HAWAIIAN ELECTRIC CO INC - Quarter Report: 2012 June (Form 10-Q)

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 June 30, 2012

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

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

State of Hawaii

(State or other jurisdiction of incorporation or organization)

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

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

(Address of principal executive offices and zip code)

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

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

(Registrant’s telephone number, including area code)

Not applicable

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

Indicate by check mark whether 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 July 23, 2012
Hawaiian Electric Industries, Inc. (Without Par Value)		97,082,085 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)

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Hawaiian Electric Industries, Inc. and Subsidiaries

Hawaiian Electric Company, Inc. and Subsidiaries

Form 10-Q—Quarter ended June 30, 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 and six months ended June 30, 2012 and 2011
2		Consolidated Statements of Comprehensive Income - three and six months ended June 30, 2012 and 2011
3		Consolidated Balance Sheets - June 30, 2012 and December 31, 2011
4		Consolidated Statements of Changes in Shareholders’ Equity - six months ended June 30, 2012 and 2011
5		Consolidated Statements of Cash Flows - six months ended June 30, 2012 and 2011
6		Notes to Consolidated Financial Statements

		Hawaiian Electric Company, Inc. and Subsidiaries
26		Consolidated Statements of Income - three and six months ended June 30, 2012 and 2011
26		Consolidated Statements of Comprehensive Income - three and six months ended June 30, 2012 and 2011
27		Consolidated Balance Sheets - June 30, 2012 and December 31, 2011
28		Consolidated Statements of Changes in Common Stock Equity - six months ended June 30, 2012 and 2011
29		Consolidated Statements of Cash Flows - six months ended June 30, 2012 and 2011
30		Notes to Consolidated Financial Statements
50	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
50		HEI Consolidated
55		Electric Utilities
64		Bank
72	Item 3.	Quantitative and Qualitative Disclosures About Market Risk
73	Item 4.	Controls and Procedures

	PART II.	OTHER INFORMATION
74	Item 1.	Legal Proceedings
74	Item 1A.	Risk Factors
74	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds
74	Item 5.	Other Information
75	Item 6.	Exhibits
76	Signatures

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Hawaiian Electric Industries, Inc. and Subsidiaries

Hawaiian Electric Company, Inc. and Subsidiaries

Form 10-Q—Quarter ended June 30, 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
Dodd-Frank Act		Dodd-Frank Wall Street Reform and Consumer Protection Act
DOH		Department of Health of the State of Hawaii
DRIP		HEI Dividend Reinvestment and Stock Purchase Plan
DSM		Demand-side management
ECAC		Energy cost adjustment clauses
EIP		2010 Equity and Incentive Plan
EGU		Electrical generating unit
Energy Agreement		Agreement dated October 20, 2008 and signed by the Governor of the State of Hawaii, the State of Hawaii Department of Business, Economic Development and Tourism, the Division of Consumer Advocacy of the Department of Commerce and Consumer Affairs, and HECO, for itself and on behalf of its electric utility subsidiaries committing to actions to develop renewable energy and reduce dependence on fossil fuels in support of the HCEI
EPA		Environmental Protection Agency — federal
EPS		Earnings per share
EVE		Economic value of equity
Exchange Act		Securities Exchange Act of 1934
FDIC		Federal Deposit Insurance Corporation
federal		U.S. Government
FHLB		Federal Home Loan Bank
FHLMC		Federal Home Loan Mortgage Corporation
FNMA		Federal National Mortgage Association
FRB		Federal Reserve Board
FSS		Forward Starting Swaps

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GLOSSARY OF TERMS, continued

Terms		Definitions

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

iii

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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, 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;

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· 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.

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PART I - FINANCIAL INFORMATION

Item 1. Financial Statements

Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Statements of Income (unaudited)

	Three months						Six months
	ended June 30						ended June 30
(in thousands, except per share amounts)	2012			2011			2012			2011
Revenues
Electric utility	$	789,552		$	728,738		$	1,539,162		$	1,374,073
Bank	64,721			66,318			129,973			131,631
Other	(5		)	(737		)	(7		)	(752		)
Total revenues	854,268			794,319			1,669,128			1,504,952
Expenses
Electric utility	728,056			686,220			1,420,412			1,286,347
Bank	42,847			42,498			85,187			86,057
Other	3,959			1,940			8,307			5,512
Total expenses	774,862			730,658			1,513,906			1,377,916
Operating income (loss)
Electric utility	61,496			42,518			118,750			87,726
Bank	21,874			23,820			44,786			45,574
Other	(3,964		)	(2,677		)	(8,314		)	(6,264		)
Total operating income	79,406			63,661			155,222			127,036
Interest expense—other than on deposit liabilities and other bank borrowings	(20,199		)	(24,177		)	(38,738		)	(44,317		)
Allowance for borrowed funds used during construction	893			553			1,763			1,073
Allowance for equity funds used during construction	1,997			1,317			3,937			2,561
Income before income taxes	62,097			41,354			122,184			86,353
Income taxes	22,824			13,742			44,122			29,806
Net income	39,273			27,612			78,062			56,547
Preferred stock dividends of subsidiaries	473			473			946			946
Net income for common stock	$	38,800		$	27,139		$	77,116		$	55,601
Basic earnings per common share	$	0.40		$	0.28		$	0.80		$	0.58
Diluted earnings per common share	$	0.40		$	0.28		$	0.80		$	0.58
Dividends per common share	$	0.31		$	0.31		$	0.62		$	0.62
Weighted-average number of common shares outstanding	96,693			95,393			96,430			95,107
Dilutive effect of share-based compensation	286			162			389			287
Adjusted weighted-average shares	96,979			95,555			96,819			95,394

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

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Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Statements of Comprehensive Income (unaudited)

	Three months ended June 30						Six months ended June 30
(in thousands)	2012			2011			2012			2011

Net income for common stock	$	38,800		$	27,139		$	77,116		$	55,601
Other comprehensive income (loss), net of taxes:
Net unrealized gains on securities:
Net unrealized gains on securities arising during the period, net of taxes of $721 and $2,755 for the three months ended June 30, 2012 and 2011 and $572 and $2,341 for the six months ended June 30, 2012 and 2011, respectively	1,093			4,061			867			3,435
Less: reclassification adjustment for net realized gains included in net income, net of taxes of $53 and $2 for the three months ended June 30, 2012 and 2011 and $53 and $2 for the six months ended June 30, 2012 and 2011, respectively	(81		)	(3		)	(81		)	(3		)
Derivatives qualified as cash flow hedges:
Net unrealized holding gains (losses) arising during the period, net of taxes of $3 and $9 for the three and six months ended June 30, 2011, respectively	—			6			—			(3		)
Less: reclassification adjustment to net income, net of tax benefits of $38 and $38 for the three months ended June 30, 2012 and 2011 and $75 and $41 for the six months ended June 30, 2012 and 2011, respectively	59			59			118			64
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 $2,405 and $1,477 for the three months ended June 30, 2012 and 2011 and $4,878 and $2,108 for the six months ended June 30, 2012 and 2011, respectively	3,768			2,449			7,641			3,488
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes of $2,095 and $1,370 for the three months ended June 30, 2012 and 2011 and $4,257 and $2,801 for the six months ended June 30, 2012 and 2011, respectively	(3,289		)	(2,105		)	(6,684		)	(4,352		)
Other comprehensive income, net of taxes	1,550			4,467			1,861			2,629
Comprehensive income attributable to common shareholders	$	40,350		$	31,606		$	78,977		$	58,230

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

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Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Balance Sheets (unaudited)

(dollars in thousands)	June 30, 2012			December 31, 2011

Assets
Cash and cash equivalents	$	207,549		$	270,265
Accounts receivable and unbilled revenues, net	386,750			344,322
Available-for-sale investment and mortgage-related securities	639,112			624,331
Investment in stock of Federal Home Loan Bank of Seattle	97,764			97,764
Loans receivable held for investment, net	3,695,474			3,642,818
Loans held for sale, at lower of cost or fair value	11,915			9,601
Property, plant and equipment, net of accumulated depreciation of $2,086,098 in 2012 and $2,049,821 in 2011	3,436,021			3,334,501
Regulatory assets	698,448			669,389
Other	566,734			519,296
Goodwill	82,190			82,190
Total assets	$	9,821,957		$	9,594,477

Liabilities and shareholders’ equity
Liabilities
Accounts payable	$	231,871		$	216,176
Interest and dividends payable	24,897			25,041
Deposit liabilities	4,136,741			4,070,032
Short-term borrowings—other than bank	96,240			68,821
Other bank borrowings	218,673			233,229
Long-term debt, net—other than bank	1,429,653			1,340,070
Deferred income taxes	396,806			354,051
Regulatory liabilities	317,958			315,466
Contributions in aid of construction	381,206			356,203
Retirement benefits liability	497,687			530,410
Other	480,156			521,979
Total liabilities	8,211,888			8,031,478

Preferred stock of subsidiaries - not subject to mandatory redemption	34,293			34,293

Commitments and contingencies (Notes 3 and 4)

Shareholders’ equity
Preferred stock, no par value, authorized 10,000,000 shares; issued: none	—			—
Common stock, no par value, authorized 200,000,000 shares; issued and outstanding: 97,023,148 shares in 2012 and 96,038,328 shares in 2011	1,377,426			1,349,446
Retained earnings	215,626			198,397
Accumulated other comprehensive loss, net of tax benefits	(17,276		)	(19,137		)
Total shareholders’ equity	1,575,776			1,528,706
Total liabilities and shareholders’ equity	$	9,821,957		$	9,594,477

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

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Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Statement of Changes in Shareholders’ Equity (unaudited)

	Common stock			Retained			Accumulated other comprehensive
(in thousands, except per share amounts)	Shares	Amount		earnings			loss			Total

Balance, December 31, 2011	96,038	$	1,349,446	$	198,397		$	(19,137	)	$	1,528,706
Net income for common stock	—	—		77,116			—			77,116
Other comprehensive income, net of tax benefits	—	—		—			1,861			1,861
Issuance of common stock, net	985	27,980		—			—			27,980
Dividend equivalents paid on equity-classified awards	—	—		(96		)	—			(96		)
Common stock dividends ($0.62 per share)	—	—		(59,791		)	—			(59,791		)
Balance, June 30, 2012	97,023	$	1,377,426	$	215,626		$	(17,276	)	$	1,575,776

Balance, December 31, 2010	94,691	$	1,314,199	$	178,667		$	(12,472	)	$	1,480,394
Net income for common stock	—	—		55,601			—			55,601
Other comprehensive income, net of taxes	—	—		—			2,629			2,629
Issuance of common stock, net	1,162	29,338		—			—			29,338
Common stock dividends ($0.62 per share)	—	—		(58,998		)	—			(58,998		)
Balance, June 30, 2011	95,853	$	1,343,537	$	175,270		$	(9,843	)	$	1,508,964

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

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Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Statements of Cash Flows (unaudited)

Six months ended June 30	2012			2011
(in thousands)
Cash flows from operating activities
Net income	$	78,062		$	56,547
Adjustments to reconcile net income to net cash provided by (used in) operating activities
Depreciation of property, plant and equipment	75,517			75,243
Other amortization	2,999			11,965
Provision for loan losses	5,924			7,105
Loans receivable originated and purchased, held for sale	(161,344		)	(64,028		)
Proceeds from sale of loans receivable, held for sale	161,713			71,829
Change in deferred income taxes	41,541			39,051
Change in excess tax benefits from share-based payment arrangements	(40		)	(55		)
Allowance for equity funds used during construction	(3,937		)	(2,561		)
Change in cash overdraft	—			(2,305		)
Changes in assets and liabilities
Increase in accounts receivable and unbilled revenues, net	(42,428		)	(52,537		)
Increase in fuel oil stock	(35,893		)	(6,509		)
Decrease (increase) in accounts, interest and dividends payable	3,578			(41,989		)
Change in prepaid and accrued income taxes and utility revenue taxes	(12,998		)	8,333
Contributions to defined benefit pension and other postretirement benefit plans	(53,356		)	(37,556		)
Change in other assets and liabilities	(62,910		)	(7,352		)
Net cash provided by (used in) operating activities	(3,572		)	55,181
Cash flows from investing activities
Available-for-sale investment and mortgage-related securities purchased	(93,808		)	(193,119		)
Principal repayments on available-for-sale investment and mortgage-related securities	75,407			161,526
Proceeds from sale of available-for-sale investment and mortgage-related securities	3,548			2,066
Net increase in loans held for investment	(61,214		)	(104,824		)
Proceeds from sale of real estate acquired in settlement of loans	6,036			3,977
Capital expenditures	(145,263		)	(89,088		)
Contributions in aid of construction	26,981			8,153
Other	—			(2,911		)
Net cash used in investing activities	(188,313		)	(214,220		)
Cash flows from financing activities
Net increase in deposit liabilities	66,709			79,577
Net increase (decrease) in short-term borrowings with original maturities of three months or less	27,419			(24,923		)
Net increase (decrease) in retail repurchase agreements	(14,556		)	1,803
Proceeds from issuance of long-term debt	417,000			125,000
Repayment of long-term debt	(328,500		)	(50,000		)
Change in excess tax benefits from share-based payment arrangements	40			55
Net proceeds from issuance of common stock	11,909			12,071
Common stock dividends	(47,851		)	(47,331		)
Preferred stock dividends of subsidiaries	(946		)	(946		)
Other	(2,055		)	(172		)
Net cash provided by financing activities	129,169			95,134
Net decrease in cash and cash equivalents	(62,716		)	(63,905		)
Cash and cash equivalents, beginning of period	270,265			330,651
Cash and cash equivalents, end of period	$	207,549		$	266,746

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

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Hawaiian Electric Industries, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1 · Basis of presentation

The accompanying unaudited consolidated financial statements have been prepared in conformity with U.S. generally accepted accounting principles (GAAP) for interim financial information, the instructions to SEC Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. In preparing the financial statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the balance sheet and the reported amounts of revenues and expenses for the period. Actual results could differ significantly from those estimates. The accompanying unaudited consolidated financial statements and the following notes should be read in conjunction with the audited consolidated financial statements and the notes thereto in HEI’s Form 10-K for the year ended December 31, 2011 and the unaudited consolidated financial statements and the notes thereto in HEI’s Quarterly Report on SEC Form 10-Q for the quarter ended March 31, 2012.

In the opinion of HEI’s management, the accompanying unaudited consolidated financial statements contain all material adjustments required by GAAP to fairly state the Company’s financial position as of June 30, 2012 and December 31, 2011, the results of its operations for the three and six months ended June 30, 2012 and 2011 and cash flows for the six months ended June 30, 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.

The Company has revised its electric utilities’ previously issued financial statements to correct an error that resulted in the understatement of franchise taxes, net of tax benefits, that should have been recorded in years prior to 2010. The Company determined the cumulative impact for periods prior to 2010 to be a charge to its earnings of $3.2 million. These adjustments were not considered to be material individually or in the aggregate to previously issued financial statements. The table below illustrates the effects of this revision on the Company’s Consolidated Financial Statements for those line items affected (these revisions have no impact on the Company’s Consolidated Statements of Income and Cash Flows for the periods reported):

(in thousands)	As previously filed		As revised		Difference
December 31, 2011
Consolidated Balance Sheet
Other assets	$	517,550	$	519,296	$	1,746
Total assets	9,592,731		9,594,477		1,746
Other liabilities	516,990		521,979		4,989
Total liabilities	8,026,489		8,031,478		4,989
Retained earnings	201,640		198,397		(3,243		)
Total shareholders’ equity	1,531,949		1,528,706		(3,243		)
Total liabilities and shareholders’ equity	9,592,731		9,594,477		1,746

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

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

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2 · Segment financial information

(in thousands)	Electric utility		Bank		Other			Total

Three months ended June 30, 2012
Revenues from external customers	$	789,539	$	64,721	$	8		$	854,268
Intersegment revenues (eliminations)	13		—		(13		)	—
Revenues	789,552		64,721		(5		)	854,268
Income (loss) before income taxes	48,501		21,873		(8,277		)	62,097
Income taxes (benefit)	18,626		7,684		(3,486		)	22,824
Net income (loss)	29,875		14,189		(4,791		)	39,273
Preferred stock dividends of subsidiaries	499		—		(26		)	473
Net income (loss) for common stock	29,376		14,189		(4,765		)	38,800

Six months ended June 30, 2012
Revenues from external customers	$	1,539,113	$	129,973	$	42		$	1,669,128
Intersegment revenues (eliminations)	49		—		(49		)	—
Revenues	1,539,162		129,973		(7		)	1,669,128
Income (loss) before income taxes	93,708		45,337		(16,861		)	122,184
Income taxes (benefit)	36,034		15,271		(7,183		)	44,122
Net income (loss)	57,674		30,066		(9,678		)	78,062
Preferred stock dividends of subsidiaries	998		—		(52		)	946
Net income (loss) for common stock	56,676		30,066		(9,626		)	77,116
Tangible assets (at June 30, 2012)	4,857,550		4,882,005		212			9,739,767

Three months ended June 30, 2011
Revenues from external customers	$	728,702	$	66,318	$	(701	)	$	794,319
Intersegment revenues (eliminations)	36		—		(36		)	—
Revenues	728,738		66,318		(737		)	794,319
Income (loss) before income taxes	28,603		23,806		(11,055		)	41,354
Income taxes (benefit)	11,080		8,611		(5,949		)	13,742
Net income (loss)	17,523		15,195		(5,106		)	27,612
Preferred stock dividends of subsidiaries	499		—		(26		)	473
Net income (loss) for common stock	17,024		15,195		(5,080		)	27,139

Six months ended June 30, 2011
Revenues from external customers	$	1,374,001	$	131,631	$	(680	)	$	1,504,952
Intersegment revenues (eliminations)	72		—		(72		)	—
Revenues	1,374,073		131,631		(752		)	1,504,952
Income (loss) before income taxes	59,870		45,533		(19,050		)	86,353
Income taxes (benefit)	22,659		16,487		(9,340		)	29,806
Net income (loss)	37,211		29,046		(9,710		)	56,547
Preferred stock dividends of subsidiaries	998		—		(52		)	946
Net income (loss) for common stock	36,213		29,046		(9,658		)	55,601
Tangible assets (at December 31, 2011)	4,674,007		4,827,784		10,496			9,512,287

Intercompany electricity sales of the electric utilities to the bank and “other” segments are not eliminated because those segments would need to purchase electricity from another source if it were not provided by consolidated HECO, the profit on such sales is nominal and the elimination of electric sales revenues and expenses could distort segment operating income and net income for common stock.

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

3 · Electric utility subsidiary

For consolidated HECO financial information, including its commitments and contingencies, see HECO’s consolidated financial statements beginning on page 26 through Note 9 on page 40.

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4 · Bank subsidiary

Selected financial information

American Savings Bank, F.S.B.

Statements of Income Data

	Three months ended June 30				Six months ended June 30
(in thousands)	2012		2011		2012		2011
Interest income
Interest and fees on loans	$	44,473	$	45,648	$	89,361	$	91,745
Interest on investment and mortgage-related securities	3,297		3,793		7,102		7,562
Total interest income	47,770		49,441		96,463		99,307
Interest expense
Interest on deposit liabilities	1,696		2,387		3,475		4,980
Interest on other borrowings	1,214		1,382		2,475		2,749
Total interest expense	2,910		3,769		5,950		7,729
Net interest income	44,860		45,672		90,513		91,578
Provision for loan losses	2,378		2,555		5,924		7,105
Net interest income after provision for loan losses	42,482		43,117		84,589		84,473
Noninterest income
Fees from other financial services	7,463		7,240		14,800		14,186
Fee income on deposit liabilities	4,322		4,599		8,600		9,048
Fee income on other financial products	1,532		1,861		3,081		3,534
Other income	3,634		3,177		7,029		5,556
Total noninterest income	16,951		16,877		33,510		32,324
Noninterest expense
Compensation and employee benefits	18,696		18,166		37,342		35,671
Occupancy	4,241		4,288		8,466		8,528
Data processing	2,489		2,058		4,600		4,028
Services	2,221		1,949		4,004		3,720
Equipment	1,807		1,772		3,537		3,429
Other expense	8,106		7,955		14,813		15,888
Total noninterest expense	37,560		36,188		72,762		71,264
Income before income taxes	21,873		23,806		45,337		45,533
Income taxes	7,684		8,611		15,271		16,487
Net income	$	14,189	$	15,195	$	30,066	$	29,046

American Savings Bank, F.S.B.

Statements of Comprehensive Income Data

	Three months ended June 30						Six months ended June 30
(in thousands)	2012			2011			2012			2011
Net income	$	14,189		$	15,195		$	30,066		$	29,046
Other comprehensive income (loss), net of taxes:
Net unrealized gains on securities:
Net unrealized gains on securities arising during the period, net of taxes, of $721 and $2,755 for the three months ended June 30, 2012 and 2011 and $572 and $2,341 for the six months ended June 30, 2012 and 2011, respectively	1,093			4,061			867			3,435
Less: reclassification adjustment for net realized gains, included in net income , net of taxes, of $53 and $2 for the three months ended June 30, 2012 and 2011 and $53 and $2 for the six months ended June 30, 2012 and 2011, respectively	(81		)	(3		)	(81		)	(3		)
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 $(168) and $(5) for the three months ended June 30, 2012 and 2011 and $(332) and $1,077 for the six months ended June 30, 2012 and 2011, respectively	255			186			503			(1,453		)
Other comprehensive income, net of taxes	1,267			4,244			1,289			1,979
Comprehensive income	$	15,456		$	19,439		$	31,355		$	31,025

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American Savings Bank, F.S.B.

Balance Sheets Data

(in thousands)	June 30, 2012			December 31, 2011

Assets
Cash and cash equivalents	$	201,193		$	219,678
Available-for-sale investment and mortgage-related securities	639,112			624,331
Investment in stock of Federal Home Loan Bank of Seattle	97,764			97,764
Loans receivable held for investment	3,734,937			3,680,724
Allowance for loan losses	(39,463		)	(37,906		)
Loans receivable held for investment, net	3,695,474			3,642,818
Loans held for sale, at lower of cost or fair value	11,915			9,601
Other	236,547			233,592
Goodwill	82,190			82,190
Total assets	$	4,964,195		$	4,909,974

Liabilities and shareholder’s equity
Deposit liabilities—noninterest-bearing	$	1,076,579		$	993,828
Deposit liabilities—interest-bearing	3,060,162			3,076,204
Other borrowings	218,673			233,229
Other	107,902			118,078
Total liabilities	4,463,316			4,421,339

Commitments and contingencies (see “Litigation” below)

Common stock	332,769			331,880
Retained earnings	176,192			166,126
Accumulated other comprehensive loss, net of tax benefits	(8,082		)	(9,371		)
Total shareholder’s equity	500,879			488,635
Total liabilities and shareholder’s equity	$	4,964,195		$	4,909,974

Other assets
Bank-owned life insurance	$	123,563		$	121,470
Premises and equipment, net	53,521			52,940
Prepaid expenses	15,423			15,297
Accrued interest receivable	14,084			14,190
Mortgage-servicing rights	8,818			8,227
Real estate acquired in settlement of loans, net	6,210			7,260
Other	14,928			14,208
	$	236,547		$	233,592

Other liabilities
Accrued expenses	$	12,928		$	21,216
Federal and state income taxes payable	35,052			35,002
Cashier’s checks	23,094			22,802
Advance payments by borrowers	9,975			10,100
Other	26,853			28,958
	$	107,902		$	118,078

Other borrowings consisted of securities sold under agreements to repurchase and advances from the Federal Home Loan Bank (FHLB) of Seattle of $169 million and $50 million, respectively, as of June 30, 2012 and $183 million and $50 million, respectively, as of 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 June 30, 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

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modified in troubled debt restructurings (TDRs). There are no commitments to lend additional funds to borrowers of other impaired loans as of June 30, 2012.

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

June 30, 2012
Federal agency obligations	$	208,255	$	3,193	$	—		$	211,448	$	—	$	—		$	—	$	—
Mortgage-related securities- FNMA, FHLMC and GNMA	334,607		11,211		(149		)	345,669		21,048		(149		)	—		—
Municipal bonds	78,532		3,478		(15		)	81,995		7,357		(15		)	—		—
	$	621,394	$	17,882	$	(164	)	$	639,112	$	28,405	$	(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 June 30, 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.

June 30, 2012	Amortized cost		Fair value
(in thousands)
Due in one year or less	$	—	$	—
Due after one year through five years	189,424		191,698
Due after five years through ten years	79,093		82,877
Due after ten years	18,270		18,868
	286,787		293,443
Mortgage-related securities-FNMA,FHLMC and GNMA	334,607		345,669
Total available-for-sale securities	$	621,394	$	639,112

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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
Six months ended June 30, 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	(1,512		)	—		(39		)	(1,247		)	—		—			(1,834		)	(1,252		)	—		(5,884		)
Recoveries	595			—		88			245			—		—			356			233			—		1,517
Provision	1,629			390		440			547			367		(1		)	572			1,010			970		5,924
Ending balance	$	7,212		$	2,078	$	4,843		$	3,340		$	2,255	$	3		$	13,961		$	3,797		$	1,974	$	39,463
Ending balance: individually evaluated for impairment	$	324		$	—	$	—		$	2,322		$	—	$	—		$	443		$	—		$	—	$	3,089
Ending balance: collectively evaluated for impairment	$	6,888		$	2,078	$	4,843		$	1,018		$	2,255	$	3		$	13,518		$	3,797		$	1,974	$	36,374

Financing Receivables:
Ending balance	$	1,893,456		$	372,616	$	589,852		$	34,200		$	50,120	$	1,797		$	704,255		$	101,042		$	—	$	3,747,338
Ending balance: individually evaluated for impairment	$	30,132		$	12,938	$	1,838		$	29,855		$	—	$	—		$	49,085		$	23		$	—	$	123,871
Ending balance: collectively evaluated for impairment	$	1,863,324		$	359,678	$	588,014		$	4,345		$	50,120	$	1,797		$	655,170		$	101,019		$	—	$	3,623,467
Year ended 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.

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The loan grade categories are:

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

Grades 1 through 6 are considered pass grades. Pass exposures generally are well protected by the current net worth and paying capacity of the obligor or by the value of the asset or underlying collateral.

The credit risk profile by internally assigned grade for loans was as follows:

	June 30, 2012						December 31, 2011
(in thousands)	Commercial real estate		Commercial construction		Commercial		Commercial real estate		Commercial construction		Commercial
Grade:
Pass	$	346,522	$	50,120	$	631,540	$	308,843	$	41,950	$	650,234
Special mention	13,156		—		22,752		8,594		—		14,660
Substandard	9,859		—		44,366		11,058		—		47,607
Doubtful	3,079		—		5,597		3,436		—		3,926
Loss	—		—		—		—		—		—
Total	$	372,616	$	50,120	$	704,255	$	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
June 30, 2012
Real estate loans:
Residential 1-4 family	$	6,317	$	3,653	$	29,346	$	39,316	$	1,854,140	$	1,893,456	$	—
Commercial real estate	151		—		3,079		3,230		369,386		372,616		—
Home equity line of credit	822		285		2,241		3,348		586,504		589,852		—
Residential land	617		649		7,408		8,674		25,526		34,200		180
Commercial construction	—		—		—		—		50,120		50,120		—
Residential construction	—		—		—		—		1,797		1,797		—
Commercial loans	2,321		1,840		1,914		6,075		698,180		704,255		117
Consumer loans	555		364		498		1,417		99,625		101,042		415
Total loans	$	10,783	$	6,791	$	44,486	$	62,060	$	3,685,278	$	3,747,338	$	712
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

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

	June 30, 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	$	30,945	$	—	$	28,298	$	—
Commercial real estate	3,079		—		3,436		—
Home equity line of credit	2,587		—		2,258		—
Residential land	7,637		180		14,535		205
Commercial construction	—		—		—		—
Residential construction	—		—		—		—
Commercial loans	17,619		117		17,946		28
Consumer loans	169		415		281		308
Total	$	62,036	$	712	$	66,754	$	541

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

	June 30, 2012						Three months ended June 30, 2012				Six months ended June 30, 2012
(in thousands)	Recorded investment		Unpaid principal balance		Related Allowance		Average recorded investment		Interest income recognized*		Average recorded investment		Interest income recognized*
With no related allowance recorded
Real estate loans:
Residential 1-4 family	$	16,405	$	22,509	$	—	$	16,897	$	79	$	17,697	$	168
Commercial real estate	12,938		12,938		—		13,152		92		13,254		237
Home equity line of credit	654		1,552		—		655		—		657		1
Residential land	22,639		29,170		—		24,774		319		26,337		724
Commercial construction	—		—		—		—		—		—		—
Residential construction	—		—		—		—		—		—		—
Commercial loans	42,811		45,783		—		44,055		450		43,107		946
Consumer loans	23		23		—		23		—		24		—
	95,470		111,975		—		99,556		940		101,076		2,076
With an allowance recorded
Real estate loans:
Residential 1-4 family	4,520		4,520		324		4,075		59		3,854		134
Commercial real estate	—		—		—		—		—		—		—
Home equity line of credit	—		—		—		—		—		—		—
Residential land	7,197		7,256		2,321		7,201		122		7,392		307
Commercial construction	—		—		—		—		—		—		—
Residential construction	—		—		—		—		—		—		—
Commercial loans	6,274		6,527		443		3,193		8		3,928		18
Consumer loans	—		—		—		—		—		—		—
	17,991		18,303		3,088		14,469		189		15,174		459
Total
Real estate loans:
Residential 1-4 family	20,925		27,029		324		20,972		138		21,551		302
Commercial real estate	12,938		12,938		—		13,152		92		13,254		237
Home equity line of credit	654		1,552		—		655		—		657		1
Residential land	29,836		36,426		2,321		31,975		441		33,729		1,031
Commercial construction	—		—		—		—		—		—		—
Residential construction	—		—		—		—		—		—		—
Commercial loans	49,085		52,310		443		47,248		458		47,035		964
Consumer loans	23		23		—		23		—		24		—
	$	113,461	$	130,278	$	3,088	$	114,025	$	1,129	$	116,250	$	2,535

* Since loan was classified as impaired.

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	December 31, 2011						Year ended December 31, 2011
(in thousands)	Recorded investment		Unpaid principal balance		Related allowance		Average recorded investment		Interest income recognized

With no related allowance recorded
Real estate loans:
Residential 1-4 family	$	19,217	$	26,614	$	—	$	21,385	$	282
Commercial real estate	13,397		13,397		—		13,404		747
Home equity line of credit	711		1,612		—		954		6
Residential land	30,781		39,136		—		33,398		1,779
Commercial construction	—		—		—		—		—
Residential construction	—		—		—		—		—
Commercial loans	41,680		43,516		—		40,952		2,912
Consumer loans	25		25		—		16		—
	105,811		124,300		—		110,109		5,726
With an allowance recorded
Real estate loans:
Residential 1-4 family	3,525		3,525		203		3,527		201
Commercial real estate	—		—		—		—		—
Home equity line of credit	—		—		—		—		—
Residential land	7,792		7,852		2,525		8,158		603
Commercial construction	—		—		—		—		—
Residential construction	—		—		—		—		—
Commercial loans	6,561		6,561		976		8,131		737
Consumer loans	—		—		—		—		—
	17,878		17,938		3,704		19,816		1,541
Total
Real estate loans:
Residential 1-4 family	22,742		30,139		203		24,912		483
Commercial real estate	13,397		13,397		—		13,404		747
Home equity line of credit	711		1,612		—		954		6
Residential land	38,573		46,988		2,525		41,556		2,382
Commercial construction	—		—		—		—		—
Residential construction	—		—		—		—		—
Commercial loans	48,241		50,077		976		49,083		3,649
Consumer loans	25		25		—		16		—
	$	123,689	$	142,238	$	3,704	$	129,925	$	7,267

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

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

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All TDR loans are classified impaired and are segregated and reviewed separately when assessing the adequacy of the allowance for loan losses based on the appropriate method of measuring impairment: (1) present value of expected future cash flows discounted at the loan’s effective original contractual rate, (2) fair value of collateral less 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 June 30, 2012					Six months ended June 30, 2012
(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	15	$	3,056	$	2,872	22	$	4,469	$	4,282
Commercial real estate	—	—		—		—	—		—
Home equity line of credit	—	—		—		—	—		—
Residential land	8	1,774		1,580		15	3,508		3,021
Commercial loans	8	1,869		1,869		14	2,029		2,029
Consumer loans	—	—		—		—	—		—
Total	31	$	6,699	$	6,321	51	$	10,006	$	9,332

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 nil for the three months ended June 30, 2012 and were as follows for the six months ended June 30, 2012:

	Six months ended June 30, 2012
(dollars in thousands)	Number of contracts	Recorded investment
Troubled debt restructurings that subsequently defaulted
Real estate loans:
Residential 1-4 family	—	$	—
Commercial real estate	—	—
Home equity line of credit	—	—
Residential land	—	—
Commercial loans	3	847
Consumer loans	—	—
Total	3	$	847

The three commercial loans that subsequently defaulted were modified by temporarily lowering the monthly payments 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 six months of 2012, the Company contributed $53 million ($52 million by the utilities and $1 million by HEI) to its retirement benefit plans, compared to $38 million (primarily by the utilities) in the first six months of 2011. The Company’s current estimate of contributions to its retirement benefit plans in 2012 is $107 million ($104 million by the utilities and $3 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.

On July 6, 2012, President Obama signed the Moving Ahead for Progress in the 21st Century Act (MAP-21), which included provisions related to the funding of pension plans. This law does not affect the Company’s accounting for pension benefits; therefore, the net periodic benefit costs disclosed for the plans were not affected. MAP-21 is expected to reduce the minimum required funding for 2012 and 2013, but specific guidance is needed from the IRS to estimate the amount of the reduction.

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 June 30												Six months ended June 30
	Pension benefits						Other benefits						Pension benefits						Other benefits
(in thousands)	2012			2011			2012			2011			2012			2011			2012			2011

Service cost	$	11,397		$	8,824		$	1,008		$	1,173		$	21,588		$	17,741		$	2,104		$	2,440
Interest cost	16,973			16,271			2,223			2,417			33,744			32,580			4,504			4,878
Expected return on plan assets	(17,736		)	(17,172		)	(2,557		)	(2,657		)	(35,592		)	(34,273		)	(5,178		)	(5,305		)
Amortization of net transition obligation	—			—			—			—			—			1			—			—
Amortization of prior service gain	(82		)	(97		)	(449		)	(309		)	(163		)	(194		)	(897		)	(533		)
Amortization of net actuarial loss	6,403			4,314			299			40			12,826			8,719			752			55
Net periodic benefit cost	16,955			12,140			524			664			32,403			24,574			1,285			1,535
Impact of PUC D&Os	(4,977		)	(556		)	(416		)	1,734			(8,834		)	(2,100		)	(1,096		)	2,752
Net periodic benefit cost (adjusted for impact of PUC D&Os)	$	11,978		$	11,584		$	108		$	2,398		$	23,569		$	22,474		$	189		$	4,287

Consolidated HEI recorded retirement benefits expense of $17 million and $20 million in the first six months 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 of their 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 six months of 2012 and 2011, the Company’s expense for its defined contribution pension plans under the Hawaiian Electric Industries Retirement Savings Plan (HEIRSP) and the ASB 401(k) Plan was $1.8 million and $1.7 million, respectively, and cash contributions were $2.7 million and $2.8 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 June 30, 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 long-term incentive plan (LTIP) awards are achieved at maximum levels).

Under the 1987 Stock Option and Incentive Plan, as amended (SOIP), grants and awards of an estimated 0.5 million shares of common stock (based on various assumptions, including LTIP awards earned at maximum levels and the use of the June 30, 2012 market price of shares as the price on the exercise/payment dates) were outstanding as of June 30, 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 June 30				Six months ended June 30
(in millions)	2012		2011		2012		2011

Share-based compensation expense (1)	$	1.7	$	0.5	$	3.5	$	1.7
Income tax benefit	0.6		0.1		1.2		0.5

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

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

June 30, 2012	Outstanding & Exercisable (Vested)
Year of grant	Range of exercise prices		Number of options	Weighted-average remaining contractual life	Weighted-average exercise price

2003	$	20.49	22,000	0.7	$	20.49

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 June 30, 2012, all NQSOs outstanding were exercisable and had an aggregate intrinsic value (including dividend equivalents) of $0.2 million.

NQSO activity and statistics were as follows:

	Three months ended June 30				Six months ended June 30
(dollars in thousands, except prices)	2012		2011		2012		2011

Shares exercised	21,500		69,500		33,500		102,000
Weighted-average exercise price	$	20.93	$	21.07	$	21.20	$	20.82
Cash received from exercise	$	450	$	1,465	$	710	$	2,123
Intrinsic value of shares exercised (1)	$	174	$	581	$	265	$	840
Tax benefit realized for the deduction of exercises	$	68	$	170	$	103	$	271

(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:

June 30, 2012			Outstanding & Exercisable (Vested)
Year of grant	Range of exercise prices		Number of shares underlying SARs	Weighted-average remaining contractual life	Weighted-average exercise price

2004	$	26.02	62,000	1.8	$	26.02
2005	26.18		108,000	2.7	26.18
	$	26.02 – 26.18	170,000	2.4	$	26.12

As of December 31, 2011, the shares underlying SARs outstanding totaled 282,000, with a weighted-average exercise price of $26.14. As of June 30, 2012, all SARs outstanding were exercisable and had an aggregate intrinsic value (including dividend equivalent rights) of $0.5 million.

SARs activity and statistics were as follows:

	Three months ended June 30				Six months ended June 30
(dollars in thousands, except prices)	2012		2011		2012		2011

Shares underlying SARS expired	—		4,000		—		40,000
Weighted-average price of shares expired	—		$	26.18	—		$	26.11
Shares underlying SARS exercised	112,000		—		112,000		—
Intrinsic value of shares exercised (1)	$	194	—		$	194	—
Tax benefit realized for the deduction of exercises	$	76	—		$	76	—

(1) Intrinsic value is the amount by which the fair market value of the underlying stock and the related dividend equivalent rights exceeds the exercise price of the right.

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

	Three months ended June 30								Six months ended June 30
	2012				2011				2012				2011
	Shares		(1)		Shares		(1)		Shares		(1)		Shares		(1)

Outstanding, beginning of period	38,107		$	23.83	88,709		$	24.63	46,807		$	24.45	89,709		$	24.64
Granted	—		—		—		—		—		—		—		—
Vested	(23,300	)	24.71		(29,800	)	26.03		(32,000	)	25.38		(29,800	)	26.03
Forfeited	—		—		(1,000	)	24.68		—		—		(2,000	)	25.02
Outstanding, end of period	14,807		$	22.45	57,909		$	23.91	14,807		$	22.45	57,909		$	23.91

(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 June 30, 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 2.4 years.

For the six months ended June 30, 2012 and 2011, total restricted stock vested had a fair value of $0.8 million and $0.8 million, respectively. The tax benefits realized for tax deductions related to restricted stock awards were $0.2 million and $0.1 million for the first six months of 2012 and 2011, respectively.

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

	Three months ended June 30								Six months ended June 30
	2012				2011				2012				2011
	Shares		(1)		Shares		(1)		Shares		(1)		Shares		(1)

Outstanding, beginning of period	318,551		$	22.80	230,517		$	21.69	247,286		$	21.80	146,500		$	19.80
Granted	2,334	(2)	26.75		1,000	(3)	26.25		94,846	(4)	26.00		86,017	(5)	24.97
Vested	(250	)	26.25		—		—		(21,497	)	24.97		—		—
Forfeited	(1,564	)	25.53		—		—		(1,564	)	25.53		(1,000	)	22.60
Outstanding, end of period	319,071		$	22.81	231,517		$	21.70	319,071		$	22.81	231,517		$	21.70

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(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 $62,000.

(3) Total weighted-average grant-date fair value of $26,000.

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

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

As of June 30, 2012, there was $4.3 million of total unrecognized compensation cost related to the nonvested restricted stock units. The cost is expected to be recognized over a weighted-average period of 2.9 years.

For the six months ended June 30, 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.

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. 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 consolidated net income, HECO consolidated net income, HECO consolidated ROACE, ASB net income and ASB return on assets — all based on the applicable three-year averages.

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

	Three months ended June 30								Six months ended June 30
	2012				2011				2012				2011
	Shares		(1)		Shares		(1)		Shares		(1)		Shares		(1)

Outstanding, beginning of period	239,470		$	29.12	200,735		$	25.94	197,385		$	25.94	126,782		$	20.33
Granted	1,442		30.71		475		35.46		78,924	(2)	30.71		75,015	(3)	35.46
Vested	—		—		—		—		(35,397	)	14.85		—		—
Forfeited	(1,505	)	30.39		(1,647	)	22.45		(1,505	)	30.39		(2,234	)	22.45
Outstanding, end of period	239,407		$	29.12	199,563		$	25.99	239,407		$	29.12	199,563		$	25.99

(1) Weighted-average grant-date fair value per share determined using a Monte Carlo simulation model.

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

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

On May 1, 2012, LTIP grants (under the 2012-2014 LTIP) were made payable in 1,442 shares of HEI common stock (based on the grant date price of $26.75 and target TRS performance levels) with a weighted-average grant date fair value of $44,000 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 six months ended June 30, 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 June 30, 2012, there was $3.5 million of total unrecognized compensation cost related to the nonvested performance awards payable in shares linked to TRS. The cost is expected to be recognized over a weighted-average period of 1.5 years.

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

	Three months ended June 30								Six months ended June 30
	2012				2011				2012				2011
	Shares		(1)		Shares		(1)		Shares		(1)		Shares		(1)

Outstanding, beginning of period	297,602		$	23.92	273,550		$	21.26	182,498		$	22.63	161,310		$	18.66
Granted	3,600		26.75		712		26.25		118,704	(2)	26.00		113,831	(3)	24.96
Vested	—		—		—		—		—		—		—		—
Cancelled	—		—		(81,908	)	18.38		—		—		(81,908	)	18.38
Forfeited	(6,018	)	24.23		(6,587	)	18.95		(6,018	)	24.23		(7,466	)	18.95
Outstanding, end of period	295,184		$	23.95	185,767		$	22.63	295,184		$	23.95	185,767		$	22.63

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

(2) Total weighted-average grant-date fair value of $3.1 million.

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

On May 1, 2012, LTIP grants (under the 2012-2014 LTIP) were made payable in 3,600 shares of HEI common stock (based on the grant date price of $26.75 and target performance levels relating to performance goals other than TRS), with a weighted-average grant date fair value of $0.1 million based on the weighted-average grant date fair value per share of $26.75.

As of June 30, 2012, there was $4.1 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 1.7 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:

	Three months ended June 30					Six months ended June 30
	2012		2011			2012		2011
	Basic and diluted		Basic and diluted			Basic and diluted		Basic and diluted
Distributed earnings	$	0.31	$	0.31		$	0.62	$	0.62
Undistributed earnings (loss)	0.09		(0.03		)	0.18		(0.04		)
	$	0.40	$	0.28		$	0.80	$	0.58

As of June 30, 2011, the antidilutive effects of SARs of 410,000 shares of HEI common stock, for which the exercise prices were greater than the closing market price of HEI’s common stock were not included in the computation of diluted EPS.

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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 instruments, fair value estimates cannot be determined with precision. Changes in the underlying assumptions used, including discount rates and estimates of future cash flows, could significantly affect the estimates. In addition, the tax ramifications related to the realization of the unrealized gains and losses could have a significant effect on fair value estimates, but have not been considered in making such estimates.

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

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

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

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

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

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.

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

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

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

The fair value of all loans was adjusted to reflect current assessments of loan collectability. Also see “Fair value measurements on a nonrecurring basis” below. ASB classifies the estimated fair value of loans receivable as Level 3 on its fair value measurement hierarchy.

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. ASB classifies the estimated fair value of deposit liabilities as Level 2 on its fair value measurement hierarchy.

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. HEI and ASB classifies the estimated fair value of other bank borrowings and long-term debt as Level 2 on its fair value hierarchy.

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.

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

	June 30, 2012										December 31, 2011
	Carrying or										Carrying or
	notional		Estimated fair value								notional		Estimated
(in thousands)	amount		Level 1		Level 2		Level 3		Total		amount		fair value

Financial assets
Cash and cash equivalents, excluding money market funds	$	207,539	$	—	$	207,539	$	—	$	207,539	$	270,255	$	270,255
Money market funds	10		—		10		—		10		10		10
Available-for-sale investment and mortgage-related securities	639,112		—		639,112		—		639,112		624,331		624,331
Investment in stock of Federal Home Loan Bank of Seattle	97,764		—		97,764		—		97,764		97,764		97,764
Loans receivable, net	3,707,389		—		—		3,942,593		3,942,593		3,652,419		3,886,253
Financial liabilities
Deposit liabilities	4,136,741		—		4,142,845		—		4,142,845		4,070,032		4,075,656		(1)
Short-term borrowings—other than bank	96,240		—		96,240		—		96,240		68,821		68,821
Other bank borrowings	218,673		—		235,807		—		235,807		233,229		250,486
Long-term debt, net—other than bank	1,429,653		—		1,476,591		—		1,476,591		1,340,070		1,400,241
Off-balance sheet items
HECO-obligated preferred securities of trust subsidiary	50,000		—		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 June 30, 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 $1.0 million and $0.3 million, respectively. As of June 30, 2012 and December 31, 2011, loans serviced by ASB for others had notional amounts of $1.1 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
(in thousands)	Level 1		Level 2		Level 3
June 30, 2012
Money market funds (“other” segment)	$	—	$	10	$	—
Available-for-sale securities (bank segment)
Mortgage-related securities-FNMA, FHLMC and GNMA	$	—	$	345,669	$	—
Federal agency obligations	—		211,448		—
Municipal bonds	—		81,995		—
	$	—	$	639,112	$	—
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 six months 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
(in millions)	Balance		Level 1		Level 2		Level 3
Loans
June 30, 2012	$	27	$	—	$	—	$	27
December 31, 2011	34		—		—		34

For the first six months 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 that were 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.

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For loans classified as Level 3 as of June 30, 2012, the significant unobservable inputs used in the fair value measurement were as follows:

($ in thousands)	Fair value at June 30, 2012		Valuation technique	Significant unobservable input	Significant unobservable input value
Residential loans	$	22,240	Third party appraisal	Property sales	64%
Home equity lines of credit	654		Third party appraisal	Property sales	42%
Commercial loan	311		Third party appraisal	U.S. government agency guarantee	75%
Commercial loans	53		Third party appraisal	Fair value of business assets	7%
Commercial loan	2,550		Present value of cash flows	Present value of expected future cash flows based on anticipated debt restructuring Discount rate	Paydown of loan — 78% 4.5%
Commercial loan	1,552		Third party appraisal	Insurance proceeds	91%

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

11 · Cash flows

Six months ended June 30	2012		2011
(in millions)
Supplemental disclosures of cash flow information
Interest paid to non-affiliates	$	42	$	50
Income tax paid/(refunded)	6		(21		)
Supplemental disclosures of noncash activities
Common stock dividends reinvested in HEI common stock (1)	12		12
Increases in common stock related to director and officer compensatory plans	4		6
Real estate acquired in settlement of loans	5		5

(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.

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Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statements of Income (unaudited)

	Three months ended June 30						Six months ended June 30
(in thousands)	2012			2011			2012			2011
Operating revenues	$	787,685		$	727,652		$	1,535,623		$	1,371,953
Operating expenses
Fuel oil	331,064			312,141			658,903			573,001
Purchased power	188,352			171,737			353,141			319,695
Other operation	64,516			67,388			126,365			132,919
Maintenance	31,235			31,276			61,273			60,472
Depreciation	36,133			36,258			72,615			72,690
Taxes, other than income taxes	76,304			67,152			147,299			127,147
Income taxes	18,574			11,160			35,939			22,770
Total operating expenses	746,178			697,112			1,455,535			1,308,694
Operating income	41,507			30,540			80,088			63,259
Other income
Allowance for equity funds used during construction	1,997			1,317			3,937			2,561
Other, net	1,363			898			2,628			1,808
Total other income	3,360			2,215			6,565			4,369
Interest and other charges
Interest on long-term debt	15,323			14,383			29,706			28,766
Amortization of net bond premium and expense	661			766			1,406			1,549
Other interest charges (credits)	(99		)	636			(370		)	1,175
Allowance for borrowed funds used during construction	(893		)	(553		)	(1,763		)	(1,073		)
Total interest and other charges	14,992			15,232			28,979			30,417
Net income	29,875			17,523			57,674			37,211
Preferred stock dividends of subsidiaries	229			229			458			458
Net income attributable to HECO	29,646			17,294			57,216			36,753
Preferred stock dividends of HECO	270			270			540			540
Net income for common stock	$	29,376		$	17,024		$	56,676		$	36,213

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

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

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statements of Comprehensive Income (unaudited)

	Three months ended June 30						Six months ended June 30
(in thousands)	2012			2011			2012			2011
Net income for common stock	$	29,376		$	17,024		$	56,676		$	36,213
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 $2,142 and $1,401 for the three months ended June 30, 2012 and 2011 and $4,354 and $2,849 for the six months ended June 30, 2012 and 2011, respectively	3,364			2,152			6,836			4,426
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes of $2,095 and $1,370 for the three months ended June 30, 2012 and 2011 and $4,257 and $2,801 for the six months ended June 30, 2012 and 2011, respectively	(3,289		)	(2,105		)	(6,684		)	(4,352		)
Other comprehensive income, net of taxes	75			47			152			74
Comprehensive income attributable to common shareholder	$	29,451		$	17,071		$	56,828		$	36,287

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

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Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Balance Sheets (unaudited)

(dollars in thousands, except par value)	June 30, 2012			December 31, 2011
Assets
Utility plant, at cost
Land	$	51,537		$	51,514
Plant and equipment	5,156,323			5,052,027
Less accumulated depreciation	(2,004,465		)	(1,966,894		)
Construction in progress	172,986			138,838
Net utility plant	3,376,381			3,275,485
Current assets
Cash and cash equivalents	5,937			48,806
Customer accounts receivable, net	200,444			183,328
Accrued unbilled revenues, net	169,879			137,826
Other accounts receivable, net	2,465			8,623
Fuel oil stock, at average cost	207,441			171,548
Materials and supplies, at average cost	50,787			43,188
Prepayments and other	43,401			36,667
Regulatory assets	30,372			20,283
Total current assets	710,726			650,269
Other long-term assets
Regulatory assets	668,076			649,106
Unamortized debt expense	11,267			12,786
Other	91,100			86,361
Total other long-term assets	770,443			748,253
Total assets	$	4,857,550		$	4,674,007
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	426,922			426,921
Retained earnings	901,195			881,041
Accumulated other comprehensive income (loss), net of income taxes	120			(32		)
Common stock equity	1,423,148			1,402,841
Cumulative preferred stock — not subject to mandatory redemption	34,293			34,293
Long-term debt, net	1,147,653			1,000,570
Total capitalization	2,605,094			2,437,704
Commitments and contingencies (Note 5)

Current liabilities
Short-term borrowings — nonaffiliates	44,242			—
Current portion of long-term debt	—			57,500
Accounts payable	206,484			188,580
Interest and preferred dividends payable	19,014			19,483
Taxes accrued	217,321			230,076
Other	55,447			69,353
Total current liabilities	542,508			564,992
Deferred credits and other liabilities
Deferred income taxes	380,484			337,863
Regulatory liabilities	317,958			315,466
Unamortized tax credits	63,437			60,614
Retirement benefits liability	463,630			495,121
Other	103,233			106,044
Total deferred credits and other liabilities	1,328,742			1,315,108
Contributions in aid of construction	381,206			356,203
Total capitalization and liabilities	$	4,857,550		$	4,674,007

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

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Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statement 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	$	881,041		$	(32	)	$	1,402,841
Net income for common stock	—	—		—		56,676			—			56,676
Other comprehensive income, net of taxes	—	—		—		—			152			152
Common stock dividends	—	—		—		(36,522		)	—			(36,522		)
Common stock issue expenses	—	—		1		—			—			1
Balance, June 30, 2012	14,234	$	94,911	$	426,922	$	901,195		$	120		$	1,423,148

Balance, December 31, 2010	13,831	$	92,224	$	389,609	$	851,613		$	709		$	1,334,155
Net income for common stock	—	—		—		36,213			—			36,213
Other comprehensive income, net of taxes	—	—		—		—			74			74
Common stock dividends	—	—		—		(35,279		)	—			(35,279		)
Balance, June 30, 2011	13,831	$	92,224	$	389,609	$	852,547		$	783		$	1,335,163

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

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Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statements of Cash Flows (unaudited)

Six months ended June 30	2012			2011
(in thousands)

Cash flows from operating activities
Net income	$	57,674		$	37,211
Adjustments to reconcile net income to net cash provided by (used in) operating activities
Depreciation of property, plant and equipment	72,615			72,690
Other amortization	2,770			10,833
Change in deferred income taxes	42,524			33,456
Change in tax credits, net	2,880			1,556
Allowance for equity funds used during construction	(3,937		)	(2,561		)
Change in cash overdraft	—			(2,305		)
Changes in assets and liabilities
Increase in accounts receivable	(10,958		)	(33,312		)
Increase in accrued unbilled revenues	(32,053		)	(18,479		)
Increase in fuel oil stock	(35,893		)	(6,509		)
Increase in materials and supplies	(7,599		)	(1,490		)
Increase in regulatory assets	(35,476		)	(14,498		)
Increase (decrease) in accounts payable	5,931			(48,288		)
Change in prepaid and accrued income taxes and utility revenue taxes	(21,141		)	12,178
Contributions to defined benefit pension and other postretirement benefit plans	(52,086		)	(37,021		)
Change in other assets and liabilities	(6,776		)	12,596
Net cash provided by (used in) operating activities	(21,525		)	16,057
Cash flows from investing activities
Capital expenditures	(141,618		)	(85,395		)
Contributions in aid of construction	26,981			8,153
Other	—			77
Net cash used in investing activities	(114,637		)	(77,165		)
Cash flows from financing activities
Common stock dividends	(36,522		)	(35,279		)
Preferred stock dividends of HECO and subsidiaries	(998		)	(998		)
Proceeds from issuance of long-term debt	417,000			—
Repayment of long-term debt	(328,500		)	—
Net increase in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less	44,242			—
Other	(1,929		)	(17		)
Net cash provided by (used in) financing activities	93,293			(36,294		)
Net decrease in cash and cash equivalents	(42,869		)	(97,402		)
Cash and cash equivalents, beginning of period	48,806			122,936
Cash and cash equivalents, end of period	$	5,937		$	25,534

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

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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 and the unaudited consolidated financial statements and the notes thereto in HECO’s Quarterly Report on SEC Form 10-Q for the quarter ended March 31, 2012.

In the opinion of HECO’s management, the accompanying unaudited consolidated financial statements contain all material adjustments required by GAAP to fairly state the financial position of HECO and its subsidiaries as of June 30, 2012 and December 31, 2011, the results of their operations for the three and six months ended June 30, 2012 and 2011 and their cash flows for the six months ended June 30, 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.

HECO and its subsidiaries revised their previously issued financial statements to correct an error that resulted in the understatement of franchise taxes, net of tax benefits, that should have been recorded in years prior to 2010. HECO and its subsidiaries determined the cumulative impact for periods prior to 2010 to be a charge to earnings of $3.2 million. These adjustments were not considered to be material individually or in the aggregate to previously issued financial statements. The table below illustrates the effects of this revision on HECO and its subsidiaries’ Consolidated Financial Statements for those line items affected (these revisions have no impact on HECO and its subsidiaries’ Consolidated Statements of Income and Cash Flows for the periods reported):

(in thousands)	As previously filed		As revised		Difference
December 31, 2011
Consolidated Balance Sheet
Prepayments and other	$	34,602	$	36,667	$	2,065
Total current assets	648,204		650,269		2,065
Total assets	4,671,942		4,674,007		2,065
Retained earnings	884,284		881,041		(3,243		)
Common stock equity	1,406,084		1,402,841		(3,243		)
Total capitalization	2,440,947		2,437,704		(3,243		)
Taxes accrued	224,768		230,076		5,308
Total current liabilities	559,684		564,992		5,308
Total capitalization and liabilities	4,671,942		4,674,007		2,065
Consolidated Statement of Changes in Common Stock Equity
Retained earnings	884,284		881,041		(3,243		)
Common stock equity	1,406,084		1,402,841		(3,243		)
December 31, 2010
Consolidated Statement of Changes in Common Stock Equity
Retained earnings	854,856		851,613		(3,243		)
Common stock equity	1,337,398		1,334,155		(3,243		)

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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 June 30, 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 six months ended June 30, 2012 and 2011 each consisted of $1.7 million of interest income received from the 2004 Debentures, $1.6 million of distributions to holders of the Trust Preferred Securities, and $0.1 million of common dividends on the trust common securities to HECO. So long as the 2004 Trust Preferred Securities are outstanding, HECO is not entitled to receive any funds from Trust III other than pro-rata distributions, subject to certain subordination provisions, on the trust common securities. In the event of a default by HECO in the performance of its obligations under the 2004 Debentures or under its Guarantees, or in the event HECO, HELCO or MECO elect to defer payment of interest on any of their respective 2004 Debentures, then HECO will be subject to a number of restrictions, including a prohibition on the payment of dividends on its common stock.

Power purchase agreements. As of June 30, 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.

Some of the IPPs provided sufficient information for HECO to determine that the IPP was not a VIE, or was either a “business” or “governmental organization,” and thus excluded from the scope of accounting standards for VIEs. A windfarm and Kalaeloa provided sufficient information, as required under their PPAs or amendments, such that HECO could determine that consolidation was not required. Management has concluded that the consolidation of some IPPs is not required as HECO and its subsidiaries do not have variable interests in the IPPs because the PPAs do not require them to absorb any variability of the IPPs.

An enterprise with an interest in a VIE or potential VIE created before December 31, 2003, and not thereafter materially modified, is not required to apply accounting standards for VIEs to that entity if the enterprise is unable to obtain the necessary information after making an exhaustive effort. HECO and its subsidiaries have made and continue to make exhaustive efforts to get the necessary information from two firm capacity producers and other small IPPs who entered into their PPAs prior to December 31, 2003 and have not provided such information, but have been unsuccessful to date as it was not a contractual requirement to provide such information prior to 2004. If the requested information is ultimately received from the remaining IPPs, a possible outcome of future analyses of such information is the consolidation of one or more of such IPPs. The consolidation of any significant IPP could have a material effect on the Company’s and HECO’s consolidated financial statements, including the recognition of a significant amount of assets and liabilities and the potential recognition of losses. If HECO and its subsidiaries determine they are required to consolidate the financial statements of such an IPP and the consolidation has a material effect, HECO and its subsidiaries would retrospectively apply accounting standards for VIEs.

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3 · Revenue taxes

HECO and its subsidiaries’ operating revenues include amounts for various Hawaii state revenue taxes. Revenue taxes are generally recorded as an expense in the period the related revenues are recognized. However, HECO and its subsidiaries’ revenue tax payments to the taxing authorities in the period are based on the prior year’s billed revenues (in the case of public service company taxes and PUC fees) or on the current year’s cash collections from electric sales (in the case of franchise taxes). For the six months ended June 30, 2012 and 2011, HECO and its subsidiaries included approximately $140 million and $121 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 six months of 2012, HECO and its subsidiaries contributed $52 million to their retirement benefit plans, compared to $37 million in the first six months of 2011. HECO and its subsidiaries’ current estimate of contributions to their retirement benefit plans in 2012 is $104 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 components of net periodic benefit cost were as follows:

	Three months ended June 30												Six months ended June 30
	Pension benefits						Other benefits						Pension benefits						Other benefits
(in thousands)	2012			2011			2012			2011			2012			2011			2012			2011

Service cost	$	11,000		$	8,474		$	959		$	1,129		$	20,802		$	17,039		$	2,007		$	2,352
Interest cost	15,465			14,803			2,147			2,340			30,726			29,652			4,352			4,724
Expected return on plan assets	(15,942		)	(15,352		)	(2,519		)	(2,618		)	(32,002		)	(30,636		)	(5,098		)	(5,226		)
Amortization of net transition obligation	—			—			(2		)	(2		)	—			—			(4		)	(4		)
Amortization of net prior service gain	(172		)	(187		)	(451		)	(312		)	(344		)	(374		)	(902		)	(539		)
Amortization of net actuarial loss	5,845			4,016			288			37			11,714			8,136			728			55
Net periodic benefit cost	16,196			11,754			422			574			30,896			23,817			1,083			1,362
Impact of PUC D&Os	(4,977		)	(556		)	(416		)	1,734			(8,834		)	(2,100		)	(1,096		)	2,752
Net periodic benefit cost (adjusted for impact of PUC D&Os)	$	11,219		$	11,198		$	6		$	2,308		$	22,062		$	21,717		$	(13	)	$	4,114

HECO and its subsidiaries recorded retirement benefits expense of $15 million and $19 million for the first six months of 2012 and 2011, respectively. The electric utilities charged a portion of the net periodic benefit cost to electric utility plant.

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Defined contribution plan information. For the first six 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 the large wind project for later review of prudence and reasonableness, and HECO is now seeking PUC approval to recover the deferred costs totaling $3.9 million for the Stage 1 studies through the REIP surcharge. 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. Decisions from the PUC are still pending.

In October 2011, HECO filed with the PUC 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 February 2012, the PUC granted HECO’s request for deferred accounting treatment for the inter-island project support costs. The amount of the deferred costs was limited to $5.89 million.

In May 2012, the PUC instituted a proceeding for a competitive bidding process for 50 MW of dispatchable renewable geothermal firm capacity generation on the island of Hawaii, and in July 2012, HELCO filed an application to defer costs related to the geothermal firm dispatchable capacity RFPs.

Interim increases. As of June 30, 2012, HECO and its subsidiaries had recognized $1 million of revenues with respect to interim orders related to general rate increase requests. Revenue amounts recorded pursuant to interim orders are subject to refund, with interest, if they exceed amounts allowed in a final order.

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

In May 2011, the PUC ordered independently conducted regulatory audits on the reasonableness of costs incurred for HECO’s East Oahu Transmission Project (EOTP), Campbell Industrial Park (CIP) combustion turbine

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No. 1 (CT-1) project, and Customer Information System (CIS) project. In July 2011, the PUC allowed HECO to defer the portion of costs that are in excess of the prior PUC approved amounts and related depreciation for HECO’s EOTP Phase 1 ($43 million) and the CIP CT-1 project ($32 million) until completion of independently conducted regulatory audits. The PUC also 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. Subsequently, in February 2012 and May 2012, the PUC granted HECO’s and MECO’s requests, respectively, to defer CIS project operation and maintenance expenses (limited to $2.3 million per year in 2011 and 2012 for HECO and limited to $0.6 million in 2012 for MECO) that are to be subject to a regulatory audit. The PUC also allowed them to accrue AFUDC on project costs (including deferred operation and maintenance expenses) until the completion of the regulatory audit and begin amortization of such costs when the amortization is included in rates. HELCO anticipates submitting a similar deferral request, but has not yet deferred any CIS project operation and maintenance costs. The PUC has 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 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 June 30, 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 at a cost of $59 million. The interim D&O issued in July 2011 in HECO’s 2011 test year rate case reflected approximately $16 million of EOTP Phase 1 costs and related depreciation expense in determining revenue requirements. As described above under “Major projects,” a regulatory audit was to be conducted before the PUC determined the recoverability of the remaining costs for EOTP Phase 1.

On March 29, 2012, the PUC approved the settlement agreement reached among HECO, the Consumer Advocate and the Department of Defense (parties in the HECO 2011 test year rate case proceeding) regarding the EOTP Phase 1 project costs. Under the settlement agreement, in lieu of a regulatory audit, HECO would write-off $9.5 million of EOTP Phase 1 gross plant in service and associated adjustments. The settlement agreement resulted in an after-tax charge to net income in the fourth quarter of 2011 of approximately $6 million. The PUC also provided for an additional interim increase of approximately $5 million in HECO’s 2011 test year rate case for the 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). In addition, the PUC eliminated the requirement for a regulatory audit for the EOTP Phase 1.

In the final D&O in the HECO 2011 test year rate case proceeding issued on June 29, 2012, the PUC approved the revenue requirements related to the prior interim D&Os related to the EOTP project costs.

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 June 30, 2012, HECO’s incurred costs for the Modified Phase 2 project amounted to $10 million (total cost of $14 million, less $4 million received in Smart Grid Investment funding).

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Management believes that no adjustment to project costs of EOTP Modified Phase 2 is required as of June 30, 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’s new software system became operational in May 2012. As of June 30, 2012, the utilities’ total deferred and capital cost estimate for the CIS project was $58.6 million (of which $58.4 million was incurred). The PUC has ordered that this project undergo a regulatory audit. See “Major Projects” above concerning the accounting treatment of the costs of the CIS project pending completion of the regulatory audit. Management believes no adjustment to the CIS project costs is required as of June 30, 2012.

Environmental regulation. HECO and its subsidiaries are subject to environmental laws and regulations that regulate the operation of existing facilities, the construction and operation of new facilities and the proper cleanup and disposal of hazardous waste and toxic substances. In recent years, legislative, regulatory and governmental activities related to the environment, including proposals and rulemaking under the Clean Air Act (CAA) and Clean Water Act (CWA), have increased significantly and management anticipates that such activity will continue.

On April 20, 2011, the Federal Register published the federal Environmental Protection Agency’s (EPA’s) proposed regulations required by section 316(b) of the CWA designed to protect aquatic organisms from adverse impacts associated with existing power plant cooling water intake structures. The proposed regulations would apply to the cooling water systems for the steam generating units at HECO’s power plants on the island of Oahu. If adopted as proposed, management believes the proposed regulations would require significant capital and annual O&M expenditures. As proposed, the regulations would require facilities to come into compliance within 8 years of the effective date of the final rule. On June 11, 2012, the EPA published additional information on the section 316(b) rulemaking that indicates that the EPA is considering incorporating site-specific compliance alternatives in the final rule. HECO submitted formal comments on July 11, 2012 in support of site-specific compliance alternatives. In mid-July 2012, EPA decided to delay issuance of the final section 316(b) rule until June 2013.

On February 16, 2012, the Federal Register published the EPA’s final rule establishing the EPA’s National Emission Standards for Hazardous Air Pollutants for fossil-fuel fired steam electrical generating units (EGUs). The final rule, known as the Mercury and Air Toxics Standards (MATS), applies to the 14 EGUs at HECO’s power plants. MATS establishes the Maximum Achievable Control Technology standards for the control of hazardous air pollutants emissions from new and existing EGUs. Based on a review of the final rule and the benefits and costs of alternative compliance strategies, HECO is pursuing a MATS compliance strategy based on switching to lower emissions fuels. 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. Potential compliance dates are after the expiration of current fuel oil contracts and future contract are planned to be amenable to fuel switching. The use of lower emissions fuels will provide for MATS compliance at lower overall costs, avoid the reduction in operational flexibility imposed by emissions control equipment, achieve timely compliance with the MATS and provide flexibility for optimizing the combined compliance strategies for MATS and the tightening of the National Ambient Air Quality Standards.

On May 29, 2012, the EPA published a proposed plan to address regional haze in Hawaii. This proposed plan would establish an aggregate annual limit for sulfur dioxide emissions from five HELCO steam generating units on the island of Hawaii. No specific control technologies were proposed for any HECO or MECO generating units. The EPA expects to issue the final regional haze plan for Hawaii in September 2012. HELCO and MECO submitted comments on the proposed plan in July 2012.

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,

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and the final form of the Hawaii regional haze plan, HECO and its subsidiaries may be required to incur material capital expenditures, higher fuel charges 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 at an adjacent parcel that Molokai Electric Company had used for equipment storage (the Adjacent Parcel) to determine the extent of impacts of subsurface contaminants. A 2011 assessment by a MECO contractor of the Adjacent Parcel identified environmental impacts, including elevated polychlorinated biphenyls (PCBs) in the subsurface soils. In cooperation with the DOH and EPA, MECO 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 June 30, 2012) for the additional investigation and estimated cleanup costs at the site and the Adjacent Parcel; however, final costs of remediation will depend on the results of continued investigation.

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

In July 2007, Act 234, which requires a statewide reduction of GHG emissions by January 1, 2020 to levels at or below the statewide GHG emission levels in 1990, became law in Hawaii. The electric utilities participated in a Task Force established under Act 234, which was charged with developing a work plan and regulatory approach to reduce GHG emissions, as well as in initiatives aimed at reducing their GHG emissions, such as 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 for public comment. 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.

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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 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	862			1,134
Liabilities incurred	—			—
Liabilities settled	(2,217		)	(573		)
Revisions in estimated cash flows	—			—
Balance, June 30	$	49,516		$	49,191

Collective bargaining agreements. As of June 30, 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.

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6 · Cash flows

Six months ended June 30	2012		2011
(in millions)

Supplemental disclosures of cash flow information
Interest paid	$	29	$	29
Income tax paid/(refunded)	3		(27		)
Supplemental disclosures of noncash activities
Additions to electric utility property, plant and equipment - Unpaid invoices and other	12		10

7 · Fair value measurements

Fair value estimates are based on the price that would be received to sell an asset, or paid upon the transfer of a liability, in an orderly transaction between market participants at the measurement date. The fair value estimates are generally determined based on assumptions that market participants would use in pricing the asset or liability and are based on market data obtained from independent sources. However, in certain cases, the electric utilities use their own assumptions about market participant assumptions based on the best information available in the circumstances. These valuations are estimates at a specific point in time, based on relevant market information, information about the financial instrument and judgments regarding future expected loss experience, economic conditions, risk characteristics of various financial instruments and other factors. These estimates do not reflect any premium or discount that could result if the electric utilities were to sell their entire holdings of a particular financial instrument at one time. Because no active trading market exists for a portion of the electric utilities’ financial instruments, fair value estimates cannot be determined with precision. Changes in the underlying assumptions used, including discount rates and estimates of future cash flows, could significantly affect the estimates. In addition, the tax ramifications related to the realization of the unrealized gains and losses could have a significant effect on fair value estimates, but have not been considered in making such estimates.

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

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.

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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:

	June 30, 2012				December 31, 2011
(in thousands)	Carrying amount		Estimated fair value		Carrying amount		Estimated fair value

Financial assets
Cash and cash equivalents (Level 2)	$	5,937	$	5,937	$	48,806	$	48,806

Financial liabilities
Short-term borrowings - nonaffiliates (Level 2)	44,242		44,242		—		—
Long-term debt, net, including amounts due within one year (Level 2)	1,147,653		1,175,269		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 June 30, 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 June 30, 2012, the undiscounted future cash outflows used were $33 million. Also, see Note 5.

8 · Credit agreement and changes in long-term debt

Credit agreement. HECO maintains an amended revolving noncollateralized credit agreement, which established a line of credit facility of $175 million, with a letter of credit sub-facility, expiring on December 5, 2016, with a syndicate of eight financial institutions. The credit facility will be maintained to support the issuance of commercial paper, but also may be drawn to repay HECO’s short-term indebtedness, to make loans to subsidiaries and for HECO’s capital expenditures, working capital and general corporate purposes.

Changes in long-term debt. 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
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	$	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 redeem special purpose revenue bonds and refunding special purpose revenue bonds issued by the Department of Budget and Finance of the State of Hawaii

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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.

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

	Three months ended June 30						Six months ended June 30
(in thousands)	2012			2011			2012			2011
Operating income from regulated and nonregulated activities before income taxes (per HEI consolidated statements of income)	$	61,496		$	42,518		$	118,750		$	87,726
Deduct:
Income taxes on regulated activities	(18,574		)	(11,160		)	(35,939		)	(22,770		)
Revenues from nonregulated activities	(1,867		)	(1,086		)	(3,539		)	(2,120		)
Add: Expenses from nonregulated activities	452			268			816			423
Operating income from regulated activities after income taxes (per HECO consolidated statements of income)	$	41,507		$	30,540		$	80,088		$	63,259

10 · 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 June 30, 2012

(in thousands)	HECO			HELCO		MECO		RHI	UBC		Reclassifications and eliminations		HECO Consolidated
Operating revenues	$	567,527		111,741		108,417		—	—		—		$	787,685
Operating expenses
Fuel oil	241,393			30,616		59,055		—	—		—		331,064
Purchased power	141,136			37,395		9,821		—	—		—		188,352
Other operation	44,621			9,948		9,947		—	—		—		64,516
Maintenance	20,542			4,885		5,808		—	—		—		31,235
Depreciation	22,737			8,301		5,095		—	—		—		36,133
Taxes, other than income taxes	55,440			10,423		10,441		—	—		—		76,304
Income taxes	13,361			2,831		2,382		—	—		—		18,574
Total operating expenses	539,230			104,399		102,549		—	—		—		746,178
Operating income	28,297			7,342		5,868		—	—		—		41,507
Other income (loss)
Allowance for equity funds used during construction	1,654			160		183		—	—		—		1,997
Equity in earnings of subsidiaries	8,250			—		—		—	—		(8,250	)	—
Other, net	1,137			99		146		—	(1	)	(18	)	1,363
Total other income (loss)	11,041			259		329		—	(1	)	(8,268	)	3,360
Interest and other charges
Interest on long-term debt	10,190			2,913		2,220		—	—		—		15,323
Amortization of net bond premium and expense	429			108		124		—	—		—		661
Other interest charges	(167		)	20		66		—	—		(18	)	(99		)
Allowance for borrowed funds used during construction	(760		)	(64	)	(69	)	—	—		—		(893		)
Total interest and other charges	9,692			2,977		2,341		—	—		(18	)	14,992
Net income (loss)	29,646			4,624		3,856		—	(1	)	(8,250	)	29,875
Preferred stock dividend of subsidiaries	—			133		96		—	—		—		229
Net income (loss) attributable to HECO	29,646			4,491		3,760		—	(1	)	(8,250	)	29,646
Preferred stock dividends of HECO	270			—		—		—	—		—		270
Net income (loss) for common stock	$	29,376		4,491		3,760		—	(1	)	(8,250	)	$	29,376

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Comprehensive Income (unaudited)

Three months ended June 30, 2012

(in thousands)	HECO			HELCO		MECO		RHI	UBC		Reclassifications and eliminations		HECO Consolidated
Net income (loss) for common stock	$	29,376		4,491		3,760		—	(1	)	(8,250	)	$	29,376
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	3,364			518		412		—	—		(930	)	3,364
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes	(3,289		)	(511	)	(406	)	—	—		917		(3,289		)
Other comprehensive income (loss), net of taxes	75			7		6		—	—		(13	)	75
Comprehensive income (loss) attributable to common shareholder	$	29,451		4,498		3,766		—	(1	)	(8,263	)	$	29,451

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Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Income (Loss) (unaudited)

Three months ended June 30, 2011

(in thousands)	HECO			HELCO		MECO		RHI	UBC		Reclassifications and eliminations		HECO Consolidated
Operating revenues	$	510,653		110,595		106,404		—	—		—		$	727,652
Operating expenses
Fuel oil	220,231			32,123		59,787		—	—		—		312,141
Purchased power	131,921			32,242		7,574		—	—		—		171,737
Other operation	48,396			9,524		9,468		—	—		—		67,388
Maintenance	22,077			4,297		4,902		—	—		—		31,276
Depreciation	22,885			8,148		5,225		—	—		—		36,258
Taxes, other than income taxes	47,108			10,163		9,881		—	—		—		67,152
Income taxes	3,640			4,725		2,795		—	—		—		11,160
Total operating expenses	496,258			101,222		99,632		—	—		—		697,112
Operating income	14,395			9,373		6,772		—	—		—		30,540
Other income (loss)
Allowance for equity funds used during construction	974			233		110		—	—		—		1,317
Equity in earnings of subsidiaries	10,963			—		—		—	—		(10,963	)	—
Other, net	626			214		62		—	(1	)	(3	)	898
Total other income (loss)	12,563			447		172		—	(1	)	(10,966	)	2,215
Interest and other charges
Interest on long-term debt	9,131			2,984		2,268		—	—		—		14,383
Amortization of net bond premium and expense	503			137		126		—	—		—		766
Other interest charges	442			93		104		—	—		(3	)	636
Allowance for borrowed funds used during construction	(412		)	(102	)	(39	)	—	—		—		(553		)
Total interest and other charges	9,664			3,112		2,459		—	—		(3	)	15,232
Net income (loss)	17,294			6,708		4,485		—	(1	)	(10,963	)	17,523
Preferred stock dividend of subsidiaries	—			133		96		—	—		—		229
Net income (loss) attributable to HECO	17,294			6,575		4,389		—	(1	)	(10,963	)	17,294
Preferred stock dividends of HECO	270			—		—		—	—		—		270
Net income (loss) for common stock	$	17,024		6,575		4,389		—	(1	)	(10,963	)	$	17,024

Consolidating Statement of Comprehensive Income (unaudited)

Three months ended June 30, 2011

(in thousands)	HECO			HELCO		MECO		RHI	UBC		Reclassifications and eliminations		HECO Consolidated
Net income (loss) for common stock	$	17,024		6,575		4,389		—	(1	)	(10,963	)	$	17,024
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	2,152			339		284		—	—		(623	)	2,152
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes	(2,105		)	(338	)	(282	)	—	—		620		(2,105		)
Other comprehensive income (loss), net of taxes	47			1		2		—	—		(3	)	47
Comprehensive income (loss) attributable to common shareholder	$	17,071		6,576		4,391		—	(1	)	(10,966	)	$	17,071

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Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Income (Loss) (unaudited)

Six months ended June 30, 2012

(in thousands)	HECO			HELCO		MECO		RHI		UBC		Reclassifications and eliminations		HECO Consolidated
Operating revenues	$	1,098,140		224,068		213,415		—		—		—		$	1,535,623
Operating expenses
Fuel oil	476,419			63,026		119,458		—		—		—		658,903
Purchased power	265,916			71,303		15,922		—		—		—		353,141
Other operation	84,569			18,963		22,833		—		—		—		126,365
Maintenance	41,378			9,134		10,761		—		—		—		61,273
Depreciation	45,308			16,737		10,570		—		—		—		72,615
Taxes, other than income taxes	105,993			20,886		20,420		—		—		—		147,299
Income taxes	25,324			7,054		3,561		—		—		—		35,939
Total operating expenses	1,044,907			207,103		203,525		—		—		—		1,455,535
Operating income	53,233			16,965		9,890		—		—		—		80,088
Other income (loss)
Allowance for equity funds used during construction	3,235			285		417		—		—		—		3,937
Equity in earnings of subsidiaries	16,740			—		—		—		—		(16,740	)	—
Other, net	2,201			200		257		(1	)	(1	)	(28	)	2,628
Total other income (loss)	22,176			485		674		(1	)	(1	)	(16,768	)	6,565
Interest and other charges
Interest on long-term debt	19,320			5,898		4,488		—		—		—		29,706
Amortization of net bond premium and expense	912			245		249		—		—		—		1,406
Other interest charges	(554		)	53		159		—		—		(28	)	(370		)
Allowance for borrowed funds used during construction	(1,485		)	(115	)	(163	)	—		—		—		(1,763		)
Total interest and other charges	18,193			6,081		4,733		—		—		(28	)	28,979
Net income (loss)	57,216			11,369		5,831		(1	)	(1	)	(16,740	)	57,674
Preferred stock dividend of subsidiaries	—			267		191		—		—		—		458
Net income (loss) attributable to HECO	57,216			11,102		5,640		(1	)	(1	)	(16,740	)	57,216
Preferred stock dividends of HECO	540			—		—		—		—		—		540
Net income (loss) for common stock	$	56,676		11,102		5,640		(1	)	(1	)	(16,740	)	$	56,676

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Comprehensive Income (unaudited)

Six months ended June 30, 2012

(in thousands)	HECO			HELCO		MECO		RHI		UBC		Reclassifications and eliminations		HECO Consolidated
Net income (loss) for common stock	$	56,676		11,102		5,640		(1	)	(1	)	(16,740	)	$	56,676
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	6,836			1,050		885		—		—		(1,935	)	6,836
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes	(6,684		)	(1,037	)	(873	)	—		—		1,910		(6,684		)
Other comprehensive income (loss), net of taxes	152			13		12		—		—		(25	)	152
Comprehensive income (loss) attributable to common shareholder	$	56,828		11,115		5,652		(1	)	(1	)	(16,765	)	$	56,828

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Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Income (Loss) (unaudited)

Six months ended June 30, 2011

(in thousands)	HECO			HELCO		MECO		RHI		UBC		Reclassifications and eliminations		HECO Consolidated
Operating revenues	$	960,477		210,230		201,246		—		—		—		$	1,371,953
Operating expenses
Fuel oil	403,497			58,614		110,890		—		—		—		573,001
Purchased power	244,672			62,264		12,759		—		—		—		319,695
Other operation	95,651			17,792		19,476		—		—		—		132,919
Maintenance	43,269			8,148		9,055		—		—		—		60,472
Depreciation	45,768			16,471		10,451		—		—		—		72,690
Taxes, other than income taxes	88,997			19,336		18,814		—		—		—		127,147
Income taxes	8,338			8,494		5,938		—		—		—		22,770
Total operating expenses	930,192			191,119		187,383		—		—		—		1,308,694
Operating income	30,285			19,111		13,863		—		—		—		63,259
Other income (loss)
Allowance for equity funds used during construction	1,934			316		311		—		—		—		2,561
Equity in earnings of subsidiaries	22,453			—		—		—		—		(22,453	)	—
Other, net	1,358			320		154		(2	)	(4	)	(18	)	1,808
Total other income (loss)	25,745			636		465		(2	)	(4	)	(22,471	)	4,369
Interest and other charges
Interest on long-term debt	18,261			5,969		4,536		—		—		—		28,766
Amortization of net bond premium and expense	1,016			280		253		—		—		—		1,549
Other interest charges	820			174		199		—		—		(18	)	1,175
Allowance for borrowed funds used during construction	(820		)	(135	)	(118	)	—		—		—		(1,073		)
Total interest and other charges	19,277			6,288		4,870		—		—		(18	)	30,417
Net income (loss)	36,753			13,459		9,458		(2	)	(4	)	(22,453	)	37,211
Preferred stock dividend of subsidiaries	—			267		191		—		—		—		458
Net income (loss) attributable to HECO	36,753			13,192		9,267		(2	)	(4	)	(22,453	)	36,753
Preferred stock dividends of HECO	540			—		—		—		—		—		540
Net income (loss) for common stock	$	36,213		13,192		9,267		(2	)	(4	)	(22,453	)	$	36,213

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Comprehensive Income (unaudited)

Six months ended June 30, 2011

(in thousands)	HECO			HELCO		MECO		RHI		UBC		Reclassifications and eliminations		HECO Consolidated
Net income (loss) for common stock	$	36,213		13,192		9,267		(2	)	(4	)	(22,453	)	$	36,213
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	4,426			696		567		—		—		(1,263	)	4,426
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes	(4,352		)	(695	)	(568	)	—		—		1,263		(4,352		)
Other comprehensive income (loss), net of taxes	74			1		(1	)	—		—		—		74
Comprehensive income (loss) attributable to common shareholder	$	36,287		13,193		9,266		(2	)	(4	)	(22,453	)	$	36,287

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Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Balance Sheet (unaudited)

June 30, 2012

(in thousands)	HECO			HELCO		MECO		RHI	UBC	Reclassifications and eliminations		HECO Consolidated
Assets
Utility plant, at cost
Land	$	43,339		5,182		3,016		—	—	—		$	51,537
Plant and equipment	3,175,570			1,056,182		924,571		—	—	—		5,156,323
Less accumulated depreciation	(1,160,195		)	(425,683	)	(418,587	)	—	—	—		(2,004,465		)
Construction in progress	144,388			15,063		13,535		—	—	—		172,986
Net utility plant	2,203,102			650,744		522,535		—	—	—		3,376,381
Investment in wholly owned subsidiaries, at equity	521,966			—		—		—	—	(521,966	)	—
Current assets
Cash and cash equivalents	2,423			2,934		475		80	25	—		5,937
Advances to affiliates	8,700			19,350		—		—	—	(28,050	)	—
Customer accounts receivable, net	143,580			29,989		26,875		—	—	—		200,444
Accrued unbilled revenues, net	124,602			24,955		20,322		—	—	—		169,879
Other accounts receivable, net	13,250			(64	)	1,371		—	—	(12,092	)	2,465
Fuel oil stock, at average cost	156,942			19,731		30,768		—	—	—		207,441
Materials and supplies, at average cost	31,268			5,722		13,797		—	—	—		50,787
Prepayments and other	26,934			8,641		7,826		—	—	—		43,401
Regulatory assets	27,862			1,241		1,269		—	—	—		30,372
Total current assets	535,561			112,499		102,703		80	25	(40,142	)	710,726
Other long-term assets
Regulatory assets	493,784			87,494		86,798		—	—	—		668,076
Unamortized debt expense	7,600			2,157		1,510		—	—	—		11,267
Other	59,708			14,397		16,995		—	—	—		91,100
Total other long-term assets	561,092			104,048		105,303		—	—	—		770,443
Total assets	$	3,821,721		867,291		730,541		80	25	(562,108	)	$	4,857,550
Capitalization and liabilities
Capitalization
Common stock equity	$	1,423,148		285,014		236,847		80	25	(521,966	)	$	1,423,148
Cumulative preferred stock—not subject to mandatory redemption	22,293			7,000		5,000		—	—	—		34,293
Long-term debt, net	780,334			201,319		166,000		—	—	—		1,147,653
Total capitalization	2,225,775			493,333		407,847		80	25	(521,966	)	2,605,094
Current liabilities
Short-term borrowings-nonaffiliates	44,242			—		—		—	—	—		44,242
Short-term borrowings-affiliate	19,350			—		8,700		—	—	(28,050	)	—
Accounts payable	164,002			22,404		20,078		—	—	—		206,484
Interest and preferred dividends payable	12,774			4,046		2,203		—	—	(9	)	19,014
Taxes accrued	150,611			34,504		32,206		—	—	—		217,321
Other	40,451			11,972		15,107		—	—	(12,083	)	55,447
Total current liabilities	431,430			72,926		78,294		—	—	(40,142	)	542,508
Deferred credits and other liabilities
Deferred income taxes	268,645			66,908		44,931		—	—	—		380,484
Regulatory liabilities	215,648			64,846		37,464		—	—	—		317,958
Unamortized tax credits	37,489			13,065		12,883		—	—	—		63,437
Retirement benefits liability	344,998			57,915		60,717		—	—	—		463,630
Other	69,077			20,583		13,573		—	—	—		103,233
Total deferred credits and other liabilities	935,857			223,317		169,568		—	—	—		1,328,742
Contributions in aid of construction	228,659			77,715		74,832		—	—	—		381,206
Total capitalization and liabilities	$	3,821,721		867,291		730,541		80	25	(562,108	)	$	4,857,550

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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	516,143			—		—		—	—	(516,143	)	—
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	22,517			6,948		7,343		—	—	(141	)	36,667
Regulatory assets	18,038			1,115		1,130		—	—	—		20,283
Total current assets	481,012			129,800		108,698		82	26	(69,349	)	650,269
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	$	3,654,134		877,657		727,600		82	26	(585,492	)	$	4,674,007
Capitalization and liabilities
Capitalization
Common stock equity	$	1,402,841		280,468		235,568		81	26	(516,143	)	$	1,402,841
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	2,054,891			491,578		407,271		81	26	(516,143	)	2,437,704
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	155,867			38,598		35,752		—	—	(141	)	230,076
Other	50,828			9,478		13,603		1	—	(4,557	)	69,353
Total current liabilities	466,617			88,966		78,757		1	—	(69,349	)	564,992
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	$	3,654,134		877,657		727,600		82	26	(585,492	)	$	4,674,007

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Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Changes in Common Stock Equity (unaudited)

Six months ended June 30, 2012

(in thousands)	HECO			HELCO		MECO		RHI		UBC		Reclassifications and eliminations		HECO Consolidated
Balance, December 31, 2011	$	1,402,841		280,468		235,568		81		26		(516,143	)	$	1,402,841
Net income (loss) for common stock	56,676			11,102		5,640		(1	)	(1	)	(16,740	)	56,676
Other comprehensive income (loss), net of taxes	152			13		12		—		—		(25	)	152
Common stock dividends	(36,522		)	(6,569	)	(4,373	)	—		—		10,942		(36,522		)
Common stock issue expenses	1			—		—		—		—		—		1
Balance, June 30, 2012	$	1,423,148		285,014		236,847		80		25		(521,966	)	$	1,423,148

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Changes in Common Stock Equity (unaudited)

Six months ended June 30, 2011

(in thousands)	HECO			HELCO		MECO		RHI		UBC		Reclassifications and eliminations		HECO Consolidated
Balance, December 31, 2010	$	1,334,155		269,986		229,651		86		5		(499,728	)	$	1,334,155
Net income (loss) for common stock	36,213			13,192		9,267		(2	)	(4	)	(22,453	)	36,213
Other comprehensive income (loss), net of taxes	74			1		(1	)	—		—		—		74
Common stock dividends	(35,279		)	(8,061	)	(6,002	)	—		—		14,063		(35,279		)
Capital contribution from parent	—			—		—		—		25		(25	)	—
Balance, June 30, 2011	$	1,335,163		275,118		232,915		84		26		(508,143	)	$	1,335,163

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Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Cash Flows (unaudited)

Six months ended June 30, 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)	$	57,216		11,369		5,831		(1	)	(1	)	(16,740	)	$	57,674
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Equity in earnings of subsidiaries	(16,790		)	—		—		—		—		16,740		(50		)
Common stock dividends received from subsidiaries	10,967			—		—		—		—		(10,942	)	25
Depreciation of property, plant and equipment	45,308			16,737		10,570		—		—		—		72,615
Other amortization	347			1,418		1,005		—		—		—		2,770
Change in deferred income taxes	31,673			5,857		4,994		—		—		—		42,524
Change in tax credits, net	2,641			125		114		—		—		—		2,880
Allowance for equity funds used during construction	(3,235		)	(285	)	(417	)	—		—		—		(3,937		)
Changes in assets and liabilities:
Increase in accounts receivable	(17,653		)	(137	)	(702	)	—		—		7,534		(10,958		)
Increase in accrued unbilled revenues	(21,274		)	(6,456	)	(4,323	)	—		—		—		(32,053		)
Increase in fuel oil stock	(28,905		)	(514	)	(6,474	)	—		—		—		(35,893		)
Increase in materials and supplies	(6,172		)	(1,022	)	(405	)	—		—		—		(7,599		)
Increase in regulatory assets	(28,190		)	(3,234	)	(4,052	)	—		—		—		(35,476		)
Increase (decrease) in accounts payable	12,843			(6,938	)	26		—		—		—		5,931
Change in prepaid and accrued income and utility revenue taxes	(9,994		)	(6,347	)	(4,800	)	—		—		—		(21,141		)
Contributions to defined benefit pension and other postretirement benefit plans	(38,693		)	(6,536	)	(6,857	)	—		—		—		(52,086		)
Change in other assets and liabilities	(4,021		)	657		4,148		(1	)	—		(7,534	)	(6,751		)
Net cash provided by (used in) operating activities	(13,932		)	4,694		(1,342	)	(2	)	(1	)	(10,942	)	(21,525		)
Cash flows from investing activities:
Capital expenditures	(111,011		)	(17,405	)	(13,202	)	—		—		—		(141,618		)
Contributions in aid of construction	23,693			2,327		961		—		—		—		26,981
Advances from (to) affiliates	(8,700		)	26,800		18,500		—		—		(36,600	)	—
Net cash provided by (used in) investing activities	(96,018		)	11,722		6,259		—		—		(36,600	)	(114,637		)
Cash flows from financing activities:
Common stock dividends	(36,522		)	(6,569	)	(4,373	)	—		—		10,942		(36,522		)
Preferred stock dividends of HECO and subsidiaries	(540		)	(267	)	(191	)	—		—		—		(998		)
Proceeds from issuance of long-term debt	327,000			31,000		59,000		—		—		—		417,000
Repayment of long-term debt	(219,580		)	(41,200	)	(67,720	)	—		—		—		(328,500		)
Net increase (decrease) in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less	(1,058		)	—		8,700		—		—		36,600		44,242
Other	(1,746		)	171		(354	)	—		—		—		(1,929		)
Net cash provided by (used in) financing activities	67,554			(16,865	)	(4,938	)	—		—		47,542		93,293
Net decrease in cash and cash equivalents	(42,396		)	(449	)	(21	)	(2	)	(1	)	—		(42,869		)
Cash and cash equivalents, beginning of period	44,819			3,383		496		82		26		—		48,806
Cash and cash equivalents, end of period	$	2,423		2,934		475		80		25		—		$	5,937

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Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Cash Flows (unaudited)

Six months ended June 30, 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)	$	36,753		13,459		9,458		(2	)	(4	)	(22,453	)	$	37,211
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Equity in earnings of subsidiaries	(22,503		)	—		—		—		—		22,453		(50		)
Common stock dividends received from subsidiaries	14,113			—		—		—		—		(14,063	)	50
Depreciation of property, plant and equipment	45,768			16,471		10,451		—		—		—		72,690
Other amortization	8,602			1,283		948		—		—		—		10,833
Change in deferred income taxes	19,474			6,234		7,748		—		—		—		33,456
Change in tax credits, net	1,193			307		56		—		—		—		1,556
Allowance for equity funds used during construction	(1,934		)	(316	)	(311	)	—		—		—		(2,561		)
Change in cash overdraft	—			(2,527	)	222		—		—		—		(2,305		)
Changes in assets and liabilities:
Increase in accounts receivable	(25,879		)	(3,111	)	(5,486	)	—		—		1,164		(33,312		)
Increase in accrued unbilled revenues	(16,571		)	(1,769	)	(139	)	—		—		—		(18,479		)
Decrease (increase) in fuel oil stock	12,090			(5,168	)	(13,431	)	—		—		—		(6,509		)
Increase in materials and supplies	(956		)	(88	)	(446	)	—		—		—		(1,490		)
Increase in regulatory assets	(9,650		)	(1,057	)	(3,791	)	—		—		—		(14,498		)
Decrease in accounts payable	(45,638		)	(35	)	(2,615	)	—		—		—		(48,288		)
Change in prepaid and accrued income and utility revenue taxes	3,724			3,682		4,772		—		—		—		12,178
Contributions to defined benefit pension and other postretirement benefit plans	(27,431		)	(4,638	)	(4,952	)	—		—		—		(37,021		)
Change in other assets and liabilities	9,116			3,502		1,143		(2	)	1		(1,164	)	12,596
Net cash provided by (used in) operating activities	271			26,229		3,627		(4	)	(3	)	(14,063	)	16,057
Cash flows from investing activities:
Capital expenditures	(60,386		)	(13,937	)	(11,072	)	—		—		—		(85,395		)
Contributions in aid of construction	4,816			2,501		836		—		—		—		8,153
Other	77			—		—		—		—		—		77
Investment in consolidated subsidiary	(25		)	—		—		—		—		25		—
Advances from (to) affiliates	—			(5,850	)	12,500		—		—		(6,650	)	—
Net cash provided by (used in) investing activities	(55,518		)	(17,286	)	2,264		—		—		(6,625	)	(77,165		)
Cash flows from financing activities:
Common stock dividends	(35,279		)	(8,061	)	(6,002	)	—		—		14,063		(35,279		)
Preferred stock dividends of HECO and subsidiaries	(540		)	(267	)	(191	)	—		—		—		(998		)
Net decrease in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less	(6,650		)	—		—		—		—		6,650		—
Other	(16		)	—		(1	)	—		25		(25	)	(17		)
Net cash provided by (used in) financing activities	(42,485		)	(8,328	)	(6,194	)	—		25		20,688		(36,294		)
Net increase (decrease) in cash and cash equivalents	(97,732		)	615		(303	)	(4	)	22		—		(97,402		)
Cash and cash equivalents, beginning of period	121,019			1,229		594		89		5		—		122,936
Cash and cash equivalents, end of period	$	23,287		1,844		291		85		27		—		$	25,534

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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 June 30, 2012) financial statements and notes thereto included in this Form 10-Q.

HEI Consolidated

RESULTS OF OPERATIONS

(in thousands, except per	Three months ended June 30				%	Primary reason(s) for
share amounts)	2012		2011		change	significant change*
Revenues	$	854,268	$	794,319	8	Increase for the electric utility segment, partly offset by a decrease for the bank segment

Operating income	79,406		63,661		25	Increase for the electric utility segment, partly offset by decreases for the bank and “other” segments

Net income for common stock	38,800		27,139		43	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	$	0.28	43	Higher net income

Weighted-average number of common shares outstanding	96,693		95,393		1	Issuances of shares under the HEI Dividend Reinvestment and Stock Purchase Plan and Company employee plans

(in thousands, except per	Six months ended June 30				%	Primary reason(s) for
share amounts)	2012		2011		change	significant change*
Revenues	$	1,669,128	$	1,504,952	11	Increase for the electric utility and bank segments

Operating income	155,222		127,036		22	Increase for the electric utility segment, partly offset by decreases for the bank and “other” segments

Net income for common stock	77,116		55,601		39	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	$	0.80	$	0.58	38	Higher net income

Weighted-average number of common shares outstanding	96,430		95,107		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 second quarters of 2012 and 2011 were 37% and 33%, respectively. The Company’s effective tax rates (combined federal and state) for the first six months of 2012 and 2011 were 36% and 35%, respectively.

Dividends. The payout ratios for the first six months 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

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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 six months of 2012. State visitor arrivals grew by 10.2% in the first six months of 2012 over the same period in 2011. State visitor expenditures also continued to grow, increasing by 21.4% in the first six months of 2012 over the same period in 2011. Hotel occupancies and room rates also continued to rise. The outlook for the visitor industry remains positive with the Hawaii Tourism Authority expecting a 12.6% increase in airline seat capacity in the third quarter of 2012.

Hawaii’s unemployment rate was 6.4% in June 2012, lower than the state’s 6.7% rate in June 2011 and the June 2012 national unemployment rate of 8.2%. Hawaii’s unemployment rate has slowly improved after reaching a high of 7.1% in 2009.

For the first half of 2012 compared to the first half of 2011, the median sales price for single family residential homes on Oahu increased by 8.7% and home sales increased 0.4%. The first half of 2012 Oahu condominium median sales price rose 0.5% above the first half of 2011, but closed sales for the same period fell 3.3%.

Hawaii’s petroleum product prices reflect supply and demand in the Asia-Pacific region and the price of crude oil in international markets. The dramatic reduction in Japan’s nuclear production following the tragic earthquake and tsunami in March 2011 has increased regional demand for energy supplies, including petroleum, such that the prices of the utilities’ fuels have remained relatively elevated through the first half of 2012 compared to the price of West Texas Intermediate crude oil, which declined in the second quarter of 2012.

The Federal Open Market Committee (FOMC) held the federal funds rate target at 0 to 0.25% on June 20, 2012, based on the current moderate economic outlook. The FOMC expects the low federal funds rate to continue at least through late 2014, citing low rates of resource utilization and a subdued outlook for inflation. The FOMC also decided to continue, through at least the end of 2012 its program to extend the average maturity of the System Open Market Account portfolio in order to put downward pressure on longer-term interest rates. The FOMC stated it is also prepared to take further action as appropriate to support a stronger economic recovery and sustained improvement in labor market conditions in a context of price stability.

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

Recent tax developments. The Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010 contained major tax provisions that continue to impact the Company, including the 50% and 100% bonus depreciation provisions for qualified property that 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 December 2011, the Internal Revenue Service (IRS) issued regulations, which provide a framework for determining whether expenditures are deductible as repairs, 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.

In June 2012, the Joint Committee on Taxation (U.S. Congress) notified the Company that they took no exception to the settlement agreement for the 2007 through 2009 tax return examination, resulting in a tax refund of $6 million. As a consequence of this final settlement, the Company reversed FIN 48 liabilities and related interest associated with the examination years (primarily comprised of the tax reserves for repairs deductions taken on

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utility generation property in 2009), resulting in an increase in net income of $0.2 million in the second quarter of 2012.

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

Retirement benefits. For the first six months of 2012, the Company’s defined benefit retirement plans’ assets generated a gain, after investment management fees, of 6.7%. The market value of the defined benefit retirement plans’ assets of the Company as of June 30, 2012 was $1.1 billion (including $973 million for the utilities) compared to $983 million at December 31, 2011 (including $893 million for the utilities).

The Company estimates that the cash funding for its retirement benefit plans in 2012 will be $107 million ($104 million by the utilities and $3 million by HEI), which more than satisfies the minimum required contribution and considers the requirements of the utilities’ tracking mechanisms, the plans’ funded status and funding policy. The increase in expected contributions is driven by the minimum funding requirements under the Pension Protection Act of 2006.

On July 6, 2012, President Obama signed the Moving Ahead for Progress in the 21st Century Act (MAP-21), which included provisions related to the funding of pension plans. This law does not affect the Company’s accounting for pension benefits, but is expected to reduce the minimum required funding for 2012 and 2013. See Note 4 of HEI’s “Notes to Consolidated Financial Statements.”

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

“Other” segment.

	Three months ended June 30						Six months ended June 30						Primary reason(s) for
(in thousands)	2012			2011			2012			2011			significant change
Revenues	$	(5	)	$	(737	)	$	(7	)	$	(752	)	Lower losses on venture capital investments

Operating loss	(3,964		)	(2,677		)	(8,314		)	(6,264		)	Higher administrative and general expenses, including compensation and employee benefits expense

Net loss	(4,765		)	(5,080		)	(9,626		)	(9,658		)	Higher operating loss, more than offset by lower interest expense due to lower long-term debt and prior year losses on FSS

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.

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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)	June 30, 2012				December 31, 2011

Short-term borrowings—other than bank	$	96	3	%	$	69	2	%
Long-term debt, net—other than bank	1,430		46		1,340		45
Preferred stock of subsidiaries	34		1		34		1
Common stock equity	1,576		50		1,529		52
	$	3,136	100	%	$	2,972	100	%

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

	Six months ended June 30, 2012		Balance
(in millions)	Average balance		June 30, 2012		December 31, 2011
Short-term borrowings(1)
Commercial paper	$	57	$	52	$	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.” The maximum amount of external short-term borrowings during the first six months of 2012 was $99 million. At July 23, 2012, HEI had $51 million in outstanding commercial paper and its line of credit facility was undrawn.

HEI has a line of credit facility of $125 million (see Note 12 of HEI’s “Notes to Consolidated Financial Statements”). There are customary conditions which must be met in order to draw on it, including compliance with its covenants (such as covenants preventing HEI’s subsidiaries from entering into agreements that restrict the ability of the subsidiaries to pay dividends to, or to repay borrowings from, HEI). In addition to customary defaults, HEI’s failure to maintain its financial ratios, as defined in the credit agreement, or meet other requirements may result in an event of default. For example, it is an event of default if HEI fails to maintain a nonconsolidated “Capitalization Ratio” (funded debt) of 50% or less (ratio of 18% as of June 30, 2012, as calculated under the credit agreement) and “Consolidated Net Worth” of at least $975 million (Net Worth of $1.6 billion as of June 30, 2012, as calculated under the credit agreement), or if HEI no longer owns HECO. The commitment fee and interest charges on drawn amounts under the credit agreement are subject to adjustment in the event of a change in HEI’s long-term credit ratings.

The Company raised $24 million through the issuance of approximately 1 million shares of common stock under the DRIP, the HEIRSP, ASB 401(k) Plan and other plans during the first six months 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

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(the occurrence of which may result in some or all of the notes then outstanding becoming immediately due and payable) and provisions requiring the maintenance by HEI of certain financial ratios generally consistent with those in HEI’s revolving noncollateralized credit agreement. For example, see discussion of “Capitalization Ratio” and “Consolidated Net Worth” above.

For the first six months of 2012, net cash used by operating activities of consolidated HEI was $4 million. Net cash used by investing activities for the same period was $188 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 $129 million as a result of several factors, including net increases in long-term debt, deposit liabilities and short-term borrowings and proceeds from the issuance of common stock under HEI plans, partly offset by the payment of common stock dividends and a net decrease in retail repurchase agreements. 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 six months of 2012, HECO and ASB paid dividends to HEI of $37 million and $20 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 six months 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 the utilities’ under-earning situation that has existed over the last several years. Prior to and during the transition to decoupling, however, the utilities’ returns have been well below PUC-allowed returns.

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

1. 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 outcomes 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 (as of June 30, 2012) returns were as follows:

%	Return on average rate base (RORB)*				ROACE**
Twelve months ended June 30, 2012	HECO	HELCO	MECO		HECO		HELCO		MECO
Utility returns	8.25	8.39	5.84		9.44		8.77		6.11
PUC-allowed returns	8.11	8.31	7.91		10.00		10.00		10.00
Difference	0.14	0.08	(2.07	)	(0.56	)	(1.23	)	(3.89	)

* 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.

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The ROACE gap is expected to continue as a result of expenses not included in setting electric rates 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, for CIP CT-1 costs that are subject to a regulatory audit, carrying charges are accrued only at HECO’s debt rate.

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 the final D&O was issued on June 29, 2012. 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’s 2012 annual decoupling filing for the tariff that is effective June 1, 2012 through May 31, 2013 reflects a RAM adjustment of $7.0 million ($3.7 million for O&M costs and $3.3 million for invested capital). The filing also includes the collection of the accrued RBA balance as of December 31, 2011 and associated revenue taxes of $22.4 million.

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.

HELCO’s tariff for its annual RAM for 2011 and 2012, which reflects a revenue adjustment that results in a reduction in annual revenues of $2.1 million, is effective through May 31, 2013. MECO filed its 2012 RAM (calculated to be $0.1 million) for informational purposes only since the pending interim D&O for its 2012 test year rate case was anticipated to be issued shortly. MECO’s interim D&O for its 2012 test year rate case was issued on May 21, 2012.

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

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Results.

Three months ended June 30				Increase
2012		2011		(decrease)						(in millions)
$	790	$	729	$	61					Revenues. Increase largely due to:
							41			Higher fuel and purchased energy costs partially offset by lower kilowatthour (KWH) sales adjusted for decoupling mechanisms and revenue taxes thereon
							14			Rate increase granted to HECO for the 2011 test year
							1			Rate increase granted to MECO for the 2012 test year

331		312		19						Fuel oil expense. Increase largely due to higher fuel costs, partly offset by less KWHs generated

188		172		16						Purchased power expense. Increase largely due to higher purchased energy costs, partly offset by less KWHs purchased

96		99		(3		)				Other operation and maintenance expenses. Decrease largely due to:
							(3		)	Increase in capitalization of administrative costs, which lowered administrative and general expenses
							(1		)	Regulatory decision allowing reversal of previously expensed interisland wind project support costs

113		103		10						Other expenses. Increase largely due to:
							5			Higher taxes other than income taxes primarily resulting from higher revenue

61		43		18						Operating income. Increase largely due to the interim rate increase for HECO

29		17		12						Net income for common stock. Increase largely due to:
							8			HECO and MECO rate increases
							2			Lower O&M expense
							1			Higher AFUDC

2,257		2,361					(104		)	Kilowatthour sales (millions)
68.0		70.5					(2.5		)	Wet-bulb temperature (Oahu average; degrees Fahrenheit)
1,150		1,257					(107		)	Cooling degree days (Oahu)
$	145.27	$	123.69				$	21.58		Average fuel oil cost per barrel

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Six months ended June 30				Increase
2012		2011		(decrease)						(in millions)
$	1,539	$	1,374	$	165					Revenues. Increase largely due to:
							134			Higher fuel prices and purchased energy costs partially offset by lower kilowatthour (KWH) sales adjusted for decoupling mechanisms and revenue taxes thereon
							26			Rate increase granted to HECO for the 2011 test year
							1			Rate increase granted to MECO for the 2012 test year

659		573		86						Fuel oil expense. Increase largely due to higher fuel costs, partly offset by less KWHs generated

353		320		33						Purchased power expense. Increase largely due to higher purchased energy costs, partly offset by less KWHs purchased

188		193		(5		)				Other operation and maintenance expenses. Decrease largely due to:
							(7		)	Increase in capitalization of administrative costs, which lowered administrative and general expenses
							(2		)	Regulatory decision allowing reversal of previously expensed interisland wind project support costs
							3			Increase in general liability reserve for an environmental matter

220		200		20						Other expenses. Increase largely due to:
							15			Higher taxes other than income taxes primarily resulting from higher revenue

119		88		31						Operating income. Increase largely due to the interim rate increase for HECO

57		36		21						Net income for common stock. Increase largely due to:
							15			HECO and MECO rate increases
							3			Lower O&M expense
							2			Higher AFUDC

4,508		4,711					(203		)	Kilowatthour sales (millions)
67.6		69.3					(1.7		)	Wet-bulb temperature (Oahu average; degrees Fahrenheit)
2,011		2,177					(166		)	Cooling degree days (Oahu)
$	139.63	$	112.23				$	27.40		Average fuel oil cost per barrel

Note: The electric utilities had effective tax rates for the second quarters of 2012 and 2011 of 38% and 39%, respectively, and for the first six months of 2012 and 2011 of 38% and 38%, respectively.

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.

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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
2009
Request (1)	7/3/08	$	97.0	5.2	11.25	8.81	$	1,408	54.30	Yes	No
Interim increase	8/3/09	61.1		4.7	10.50	8.45	1,169		55.81		No
Interim increase (adjusted)	2/20/10	73.8		5.7	10.50	8.45	1,251		55.81		No
Final increase (2)	3/1/11	66.4		5.1	10.00	8.16	1,250		55.81		Yes
2011 (3)
Request	7/30/10	$	113.5	6.6	10.75	8.54	$	1,569	56.29	Yes	Yes
Interim increase	7/26/11	53.2		3.1	10.00	8.11	1,354		56.29		Yes
Interim increase (adjusted)	4/2/12	58.2		3.4	10.00	8.11	1,385		56.29		Yes
Interim increase (adjusted)	5/21/12	58.8		3.4	10.00	8.11	1,386		56.29		Yes
Final increase	Pending	58.1		3.4	10.00	8.11	1,386		56.29		Yes
HELCO
2010 (4)
Request	12/9/09	$	20.9	6.0	10.75	8.73	$	487	55.91	Yes	Yes
Interim increase	1/14/11	6.0		1.7	10.50	8.59	465		55.91		No
Interim increase (adjusted)	1/1/12	5.2		1.5	10.50	8.59	465		55.91		No
Final increase	4/9/12	4.5		1.3	10.00	8.31	465		55.91		Yes
2013
Request (see discussion below)	Pending
MECO
2010 (5)
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 (6)	7/22/11	$	27.5	6.7	11.00	8.72	$	393	56.85	Yes	Yes
Interim increase	6/1/12	13.1		3.2	10.00	7.91	393		56.86		Yes

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

(1) In April 2009, HECO reduced this rate increase request by $6.2 million because a new Customer Information System would not be placed in service as originally planned (see Note 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) HELCO’s request was primarily to cover investments for system upgrade projects, two major transmission line upgrades and increasing O&M expenses. On February 8, 2012, the PUC issued a final D&O, which reflected the approval of decoupling and cost-recovery mechanisms, and on February 21, 2012, HELCO filed its revised tariffs to reflect the increase in rates. On April 4, 2012, the PUC issued an order approving the revised tariffs, which became effective April 9, 2012. HELCO implemented the decoupling mechanism and began tracking the target revenues and actual recorded revenues via a revenue balancing account. HELCO also reset the heat rates and implemented heat rate deadbands and the PPAC, which provides a surcharge mechanism that more closely aligns cost recovery with costs incurred. The revised tariffs reflect a lower increase in annual revenue requirement compared to the interim increase due to factors that became effective concurrently with the revised tariffs (lower depreciation rates and lower ROACE) and therefore, no refund to customers was required.

(5) MECO’s interim increase, effective August 1, 2010, was based on a stipulated agreement reached with the Consumer Advocate and temporary approval of new depreciation rates and methodology in a separate depreciation proceeding. The adjustment to this increase, effective January 12, 2011, reflects the final rates from MECO’s 2007 test year rate case. On February 13, 2012, the PUC issued an order instructing MECO and the

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

(6) 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.

HECO 2011 test year rate case. On July 22, 2011, the PUC issued an interim D&O in HECO’s 2011 test year rate case, which became effective July 26, 2011. The PUC did not approve the portion of the settlement agreement with the Consumer Advocate allowing deferral of certain costs and HECO filed a motion for clarification and/or partial reconsideration of the interim D&O’s findings and conclusions on the deferral of costs.

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

On February 3, 2012, the parties reached a settlement agreement on the EOTP Phase 1 project costs, agreeing that, in lieu of a regulatory audit, HECO would write-off $9.5 million of gross plant in service EOTP Phase 1 costs and associated adjustments and carrying charges. The settlement agreement resulted in an after-tax charge to net income in the fourth quarter of 2011 of approximately $6 million. The parties also agreed to stipulate to an additional annual interim increase of $5 million to be effective March 1, 2012, based on additional revenue requirements reflecting all remaining EOTP costs not previously included in rates and offset by other minor adjustments to the interim increase that became effective on July 26, 2011. On March 29, 2012, the PUC approved the settlement agreement, and ordered that the regulatory audit for EOTP Phase 1 need not be conducted. 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 submitted a tariff to reflect this adjustment and on May 14, 2012, the PUC approved HECO’s request for this interim increase, which became effective May 21, 2012.

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

On July 24, 2012, HECO submitted the tariffs reflecting the final rates for review and is requesting approval to make the final rates effective September 1, 2012. Since the final rate increase as a result of the second stipulated supplement to the settlement agreement is lower than the interim increase currently in effect, HECO will be refunding customers approximately $0.8 million with accrued interest since July 26, 2011. The refund amount through June 30, 2012 of approximately $0.8 million has been accrued as of June 30, 2012.

HELCO 2013 test year rate case. 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.

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

Clean energy strategy. The utilities’ policy is to support efforts to increase renewable energy in Hawaii. The utilities believe their actions will help stabilize customer bills over time as they become less dependent on costly and price-volatile fossil fuel. The utilities’ clean energy strategy will also allow them to meet Hawaii’s RPS law, which requires electric utilities to meet an RPS of 10%, 15%, 25% and 40% by December 31, 2010, 2015, 2020 and 2030, respectively. HECO met the 10% RPS for 2010 with a consolidated RPS of 20.7%, including savings from energy efficiency programs and solar water heating (or 9.5% without DSM energy savings). Energy savings resulting from DSM energy efficiency programs and solar water heating will not count toward the RPS after 2014. Through June 2012, HECO achieved an RPS without DSM energy savings of 13%, primarily through a comprehensive portfolio of renewable energy power purchase agreements, net energy metering programs and biofuels. The utilities believe they are on track to meet the 2015 RPS.

Recent developments in the utilities’ clean energy strategy include:

· 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. In August 2012, HECO, on behalf of HELCO, negotiated a new contract with AKP, subject to PUC approval.

· 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. With an expectation of a slight decline in 2013 energy sales from 2012 levels and then relatively flat sales until 2022, the need for additional firm capacity on Maui and Oahu is being reassessed in terms of both the amount of capacity needed and the timing of the need. MECO expects the amount of new capacity needed to range from 20 MW to 35 MW and the timing to be dependent on an evaluation of load forecast scenarios. HECO expects the amount of new capacity needed to range from 150 MW to 200 MW and the timing to be dependent on the possible retirement of generating units. MECO and HELCO plan to file draft RFPs with the PUC in the third quarter of 2012.

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

· 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.

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· In May 2012, MECO began purchasing wind energy from the 21 MW Kaheawa Wind Power II, LLC facility while it was undergoing testing. The facility went into commercial operation in July 2012.

· In May 2012, HECO signed a contract, subject to PUC approval, with the City and County of Honolulu to purchase an additional 27 MW of capacity and energy from the existing H-POWER waste-to-energy plant.

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

· HECO, HELCO, and MECO began accepting energy from feed-in tariff projects in 2011. As of June 2012, there were 3,500 kW, 345 kW, and 737 kW of installed feed-in tariff capacity from renewable energy technologies at HECO, HELCO, and MECO respectively.

· As of June 2012, there were 50,261 kW, 12,803 kW, and 17,419 kW of installed net energy metering capacity from renewable energy technologies at HECO, HELCO, and MECO, respectively. Net energy metering is proceeding at a record pace. The amount of net energy metering capacity installed in the first half of 2012 is roughly equal to the amount installed in all of 2011, which itself was at a record level.

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.

In June 2012, a Hawaii law was enacted that establishes a regulatory framework for undersea electric transmission cables connecting the electric utility systems on two or more islands. The law applies to undersea cable systems that are developed and owned by cable companies selected through an RFP process, who obtain certificates of public convenience and necessity from 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)	June 30, 2012				December 31, 2011
Short-term borrowings	$	44	2	%	$	—	—	%
Long-term debt, net	1,148		43		1,058		43
Preferred stock	34		1		34		1
Common stock equity	1,423		54		1,403		56
	$	2,649	100	%	$	2,495	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)	Six months ended June 30, 2012		June 30, 2012		December 31, 2011
Short-term borrowings(1)
Commercial paper	$	18	$	44	$	—
Line of credit draws	—		—		—
Borrowings from HEI	—		—		—
Undrawn capacity under line of credit facility (expiring December 5, 2016)	N/A		175		175

(1) The maximum amount of external short-term borrowings during the first six months of 2012 was $97 million. At June 30, 2012, HECO had $19 million of short-term borrowings from HELCO, and MECO had $9 million of short-term borrowings from HECO. These borrowings are eliminated in consolidation. At July 23, 2012, HECO had $114 million of outstanding commercial paper, its

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line of credit facility was undrawn, it had no borrowings from HEI, it had borrowings of $22 million from HELCO and it had a loan to MECO of $13 million.

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 42% for MECO as of June 30, 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 54% as of June 30, 2012, as calculated under the credit agreement), or if HECO is no longer owned by HEI.

Special purpose revenue bonds (SPRBs) and refunding SPRBs have been issued by the Department of Budget and Finance of the State of Hawaii (DBF) to finance and refinance capital improvement projects of HECO and its subsidiaries, with the source of their repayment being the unsecured financial obligations of HECO and its subsidiaries under loan agreements and notes issued to the DBF, including HECO’s guarantees of its subsidiaries’ obligations. The payment of principal and interest due on the various series of SPRBs and refunding SPRBs currently outstanding and issued prior to 2009 are insured by one of the following bond insurers: Ambac Assurance Corporation; Financial Guaranty Insurance Company (FGIC), which was placed in a rehabilitation proceeding in the State of New York in June 2012; MBIA Insurance Corporation (which bonds have been reinsured by National Public Finance Guarantee Corp.); or Syncora Guarantee Inc. (which bonds have been reinsured by Syncora Capital Assurance Inc.). The Standard & Poor’s (S&P’s) and Moody’s Investor Service’s ratings of each of these insurers, which at the time the insured obligations were issued were higher than the ratings of the utilities, are currently either lower than the ratings of the utilities (with the exception of one insurer’s higher rating by S&P) or have been withdrawn.

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 of various maturities (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, with stated interest rates ranging from 3.79% to 5.39%. Proceeds of $267 million of the Notes, together with additional funds, were used to redeem an aggregate principal amount of $271 million of bonds (with stated interest rates ranging from 5.45% to 6.20%). The $150 million of proceeds of the remaining HECO Notes, bearing interest at 5.39%, were used to finance or refinance capital expenditures.

The three 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 of each and all of the utilities then outstanding 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, which established a line of credit facility of $175 million.

Operating activities used $22 million in net cash during the first six months of 2012. Investing activities for the same period used net cash of $115 million for capital expenditures, net of contributions in aid of construction. Financing activities for the same period provided net cash of $93 million, primarily due to the increase in long-term debt and short-term borrowings, partly offset by payment of $38 million of common and preferred dividends.

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Bank

RESULTS OF OPERATIONS

	Three months ended June 30				%
(in thousands)	2012		2011		Change		Primary reason(s) for significant change
Revenues	$	64,721	$	66,318	(2	)	Lower interest income primarily due to lower yields on earning assets as a result of the lower interest rate environment. Higher gain on sale of loans was offset by a nonrecurring insurance gain in 2011.

Operating income	21,874		23,820		(8	)	Lower net interest income and higher noninterest expenses

Net income	14,189		15,195		(7	)	Lower operating income

	Six months ended June 30				%
(in thousands)	2012		2011		change		Primary reason(s) for significant change
Revenues	$	129,973	$	131,631	(1	)	Lower interest income primarily due to lower yields on earning assets as a result of the lower interest rate environment. Higher gain on sale of loans was partially offset by lower fee income and a nonrecurring insurance gain in 2011.

Operating income	44,786		45,574		(2	)	Lower net interest income and higher noninterest expenses, partly offset by lower provision for loan losses

Net income	30,066		29,046		4		Lower operating income was offset by lower income tax expense

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

	Three months ended June 30				Six months ended June 30
(in thousands)	2012		2011		2012		2011
Gain on sale of loans	$	2,185	$	518	$	4,220	$	1,176
Bank-owned life insurance	993		2,142		1,972		3,111
Other	456		517		837		1,269
Total other income	$	3,634	$	3,177	$	7,029	$	5,556
FDIC insurance premium	$	854	$	876	$	1,707	$	2,303
Marketing	554		710		1,104		1,351
Office supplies, printing and postage	919		926		1,909		1,844
Communication	430		444		866		831
Other	5,349		4,999		9,227		9,559
Total other expense	$	8,106	$	7,955	$	14,813	$	15,888

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 six months ended June 30, 2012, ASB reported a 1.22% return on assets, net interest margin of 4.01% and a 58% efficiency ratio.

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Results — three months ended June 30, 2012 vs. three months ended June 30, 2011.

Increase (decrease)					(in millions)

$	(1	)			Net interest income before provision for loan losses. Higher average earning asset balances and lower funding costs were more than offset by lower yields on earning assets. ASB’s average loan portfolio balance for the three months ended June 30, 2012 was $129 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 $99 million, $120 million and $62 million, respectively. ASB targeted these loan types because of their shorter duration and/or variable rates. Despite a $101 million increase in residential loan production, the average residential loan portfolio decreased by $148 million due to higher repayments and loan sales in connection with ASB’s long-term strategy to manage interest rate risk. The loan portfolio yield was impacted by the low interest rate environment as new loan production yields were lower than the average portfolio yield and the shift in mix of the loan portfolio. The average investment and mortgage-related securities portfolio balance decreased by $65 million as ASB experienced higher prepayments on the portfolio and funded higher loan originations. Average deposit balances for the three months ended June 30, 2012 increased by $61 million compared to average balances for the same period in 2011 due to an increase in core deposits of $144 million, partly offset by a decrease in term certificates of $83 million. The other borrowings average balance decreased by $25 million due to the payoff of a maturing FHLB advance and lower retail repurchase agreements.

—					Provision for loan loss. Decrease primarily due to lower net charge-offs in the residential land portfolio along with improved credit quality associated with the gradual improvement in Hawaii’s economy, offset by loan loss reserves established for the growth in the loan portfolio.

—					Noninterest income. Higher gain on sale of loans as more residential loans were sold in order to manage interest rate risk, offset by a nonrecurring insurance gain in 2011

(1		)			Noninterest expense. Higher employee benefit expenses and higher product and project related expenses

(1		)			Net income. Decrease largely due to:
			(1	)	Lower net interest income
			(1	)	Higher noninterest expenses
			1		Lower tax expense

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Results — six months ended June 30, 2012 vs. six months ended June 30, 2011.

Increase (decrease)					(in millions)

$	(1	)			Net interest income before provision for loan losses. Higher average earning asset balances and lower funding costs were more than offset by lower yields on earning assets. ASB’s average loan portfolio balance for the six months ended June 30, 2012 was $139 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 $122 million, $120 million and $57 million, respectively. ASB targeted these loan types because of their shorter duration and/or variable rates. Despite a $171 million increase in residential loan production, the average residential loan portfolio decreased by $150 million due to higher repayments and loan sales in connection with ASB’s long-term strategy to manage interest rate risk. The loan portfolio yield was impacted by the low interest rate environment as new loan production yields were lower than the average portfolio yield and the shift in mix of the loan portfolio. The average investment and mortgage-related securities portfolio balance decreased by $65 million as ASB experienced higher prepayments on the portfolio and funded higher loan originations. Average deposit balances for the six months ended June 30, 2012 increased by $83 million compared to average balances for the same period in 2011 due to an increase in core deposits of $177 million, partly offset by a decrease in term certificates of $94 million. The other borrowings average balance decreased by $15 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 gradual improvement 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, partly offset by a nonrecurring insurance gain in 2011

(1		)			Noninterest expense. Higher employee benefit expenses and higher product and project related expenses, partly offset by a reversal of interest expense for an uncertain tax position

1					Net income. Increase largely due to:
			(1	)	Lower net interest income
			1		Lower provision for loan losses
			1		Higher noninterest income
			(1	)	Higher noninterest expense
			1		Lower income tax expense

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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 June 30	2012						2011
(dollars in thousands)	Average balance			Interest		Average rate (%)	Average balance			Interest		Average rate (%)

Assets:
Other investments (1)	$	201,812		$	66	0.13	$	223,676		$	79	0.14
Investment and mortgage-related securities	624,581			3,435		2.20	689,463			3,836		2.23
Loans receivable (2)	3,724,607			44,473		4.79	3,595,485			45,648		5.08
Total interest-earning assets (3)	4,551,000			47,974		4.22	4,508,624			49,563		4.40
Allowance for loan losses	(39,295		)				(40,078		)
Non-interest-earning assets	429,258						417,899
Total assets	$	4,940,963					$	4,886,445
Liabilities and shareholder’s equity:
Interest-bearing demand and savings deposits	$	2,525,859		407		0.06	$	2,526,193		718		0.11
Time certificates	530,896			1,289		0.97	613,951			1,669		1.09
Total interest-bearing deposits	3,056,755			1,696		0.22	3,140,144			2,387		0.30
Other borrowings	225,745			1,214		2.13	250,407			1,382		2.19
Total interest-bearing liabilities	3,282,500			2,910		0.35	3,390,551			3,769		0.44
Non-interest bearing liabilities:
Deposits	1,052,275						907,592
Other	106,125						89,566
Total liabilities	4,440,900						4,387,709
Shareholder’s equity	500,063						498,736
Total liabilities and shareholder’s equity	$	4,940,963					$	4,886,445
Net interest income				$	45,064					$	45,794
Net interest margin (%) (4)						3.97						4.07

Six months ended June 30	2012						2011
(dollars in thousands)	Average balance			Interest		Average rate (%)	Average balance			Interest		Average rate (%)

Assets:
Other investments (1)	$	226,714		$	162	0.14	$	229,826		$	165	0.14
Investment and mortgage-related securities	609,826			7,315		2.40	674,477			7,645		2.27
Loans receivable (2)	3,710,338			89,361		4.83	3,571,040			91,745		5.15
Total interest-earning assets (3)	4,546,878			96,838		4.27	4,475,343			99,555		4.46
Allowance for loan losses	(38,741		)				(39,953		)
Non-interest-earning assets	430,929						417,109
Total assets	$	4,939,066					$	4,852,499
Liabilities and shareholder’s equity:
Interest-bearing demand and savings deposits	$	2,539,960		868		0.07	$	2,493,674		1,422		0.11
Time certificates	536,113			2,607		0.98	629,567			3,558		1.14
Total interest-bearing deposits	3,076,073			3,475		0.23	3,123,241			4,980		0.32
Other borrowings	231,535			2,475		2.12	246,418			2,749		2.22
Total interest-bearing liabilities	3,307,608			5,950		0.36	3,369,659			7,729		0.46
Non-interest bearing liabilities:
Deposits	1,026,187						895,680
Other	108,519						90,536
Total liabilities	4,442,314						4,355,875
Shareholder’s equity	496,752						496,624
Total liabilities and shareholder’s equity	$	4,939,066					$	4,852,499
Net interest income				$	90,888					$	91,826
Net interest margin (%) (4)						4.01						4.11

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(1)	Includes federal funds sold, interest bearing deposits and stock in the FHLB of Seattle.
(2)	Includes loan fees of $1.3 million and $0.6 million for the three months ended June 30, 2012 and 2011, respectively, and $2.5 million and $1.8 million for the six months ended June 30, 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 June 30, 2012 and 2011, respectively, and $0.4 million and $0.2 million for the six months ended June 30, 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.

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:

	June 30, 2012				December 31, 2011
(dollars in thousands)	Balance			% of total	Balance			% of total
Real estate loans:
Residential 1-4 family	$	1,893,456		50.5	$	1,926,774		52.2
Commercial real estate	372,616			10.0	331,931			9.0
Home equity line of credit	589,852			15.7	535,481			14.5
Residential land	34,200			0.9	45,392			1.2
Commercial construction	50,120			1.3	41,950			1.1
Residential construction	1,797			0.1	3,327			0.1
Total real estate loans, net	2,942,041			78.5	2,884,855			78.1

Commercial loans	704,255			18.8	716,427			19.4
Consumer loans	101,042			2.7	93,253			2.5
	3,747,338			100.0	3,694,535			100.0
Less: Deferred fees and discounts	(12,401		)		(13,811		)
Allowance for loan losses	(39,463		)		(37,906		)
Total loans, net	$	3,695,474			$	3,642,818

The increase in the total loan portfolio during the first six months of 2012 was primarily due to an increase in ASB’s home equity lines of credit and commercial real estate 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:

	June 30, 2012		December 31,2011
Federal agency obligations	33	%	35	%
Mortgage-related securities — FNMA, FHLMC and GNMA	54		55
Municipal bonds	13		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

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agreements to repurchase continue to be additional sources of funds. Advances from the FHLB of Seattle declined $15 million from June 30, 2011 to June 30, 2012 due to the payoff of a maturing advance in the fourth quarter of 2011. As of June 30, 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 six months ended June 30, 2012 was 0.17%, compared to 0.25% for the six months ended June 30, 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” impairment in the value of the securities. As of June 30, 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 $11 million and $10 million, respectively. See “Item 3. Quantitative and qualitative disclosures about market risk.”

During the first six months of 2012, ASB recorded a provision for loan losses of $5.9 million primarily due to charge-offs during the year for 1-4 family, residential land, commercial and consumer loans. During the first six months of 2011, ASB recorded a provision for loan losses of $7.1 million primarily due to the net charge-offs during the year 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.

	Six months ended June 30						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	5,924			7,105			15,009
Less: net charge-offs	4,367			8,468			17,749
Allowance for loan losses, end of period	$	39,463		$	39,283		$	37,906
Ratio of allowance for loan losses, end of period, to end of period loans outstanding	1.06		%	1.09		%	1.03		%
Ratio of net charge-offs during the period to average loans outstanding (annualized)	0.24		%	0.47		%	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 transferred to the OCC, the FDIC, the Federal Reserve Board (FRB) and the Consumer Financial Protection Bureau (Bureau). Supervision and regulation of HEI, as a thrift holding company, moved to the FRB, and supervision and regulation of ASB, as a federally chartered savings bank, moved to the OCC. While the laws and regulations applicable to HEI and ASB did not generally change, the applicable laws and regulations are being interpreted, and amended regulations may be or have been 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

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

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

The “Durbin Amendment” to the Dodd-Frank Act required the FRB to issue rules to ensure that debit card interchange fees are “reasonable and proportional” to the processing costs incurred. In June 2011, the FRB issued a final rule establishing standards for debit card interchange fees and prohibiting network exclusivity arrangements and routing restrictions. Under the final rule, effective October 1, 2011, the maximum permissible interchange fee that an issuer may receive for an electronic debit transaction is 21-24 cents, depending on certain components. ASB currently earns an average of 54 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.

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

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

The second NPR, titled Regulatory Capital Rules: Standardized Approach for Risk-weighted Assets; Market Discipline and Disclosure Requirements (Standardized Approach NPR), proposes to revise and harmonize the

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rules for calculating risk-weighted assets to enhance risk sensitivity and address weaknesses identified over the past several years. The Standardized Approach NPR would incorporate aspects of the Basel II standardized framework such as methods for determining risk-weighted assets for residential mortgages, securitization exposures, and counterparty credit risk. The Standardized Approach NPR would apply to the same set of institutions as the Basel III NPR, but also introduces disclosure requirements for U.S. banking organizations with $50 billion or more in assets.

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

Proposed Capital Requirements

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

The final rules are proposed to become effective January 1, 2013. The proposed rules allow for a transition period to meet the proposed capital requirement levels. ASB is reviewing the proposed rules and the impact to its capital ratios. Based on a preliminary assessment, management believes ASB and HEI can satisfy the proposed capital rules, if adopted.

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

FINANCIAL CONDITION

Liquidity and capital resources.

(dollars in millions)	June 30, 2012		December 31, 2011		% change
Total assets	$	4,964	$	4,910	1
Available-for-sale investment and mortgage-related securities	639		624		2
Loans receivable held for investment, net	3,695		3,643		1
Deposit liabilities	4,137		4,070		2
Other bank borrowings	219		233		(6	)

As of June 30, 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 June 30, 2012, ASB’s unused FHLB borrowing capacity was approximately $0.9 billion. As of June 30, 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 six months of 2012, net cash provided by ASB’s operating activities was $23 million. Net cash used during the same period by ASB’s investing activities was $73 million, primarily due to purchases of investment and mortgage-related securities of $94 million and a net increase in loans receivable of $60 million, offset by repayments of investment and mortgage-related securities of $75 million and proceeds from the sale of mortgage-related securities and real estate acquired in settlement of loans of $4 million and $3 million, respectively. Net cash provided in financing activities during this period was $32 million, primarily due to net increases in deposit liabilities of $67 million, offset by a decrease in retail repurchase agreements of $15 million and the payment of $20 million in common stock dividends to HEI.

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 June 30, 2012, ASB was well-capitalized (minimum ratio

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requirements noted in parentheses) with a leverage ratio of 9.2% (5.0%), a Tier-1 risk-based capital ratio of 11.8% (6.0%) and a total risk-based capital ratio of 12.8% (10.0%). FRB approval is required before ASB can pay a dividend or otherwise make a capital distribution to HEI (through ASHI).

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 June 30, 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)	June 30, 2012		December 31, 2011		June 30, 2012		December 31, 2011
+300	0.4	%	0.5	%	(9.0	)%	(7.4	)%
+200	(0.3	)	(0.3	)	(4.9	)	(3.8	)
+100	(0.3	)	(0.4	)	(2.2	)	(1.5	)
-100	(0.4	)	(0.4	)	(1.9	)	(3.5	)

Management believes that ASB’s interest rate risk position as of June 30, 2012 represents a reasonable level of risk. The net interest income (NII) sensitivities as of December 31, 2011 and June 30, 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 very comparable NII profiles. 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 $819 million as of June 30, 2012 compared to $848 million as of December 31, 2011.

The change in EVE was more sensitive to rising rate scenarios as of June 30, 2012 compared to December 31, 2011 due to the shift in asset mix from cash and residential mortgages to investments, commercial real estate and consumer loans over the first six months of 2012.

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

In May 2012, the electric utilities converted their customer information system, including modules used to collect customer account information, gather monthly electricity use data, create bills and accept payments. The implementation of these modules resulted in material changes to the Company’s internal controls over financial reporting (as defined in Rules 13(a)-15(f) and 15(d)-15(f) under the Exchange Act). Therefore, the electric utilities modified the design and documentation of internal control processes and procedures relating to the new system to replace existing internal controls over financial reporting, as appropriate. The system changes were undertaken to replace the electric utilities’ outdated legacy system and provide reliability, flexibility, and increased customer service for the electric utilities and their customers, and were not undertaken in response to any actual or perceived deficiencies in the electric utilities’ internal control over financial reporting.

During the second quarter of 2012, there were no other 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 June 30, 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 June 30, 2012. Based on their evaluations, as of June 30, 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

In May 2012, the electric utilities converted their customer information system, including modules used to collect customer account information, gather monthly electricity use data, create bills and accept payments. The implementation of these modules resulted in material changes to the electric utilities’ internal controls over financial reporting (as defined in Rules 13(a)-15(f) and 15 (d)-15(f) under the Exchange Act). Therefore, the electric utilities modified the design and documentation of internal control processes and procedures relating to the new system to replace existing internal controls over financial reporting, as appropriate. The system changes were undertaken to replace the electric utilities’ outdated legacy system and provide reliability, flexibility, and increased customer service for the electric utilities and their customers, and were not undertaken in response to any actual or perceived deficiencies in the electric utilities’ internal control over financial reporting.

During the second quarter of 2012, there were no other 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 June 30, 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 June 30, 2012. Based on their evaluations, as of June 30, 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

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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.

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

There were no purchases of HEI common shares made during the quarter ended June 30, 2012. However, certain purchases of HEI common shares were made in prior periods as follows:

ISSUER PURCHASES OF EQUITY SECURITIES

Period	(a) Total Number of Shares Purchased *	(b) Average Price Paid per Share		(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
May 2010	1,029	$	23.165	—	NA
December 2011	101	$	25.53	—	NA
February 2012	769	$	25.395	—	NA

NA Not applicable.

* Represents HEI common shares purchased from employees who used the proceeds toward satisfying the employees’ liability for payroll taxes owed on compensation for vested restricted stock.

Item 5. Other Information

A. Ratio of earnings to fixed charges.

	Six months ended June 30		Years ended December 31
	2012	2011	2011	2010	2009	2008	2007
HEI and Subsidiaries
Excluding interest on ASB deposits	3.59	2.66	3.22	2.89	2.29	2.06	1.78
Including interest on ASB deposits	3.41	2.51	3.03	2.64	1.95	1.71	1.52
HECO and Subsidiaries	3.79	2.76	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	Nineteenth Amendment effective as of January 1, 2012, to Trust Agreement (dated as of February 1, 2000) between HEI, ASB and Fidelity Management Trust Company, as Trustee

HEI Exhibit 4.2	Letter Amendment effective as of July 31, 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, six months ended June 30, 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	HEI Certification Pursuant to 18 U.S.C. Section 1350

HEI Exhibit 101.INS	XBRL Instance Document

HEI Exhibit 101.SCH	XBRL Taxonomy Extension Schema Document

HEI Exhibit 101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document

HEI Exhibit 101.DEF	XBRL Taxonomy Extension Definition Linkbase Document

HEI Exhibit 101.LAB	XBRL Taxonomy Extension Label Linkbase Document

HEI Exhibit 101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

HECO Exhibit 12.2	Hawaiian Electric Company, Inc. and Subsidiaries Computation of ratio of earnings to fixed charges, six months ended June 30, 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 32.2	HECO Certification Pursuant to 18 U.S.C. Section 1350

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SIGNATURES

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

HAWAIIAN ELECTRIC INDUSTRIES, INC.		HAWAIIAN ELECTRIC COMPANY, INC.
(Registrant)		(Registrant)


By	/s/ Constance H. Lau	By	/s/ Richard M. Rosenblum
	Constance H. Lau		Richard M. Rosenblum
	President and Chief Executive Officer		President and Chief Executive Officer
	(Principal Executive Officer of HEI)		(Principal Executive Officer of HECO)


By	/s/ James A. Ajello	By	/s/ Tayne S. Y. Sekimura
	James A. Ajello		Tayne S. Y. Sekimura
	Executive Vice President,		Senior Vice President
	Chief Financial Officer and Treasurer		and Chief Financial Officer
	(Principal Financial Officer of HEI)		(Principal Financial Officer of HECO)


By	/s/ 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: August 3, 2012		Date: August 3, 2012