of the projected costs for the

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future retirement of specific assets and are recognized in the period in which the liability is incurred if a reasonable estimate of fair value can be made. HECO and its subsidiaries’ recognition of AROs have no impact on its earnings. The cost of the AROs is recovered over the life of the asset through depreciation. AROs recognized by HECO and its subsidiaries relate to obligations to retire plant and equipment, including removal of asbestos and other hazardous materials.

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

(in thousands)	2012			2011
Balance, January 1	$	50,871		$	48,630
Accretion expense	451			566
Liabilities incurred	—			—
Liabilities settled	(210		)	(482		)
Revisions in estimated cash flows	—			—
Balance, March 31	$	51,112		$	48,714

Collective bargaining agreements.  As of March 31, 2012, approximately 53% of the electric utilities’ employees were members of the International Brotherhood of Electrical Workers, AFL-CIO, Local 1260, which is the only union representing employees of the electric utilities. On March 11, 2011, the utilities’ bargaining unit employees ratified a new collective bargaining agreement and a new benefit agreement. The new collective bargaining agreement covers a term from January 1, 2011 to October 31, 2013 and provides for non-compounded wage increases (1.75%, 2.5%, and 3.0% for 2011, 2012 and 2013, respectively). The new benefit agreement covers a term from January 1, 2011 to October 31, 2014 and includes changes to medical, dental and vision plans with increased employee contributions and changes to retirement benefits for employees.

6 · Cash flows

Three months ended March 31
(in millions)	2012			2011
Supplemental disclosures of cash flow information
Interest paid	$	15		$	15
Income tax paid/(refunded)	(1		)	(33		)
Supplemental disclosures of noncash activities
Electric utility property, plant and equipment - Unpaid invoices and other	3			1

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. Fair value estimates are provided for certain financial instruments without attempting to estimate the value of anticipated future business and the value of assets and liabilities that are not considered financial instruments. In addition, the tax ramifications related to the realization of the unrealized gains and losses could have a significant effect on fair value estimates, but have not been considered in making such estimates.

The Company groups its financial assets measured at fair value in three levels outlined as follows:

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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 shall be used to measure fair value whenever available.

Level 2:Inputs to the valuation methodology include quoted prices for similar assets or liabilities in active markets; inputs to the valuation methodology include quoted prices for identical or similar assets or liabilities in markets that are not active; or inputs to the valuation methodology that are derived principally from or can be corroborated by observable market data by correlation or other means.

Level 3:Inputs to the valuation methodology are unobservable and significant to the fair value measurement. Level 3 assets and liabilities include financial instruments whose value is determined using discounted cash flow methodologies, as well as instruments for which the determination of fair value requires significant management judgment or estimation.

The 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:

Cash and cash equivalents and short-term borrowings.  The carrying amount approximated fair value because of the short maturity of these instruments.

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

Off-balance sheet financial instruments.  Fair value of HECO-obligated preferred securities of trust subsidiaries was based on quoted market prices.

The estimated fair values of certain of the electric utilities’ financial instruments (with the level of the fair value hierarchy in which the fair value measurements are categorized noted in parentheses) were as follows:

	March 31, 2012				December 31, 2011
(in thousands)	Carrying amount		Estimated fair value		Carrying amount		Estimated fair value
Financial assets
Cash and cash equivalents (Level 2)	$	5,850	$	5,850	$	48,806	$	48,806
Financial liabilities
Short-term borrowings - nonaffiliates (Level 2)	84,942		84,942		—		—
Long-term debt, net, including amounts due within one year (Level 2)	1,000,602		1,037,062		1,058,070		1,095,133
Off-balance sheet item
HECO-obligated preferred securities of trust subsidiary (Level 2)	50,000		50,000		50,000		50,000

Fair value measurements on a nonrecurring basis.  From time to time, the utilities 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 application of lower-of-cost-or-market accounting or writedowns of individual assets. As of March 31, 2012, there were no adjustments to fair value for assets measured at fair value on a nonrecurring basis in accordance with GAAP.

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. The expected future cash flows to retire the assets are significant unobservable inputs used to measure fair value. HECO estimates these cash flows based on the cost of past asset retirements and contractor cost estimates. As of March 31, 2012, the undiscounted future cash outflows used were $33 million. Also, see Note 5.

8 · 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

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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.

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

Three months ended March 31
(in thousands)	2012			2011
Operating income from regulated and nonregulated activities before income taxes (per HEI consolidated statements of income)	$	57,254		$	45,208
Deduct:
Income taxes on regulated activities	(17,365		)	(11,610		)
Revenues from nonregulated activities	(1,672		)	(1,034		)
Add:
Expenses from nonregulated activities	364			155
Operating income from regulated activities after income taxes (per HECO consolidated statements of income)	$	38,581		$	32,719

10 · Subsequent event

On April 19, 2012, HECO, MECO and HELCO issued through a private placement taxable unsecured senior notes (the HECO Notes, MECO Notes and HELCO Notes, and together, the Notes) in the aggregate principal amounts of $327 million, $59 million and $31 million, respectively, as follows:

(in thousands)
Long-term debt, net
HECO, 3.79%, series 2012A, due 2018	$	30,000
HELCO, 3.79%, series 2012A, due 2018	11,000
MECO, 3.79%, series 2012A, due 2018	9,000
HECO, 4.03%, series 2012B, due 2020	62,000
MECO, 4.03%, series 2012B, due 2020	20,000
HECO, 4.55%, series 2012C, due 2023	50,000
HELCO, 4.55%, series 2012B, due 2023	20,000
MECO, 4.55%, series 2012C, due 2023	30,000
HECO, 4.72%, series 2012D, due 2029	35,000
HECO, 5.39%, series 2012E, due 2042	150,000
Long-term debt, net	$	417,000

All proceeds of the Notes, except the Series 2012E of the HECO Notes, have been applied ($267 million in the aggregate), together with such additional funds as are required, to defease or redeem special purpose revenue bonds and refunding special purpose revenue bonds issued by the Department of Budget and Finance of the State of Hawaii for the benefit of the utilities, which outstanding bonds have an aggregate principal amount of $271 million and stated interest rates ranging from 5.45% to 6.20%.

The note agreements contain customary representations and warranties, affirmative and negative covenants, and events of default (the occurrence of which may result in some or all of the Notes becoming immediately due and payable) and provisions requiring the maintenance by HECO and each of MECO and HELCO of certain financial ratios generally consistent with those in HECO’s existing amended revolving noncollateralized credit agreement.

All of the Notes may be prepaid in whole or in part at any time at the prepayment price of the principal amount of the Notes plus payment of a “Make-Whole Amount.” Each of the note agreements also (a) requires the utilities to offer to prepay the Notes (without a Make-Whole Amount) in the event that HEI ceases to own 100% of the common stock or other securities of HECO that is ordinarily entitled, in the absence of contingencies, to vote in the election of HECO directors unless, at the time of such cessation of ownership and at all times during the period of 90 consecutive days thereafter, the long-term unsecured, unenhanced debt of HECO maintains an investment grade rating by at least one rating agency or, if more than one rating agency rates such indebtedness, then by each such rating agency, and (b) permits the utilities to offer to prepay Notes (without a Make-Whole amount) in the event of a sale of assets that would otherwise constitute a covenant default.

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HECO’s consolidated long-term debt was reduced at the end of the first quarter of 2012 as a result of the defeaseance on March 30, 2012 of $57.5 million of 4.95% refunding special purpose revenue bonds issued for the benefit of HECO and its subsidiaries and maturing on April 1, 2012.

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 and (b) 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.

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Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Income (Loss) (unaudited)

Three months ended March 31, 2012

(in thousands)	HECO			HELCO		MECO		RHI		UBC	Reclassifications and eliminations		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	1,064			101		111		(1	)	—	(10	)	1,265
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 (credits)	(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		RHI		UBC	Reclassifications and eliminations		HECO Consolidated
Net income (loss) for common stock	$	27,300		6,611		1,880		(1	)	—	(8,490	)	$	27,300
Other comprehensive income, net of taxes:
Retirement benefit plans:
Less: amortization of net loss, prior service gain and transition obligation included 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, net of taxes	77			6		6		—		—	(12	)	77
Comprehensive income attributable to common shareholder	$	27,377		6,617		1,886		(1	)	—	(8,502	)	$	27,377

39

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Income (Loss) (unaudited)

Three months ended March 31, 2011

(in thousands)	HECO			HELCO		MECO		RHI		UBC		Reclassifications and eliminations		HECO Consolidated
Operating revenues	$	449,824		99,635		94,842		—		—		—		$	644,301
Operating expenses
Fuel oil	183,266			26,491		51,103		—		—		—		260,860
Purchased power	112,751			30,022		5,185		—		—		—		147,958
Other operation	47,255			8,268		10,008		—		—		—		65,531
Maintenance	21,192			3,851		4,153		—		—		—		29,196
Depreciation	22,883			8,323		5,226		—		—		—		36,432
Taxes, other than income taxes	41,889			9,173		8,933		—		—		—		59,995
Income taxes	4,698			3,769		3,143		—		—		—		11,610
Total operating expenses	433,934			89,897		87,751		—		—		—		611,582
Operating income	15,890			9,738		7,091		—		—		—		32,719
Other income (loss)
Allowance for equity funds used during construction	960			83		201		—		—		—		1,244
Equity in earnings of subsidiaries	11,490			—		—		—		—		(11,490	)	—
Other, net	732			106		92		(2	)	(3	)	(15	)	910
Total other income (loss)	13,182			189		293		(2	)	(3	)	(11,505	)	2,154
Interest and other charges
Interest on long-term debt	9,130			2,985		2,268		—		—		—		14,383
Amortization of net bond premium and expense	513			143		127		—		—		—		783
Other interest charges	378			81		95		—		—		(15	)	539
Allowance for borrowed funds used during construction	(408		)	(33	)	(79	)	—		—		—		(520		)
Total interest and other charges	9,613			3,176		2,411		—		—		(15	)	15,185
Net income (loss)	19,459			6,751		4,973		(2	)	(3	)	(11,490	)	19,688
Preferred stock dividend of subsidiaries	—			134		95		—		—		—		229
Net income (loss) attributable to HECO	19,459			6,617		4,878		(2	)	(3	)	(11,490	)	19,459
Preferred stock dividends of HECO	270			—		—		—		—		—		270
Net income (loss) for common stock	$	19,189		6,617		4,878		(2	)	(3	)	(11,490	)	$	19,189

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Comprehensive Income (Loss) (unaudited)

Three months ended March 31, 2011

(in thousands)	HECO			HELCO		MECO		RHI		UBC		Reclassifications and eliminations		HECO Consolidated
Net income (loss) for common stock	$	19,189		6,617		4,878		(2	)	(3	)	(11,490	)	$	19,189
Other comprehensive income (loss), net of taxes:
Retirement benefit plans:
Less: amortization of net loss, prior service gain and transition obligation included in net periodic benefit cost, net of tax benefits	2,274			357		283		—		—		(640	)	2,274
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes	(2,247		)	(357	)	(286	)	—		—		643		(2,247		)
Other comprehensive income (loss), net of taxes	27			—		(3	)	—		—		3		27
Comprehensive income (loss) attributable to common shareholder	$	19,216		6,617		4,875		(2	)	(3	)	(11,487	)	$	19,216

40

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Balance Sheet (unaudited)

March 31, 2012

(in thousands)	HECO			HELCO		MECO		RHI	UBC	Reclassifications and eliminations		HECO Consolidated
Assets
Utility plant, at cost
Land	$	43,306		5,182		3,016		—	—	—		$	51,504
Plant and equipment	3,125,717			1,051,112		918,251		—	—	—		5,095,080
Less accumulated depreciation	(1,146,385		)	(420,069	)	(414,510	)	—	—	—		(1,980,964		)
Construction in progress	126,837			11,494		12,336		—	—	—		150,667
Net utility plant	2,149,475			647,719		519,093		—	—	—		3,316,287
Investment in wholly owned subsidiaries, at equity	520,247			—		—		—	—	(520,247	)	—
Current assets
Cash and cash equivalents	1,980			2,676		1,088		80	26	—		5,850
Advances to affiliates	—			35,900		4,000		—	—	(39,900	)	—
Customer accounts receivable, net	108,241			27,597		23,041		—	—	—		158,879
Accrued unbilled revenues, net	92,140			18,442		16,060		—	—	—		126,642
Other accounts receivable, net	10,958			1,848		2,072		—	—	(6,807	)	8,071
Fuel oil stock, at average cost	139,856			21,275		24,875		—	—	—		186,006
Materials and supplies, at average cost	27,416			5,828		13,505		—	—	—		46,749
Prepayments and other	19,056			3,302		9,250		—	—	(398	)	31,210
Regulatory assets	24,005			1,156		1,203		—	—	—		26,364
Total current assets	423,652			118,024		95,094		80	26	(47,105	)	589,771
Other long-term assets
Regulatory assets	481,165			86,036		84,109		—	—	—		651,310
Unamortized debt expense	8,233			2,383		1,861		—	—	—		12,477
Other	57,523			12,429		16,267		—	—	—		86,219
Total other long-term assets	546,921			100,848		102,237		—	—	—		750,006
Total assets	$	3,640,295		866,591		716,424		80	26	(567,352	)	$	4,656,064
Capitalization and liabilities
Capitalization
Common stock equity	$	1,415,200		284,388		235,753		80	26	(520,247	)	$	1,415,200
Cumulative preferred stock—not subject to mandatory redemption	22,293			7,000		5,000		—	—	—		34,293
Long-term debt, net	629,774			204,118		166,710		—	—	—		1,000,602
Total capitalization	2,067,267			495,506		407,463		80	26	(520,247	)	2,450,095
Current liabilities
Short-term borrowings-nonaffiliates	84,942			—		—		—	—	—		84,942
Short-term borrowings-affiliate	39,900			—		—		—	—	(39,900	)	—
Accounts payable	114,634			27,241		16,816		—	—	—		158,691
Interest and preferred dividends payable	11,443			3,888		3,509		—	—	(5	)	18,835
Taxes accrued	125,311			30,588		27,772		—	—	(398	)	183,273
Other	40,144			10,516		15,089		—	—	(6,802	)	58,947
Total current liabilities	416,374			72,233		63,186		—	—	(47,105	)	504,688
Deferred credits and other liabilities
Deferred income taxes	250,654			63,610		43,710		—	—	—		357,974
Regulatory liabilities	215,187			63,472		37,901		—	—	—		316,560
Unamortized tax credits	36,183			12,982		12,776		—	—	—		61,941
Retirement benefits liability	355,871			59,935		62,711		—	—	—		478,517
Other	73,087			21,259		13,904		—	—	—		108,250
Total deferred credits and other liabilities	930,982			221,258		171,002		—	—	—		1,323,242
Contributions in aid of construction	225,672			77,594		74,773		—	—	—		378,039
Total capitalization and liabilities	$	3,640,295		866,591		716,424		80	26	(567,352	)	$	4,656,064

41

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Balance Sheet (unaudited)

December 31, 2011

(in thousands)	HECO			HELCO		MECO		RHI	UBC	Reclassifications and eliminations		HECO Consolidated
Assets
Utility plant, at cost
Land	$	43,316		5,182		3,016		—	—	—		$	51,514
Plant and equipment	3,091,908			1,048,599		911,520		—	—	—		5,052,027
Less accumulated depreciation	(1,141,839		)	(414,769	)	(410,286	)	—	—	—		(1,966,894		)
Construction in progress	117,625			8,144		13,069		—	—	—		138,838
Net utility plant	2,111,010			647,156		517,319		—	—	—		3,275,485
Investment in wholly owned subsidiaries, at equity	517,216			—		—		—	—	(517,216	)	—
Current assets
Cash and cash equivalents	44,819			3,383		496		82	26	—		48,806
Advances to affiliates	—			46,150		18,500		—	—	(64,650	)	—
Customer accounts receivable, net	130,190			28,602		24,536		—	—	—		183,328
Accrued unbilled revenues, net	103,328			18,499		15,999		—	—	—		137,826
Other accounts receivable, net	8,987			1,186		3,008		—	—	(4,558	)	8,623
Fuel oil stock, at average cost	128,037			19,217		24,294		—	—	—		171,548
Materials and supplies, at average cost	25,096			4,700		13,392		—	—	—		43,188
Prepayments and other	21,135			6,575		7,033		—	—	(141	)	34,602
Regulatory assets	18,038			1,115		1,130		—	—	—		20,283
Total current assets	479,630			129,427		108,388		82	26	(69,349	)	648,204
Other long-term assets
Regulatory assets	478,851			86,394		83,861		—	—	—		649,106
Unamortized debt expense	8,446			2,464		1,876		—	—	—		12,786
Other	58,672			11,843		15,846		—	—	—		86,361
Total other long-term assets	545,969			100,701		101,583		—	—	—		748,253
Total assets	$	3,653,825		877,284		727,290		82	26	(586,565	)	$	4,671,942
Capitalization and liabilities
Capitalization
Common stock equity	$	1,406,084		281,055		236,054		81	26	(517,216	)	$	1,406,084
Cumulative preferred stock—not subject to mandatory redemption	22,293			7,000		5,000		—	—	—		34,293
Long-term debt, net	629,757			204,110		166,703		—	—	—		1,000,570
Total capitalization	2,058,134			492,165		407,757		81	26	(517,216	)	2,440,947
Current liabilities
Current portion of long-term debt	42,580			7,200		7,720		—	—	—		57,500
Short-term borrowings-affiliate	64,650			—		—		—	—	(64,650	)	—
Accounts payable	140,044			29,616		18,920		—	—	—		188,580
Interest and preferred dividends payable	12,648			4,074		2,762		—	—	(1	)	19,483
Taxes accrued	152,315			37,638		34,956		—	—	(141	)	224,768
Other	50,828			9,478		13,603		1	—	(4,557	)	69,353
Total current liabilities	463,065			88,006		77,961		1	—	(69,349	)	559,684
Deferred credits and other liabilities
Deferred income taxes	236,890			61,044		39,929		—	—	—		337,863
Regulatory liabilities	215,401			62,049		38,016		—	—	—		315,466
Unamortized tax credits	34,877			12,951		12,786		—	—	—		60,614
Retirement benefits liability	368,245			62,036		64,840		—	—	—		495,121
Other	72,418			22,391		11,235		—	—	—		106,044
Total deferred credits and other liabilities	927,831			220,471		166,806		—	—	—		1,315,108
Contributions in aid of construction	204,795			76,642		74,766		—	—	—		356,203
Total capitalization and liabilities	$	3,653,825		877,284		727,290		82	26	(586,565	)	$	4,671,942

42

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		RHI		UBC	Reclassifications and eliminations		HECO Consolidated
Balance, December 31, 2011	$	1,406,084		281,055		236,054		81		26	(517,216	)	$	1,406,084
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	$	1,415,200		284,388		235,753		80		26	(520,247	)	$	1,415,200

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Changes in Common Stock Equity (unaudited)

Three months ended March 31, 2011

(in thousands)	HECO			HELCO		MECO		RHI		UBC		Reclassifications and eliminations		HECO Consolidated
Balance, December 31, 2010	$	1,337,398		270,573		230,137		86		5		(500,801	)	$	1,337,398
Net income (loss) for common stock	19,189			6,617		4,878		(2	)	(3	)	(11,490	)	19,189
Other comprehensive income (loss), net of taxes	27			—		(3	)	—		—		3		27
Common stock dividends	(17,640		)	(4,031	)	(3,001	)	—		—		7,032		(17,640		)
Balance, March 31, 2011	$	1,338,974		273,159		232,011		84		2		(505,256	)	$	1,338,974

43

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Cash Flows (unaudited)

Three months ended March 31, 2012

(in thousands)	HECO			HELCO		MECO		RHI		UBC	Elimination addition to (deduction from) cash flows		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 in accounts receivable	19,978			343		2,431		—		—	2,249		25,001
Decrease (increase) in accrued unbilled revenues	11,188			57		(61	)	—		—	—		11,184
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		)
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 affiliate	—			10,250		14,500		—		—	(24,750	)	—
Net cash provided by (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 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		82		26	—		48,806
Cash and cash equivalents, end of period	$	1,980		2,676		1,088		80		26	—		$	5,850

44

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Cash Flows (unaudited)

Three months ended March 31, 2011

(in thousands)	HECO			HELCO		MECO		RHI		UBC		Elimination addition to (deduction from) cash flows		HECO Consolidated
Cash flows from operating activities:
Net income (loss)	$	19,459		6,751		4,973		(2	)	(3	)	(11,490	)	$	19,688
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Equity in earnings of subsidiaries	(11,515		)	—		—		—		—		11,490		(25		)
Common stock dividends received from subsidiaries	7,057			—		—		—		—		(7,032	)	25
Depreciation of property, plant and equipment	22,883			8,323		5,226		—		—		—		36,432
Other amortization	1,167			660		461		—		—		—		2,288
Change in deferred income taxes	7,674			2,849		2,998		—		—		—		13,521
Change in tax credits, net	592			154		9		—		—		—		755
Allowance for equity funds used during construction	(960		)	(83	)	(201	)	—		—		—		(1,244		)
Change in cash overdraft	—			(2,527	)	(161	)	—		—		—		(2,688		)
Changes in assets and liabilities:
Increase in accounts receivable	(3,982		)	(1,192	)	(3,927	)	—		—		(2,170	)	(11,271		)
Decrease (increase) in accrued unbilled revenues	(10,127		)	(514	)	1,239		—		—		—		(9,402		)
Decrease (increase) in fuel oil stock	6,381			(685	)	(9,209	)	—		—		—		(3,513		)
Increase in materials and supplies	(38		)	(415	)	(612	)	—		—		—		(1,065		)
Increase in regulatory assets	(6,518		)	(708	)	(646	)	—		—		—		(7,872		)
Decrease in accounts payable	(35,481		)	(1,603	)	(5,039	)	—		—		—		(42,123		)
Change in prepaid and accrued income and utility revenue taxes	(2,688		)	270		2,658		—		—		—		240
Contributions to defined benefit pension and other postretirement benefit plans	(23,871		)	(3,390	)	(3,432	)	—		—		—		(30,693		)
Change in other assets and liabilities	4,712			1,143		1,287		—		3		2,170		9,315
Net cash provided by (used in) operating activities	(25,255		)	9,033		(4,376	)	(2	)	—		(7,032	)	(27,632		)
Cash flows from investing activities:
Capital expenditures	(25,594		)	(6,752	)	(5,210	)	—		—		—		(37,556		)
Contributions in aid of construction	3,218			2,122		409		—		—		—		5,749
Advances from affiliate	—			150		12,500		—		—		(12,650	)	—
Net cash provided by (used in) investing activities	(22,376		)	(4,480	)	7,699		—		—		(12,650	)	(31,807		)
Cash flows from financing activities:
Common stock dividends	(17,640		)	(4,031	)	(3,001	)	—		—		7,032		(17,640		)
Preferred stock dividends of HECO and subsidiaries	(270		)	(134	)	(95	)	—		—		—		(499		)
Net decrease in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less	(12,650		)	—		—		—		—		12,650		—
Other	(4		)	—		—		—		—		—		(4		)
Net cash used in financing activities	(30,564		)	(4,165	)	(3,096	)	—		—		19,682		(18,143		)
Net increase (decrease) in cash and cash equivalents	(78,195		)	388		227		(2	)	—		—		(77,582		)
Cash and cash equivalents, beginning of period	121,019			1,229		594		89		5		—		122,936
Cash and cash equivalents, end of period	$	42,824		1,617		821		87		5		—		$	45,354

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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 2011 and should be read in conjunction with the 2011 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 2011, as well as the quarterly (as of and for the three months ended March 31, 2012) 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)	2012		2011		change	significant change*
Revenues	$	814,860	$	710,633	15	Increase for the electric utility segment
Operating income	75,816		63,375		20	Increase for the electric utility and bank segments, partly offset by a decrease for the “other” segment
Net income for common stock	38,316		28,462		35	Higher operating income, lower “interest expense—other than on deposit liabilities and other bank borrowings” and higher AFUDC, partly offset by higher income taxes**
Basic earnings per common share	$	0.40	$	0.30	33	Higher net income, partly offset by higher weighted average shares outstanding
Weighted-average number of common shares outstanding	96,167		94,817		1	Issuances of shares under the HEI Dividend Reinvestment and Stock Purchase Plan and Company employee plans

*Also, see segment discussions which follow.

**The Company’s effective tax rates (combined federal and state) for the first quarters of 2012 and 2011 were 35% and 36%, respectively.

Dividends.  The payout ratios for the first quarter of 2012 and full year 2011 were 78% and 86%, 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 (HTA); Honolulu Board of REALTORS®; Bureau of Economic Analysis and national and local newspapers).

Hawaii’s tourism industry, a significant driver of Hawaii’s economy, continued to improve in the first quarter of 2012. State visitor arrivals grew by 7.8% in the first quarter of 2012 over the first quarter of 2011. State visitor expenditures also continued to grow, increasing by 12.5% in the first quarter of 2012 over the same period in 2011. (Note: Statistics excluded data for February 29, 2012 for comparative purposes.) Hotel occupancies and room rates remain higher for the first quarter of 2012 compared to the same period in 2011. The outlook for the visitor industry remains positive with the Hawaii Tourism Authority expecting a 7.5% increase in airline seat capacity in the second quarter of 2012.

Hawaii’s unemployment rate was 6.4% in March 2012, lower than the 6.6% in March 2011, and lower than the March 2012 national unemployment rate of 8.2%. Hawaii’s unemployment rate has slowly improved since October 2011 while the national unemployment rate fell to the lowest level since February 2009. Hawaii jobs continued to grow during the first three months of 2012, but not enough to reach 2008 levels.

For the first quarter of 2012 compared to the first quarter of 2011, the median sales price for single family residential homes on Oahu increased by 10.4%, but Oahu home sales decreased 1.3%. Also for the first quarter of

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2012 compared to the first quarter of 2011, closed sales for Oahu condominiums fell 6.0% while median condominium prices were unchanged.

The price of a barrel of West Texas Intermediate (WTI) crude oil reached $113.93 on April 29, 2011, its highest level since 2008, but declined somewhat to average $103 per barrel in the first quarter of 2012. However, while mainland WTI U.S. prices declined below the April 2011 price, Hawaii’s petroleum product prices, which reflect supply and demand in the Asia-Pacific region and the price of crude oil in international markets, have remained high, due in part to the dramatic reduction in Japan’s nuclear production following the tragic earthquake and tsunami in March 2011. With the increased regional demand for oil, the utilities’ oil prices have remained high through the first quarter of 2012.

The Federal Open Market Committee (FOMC) held the federal funds rate target at 0 to 0.25% on March 13, 2012 based on the current moderate economic outlook and expectations of only temporary inflationary pressure from recent increases in oil and gasoline prices. The FOMC also expects the low federal funds rate to continue through late 2014, citing low rates of resource utilization and a subdued outlook for inflation. The FOMC continued its program, announced in September 2011, to extend the average maturity of the System Open Market Account portfolio to support a stronger economic recovery in a context of price stability.

Overall, Hawaii’s economy is expected to see only modest growth in 2012 and 2013 with local economic growth supported by moderate improvement in the U.S. economy and impeded by continued uncertainty in global economies.

Recent tax developments.  The Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act (the 2010 Act) enacted at the end of 2010 contained major tax provisions which continue to impact the Company. Specifically the 50% and 100% bonus depreciation provisions for certain property result in an estimated net increase in federal tax depreciation of $153 million for 2011 and $116 million for 2012, primarily attributable to the utilities. In addition, the 2010 Act provided for a 2% reduction in the Social Security tax on employees for 2011. This 2% reduction in social security tax has been extended through the end of 2012.

In December 2011, the Internal Revenue Service (IRS) issued temporary regulations, which provide a framework for determining whether expenditures are deductible as repairs. Although labeled “temporary,” these regulations have the binding effect of final regulations and are effective January 1, 2012. The IRS is expected to issue additional revenue procedures containing transitional rules and guidance. The Company will analyze these regulations and any subsequently issued guidance for their impacts and for the opportunities they present for 2012 and future years.

On April 30, 2012, HEI and the IRS reached agreement on the adjustments proposed by the IRS in its examination of tax years 2007 to 2009, subject to final approval by the U.S. Congress Joint Committee on Taxation. The IRS accepted the Company’s repair deduction claimed in its 2009 income tax return.

Retirement benefits.  For the first quarter of 2012, the Company’s and HECO and its subsidiaries’ defined benefit retirement plans’ assets generated a gain, after investment management fees, of 9.2%. The market value of the defined benefit retirement plans’ assets of the Company as of March 31, 2012 was $1.1 billion (including $985 million for HECO and its subsidiaries) compared to $983 million at December 31, 2011 (including $893 million for HECO and its subsidiaries).

HEI and HECO and its subsidiaries estimate that the cash funding for their qualified defined benefit pension plans in 2012 will be about $2 million and $102 million, respectively, which is expected to fully satisfy the minimum required contribution, including requirements of the utilities’ pension tracking mechanisms and the plans’ funding policy. The increase in expected contributions is driven by the minimum funding requirements under the Pension Protection Act of 2006.

Commitments and contingencies.  See Note 9 of HEI’s “Notes to Consolidated Financial Statements.”

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“Other” segment.

	Three months ended March 31						%
(in thousands)	2012			2011			change	Primary reason(s) for significant change
Revenues	$	(2	)	$	(15	)	NM
Operating loss	(4,350		)	(3,587		)	NM	Higher administrative and general expenses
Net loss	(4,861		)	(4,578		)	NM	Higher operating loss, partly offset by lower interest expense

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; The Old Oahu Tug Service, Inc., a maritime freight transportation company that ceased operations in 1999; and Pacific Energy Conservation Services, Inc., a contract services company which provided windfarm operational and maintenance services to an affiliated electric utility until the windfarm was dismantled (dissolved in April 2011); 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, 2012				December 31, 2011
Short-term borrowings—other than bank	$	156	5	%	$	69	2	%
Long-term debt, net—other than bank	1,283		43		1,340		45
Preferred stock of subsidiaries	34		1		34		1
Common stock equity	1,554		51		1,532		52
	$	3,027	100	%	$	2,975	100	%

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

	Three months ended March 31, 2012		Balance
(in millions)	Average balance		March 31, 2012		December 31, 2011
Short-term borrowings(1)
Commercial paper	$	59	$	71	$	69
Line of credit draws	—		—		—
Undrawn capacity under HEI’s line of credit facility (expiring December 5, 2016)	125		125		125

(1)This table does not include HECO’s separate commercial paper issuances and line of credit facilities and draws, which are disclosed below under “Electric utility—Financial Condition—Liquidity and capital resources. At April 29, 2012, HEI had $68 million of 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, 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, 2012, as calculated under the credit agreement) and “Consolidated Net Worth” of at least $975 million (Net Worth of $1.6 billion as of March 31, 2012, as calculated under the credit agreement), or if HEI no longer owns HECO. The commitment fee and interest

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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.

HEI raised $12 million through the issuance of approximately 0.5 million shares of common stock under the DRIP, the HEIRSP, ASB 401(k) Plan and other plans during the first quarter of 2012. From August 18, 2011 to January 8, 2012, HEI had been satisfying the requirements of the DRIP, HEIRSP, ASB 401(k) Plan and other plans through open market purchases of its common stock. On January 9, 2012, HEI began satisfying these requirements through new issuances of its common stock.

On March 24, 2011, HEI issued $125 million of Senior Notes via a private placement ($75 million of 4.41% notes due March 24, 2016 and $50 million of 5.67% notes due March 24, 2021). HEI used part of the net proceeds from the issuance of the Senior Notes to pay down commercial paper (originally issued to refinance $50 million of 4.23% medium-term notes that matured on March 15, 2011) and ultimately used the remaining proceeds to refinance part of the $100 million of 6.141% medium-term notes that matured on August 15, 2011. The 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, expiring on May 7, 2013. For example, it is an event of default if HEI fails to maintain an unconsolidated “Capitalization Ratio” (funded debt) of 50% or less (ratio of 19% as of March 31, 2012, as calculated under the agreement) or “Consolidated Net Worth” of at least $975 million (Net Worth of $1.6 billion as of March 31, 2012, as calculated under the agreement).

For the first quarter of 2012, net cash used by operating activities of consolidated HEI was $16 million. Net cash used by investing activities for the same period was $81 million, primarily due to net increases in ASB’s loans held for investment, HECO’s consolidated capital expenditures and a net increase in ASB’s investment and mortgage-related securities. Net cash provided by financing activities during this period was $63 million as a result of several factors, including net increases in short-term borrowings and deposit liabilities and proceeds from the issuance of common stock under HEI plans, partly offset by repayments of long-term debt and 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 2012, HECO and ASB paid dividends to HEI of $18 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 50 to 51, 66 to 69, and 79 to 81 of HEI’s MD&A included in Part II, Item 7 of HEI’s 2011 Form 10-K.

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

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 51 to 52, 69 to 70, and 81 to 82 of HEI’s MD&A included in Part II, Item 7 of HEI’s 2011 Form 10-K.

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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 2011 and the first quarter of 2012, the utilities continued to make significant progress in implementing their clean energy strategies and the PUC issued several important regulatory decisions, all of which are key steps to support Hawaii’s efforts to reduce its dependence on oil. Included in the PUC decisions were a number of interim and final rate case decisions (see table in “Most recent rate proceedings” below). Additional PUC decisions are needed that will allow the utilities to recover their increasing expenditures for clean energy and reliability on a more timely basis.

Regulatory.  With PUC approval, decoupling was implemented by HECO on March 1, 2011, by HELCO on April 9, 2012 and by MECO on May 4, 2012. Decoupling is a regulatory model that is intended to facilitate meeting the State’s goals to transition to a clean energy economy and achieve an aggressive renewable portfolio standard. The decoupling model implemented in Hawaii delinks revenues from sales and includes annual revenue adjustments for O&M expenses and rate base additions. The decoupling mechanism has three components: (1) a sales decoupling component via a revenue balancing account (RBA), (2) a revenue escalation component via a revenue adjustment mechanism (RAM) and (3) an earnings sharing mechanism, which would provide for a reduction of revenues between rate cases in the event the utility exceeds the return on average common equity (ROACE) allowed in its most recent rate case. Decoupling provides for more timely cost recovery and earning on investments. The implementation of decoupling has resulted in an improvement in HECO’s under-earning situation that has existed over the last several years. Prior to and during the transition to decoupling, however, the utilities’ returns have been well below PUC-allowed returns.

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

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

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

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

Critical to improving earnings are the issuance of an interim decision in MECO’s 2012 test year rate case and the outcome of the regulatory audits to be conducted on certain major projects. See “Major projects” in Note 5 to HECO’s “Notes to Consolidated Financial Statements” for a discussion of the regulatory audits ordered by the PUC.

Future earnings growth is also dependent on rate base growth. The utilities’ five-year 2012-2016 forecast reflects net capital expenditures of $3.0 billion and a compounded annual rate base growth rate of approximately 7% to 9%. Many of the major initiatives within this forecast are expected to be completed beyond the 5-year period. Major initiatives which comprise approximately 40% of the 5-year plan include projects relating to: (1) environmental compliance; (2) fuel infrastructure investments; (3) new generation; and (4) infrastructure investments to integrate more energy from renewables into the system. Estimates for these initiatives could change with time, based on external factors such as the timing and technical requirements for environmental compliance.

Actual and PUC-allowed returns were as follows:

%	Return on average rate base (RORB)*					ROACE**
Twelve months ended March 31, 2012	HECO		HELCO	MECO		HECO		HELCO		MECO
Utility returns	7.42		8.81	6.15		7.7		9.6		6.4
PUC-allowed returns	8.11		8.59	8.43		10.0		10.5		10.5
Difference	(0.69	)	0.22	(2.28	)	(2.3	)	(0.9	)	(4.1	)

*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.

The ROACE gap is expected to continue as a result of disallowed expenses and the timing of general rate case decisions or, in non-rate case years, the effective date of the revenue adjustment mechanism (RAM) adjustment. In addition, HECO’s Customer Information System (CIS) is scheduled to go into service in the second quarter of 2012. While HECO (and not HELCO or MECO) may continue to defer the project costs until the completion of the regulatory audit, carrying charges are accrued only at HECO’s debt rate, similar to the $32 million of the CIP CT-1 costs that are subject to a regulatory audit.

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Decoupling implementation.  Effective March 1, 2011, as part of the decoupling implementation, HECO established the RBA and started recording the difference between target revenues from its HECO 2009 rate case and actual revenues. Beginning June 1, 2011, HECO began accruing and collecting 2011 RAM revenues of $15 million annually, or $1.3 million per month, which was superseded on July 26, 2011 by the implementation of interim rates in HECO’s 2011 general rate case. The HECO 2011 rate case interim D&O reset target revenues, O&M expenses and rate base for the decoupling mechanisms until a final D&O is issued. Under the decoupling tariff order, in future non-rate case years, HECO will accrue and collect 7/12ths of the annual RAM adjusted revenues in one year and the remaining 5/12ths in the following year. HECO had expected to be able to accrue RAM-adjusted revenues from January 1 of each RAM period. On March 30, 2012, HECO submitted its annual decoupling filing to reflect a RAM adjustment for 2012 of $7.6 million ($3.7 million for O&M costs and $3.9 million for invested capital). The filing also includes the collection of the accrued RBA balance as of December 31, 2011 and associated revenue taxes of $22.7 million. The tariff rate to recover the RAM and the RBA balance will be effective June 1, 2012 through May 31, 2013, unless the PUC suspends the tariff.

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

On April 11, 2012 (revised April 18, 2012), HELCO submitted a proposed tariff for its annual RAM for 2011 and 2012, reflecting a revenue adjustment that will result in a reduction in annual revenues of $2.1 million effective June 18, 2012 to May 31, 2013, unless the PUC suspends the tariff.

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

Results — three months ended March 31, 2012 vs. three months ended March 31, 2011.

Three months ended March 31
2012		2011		Increase (decrease)			(in millions)
$	750	$	645	$	105		Revenues. Increase largely due to:
				$	108		Higher fuel prices
				12			Rate increase granted to HECO for the 2011 test year
				(4		)	Lower KWH sales at HELCO and MECO
328		261		67			Fuel oil expense. Increase largely due to higher fuel costs, partly offset by less KWHs generated
165		148		17			Purchased power expense. Increase largely due to higher purchased energy costs, partly offset by less KWHs purchased
92		95		(3)			“Other operation” and maintenance expenses. Decrease largely due to:
				(4		)	Increase in capitalization of administrative costs, which lowered administrative and general expenses
				(2		)	Regulatory decision allowing reversal of previously expensed Customer Information System (CIS) and Interisland Renewable Energy Network costs
				3			Increase in general liability reserve for an environmental matter
108		96		12			Other expenses. Increase largely due to higher taxes other than income taxes primarily resulting from higher revenue
57		45		12			Operating income. Increase largely due to the interim rate increase for HECO.
27		19		8			Net income for common stock. Increase largely due to:
				7			Interim rate increase
				(1		)	Lower KWH sales at HELCO and MECO net of energy cost savings
				1			Lower O&M expense
				1			Higher AFUDC
2,251		2,350		(99		)	Kilowatthour sales (millions)
67.2		68.1		(0.9		)	Wet-bulb temperature (Oahu average; degrees Fahrenheit)
861		920		(59		)	Cooling degree days (Oahu)
$	134.37	$	101.03	$	33.34		Average fuel oil cost per barrel
447,407		445,151		2,256			Customer accounts (end of period)

Note:  The electric utilities had effective tax rates for the first quarters of 2012 and 2011 of 39% and 37%, respectively.

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Most recent rate proceedings.  The electric utilities initiate PUC proceedings (currently, every third year) 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	Reflects decoupling
HECO
2007
Request	12/22/06	$	99.6	7.1	11.25	8.92	$	1,214	55.10	Yes	No
Interim increase	10/22/07	70.0		5.0	10.70	8.62	1,158		55.10		No
Interim increase (adjusted)	6/20/08	77.9		5.6	10.70	8.62	1,158		55.10		No
Final increase	3/1/11	77.5		5.5	10.70	8.62	1,158		55.10		No
2009
Request (1)	7/3/08	$	97.0	5.2	11.25	8.81	$	1,408	54.30	Yes	No
Interim increase	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) (4)	Pending	58.8		3.4	10.00	8.11	1,386		56.29		Yes
Final increase	Pending
HELCO
2006
Request	5/5/06	$	29.9	9.2	11.25	8.65	$	369	50.83	Yes	No
Interim increase	4/5/07	24.6		7.6	10.70	8.33	357		51.19		No
Final increase (5)	1/14/11	24.6		7.6	10.70	8.33	357		51.19		No
2010
Request (6)	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 (6)	4/9/12	4.5		1.3	10.00	8.31	465		55.91		Yes
MECO
2007
Request	2/23/07	$	19.0	5.3	11.25	8.98	$	386	54.89	Yes	No
Interim increase	12/21/07	13.2		3.7	10.70	8.67	383		54.89		No
Final increase	1/12/11	13.2		3.7	10.70	8.67	383		54.89		No
2010 (7)
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 (8)	7/22/11	$	27.5	6.7	11.00	8.72	$	393	56.85	Yes	Yes

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

(1)In April 2009, HECO reduced this rate increase request by $6.2 million because a new Customer Information System would not be placed in service as originally planned (see Note 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 without the then estimated impacts of the implementation of decoupling as proposed in the PUC’s separate decoupling proceeding and depreciation rates and methodology as proposed by HECO in a separate depreciation proceeding. Including the estimated effects of the implementation of decoupling at the time, the effective revenue request was $94.0 million, or 5.4%. HECO’s request was primarily to pay for major capital projects and higher O&M costs to maintain and improve service reliability and to recover the costs for several proposed programs to help reduce Hawaii’s dependence on imported oil, and to further increase reliability and fuel security.

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

(4)Increase to be effective May 21, 2012.

(5)A participant in the rate case proceeding filed an appeal of the final D&O. Subsequently, the Intermediate Court of Appeals affirmed the PUC’s final D&O.

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

(7)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.

(8)On February 13, 2012, the PUC issued an order instructing MECO and the Consumer Advocate to submit a revised stipulated agreement by March 15, 2012 to provide them the opportunity to incorporate the applicable rulings and decisions in D&Os issued in related proceedings since the first stipulation was filed, including the final decoupling D&O, the final D&Os in the MECO 2007, HECO 2009, and HELCO 2010 test year rate cases (including the findings related to ROACE with the implementation of decoupling), the interim D&O in the HECO 2011 test year rate case and the final D&O in MECO’s depreciation proceeding. MECO’s request is required to pay for O&M expenses and additional investments in plant and equipment required to maintain and improve system reliability and to cover the increased costs to support the integration of more renewable energy generation. The request is for an increase over rates currently in effect. MECO’s electric rates currently in effect include the $8.5 million annual interim rate increase granted in the 2010 test year rate case, which is subject to a final D&O and subject to refund with interest if the final D&O provides for a lesser increase. The Consumer Advocate filed its direct testimony in February 2012 and proposed an increase of $9.6 million, based on a ROACE of 9%, a RORB of 7.59% and an average rate base of $397 million.

HECO 2011 test year rate case. On July 22, 2011, the PUC issued an interim D&O in HECO’s 2011 test year rate case, effective July 26, 2011, granting a total annual interim increase of $53.2 million, or 3.1%, or an increase of $38.2 million in annual revenues, or 2.2%, net of the $15 million of revenues currently being recovered through the decoupling Revenue Adjustment Mechanism (RAM). The interim increase reflected the new depreciation rates and methods approved by the PUC in a separate proceeding, which resulted in a $2 million decrease in depreciation expense effective with interim rates to the end of 2011. The PUC did not approve the portion of the settlement agreement allowing deferral of certain costs and HECO filed a motion for clarification and/or partial reconsideration of the interim D&O’s findings and conclusions on the deferral of costs.

On November 30, 2011, HECO, the Consumer Advocate and the Department of Defense (parties in the proceeding) filed a joint motion requesting a net reduction of $512,000 to the interim increase due to certain modifications to the test year composite income tax rate, and DSM and regulatory commission expenses. On March 13, 2012, the PUC approved the motion. On April 20, 2012, HECO filed proposed tariffs to refund $367,500 (which includes interest) to customers for this reduction going back to the July 26, 2011 effective date of the interim increase.

On February 24, 2012, the PUC issued an order which approved in part and denied in part HECO’s motion for partial reconsideration:

(1)With respect to interisland wind project support costs, the PUC granted HECO’s request to defer the costs for outside contract services retained to support and conduct the request for proposals to provide 200 MW or more of renewable energy for Oahu, but limited the amount to be deferred to $2,850,000 per year for three years. HECO is also allowed to accrue a carrying charge on these deferred costs at the annual short term debt rate of 1.75%. The deferred costs and associated carrying charges will be amortized over three years beginning with the effective date of the interim rates in HECO’s next general rate case. HECO’s next scheduled rate case will be based on a 2014 test year.

(2)With respect to Enterprise Resource Planning/Enterprise Asset Management (ERP/EAM) system evaluation costs, the PUC denied HECO’s request to defer consultant expenses related to the ERP/EAM system evaluation and software and system integrator selection process, but allowed HECO to include $552,000 in its 2011 test year expenses for such costs.

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(3)With respect to operation and maintenance (O&M) expenses related to the Customer Information System (CIS) project, the PUC granted HECO’s request to defer CIS project O&M expenses (limited to $2,258,000 per year in 2011 and 2012 under the settlement agreement) that are to be subject to a regulatory audit of project costs, and allowed HECO to accrue an allowance for funds used during construction on these deferred costs until the completion of the regulatory audit.

The PUC’s order allowing deferral of costs and carrying charges is effective retroactively from the date of the interim D&O (July 22, 2011).

As a result of the order, HECO reflected in the first quarter of 2012, the deferral of $2.3 million ($1.4 million for the interisland wind project support costs and $0.9 million for CIS project O&M expenses) incurred from July 22, 2011 through December 31, 2011 that were previously expensed and will also defer any 2012 costs incurred up to the limitations stated in the order.

On February 3, 2012, the parties signed a settlement agreement, subject to PUC approval, regarding the EOTP Phase 1 project costs. The parties agreed that, in lieu of a regulatory audit, HECO would write-off $9.5 million of gross plant in-service costs associated with EOTP Phase 1, and associated adjustments in the accumulated depreciation, deferred depreciation expense, accumulated deferred income taxes, unamortized state investment tax credits and carrying charges. The settlement agreement resulted in an after-tax charge to net income in the fourth quarter of 2011 of approximately $6 million. The parties agreed to stipulate, subject to PUC approval, to an additional annual interim increase of $5 million to be effective March 1, 2012, based on additional revenue requirements reflecting all remaining EOTP costs not previously included in rates and offset by other minor adjustments to the interim increase that became effective on July 26, 2011.

On March 29, 2012, the PUC approved the settlement agreement, and ordered that the interim increase for HECO’s 2011 test year rate case be adjusted by $5 million. The PUC also ordered that the regulatory audit for EOTP Phase 1 will not be conducted. HECO submitted a revised tariff to reflect an increase in the interim increase effective April 2, 2012.

On April 20, 2012, HECO requested an adjustment of $607,000 (i.e., $552,000 grossed up for revenue taxes) to its interim increase to include the ERP/EAM system evaluation costs in its 2011 test year expenses. HECO has submitted a tariff to reflect an increase in interim increase effective May 21, 2012 for PUC approval.

Management cannot predict or provide any assurances on the timing or ultimate outcome of HECO’s 2011 test year rate case proceeding or the regulatory audit proceeding.

See “Major projects” in Note 5 to HECO’s “Notes to Consolidated Financial Statements” for a discussion of the deferral of project costs in the interim D&O.

HELCO 2010 test year rate case.  On February 8, 2012, the PUC issued a final D&O in HELCO’s 2010 test year rate case, which allows HELCO to implement the decoupling mechanism. In the final D&O, the ROACE of 10.00% and RORB of 8.31% reflect the PUC’s approval of decoupling and other cost-recovery mechanisms that the PUC concluded will cumulatively lower HELCO’s business risk. The PUC also approved the PPAC, which is also intended to lower financial risk of recovery of such expenses. The final D&O accepts HELCO’s proposed austerity adjustment to reduce expenses by $0.4 million in lieu of the PUC’s downward adjustments to the labor costs and employee benefits included in the interim D&O.

On April 4, 2012, the PUC issued an order, approving the revised revenue requirements and tariffs implementing the final D&O. On April 9, 2012, the revised tariffs became effective and HELCO implemented the decoupling mechanism. HELCO began tracking the target revenues and actual recorded revenues via a revenue balancing account, reset the heat rates (by fuel type) to reflect the current complement of HELCO units, 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 requirements of $4.5 million, compared to the interim increase of $5.2 million. Since the lower revenue requirements are due to factors that became effective concurrently with the revised tariffs (lower depreciation rates and lower ROACE), no refund to customers is required.

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	Interim D&O 1/14/2011	Final D&O 4/4/2012
Revenue increase	$5.2 million* (1.5% increase)	$4.5 million (1.3% increase)
Depreciation and amortization expenses	$31.7 million	$31.3 million
ROACE (%)	10.50%	10.0%**
Common equity capitalization (%)	55.91%	55.91%
RORB (%)	8.59%	8.31%
Average rate base amount	$465 million	$465 million

*	Adjusted from $6.0 million to $5.2 million on January 1, 2012 as required under the interim D&O.
**	Reflects decoupling and other cost-recovery mechanisms.

HELCO Notice of Intent.  On May 1, 2012, HELCO filed a Notice of Intent to file an application for a general rate increase on or after July 2, 2012, using a 2013 test year.

MECO 2010 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 in MECO’s 2010 test year rate case proceeding to provide them the opportunity to incorporate the applicable rulings and decisions in D&Os issued in related proceedings since the first stipulation in that rate case was filed in June 2010, including the final decoupling D&O, the final D&Os in the MECO 2007, HECO 2009 and HELCO 2010 test year rate cases (including the findings related to ROACE with the implementation of decoupling), the interim D&O in the HECO 2011 test year rate case and the final D&O in MECO’s depreciation proceeding.

On March 29, 2012, MECO and the Consumer Advocate (the parties) executed and 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. On May 4, 2012, the tariffs implementing the D&O became effective and MECO implemented the decoupling mechanism approved by the PUC in a separate decoupling proceeding. MECO also began tracking the target revenues and actual recorded revenues via an RBA, reset the heat rates and implemented heat rate deadbands. The revised tariffs include the implementation of the purchase power adjustment clause, which allows MECO to recover non-energy purchased power expense through a surcharge mechanism rather than through base rates as currently recovered.

The tariffs that became effective on May 4, 2012, reflect a lower increase in annual revenue requirements than the interim increase previously in effect. Since the lower revenue increase is due to factors that became effective concurrently with the effective date of the revised increase (lower depreciation rates and lower ROACE to reflect decoupling and other cost-recovery mechanisms), no refund to customers is required.

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MECO 2012 test year rate case.  On April 20, 2012, MECO and the Consumer Advocate (the parties) executed and filed an agreement covering all of the issues in MECO’s 2012 test year rate case proceeding. The agreement is subject to approval by the PUC, which may accept or reject the agreement in part or in full. If the PUC does not accept the material terms of the agreement, any (and all) of the parties may withdraw from the agreement and pursue their respective positions in the proceeding without prejudice.

The settlement agreement represents a negotiated compromise of the parties’ respective positions. A comparison of the settlement agreement and MECO’s requested increase in its application for a general rate increase filed on July 22, 2011 is as follows:

	Application 7/22/11	Settlement Agreement
Request amount	$27.5 million (6.7% increase)	$14.9 million (3.6% increase)
ROACE (%)	11.00%	10.0%
Common equity capitalization (%)	56.85%	56.86%
RORB (%)	8.72%	7.91%
Average rate base amount	$393 million	$393 million

The 46% reduction in “Request amount” was comprised as follows:

	(in millions)
Reduction items
Reduction in ROACE to 10%	$	4.0
Agreement to allow deferral and recovery of certain costs via surcharge mechanism or future rate case	2.8
Reduction in operations and maintenance expense	3.8
Reduction in cost of debt	1.7
Other settled items	0.3
Total reduction	$	12.6

The 10% ROACE included in the settlement agreement assumes the implementation of decoupling (consistent with the ROACE allowed in other rate case decisions reflecting decoupling), which is expected to be effective for MECO upon the earlier approval of final rates from its 2010 rate case or interim rates from the 2012 rate case.

The requested increase in revenues is primarily to pay for the cost of improvements to integrate additional renewable energy and improve the reliability of service for MECO’s Maui, Lanai and Molokai customers.

On May 3, 2012, the PUC requested that MECO adjust the settlement agreement to reflect the final D&O issued in the MECO 2010 test year rate case.

The current stipulated schedule approved by the PUC contemplates the issuance of an interim D&O by May 22, 2012. However, management cannot predict or provide any assurances concerning the timing or amount of any interim decision in, or the ultimate outcome of MECO’s 2012 test year rate case proceeding.

Clean energy strategy.  The utilities’ policy is to support efforts to increase renewable energy in Hawaii. The utilities believe their actions will help stabilize customer bills over time as they become less dependent on costly and price-volatile fossil fuel. The utilities’ clean energy strategy will also allow them to meet Hawaii’s RPS law, which requires electric utilities to meet an RPS of 10%, 15%, 25% and 40% by December 31, 2010, 2015, 2020 and 2030, respectively. HECO met the 10% RPS for 2010 with a consolidated RPS of 20.7%, including savings from energy efficiency programs and solar water heating (or 9.5% without DSM energy savings). Energy savings resulting from DSM energy efficiency programs and solar water heating will not count toward the RPS after 2014. The utilities believe they are on track to meet the 2015 RPS.

Recent developments in the utilities’ clean energy strategy include:

·In January 2011, HELCO signed a 20-year contract, subject to PUC approval, with Aina Koa Pono-Ka’u LLC to supply 16 million gallons of biodiesel per year with initial consumption to begin by 2015. In September 2011, however, the PUC denied the utilities’ requested approval of the contract citing the higher cost of the biofuel over the cost of petroleum diesel. HECO, on behalf of HELCO, is negotiating changes to the original contract with AKP with the intent of submitting a new contract to the PUC for its approval.

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

·In February 2011, the PUC opened dockets related to MECO’s and HECO’s plans to proceed with competitive bidding processes to acquire up to approximately 50 MW and 300 MW, respectively, of new, renewable firm dispatchable capacity generation resources, with the initial increments expected to come on line in the 2015 and 2017 timeframes, respectively.

·In July 2011, the PUC directed HECO to submit a draft RFP for the PUC’s consideration for a competitive bidding process for 200 MW or more of renewable energy to be delivered to, or to be sited on, the island of Oahu. In October 2011, HECO filed a draft RFP with the PUC.

·In August 2011, HECO signed a 20-year contract, subject to PUC approval, with Hawaii BioEnergy to supply 10 million gallons per year of biocrude at Kahe Power Plant with initial consumption to begin as early as 2015. In 2011, HECO also signed other contracts, subject to PUC approval, for lesser amounts of biocrude and for biodiesel for testing or operations.

·In May 2012, the PUC opened a docket for HELCO to acquire up to 50 MW of dispatchable renewable geothermal firm capacity generation on the island of Hawaii through a competitive procurement process.

Legislation.  In April 2012, a Hawaii law was enacted which provides that all purchased power costs arising out of power purchase agreements that have been approved by the PUC and are binding obligations on the electric utility, shall be allowed to be recovered by the utility from its customers through one or more surcharges, which shall be established by the PUC.

Commitments and contingencies.  See Note 5 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, 2012				December 31, 2011
Short-term borrowings	$	85	3	%	$	—	—	%
Long-term debt, net	1,001		40		1,058		44
Preferred stock	34		1		34		1
Common stock equity	1,415		56		1,406		55
	$	2,535	100	%	$	2,498	100	%

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, 2012		March 31, 2012		December 31, 2011
Short-term borrowings(1)
Commercial paper	$	10	$	85	$	—
Line of credit draws	—		—		—
Borrowings from HEI	—		—		—
Undrawn capacity under line of credit facility (expiring December 5, 2016)	175		175		175

(1) The maximum amount of external short-term borrowings during the first quarter of 2012 was $85 million. At March 31, 2012, HECO had $36 million and $4 million of short-term borrowings from HELCO and MECO, respectively, which borrowings are eliminated in consolidation. At April 29, 2012, HECO had no outstanding commercial paper, its line of credit facility was undrawn, it had no borrowings from HEI or MECO, and it had borrowings of $41 million from HELCO.

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HECO has a line of credit facility of $175 million (see Note 8 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 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 41% for HELCO and 41% for MECO as of March 31, 2012, as calculated under the credit 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 56% as of March 31, 2012, as calculated under the credit agreement), or if HECO is no longer owned by HEI.

On November 1, 2011, the PUC authorized HECO, HELCO and MECO to issue up to $150 million, $10 million and $10 million, respectively, in one or more registered public offerings or private placements of unsecured obligations bearing taxable interest, on or before December 31, 2012. On December 22, 2011, the PUC authorized HECO, HELCO and MECO to issue up to $217 million, $34 million and $60 million, respectively, in one or more registered public offerings and/or private placements of unsecured taxable debt obligations and/or refunding SPRBs through December 31, 2012 to refinance certain series of outstanding SPRBs. The PUC also approved the use of an expedited approval procedure for the approval of additional financings or refinancings by HECO, HELCO and MECO during 2013 through 2015, subject to certain conditions.

On April 19, 2012, HECO, MECO and HELCO issued through a private placement taxable unsecured senior notes (the HECO Notes, MECO Notes and HELCO Notes, and together, the Notes) in the aggregate principal amounts of $327 million, $59 million and $31 million, respectively. See Note 10 of HECO’s “Notes to Consolidated Financial Statements.”

Operating activities used $11 million in net cash during the first three months of 2012. Investing activities for the same period used net cash of $41 million for capital expenditures, net of contributions in aid of construction. Financing activities for the same period provided net cash of $9 million, primarily due the increase in short-term borrowings, partly offset by repayment of long-term debt and payment of $19 million of common and preferred dividends.

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Bank

RESULTS OF OPERATIONS

	Three months ended March 31				%
(in thousands)	2012		2011		change	Primary reason(s) for significant change
Revenues	$	65,252	$	65,313	—	Lower interest income primarily due to lower yields on earning assets as a result of the lower interest rate environment was offset by higher gain on sale of loans
Operating income	22,912		21,754		5	Lower provision for loan losses
Net income	15,877		13,851		15	Higher operating income and lower income tax expense

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

Management is working to grow its bank franchise in Hawaii and remains focused on maintaining ASB as a high performing community bank with a targeted return on assets of 1.15%-1.2%, net interest margin near 4% and an efficiency ratio in the mid-50s. Despite the revenue pressures across the banking industry, management expects ASB’s low-cost funding base, reduced cost structure and lower-risk profile to continue to deliver strong performance compared to industry peers.

For the three months ended March 31, 2012, ASB reported a strong 1.29% return on assets, net interest margin of 4.04% and 56% efficiency ratio.

Results — three months ended March 31, 2012 vs. three months ended March 31, 2011.

Increase (decrease)	(in millions)
$ —	Net interest income before provision for loan losses. Higher average earning asset balances and lower funding costs were offset by lower yields on earning assets. ASB’s average loan portfolio balance for the three months ended March 31, 2012 was $150 million higher than the 2011 average loan portfolio balance for the same period as the average commercial markets, home equity lines of credit and commercial real estate loan balances increased by $145 million, $119 million and $52 million, respectively. ASB targeted these loan types because of their shorter duration and/or variable rates. Despite a $70 million increase in residential loan production, the average residential loan portfolio decreased by $153 million in connection with ASB’s long-term strategy to manage interest rate risk and position ASB to benefit when interest rates rise. The loan portfolio yield was impacted by the low interest rate environment as new loan production yields were lower than the average portfolio yield and the shift in mix of the loan portfolio. The average investment and mortgage-related securities portfolio balance decreased by $64 million as ASB experienced higher prepayments on the portfolio and funded higher loan originations. Average deposit balances for the three months ended March 31, 2012 increased by $106 million compared to average balances for the same period in 2011 due to an increase in core deposits of $210 million, partly offset by a decrease in term certificates of $104 million. The other borrowings average balance decreased by $5 million due to the payoff of a maturing FHLB advance.
(1)	Provision for loan loss. Decrease primarily due to lower net charge-offs, lower loss reserves for the residential land portfolio due to the contraction of the portfolio and improved credit quality associated with the modest recovery in Hawaii’s economy.
1	Noninterest income. Higher gain on sale of loans as more residential loans were sold in order to manage interest rate risk
—	Noninterest expense. Higher compensation and employee benefits expense was largely offset by a reversal of interest expense for an uncertain tax position
2	Net income. Increase largely due to:
1	Lower provision for loan losses
1	Higher noninterest income

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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	2012						2011
(dollars in thousands)	Average balance			Interest		Average rate (%)	Average balance			Interest		Average rate (%)
Assets:
Other investments (1)	$	251,615		$	97	0.15	$	236,045		$	86	0.15
Investment and mortgage-related securities	595,072			3,879		2.61	659,326			3,809		2.31
Loans receivable (2)	3,696,068			44,888		4.87	3,546,322			46,097		5.22
Total interest-earning assets(3)	4,542,755			48,864		4.31	4,441,693			49,992		4.52
Allowance for loan losses	(38,187		)				(39,827		)
Non-interest-earning assets	432,600						416,309
Total assets	$	4,937,168					$	4,818,175
Liabilities and shareholder’s equity:
Interest-bearing demand and savings deposits	$	2,554,060		$	461	0.07	$	2,460,794		$	704	0.12
Time certificates	541,330			1,318		0.98	645,356			1,889		1.19
Total interest-bearing deposits	3,095,390			1,779		0.23	3,106,150			2,593		0.34
Other borrowings	237,326			1,261		2.10	242,385			1,367		2.26
Total interest-bearing liabilities	3,332,716			3,040		0.36	3,348,535			3,960		0.48
Non-interest bearing liabilities:
Deposits	1,000,099						883,635
Other	110,913						91,517
Total liabilities	4,443,728			3,040		0.28	4,323,687			3,960		0.38
Shareholder’s equity	493,440						494,488
Total liabilities and shareholder’s equity	$	4,937,168					$	4,818,175
Net interest income				$	45,824					$	46,032
Net interest margin (%) (4)						4.04						4.16

(1)	Includes federal funds sold, interest bearing deposits and stock in the FHLB of Seattle.
(2)	Includes loan fees of $1.1 million and $1.2 million for the three months ended March 31, 2012 and 2011, respectively, together with interest accrued prior to suspension of interest accrual on nonaccrual loans, includes nonaccrual loans.
(3)	Interest income includes taxable equivalent basis adjustments, based upon a federal statutory tax rate of 35%, of $0.2 million and $0.1 million for the three months ended March 31, 2012 and 2011, respectively.
(4)	Defined as net interest income as a percentage of average earning assets.

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

Loan originations and mortgage-related securities are ASB’s primary sources of earning assets.

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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, 2012				December 31, 2011
(dollars in thousands)	Balance			% of total	Balance			% of total
Real estate loans:
Residential 1-4 family	$	1,895,442		50.9	$	1,926,774		52.2
Commercial real estate	351,716			9.4	331,931			9.0
Home equity line of credit	562,386			15.1	535,481			14.5
Residential land	39,025			1.1	45,392			1.2
Commercial construction	47,850			1.3	41,950			1.1
Residential construction	3,082			0.1	3,327			0.1
Total real estate loans, net	2,899,501			77.9	2,884,855			78.1
Commercial loans	727,292			19.5	716,427			19.4
Consumer loans	97,262			2.6	93,253			2.5
	3,724,055			100.0	3,694,535			100.0
Less:  Deferred fees and discounts	(12,820		)		(13,811		)
Allowance for loan losses	(38,834		)		(37,906		)
Total loans, net	$	3,672,401			$	3,642,818

The increase in the total loan portfolio during the first quarter of 2012 was primarily due to an increase in ASB’s home equity lines of credit, commercial real estate and commercial loan portfolios.

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, 2012		December 31,2011
Federal agency obligations	33	%	35	%
Mortgage-related securities — FNMA, FHLMC and GNMA	57		55
Municipal bonds	10		10
	100	%	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 the securities carry implied AA+ ratings.

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. Core deposits continue to be strong, as depositors remain risk adverse. 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 declined $15 million from March 31, 2011 to March 31, 2012 due to the payoff of a maturing advance in the fourth quarter of 2011. As of March 31, 2012 and December 31, 2011, ASB’s costing liabilities consisted of 95% deposits and 5% other borrowings. The weighted average cost of deposits for the three months ended March 31, 2012 was 0.17%, compared to 0.26% for the three months ended March 31, 2011 and 0.18% for 2011.

Other factors.  Interest rate risk is a significant risk of ASB’s operations and also represents a market risk factor affecting the fair value of ASB’s investment securities. Increases and decreases in prevailing interest rates generally translate into decreases and increases in fair value of those instruments. In addition, changes in credit spreads also impact the fair values of those instruments.

Although higher long-term interest rates or other conditions in credit markets (such as the effects of the deteriorated subprime market) could reduce the market value of available-for-sale investment and mortgage-related securities and reduce shareholder’s equity through a balance sheet charge to accumulated other comprehensive income (AOCI), this reduction in the market value of investments and mortgage-related securities would not result in a charge to net income in the absence of a sale of such securities or an “other-than-temporary”

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impairment in the value of the securities. As of March 31, 2012 and December 31, 2011, the unrealized gains, net of taxes, on available-for-sale investments and mortgage-related securities (including securities pledged for repurchase agreements) in AOCI was $10 million. See “Item 3. Quantitative and qualitative disclosures about market risk.”

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. During the first quarter of 2011, ASB recorded a provision for loan losses of $4.6 million primarily due to the net charge-offs during the quarter for 1-4 family, residential land, and commercial 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)	2012			2011			2011
Allowance for loan losses, January 1	$	37,906		$	40,646		$	40,646
Provision for loan losses	3,546			4,550			15,009
Less: net charge-offs	2,618			4,382			17,749
Allowance for loan losses, end of period	$	38,834		$	40,814		$	37,906
Ratio of allowance for loan losses, end of period, to end of period loans outstanding	1.05		%	1.14		%	1.03		%
Ratio of net charge-offs during the period to average loans outstanding (annualized)	0.28		%	0.49		%	0.49		%

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 and ASB, has changed and will continue to change as a result of the enactment of the Dodd-Frank Act, which became law in July 2010. Importantly for HEI and ASB, under the Dodd-Frank Act, on July 21, 2011, all of the functions of the Office of Thrift Supervision (OTS) transferred to the OCC, the FDIC, the Federal Reserve Board (FRB) and the Consumer Financial Protection Bureau (Bureau). Supervision and regulation of HEI, as a thrift holding company, moved to the FRB, and supervision and regulation of ASB, as a federally chartered savings bank, moved to the OCC. While the laws and regulations applicable to HEI and ASB did not generally change—the Home Owners Loan Act and regulations issued thereunder still apply—the applicable laws and regulations are being interpreted, and new and amended regulations may be adopted, by the Bureau, FRB, and the OCC. HEI will for the first time be subject to minimum consolidated capital requirements, and ASB may be required to be supervised through ASHI, its intermediate holding company. The Dodd-Frank Act requires regulators, at a minimum, to apply to bank and thrift holding companies leverage and risk-based capital standards that are at least as strict as those in effect at the insured depository institution level on the date the Act became effective, although there will be a phase-in period for meeting these standards. In addition, HEI will continue to be required to serve as a source of strength to ASB in the event of its financial distress. The Dodd-Frank Act also imposes new restrictions on the ability of a savings bank to pay dividends should it fail to remain a qualified thrift lender.

More stringent affiliate transaction rules now apply to ASB in the securities lending, repurchase agreement and derivatives areas. Standards were raised with respect to the ability of ASB to merge with or acquire another institution. In reviewing a potential merger or acquisition, the approving federal agency will need to consider the extent to which the proposed transaction will result in “greater or more concentrated risks to the stability of the U.S. banking or financial system.”

The Dodd-Frank Act 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. ASB may also be subject to new state regulation because of a provision in the Dodd-Frank Act.

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

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state consumer financial law on a “case by case” basis only when (1) the state law would have a discriminatory effect on the bank compared to that on a bank chartered in that state; (2) the state law prevents or significantly interferes with a bank’s exercise of its power; or (3) the state law is preempted by another federal law.

The Dodd-Frank Act also adopts a number of provisions that will impact the mortgage industry, including the imposition of new specific duties on the part of mortgage originators (such as ASB) to act in the best interests of consumers and to take steps to ensure that consumers will have the capability to repay loans they may obtain, as well as provisions imposing new disclosure requirements and requiring appraisal reforms. Regulations are required to be adopted within 18 months after the date that is to be specified by the Secretary of the Treasury for the transfer of consumer protection power to the Bureau.

The “Durbin Amendment” to the Dodd-Frank Act required the FRB to issue rules to ensure that debit card interchange fees are “reasonable and proportional” to the processing costs incurred. In June 2011, the FRB issued a final rule establishing standards for debit card interchange fees and prohibiting network exclusivity arrangements and routing restrictions. Under the final rule, effective October 1, 2011, the maximum permissible interchange fee that an issuer may receive for an electronic debit transaction is 21-24 cents, depending on certain components. For the three months ended March 31, 2012, ASB had earned an average of 53 cents per transaction. As specified in the Dodd-Frank Act, these regulations exempt banks like ASB with less than $10 billion in assets. However, market pressures could very well push the impact down to all banks.

Many of the provisions of the Dodd-Frank Act, as amended, will not become effective until implementing regulations are issued and effective. Thus, management cannot predict the ultimate impact of the Dodd-Frank Act, as amended, on the Company or ASB at this time. Nor can management predict the impact or substance of other future federal or state legislation or regulation, or the application thereof.

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, 2012		December 31, 2011		% change
Total assets	$	4,963	$	4,910	1
Available-for-sale investment and mortgage-related securities	631		624		1
Loans receivable held for investment, net	3,672		3,643		1
Deposit liabilities	4,125		4,070		1
Other bank borrowings	233		233		—

As of March 31, 2012, ASB was one of Hawaii’s largest financial institutions based on assets of $5.0 billion and deposits of $4.1 billion.

As of March 31, 2012, ASB’s unused FHLB borrowing capacity was approximately $1.0 billion. As of March 31, 2012, ASB had commitments to borrowers for loan commitments and unused lines and letters of credit of $1.4 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 2012, net cash provided by ASB’s operating activities was $9 million. Net cash used during the same period by ASB’s investing activities was $40 million, primarily due to purchases of investment and mortgage-related securities of $54 million and a net increase in loans receivable of $34 million, offset by repayments of investment and mortgage-related securities of $46 million. Net cash provided in financing activities during this period was $41 million, primarily due to net increases in deposit liabilities of $55 million, offset by a decrease in mortgage escrow deposits of $4 million and the payment of $10 million in common stock dividends.

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, 2012, 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 11.9% (6.0%) and a total risk-based capital ratio of 12.9% (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 and financial condition. For additional quantitative and qualitative information about the Company’s market risks, see pages 82 to 85, HEI’s Quantitative and Qualitative Disclosures About Market Risk, in Part II, Item 7A of HEI’s 2011 Form 10-K and HECO’s Quantitative and Qualitative Disclosures About Market Risk, which is incorporated into Part II, Item 7A of HECO’s 2011 Form 10-K by reference to Exhibit 99.2.

ASB’s interest-rate risk sensitivity measures as of March 31, 2012 and December 31, 2011 constitute “forward-looking statements” and were as follows:

Change in interest rates	Change in NII (gradual change in interest rates)				Change in EVE (instantaneous change in interest rates)
(basis points)	March 31, 2012		December 31, 2011		March 31, 2012		December 31, 2011
+300	0.6	%	0.5	%	(9.4	)%	(7.4	)%
+200	(0.3	)	(0.3	)	(5.3	)	(3.8	)
+100	(0.4	)	(0.4	)	(2.3	)	(1.5	)
-100	(0.4	)	(0.4	)	(1.7	)	(3.5	)

Management believes that ASB’s interest rate risk position as of March 31, 2012 represents a reasonable level of risk. The net interest income (NII) sensitivities as of December 31, 2011 and March 31, 2012 were very similar. Despite shifts in the balance sheet mix, changes in interest income and expense over a forward looking 12 months with a gradual change in rates resulted in the same NII profile. In the +300 scenario, the interest income benefit from the rate increase is not fully realized until the interest rate on certain loans exceeds their floor rate.

ASB’s base economic value of equity (EVE) was approximately $830 million as of March 31, 2012 compared to $848 million as of December 31, 2011.

The change in EVE was more sensitive to rising rate scenarios as of March 31, 2012 compared to December 31, 2011 due to an increase in rates over the first quarter of 2012, which extended the duration for residential loans and certain investment securities.

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 2012, 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, 2012 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, 2012. Based on their evaluations, as of March 31, 2012, they have concluded that the disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) 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 2012, 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, 2012 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, 2012. Based on their evaluations, as of March 31, 2012, they have concluded that the disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) 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

For information about Risk Factors, see pages 26 to 36 of HEI’s 2011 Form 10-K, and “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Quantitative and Qualitative Disclosures about Market Risk,” HEI’s Consolidated Financial Statements and HECO’s Consolidated Financial Statements herein. Also, see “Forward-Looking Statements” on pages v and vi of HEI’s 2011 Form 10-K, as updated on pages iv and v herein.

Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds

Purchases of HEI common shares were made during the first quarter to satisfy the requirements of certain plans as follows:

ISSUER PURCHASES OF EQUITY SECURITIES

Period*	(a)Total Number of Shares Purchased **	(b)AveragePrice Paidper Share **		(c) Total Number of  Shares Purchased as Part of Publicly Announced Plans or Programs	(d)Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
January 1 to 8, 2012	860	$	25.90	—	NA

NA  Not applicable.

* Trades (total number of shares purchased) are reflected in the month in which the order is placed.

** The purchases were made to satisfy the requirements of the ASB 401(k) Plan for shares purchased for cash or by the reinvestment of dividends by participants under those plans and none of the purchases were made under publicly announced repurchase plans or programs. Average prices per share are calculated exclusive of any commissions payable to the brokers making the purchases for the ASB 401(k) Plan. The repurchased shares were issued for the accounts of the participants under registration statements registering the shares issued under these plans.

Item 5. Other Information

A.    Ratio of earnings to fixed charges.

	Three months ended March 31		Years ended December 31
	2012	2011	2011	2010	2009	2008	2007
HEI and Subsidiaries
Excluding interest on ASB deposits	3.63	2.89	3.22	2.89	2.29	2.06	1.78
Including interest on ASB deposits	3.44	2.70	3.03	2.64	1.95	1.71	1.52
HECO and Subsidiaries	3.77	2.85	3.52	2.88	2.99	3.48	2.43

See HEI Exhibit 12.1 and HECO Exhibit 12.2.

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Item 6. Exhibits

HEI Exhibit 4.1	Letter Amendment effective March 21, 2012, to Trust Agreement (dated as of February 1, 2000) between HEI, ASB and Fidelity Management Trust Company, as Trustee
HEI Exhibit 12.1	Hawaiian Electric Industries, Inc. and Subsidiaries
	Computation of ratio of earnings to fixed charges, three months ended March 31, 2012 and 2011 and years ended December 31, 2011, 2010, 2009, 2008 and 2007
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	Written Statement of Constance H. Lau (HEI Chief Executive Officer) Furnished Pursuant to 18 U.S.C. Section 1350, as Adopted by Section 906 of the Sarbanes-Oxley Act of 2002
HEI Exhibit 32.2	Written Statement of James A. Ajello (HEI Chief Financial Officer) Furnished Pursuant to 18 U.S.C. Section 1350, as Adopted by Section 906 of the Sarbanes-Oxley Act of 2002
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, 2012 and 2011 and years ended December 31, 2011, 2010, 2009, 2008 and 2007
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 32.3	Written Statement of Richard M. Rosenblum (HECO Chief Executive Officer) Furnished Pursuant to 18 U.S.C. Section 1350, as Adopted by Section 906 of the Sarbanes-Oxley Act of 2002
HECO Exhibit 32.4	Written Statement of Tayne S. Y. Sekimura (HECO Chief Financial Officer) Furnished Pursuant to 18 U.S.C. Section 1350, as Adopted by Section 906 of the Sarbanes-Oxley Act of 2002

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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/ David M. Kostecki	By	/s/ Patsy H. Nanbu
	David M. Kostecki		Patsy H. Nanbu
	Vice President-Finance, Controller		Controller
	and Chief Accounting Officer		(Principal Accounting Officer of HECO)
	(Principal Accounting Officer of HEI)
Date: May 9, 2012		Date: May 9, 2012

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